Edgar Filing: North American Energy Partners Inc.

6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

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

under the Securities Exchange Act of 1934

For the month of November 2008

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 o Form 40-F þ

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): o

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): o

Documents Included as Part of this Report


1.	Interim consolidated financial statements of North American Energy Partners Inc. for the three and six months ended September 30, 2008.

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

SIGNATURES

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

NORTH AMERICAN ENERGY PARTNERS INC.


	By:	/s/ Peter Dodd

Name: Peter Dodd


	Title:	Chief Financial Officer

Date: November 6, 2008

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Financial Statements
For the three and six months ended September 30, 2008
(Expressed in thousands of Canadian dollars)
(Unaudited)

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Balance Sheets


	September 30,			March 31,
(In thousands of Canadian dollars)	2008			2008
	(Unaudited)

ASSETS
Current assets:
Cash and cash equivalents	$	—		$	32,871
Accounts receivable		138,644			166,002
Unbilled revenue		110,160			70,883
Inventory (note 3(c))		9,403			110
Prepaid expenses and deposits		8,387			9,300
Other assets (note 3(c))		—			3,703
Future income taxes		7,290			8,217

		273,884			291,086
Future income taxes		11,591			18,199
Assets held for sale		856			1,074
Plant and equipment (note 5)		335,762			281,039
Goodwill		200,072			200,072
Intangible assets, net of accumulated amortization of $2,659 (March 31, 2008 — $2,105)		1,574			2,128

	$	823,739		$	793,598

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Cheques issued in excess of cash deposits	$	311		$	—
Accounts payable		95,811			113,143
Accrued liabilities		38,983			45,078
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		13,593			4,772
Current portion of capital lease obligations		5,398			4,733
Current portion of derivative financial instruments (note 10(a))		7,203			4,720
Future income taxes		12,283			10,907

		173,582			183,353
Revolving credit facility (note 6(a))		10,000			—
Deferred lease inducements		888			941
Capital lease obligations		11,804			10,043
Director deferred stock unit liability		421			190
Senior notes (note 6(b))		211,843			198,245
Derivative financial instruments (note 10(a))		87,629			93,019
Asset retirement obligation (note 7)		417			—
Future income taxes		23,149			24,443

		519,733			510,234

Shareholders’ equity:
Common shares (authorized — unlimited number of voting and non-voting common shares; issued and outstanding — 36,038,476 voting common shares (March 31, 2008 — 35,929,476 voting common shares) (note 8(a))		299,973			298,436
Contributed surplus (note 8(b))		4,455			4,215
Deficit		(422	)		(19,287	)

		304,006			283,364

Guarantee (note 16)
	$	823,739		$	793,598

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

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


(In thousands of Canadian dollars, except per share amounts)	Three Months Ended September 30,						Six Months Ended September 30,
(Unaudited)	2008			2007			2008			2007
				Restated						Restated
				(See note 4)						(See note 4)

Revenue	$	280,283		$	223,575		$	539,270		$	391,202
Project costs		154,961			135,266			303,592			229,939
Equipment costs		60,787			42,212			106,597			87,351
Equipment operating lease expense		9,586			3,569			18,384			7,504
Depreciation		10,668			7,318			18,826			16,294

Gross profit		44,281			35,210			91,871			50,114
General and administrative costs		19,345			17,360			38,561			31,987
Loss on disposal of plant and equipment		1,612			576			2,756			845
Loss on disposal of asset held for sale		2			—			24			316
Amortization of intangible assets		276			182			554			323

Operating income before the undernoted		23,046			17,092			49,976			16,643
Interest expense (note 9)		6,440			6,196			12,889			12,934
Foreign exchange loss/(gain)		8,236			(14,252	)		6,595			(31,352	)
Realized and unrealized loss on derivative financial instruments (note 10(a))		7,618			19,686			5,353			41,200
Other income		(3	)		(128	)		(21	)		(236	)

Income (loss) before income taxes		755			5,590			25,160			(5,903	)
Income taxes (note 12(c)):
Current income taxes		62			—			62			21
Future income taxes (recovery)		1,915			2,414			7,224			(518	)

Net (loss) income and comprehensive (loss) income for the period		(1,222	)		3,176			17,874			(5,406	)
Retained earnings (deficit), beginning of period — as previously reported		800			(67,653	)		(19,287	)		(55,526	)
Change in accounting policy related to financial instruments (note 4)		—			—			—			(3,545	)
Change in accounting policy related to inventory (note 3(c))		—			—			991			—

Deficit, end of period	$	(422	)	$	(64,477	)	$	(422	)	$	(64,477	)

Net (loss) income per share — basic (note 8(c))	$	(0.03	)	$	0.09		$	0.50		$	(0.15	)

Net (loss) income per share — diluted (note 8(c))	$	(0.03	)	$	0.09		$	0.48		$	(0.15	)

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Statements of Cash Flows


(In thousands of Canadian dollars)	Three Months Ended September 30,						Six Months Ended September 30,
(Unaudited)	2008			2007			2008			2007
				Restated						Restated
				(See note 4)						(See note 4)

Cash provided by (used in):
Operating activities:
Net (loss) income for the period	$	(1,222	)	$	3,176		$	17,874		$	(5,406	)
Items not affecting cash:
Depreciation		10,668			7,318			18,826			16,294
Write-down of other assets to replacement cost		—			1,848			—			1,848
Amortization of intangible assets		276			182			554			323
Amortization of deferred lease inducements		(27	)		(52	)		(53	)		(52	)
Loss on disposal of plant and equipment		1,612			576			2,756			845
Loss on disposal of assets held for sale		2			—			24			316
Unrealized foreign exchange loss/(gain) on senior notes		8,147			(13,864	)		6,316			(31,014	)
Amortization of bond issue costs, premiums and financing costs		184			110			358			507
Unrealized change in the fair value of derivative financial instruments		6,950			19,019			4,017			39,865
Stock-based compensation expense (note 14)		670			388			1,306			747
Accretion expense — asset retirement obligation		57			—			106			—
Future income taxes		1,915			2,414			7,224			(518	)
Net changes in non-cash working capital (note 12(b))		(38,342	)		1,175			(35,077	)		4,825

		(9,110	)		22,290			24,231			28,580

Investing activities:
Acquisition, net of cash acquired		—			—			—			(1,581	)
Purchase of plant and equipment		(16,177	)		(33,352	)		(75,526	)		(43,545	)
Additions to assets held for sale		—			—			—			(2,248	)
Proceeds on disposal of plant and equipment		3,296			226			4,648			3,916
Proceeds on disposal of assets held for sale		2			—			194			10,200
Net changes in non-cash working capital (note 12(b))		(38,214	)		17,493			5,259			14,249

		(51,093	)		(15,633	)		(65,425	)		(19,009	)

Financing activities:
Cheques issued in excess of cash deposits		311			—			311			—
Increase (decrease) in revolving credit facility		10,000			(20,000	)		10,000			(20,500	)
Repayment of capital lease obligations		(1,465	)		(806	)		(2,690	)		(1,608	)
Issue of common shares		—			—			—			740
Stock options exercised (note 8(a))		25			—			702			—
Financing costs		—			—			—			(767	)

		8,871			(20,806	)		8,323			(22,135	)

Decrease in cash and cash equivalents		(51,332	)		(14,149	)		(32,871	)		(12,564	)
Cash and cash equivalents, beginning of period		51,332			9,480			32,871			7,895

Cash and cash equivalents, end of period	$	—		$	(4,669	)	$	—		$	(4,669	)

Supplemental cash flow information (note 12(a))

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements
For the three and six months ended September 30, 2008
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
(Unaudited)


1.	Nature of operations

North American Energy Partners Inc. was incorporated under the Canada Business Corporations Act on October 17, 2003. On November 26, 2003, North American Energy Partners Inc. (the “Company”) purchased all of 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 and substantially all of the plant and equipment, prepaids and accounts payable of North American Equipment Ltd. 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, pipeline and piling installations in Canada.


2.	Basis of presentation

These unaudited interim consolidated financial statements (the “financial statements”) are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) for interim financial statements and do not include all of the disclosures normally contained in the Company’s annual consolidated financial statements. Since the determination of many assets, liabilities, revenues and expenses is dependent on future events, the preparation of these financial statements requires the use of estimates and assumptions. In the opinion of management, these financial statements have been prepared within reasonable limits of materiality. Except as disclosed in note 3, these financial statements follow the same significant accounting policies as described and used in the most recent annual consolidated financial statements of the Company for the year ended March 31, 2008 and should be read in conjunction with those consolidated financial statements.

These financial statements include the accounts of the Company, its wholly-owned subsidiaries, NACGI and NACG Finance LLC, the Company’s joint venture, Noramac Ventures Inc. and the following 100% owned subsidiaries of NACGI:


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


3.	Recently adopted Canadian accounting pronouncements


a)	*Financial instruments — disclosure and presentation*

Effective April 1, 2008, the Company prospectively adopted the Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 3862, “Financial Instruments — Disclosures”, which replaces disclosure guidance in CICA Handbook Section 3861 and provides expanded disclosure requirements that enable users to evaluate the significance of financial instruments on the entity’s financial position and its performance and the nature and extent of risks arising from financial instruments to which the entity is exposed during the period and at the balance sheet date, and how the entity manages those risks. This standard harmonizes disclosures with International Financial Reporting Standards. The Company has provided the additional required disclosures in note 10 to its interim consolidated financial statements for the three and six months ended September 30, 2008.

Effective April 1, 2008, the Company adopted CICA Handbook Section 3863, “Financial Instruments — Presentation”, which carries forward presentation guidance in CICA Handbook Section 3861. This Section establishes standards for presentation of financial instruments and non-financial derivatives. It deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, gains and losses, and the circumstances in which financial assets and financial liabilities are offset. The adoption of this standard did not have a material impact on the presentation of financial instruments in the Company’s financial statements.


b)	*Capital disclosures*

Effective April 1, 2008, the Company prospectively adopted CICA Handbook Section 1535, “Capital Disclosures”, which requires disclosure of qualitative and quantitative information that enables users to evaluate the Company’s objectives, policies and process for managing capital. The Company has provided the additional required disclosures in note 11 to its interim consolidated financial statements for the three and six months ended September 30, 2008.


c)	*Inventories*

Effective April 1, 2008, the Company retrospectively adopted CICA Handbook Section 3031, “Inventories” without restatement of prior periods. This standard requires inventories to be measured at the lower of cost and net realizable value and provides guidance on the determination of cost, including the allocation of overheads and other costs to inventories, the requirement for an entity to use a consistent cost formula for inventory of a similar nature and use, and the reversal of previous write-downs to net realizable value when there is subsequent increases in the value of inventories. This new standard also clarifies that spare component parts that do not qualify for recognition as property, plant and equipment should be classified as inventory. To adopt the new standard, the Company reversed a tire impairment that was previously recorded at March 31, 2008 in other assets of $1,383 with a corresponding decrease to opening deficit of $991 net of future taxes of $392. The Company then reclassified $5,086 of tires and spare component parts from ‘other assets’ to ‘inventory’. As at September 30, 2008, inventory is comprised of tires and spare component parts of $9,293 and job materials of $110. The Company carries inventory at the lower of weighted average cost and net realizable value. The carrying amount of inventory pledged as security for borrowings under the revolving credit facility (note 6 (a)) is approximately $9,403 as at September 30, 2008. The adoption of this standard did not have a significant impact on net (loss) income for the three and six months ended September 30, 2008.


d)	*Going concern*

Effective April 1, 2008, the Company prospectively adopted CICA Section 1400, “General Standards of Financial Statement Presentation”. These amendments require management to assess an entity’s ability to continue as a going concern. When management is aware of material uncertainties related to events or conditions that may cast doubt on an entity’s ability to continue as a going concern, those uncertainties must be disclosed. In assessing the appropriateness of the going concern assumption, the standard requires management to consider all available information about the future, which is at least, but not limited to, twelve months from the balance sheet date. The adoption of this standard did not have a material impact on the presentation and disclosures within the Company’s consolidated financial statements.


e)	*Recent Canadian accounting pronouncements not yet adopted*


i.	Goodwill and intangible assets

In February 2008, the CICA issued Handbook Section 3064, “Goodwill and Intangible Assets” which replaces Section 3062, Goodwill and Intangible Assets, and Section 3450, Research and Development Costs, establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Accounting Standard IAS 38, Intangible Assets. This new standard is effective for the Company’s interim and annual consolidated financial statements commencing April 1, 2009. The Company is currently evaluating the impact of this standard.


4.	Restatement

In preparing the financial statements for the year ended March 31, 2008, the Company determined that its previously issued interim unaudited consolidated financial statements for the three and six months ended September 30, 2007 did not properly account for an embedded derivative that is not closely related to the host contract with respect to price escalation features in a supplier maintenance contract. As disclosed in the annual consolidated statements, the Company has restated its original transition adjustment on adoption of CICA Handbook Section 3855, “Financial Instruments — Recognition and Measurement” disclosed in the financial statements for the three and six months ended September 30, 2007 and recorded the fair value of this embedded derivative liability of $2,474 on April 1, 2007, with a corresponding increase in the opening deficit of $1,769, net of future income taxes of $705.

The embedded derivative is measured at fair value and included in derivative financial instruments on the consolidated balance sheet with changes in fair value recognized in net income since April 1, 2007 and the comparative figures for the three and six months ended September 30, 2007 have been restated to account for this embedded derivative.

The impact of this restatement on the Interim Consolidated Statements of Operations, Comprehensive Income (Loss) and Deficit is as follows:


	As Previously
Three Months Ended September 30, 2007	Reported			Adjustments			As Restated

Realized and unrealized loss on derivative financial instruments	$	21,236		$	(1,550	)	$	19,686
Future income taxes		1,972			442			2,414
Net income		2,068			1,108			3,176
Deficit, beginning of period		(67,625	)		(28	)		(67,653	)
Deficit, end of period		(65,557	)		1,080			(64,477	)
Basic and diluted net income per share		0.06			0.03			0.09


	As Previously
Six Months Ended September 30, 2007	Reported			Adjustments			As Restated

Realized and unrealized loss on derivative financial instruments	$	45,185		$	(3,985	)	$	41,200
Future income taxes		(1,654	)		1,136			(518	)
Net (loss) income		(8,255	)		2,849			(5,406	)
Change in accounting policy related to financial instruments	$	(1,776	)	$	(1,769	)	$	(3,545	)
Deficit, end of period		(65,557	)		1,080			(64,477	)
Basic and diluted loss per share		(0.23	)		0.08			(0.15	)

The impact of this restatement on the Interim Consolidated Balance Sheets is as follows:


	As Previously
As at September 30, 2007	Reported			Adjustments			As Restated

Derivative financial instruments	$	108,538		$	(1,511	)	$	107,027
Future income taxes (long-term asset)		26,007			(431	)		25,576
Deficit		(65,557	)		1,080			(64,477	)

The impact of this restatement on the Interim Consolidated Statements of Cash Flows is as follows:


	As Previously
Three Months Ended September 30, 2007	Reported		Adjustments			As Restated

Net income	$	2,068	$	1,108		$	3,176
Unrealized change in fair value of derivative financial instruments		20,569		(1,550	)		19,019
Future income taxes		1,972		442			2,414


	As Previously
Six Months Ended September 30, 2007	Reported			Adjustments			As Restated

Net (loss) income	$	(8,255	)	$	2,849		$	(5,406	)
Unrealized change in fair value of derivative financial instruments		43,850			(3,985	)		39,865
Future income taxes		(1,654	)		1,136			(518	)


5.	Plant and equipment


			Accumulated		Net Book
September 30, 2008	Cost		Depreciation		Value

Heavy equipment	$	335,848	$	71,109	$	264,739
Major component parts in use		14,055		1,665		12,390
Other equipment		18,969		7,166		11,803
Licensed motor vehicles		10,537		7,018		3,519
Office and computer equipment		10,682		4,392		6,290
Buildings		19,904		4,148		15,756
Leasehold improvements		6,474		1,435		5,039
Assets under capital lease		26,321		10,095		16,226

	$	442,790	$	107,028	$	335,762


			Accumulated		Net Book
March 31, 2008	Cost		Depreciation		Value

Heavy equipment	$	281,975	$	62,539	$	219,436
Major component parts in use		12,291		4,797		7,494
Other equipment		17,086		6,232		10,854
Licensed motor vehicles		8,981		6,110		2,871
Office and computer equipment		9,016		3,479		5,537
Buildings		19,530		3,443		16,087
Leasehold improvements		6,272		1,107		5,165
Assets under capital lease		23,271		9,676		13,595

	$	378,422	$	97,383	$	281,039

During the three and six months ended September 30, 2008, additions of plant and equipment included $3,952 and $5,116, respectively, for capital leases (three and six months ended September 30, 2007 — $280 and $292 respectively). Depreciation of equipment under capital leases of $1,585 and $2,233 for the three and six months ended September 30, 2008, respectively is included in depreciation expense (three and six months ended September 30, 2007 - $613 and $1,146 respectively).


6.	Debt


a)	*Revolving credit facility*

On June 7, 2007, the Company modified its amended and restated credit agreement to provide for borrowings of up to $125.0 million (previously $55.0 million) under which revolving loans and letters of credit may be issued. This facility matures on June 7, 2010. Advances under the revolving credit facility may be repaid from time to time at the option of the Company. Based upon the Company’s current credit rating, prime rate revolving loans under the agreement will bear interest at the Canadian prime rate plus 0.25% per annum, Canadian bankers’ acceptances have stamping fees equal to 1.75% per annum and letters of credit are subject to a fee of 1.25% per annum.

This credit facility is secured by a first priority lien on substantially all the Company’s existing and after-acquired property and contains certain restrictive covenants including, but not limited to, incurring additional debt,

transferring or selling assets, making investments including acquisitions or to pay dividends or redeem shares of capital stock. The Company is also required to meet certain financial covenants under the credit agreement.

As of September 30, 2008, the Company had outstanding borrowings of $10.0 million (March 31, 2008 — $nil) under the revolving credit facility and had issued $20.8 million in letters of credit to support bonding requirements and performance guarantees associated with customer contracts and operating leases. The funds available under the revolving credit facility are reduced for any outstanding letters of credit. The Company’s borrowing availability under the facility was $94.2 million at September 30, 2008.


b)	*Senior notes*


	September 30,			March 31,
	2008			2008

Principal outstanding of 83/4% senior unsecured notes due in 2011 ($US)	$	200,000		$	200,000
Unrealized foreign exchange		11,980			5,574
Unamortized bond issue costs, financing costs and premiums, net		(2,791	)		(3,059	)
Fair value of embedded prepayment and early redemption options		2,654			(4,270	)

	$	211,843		$	198,245

The 83/4% senior notes were issued on November 26, 2003 in the amount of US$200 million (Canadian $263 million). These notes mature on December 1, 2011 with interest payable semi-annually on June 1 and December 1 of each year.

The 83/4% senior notes are unsecured senior obligations and rank equally with all other existing and future unsecured senior debt and senior to any subordinated debt that may be issued by the Company or any of its subsidiaries. The notes are effectively subordinated to all secured debt to the extent of the outstanding amount of such debt.

The 83/4% senior notes are redeemable at the option of the Company, in whole or in part, at any time on or after: December 1, 2007 at 104.4% of the principal amount; December 1, 2008 at 102.2% of the principal amount; December 1, 2009 at 100.00% of the principal amount; plus, in each case, interest accrued to the redemption date.

If a change of control occurs, the Company will be required to offer to purchase all or a portion of each holder’s 83/4% senior notes, at a purchase price in cash equal to 101.0% of the principal amount of the notes offered for repurchase plus accrued interest to the date of purchase.

As at September 30, 2008, the Company’s effective weighted average interest rate on its 83/4% senior notes, including the effect of financing costs and premiums, net, was approximately 9.31%.


7.	Asset retirement obligation

During the quarter ended June 30, 2008, the Company recorded an asset retirement obligation related to the future retirement of a facility on leased land. Accretion expense associated with this obligation is included in equipment costs in the Interim Consolidated Statements of Operations, Comprehensive Income (Loss) and Deficit.

The following table presents the reconciliation of the liability for the asset retirement obligation:


At September 30, 2008	Amount

Balance, beginning of period	$	—
Obligation relating to the future retirement of a facility on leased land		311
Accretion expense		106
Liabilities settled in the current period		—

Balance, end of period	$	417

At September 30, 2008, estimated undiscounted cash flows required to settle the obligation were $1,454. The credit adjusted risk-free rate assumed in measuring the asset retirement obligation was 8.94%. The Company expects to settle this obligation in 2021.


8.	Shares


a)	*Common shares*

Authorized:

Unlimited number of common voting shares

Unlimited number of common non-voting shares

Issued:


	Number of
	Shares		Amount

*Common voting shares*
Outstanding at March 31, 2008		35,929,476	$	298,436
Issued on exercise of options		109,000		702
Transferred from contributed surplus on exercise of options		—		835

Outstanding at September 30, 2008		36,038,476	$	299,973


b)	*Contributed surplus*


Balance, March 31, 2008	$	4,215
Stock-based compensation (note 14)		933
Deferred performance share unit plan (note 14)		142
Transferred to common shares on exercise of options		(835	)

Balance, September 30, 2008	$	4,455


c)	*Net (loss) income per share*


						Six Months Ended
	Three Months Ended September 30,					September 30,
	2008			2007		2008		2007
				(Restated)				(Restated)

Basic net (loss) income per share
Net (loss) income available to common shareholders	$	(1,222	)	$	3,176	$	17,874	$	(5,406	)
Weighted average number of common shares		36,037,867			35,752,060		36,003,454		35,711,861

Basic net (loss) income per share	$	(0.03	)	$	0.09	$	0.50	$	(0.15	)

Diluted net (loss) income per share
Net (loss) income available to common shareholders	$	(1,222	)	$	3,176	$	17,874	$	(5,406	)

Weighted average number of common shares		36,037,867			35,752,060		36,003,454		35,711,861
Dilutive effect of:
Stock options		—			1,116,755		952,872		—

Weighted average number of diluted common shares		36,037,867			36,868,815		36,956,326		35,711,861

Diluted net (loss) income per share	$	(0.03	)	$	0.09	$	0.48	$	(0.15	)

For the three months ended September 30, 2008 and the six months ended September 30, 2007 the effect of outstanding stock options on loss per share was anti-dilutive. As such, the effect of outstanding stock options used to calculate the diluted net loss per share has not been disclosed.


9.	Interest expense


	Three Months Ended				Six Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

Interest on senior notes	$	5,834	$	5,834	$	11,669	$	11,669
Amortization of bond issue costs and premiums		184		110		358		507
Interest on revolving credit facility		90		30		90		187
Interest on capital lease obligations		264		152		545		333

Interest on long-term debt		6,372		6,126		12,662		12,696
Other interest		68		70		227		238

	$	6,440	$	6,196	$	12,889	$	12,934


10.	Financial instruments and risk management


a)	*Fair value and classification of financial instruments*

Based on the measurement categories set out in CICA Handbook Section 3855, “Financial Instruments — Recognition and Measurement”, the Company’s financial instruments are classified as follows:


	•	Cash and cash equivalents are classified as financial assets held for trading and are recorded at fair value, with realized and unrealized gains and losses reported in net income;

	•	Accounts receivable and unbilled revenue are classified as loans and receivables and are initially recorded at fair value and subsequent to initial recognition are accounted for at amortized cost using the effective interest method;

	•	The Company has classified cheques issued in excess of cash deposits, amounts due under its revolving credit facility, accounts payable, accrued liabilities, and senior notes as other financial liabilities. Other financial liabilities are accounted for on initial recognition at fair value and subsequent to initial recognition at amortized cost using the effective interest method with gains and losses reported in net income in the period that the liability is derecognized; and

	•	Derivative financial instruments, including non-financial derivatives, are classified as held-for-trading and are measured at fair value with realized and unrealized gains and losses recognized in the Consolidated Statement of Operations, Comprehensive Income (Loss) and Deficit, unless exempted from derivative treatment as a normal purchase or sale.

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 accounts receivable, unbilled revenue, cheques issued in excess of cash deposits, 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 revolving credit facility 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 loans with similar terms. Based on these estimates, the fair value of amounts due under the revolving credit facility as at September 30, 2008 and March 31, 2008 are not significantly different than their carrying value.

The fair values of the Company’s cross-currency and interest rate swap agreements are based on values quoted by the counterparties to the agreements. 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 to estimate fair value. 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 impact of such variations could be material.


	September 30, 2008						March 31, 2008
Asset (Liability)	Carrying Amount			Fair Value			Carrying Amount			Fair Value

Senior notes(i)		(211,843	)		(207,740	)		(198,245	)		(209,178	)
Capital lease obligations(ii)		(17,202	)		(17,750	)		(14,776	)		(14,776	)


(i)		The fair value of the $US denominated 83/4% senior notes is based upon their period end closing market price as at September 30, 2008 and March 31, 2008.

(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 rate currently estimated to be available for loans with similar terms.

Derivative financial instruments that are used for risk management purposes, as described in Note 10(b) under — Risk Management consist of the following:


	Derivative
	Financial		Senior
September 30, 2008	Instruments		Notes

Cross-currency and interest rate swaps	$	74,093		—
Embedded price escalation features in a long-term revenue construction contract		10,317		—
Embedded price escalation features in long-term supplier contracts		10,422		—
Embedded prepayment and early redemption options on senior notes		—		2,654

Total fair value of derivative financial instruments		94,832		2,654
Less: current portion		7,203		—

	$	87,629		2,654


	Derivative
	Financial		Senior
March 31, 2008	Instruments		Notes

Cross-currency and interest rate swaps	$	81,649		—
Embedded price escalation features in a long-term revenue construction contract		14,821		—
Embedded price escalation features in a long-term supplier contract		1,269		—
Embedded prepayment and early redemption options on senior notes		—		(4,270	)

Total fair value of derivative financial instruments		97,739		(4,270	)
Less: current portion		4,720		—

	$	93,019		(4,270	)

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


	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
				(Restated						(Restated
				— note 4)						— note 4)

Realized and unrealized (gain) loss on cross-currency and interest rate swaps	$	(5,767	)	$	15,852		$	(6,220	)	$	30,173
Unrealized (gain)/loss on embedded price escalation features in a long-term revenue construction contract		(3,869	)		5,590			(4,504	)		11,591
Unrealized loss/(gain) on embedded price escalation features in long-term supplier contracts		9,354			(1,550	)		9,153			(3,985	)
Unrealized loss (gain) on embedded prepayment and early redemption options on senior notes		7,900			(206	)		6,924			3,421

	$	7,618		$	19,686		$	5,353		$	41,200


b)	*Risk Management*

The Company is exposed to market, credit and liquidity risks associated with its financial instruments. The Company will from time to time use various financial instruments to reduce market risk exposures from changes in foreign currency exchange rates and interest rates. The Company does not hold or use any derivative instruments for trading or speculative purposes.

Overall, the Company’s Board of Directors has responsibility for the establishment and approval of the Company’s risk management policies. Management performs a risk assessment on a continual basis to ensure that all significant risks related to the Company and its operations have been reviewed and assessed to reflect changes in market conditions and the Company’s operating activities.

Market Risk

Market risk is the risk of loss that results from changes in market factors such as foreign currency exchange rates and interest rates. The level of market risk to which the Company is exposed at any point in time varies depending on market conditions, expectations of future price or market rate movements and composition of the Company’s financial assets and liabilities held, non-trading physical assets and contract portfolios.

To manage the exposure related to changes in market risk, the Company uses 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. Market risk exposures are monitored regularly and tolerances and control processes are in place to monitor that only authorized activities are undertaken.

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


i.	*Foreign exchange risk*

The Company has 83/4% senior notes denominated in U.S. dollars in the amount of US$200 million. In order to reduce its exposure to changes in the U.S. to Canadian dollar exchange rate, the Company entered into a cross-currency swap agreement to manage this foreign currency exposure for both the principal balance due on

December 1, 2011 as well as the semi-annual interest payments from the issue date to the maturity date. In conjunction with the cross-currency swap agreement, the Company also entered into a U.S. dollar interest rate swap and a Canadian dollar interest rate swap as discussed in note 10(b)(ii) below. These derivative financial instruments were not designated as hedges for accounting purposes. At September 30, 2008 and March 31, 2008, the notional principal amount of the cross-currency swaps was US$200 million and Canadian $263 million.

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

With other variables unchanged, a 100 basis point increase (decrease) of the Canadian dollar to the U.S. dollar related to the U.S. dollar denominated senior notes would decrease (increase) net income by approximately $1.8 million. With other variables unchanged, a 100 basis point increase (decrease) in the Canadian to the U.S. dollar related to the cross-currency swap would increase (decrease) net income by approximately $2.0 million. The impact on short-term exposures would be insignificant. There would be no impact to other comprehensive income.


*ii.*	*Interest rate risk*

The Company is exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial instruments. Amounts outstanding under the Company’s revolving credit facility are subject to a floating rate. The Company’s senior notes are subject to a fixed rate.

In some circumstances, floating rate funding may be used for short-term borrowings and other liquidity requirements. The Company may use derivative instruments to manage interest rate risk.

In conjunction with the cross-currency swap agreement discussed in note 10(b)(i) above, the Company also entered into a U.S. dollar interest rate swap and a Canadian dollar interest rate swap with the net effect of economically converting the 8.75% rate payable on the 83/4% senior notes into a fixed rate of 9.765% for the duration that the 83/4% senior notes are outstanding. On May 19, 2005 in connection with the Company’s new revolving credit facility at that time, this fixed rate was increased to 9.889%. These derivative financial instruments were not designated as a hedge for accounting purposes.

At September 30, 2008 and March 31, 2008, the notional principal amounts of the interest rate swaps were US$200 million and Canadian $263 million.

As at September 30, 2008, holding all other variables constant, a 1% increase (decrease) to Canadian interest rates would impact the fair value of the interest rate swaps by $6.7 million with this change in fair value being recorded in net income. As at September 30, 2008, holding all other variables constant, a 1% increase (decrease) to US interest rates would impact the fair value of the interest rate swaps by $2.7 million with this change in fair value being recorded in net income. As at September 30, 2008, holding all other variables constant, a 1% increase (decrease) of Canadian to US interest rate volatility would impact the fair value of the interest rate swaps by $1.8 million with this change in fair value being recorded in net income.

At September 30, 2008 the Company held $10 million of floating rate debt pertaining to its revolving credit facility (March 31, 2008 — $nil). As at September 30, 2008, holding all other variables constant, a 1% increase (decrease) to interest rates would not have a significant impact on net income or equity. This assumes that the amount of floating rate debt remains unchanged from that which was held at September 30, 2008.

As at September 30, 2008 the Company is party to an interim financing agreement related to the manufacture of a piece of heavy equipment. While the equipment is under construction, the progress payments made to the manufacturer by the third party finance company are subject to a floating interest rate. This borrowing cost will be capitalized by the third party finance company until the equipment is commissioned, which is expected to be in fiscal 2009. This borrowing cost will be factored into the Company’s future operating lease payments. A 1% increase (decrease) in interest rates would result in an insignificant increase (decrease) to the borrowing cost which will be capitalized by the third party finance company. This additional (reduced) cost will impact the Company’s net income through the increased (reduced) operating lease payments in future periods.

Credit Risk

Credit risk is the financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company manages the credit risk associated with its cash by holding its funds with reputable financial institutions. The Company is exposed to credit risk through its accounts receivable and unbilled revenue. Credit risk for trade and other accounts receivables, and unbilled revenue are managed through established credit monitoring activities.

The Company has a concentration of customers in the oil and gas sector. The concentration risk is mitigated primarily by the customers being large investment grade organizations. The credit worthiness of new customers is subject to review by management through consideration of the type of customer and the size of the contract.

At September 30, 2008 and March 31, 2008, the following customers represented 10% or more of accounts receivable and unbilled revenue:


	September 30,			March 31,
	2008			2008

Customer A		24	%		19	%
Customer B		12	%		8	%
Customer C		10	%		9	%
Customer D		9	%		11	%
Customer E		8	%		18	%
Customer F		0	%		11	%

The Company reviews its accounts receivable accounts regularly and amounts are written down to their expected realizable value when outstanding amounts are determined not to be fully collectible. This generally occurs when the customer has indicated an inability to pay, the Company is unable to communicate with the customer over an extended period of time, and other methods to obtain payment have been considered and have not been successful. Bad debt expense is charged to net income in the period that the account is determined to be doubtful. Estimates of the allowance for doubtful accounts are determined on a customer-by-customer evaluation of collectability at each reporting date taking into consideration the following factors: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition and historical experience.

The Company’s maximum exposure to credit risk for trade accounts receivable is the carrying value of $133,013 as at September 30, 2008 (March 31, 2008 — $157,237), other receivables is the carrying value of $5,631 (March 31, 2008 — $8,765) and unbilled revenue is the carrying value of $110,160 as at September 30, 2008 (March 31, 2008 — $70,883). On a geographic basis as at September 30, 2008, approximately 99% (March 31, 2008 — 89%) of the balance of trade accounts receivable (before considering the allowance for doubtful accounts) was due from customers based in Western Canada.

Payment terms are generally net 30 days. As at September 30, 2008 and March 31, 2008 trade receivables are aged as follows:


	September 30,		March 31,
	2008		2008

Not past due	$	106,659	$	124,211
Past due 1-30 days		7,178		19,790
Past due 31-60 days		9,202		1,896
More than 61 days		9,974		11,340

Total	$	133,013	$	157,237

As at September 30, 2008, the Company has recorded an allowance for doubtful accounts of $2,043 (March 31, 2008 — $742) of which 72% relates to amounts that are more than 61 days past due.

The allowance is an estimate of the September 30, 2008 trade receivable balances that are considered uncollectible. Changes to the allowance during the three and six months ended September 30, 2008 consisted of payments received on outstanding balances of $32 and $100 respectively (three and six months ended September 30, 2007 — $nil and $nil, respectively), and bad debt expense of $1,323 and $1,401 for the three and six months ended September 30, 2008 (three and six months ended September 30, 2007 — $nil and $nil, respectively).

Credit risk on cross-currency and interest rate swap agreements arises from the possibility that the counterparties to the agreements may default on their respective obligations under the agreements. This credit risk only arises in instances where these agreements have positive fair value for the Company.

Liquidity Risks

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company manages liquidity risk through management of its capital structure and financial leverage, as outlined in note 11 to the unaudited interim consolidated financial statements. It also manages liquidity risk by continuously monitoring actual and projected cash flows to ensure that it will always have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company’s reputation. The Company believes that forecasted cash flows from operating activities, along with the available lines of credit, will provide sufficient cash requirements to cover the Company’s forecasted normal operating and budgeted capital expenditures.

The Company’s principal sources of cash are funds from operations and borrowings under our revolving credit facility.

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

At September 30, 2008 the Company was in compliance with its senior leverage, its interest coverage, and working capital covenants.

The following are the undiscounted contractual maturities of financial liabilities and other contractual commitments measured at period end exchange rates:


					Fiscal Year
	Carrying		Contractual		Remaining										2014 and
	Amount		Cash Flows		2009		2010		2011		2012		2013		Thereafter

Revolving credit facility	$	10,000	$	10,000	$	—	$	—	$	10,000	$	—	$	—	$	—
Accounts payable and accrued liabilities		126,125		126,125		126,125		—		—		—		—		—
Capital lease obligations (including interest)		17,202		19,047		3,144		5,457		4,667		4,062		1,618		99
Senior notes		211,843		211,980		—		—		—		211,980		—		—
Interest on senior notes		8,669		74,792		5,753		23,013		23,013		23,013		—		—
Cross-currency and interest rate swaps		74,093		72,737		749		2,996		2,996		65,996		—		—

Total	$	447,932	$	514,681	$	135,771	$	31,466	$	40,676	$	305,051	$	1,618	$	99


11.	Capital disclosures

The Company’s objectives in managing capital are to ensure sufficient liquidity to pursue its strategy of organic growth combined with strategic acquisitions and to provide returns to its shareholders. The Company defines capital that it manages as the aggregate of its shareholders’ equity, which is comprised of issued capital, contributed surplus, accumulated other comprehensive income (loss) and deficit. The Company manages its capital structure and makes adjustments to it in light of general economic conditions, the risk characteristics of the underlying assets and the Company’s working capital requirements. In order to maintain or adjust its capital structure, the Company, upon approval from its Board of Directors, may issue or repay long-term debt, issue shares, repurchase shares through a normal course issuer bid, pay dividends or undertake other activities as deemed appropriate under the specific circumstances. The Board of Directors reviews and approves any material transactions out of the ordinary course of business, including proposals on acquisitions or other major investments or divestitures, as well as capital and operating budgets.

The Company monitors debt leverage ratios as part of the management of liquidity and shareholders’ return and to sustain future development of the business. The Company is also subject to externally imposed capital requirements under its revolving credit facility and indenture agreement governing the U.S. dollar denominated 83/4% senior notes, which contains certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or to pay dividends or redeem shares of capital stock. The Company’s overall strategy with respect to capital risk management remains unchanged from the year ended March 31, 2008.

The Company is subject to restrictive covenants under its banking agreements with its principal lenders related to its revolving credit facility (note 6(a)), its capital lease obligations and senior notes (note 6(b)) that are measured on a quarterly basis. These covenants include, but are not limited to, a current ratio, senior leverage ratio, and interest coverage ratio. As at September 30, 2008, the Company was in compliance with all externally imposed covenant requirements.


12.	Other information


a)	*Supplemental cash flow information*


	Three Months Ended September 30,				Six Months Ended September 30,
	2008		2007		2008		2007

Cash paid during the period for:
Interest	$	353	$	252	$	13,821	$	13,762
Income taxes		—		—		—		22
Cash received during the period for:
Interest		1		78		6		184
Income taxes		62		—		62
Non-cash transactions:
Acquisition of plant and equipment by means of capital leases		3,952		280		5,116		292
Lease inducements		—		69		—		1,045


b)	*Net change in non-cash working capital*


	Three Months Ended September 30,						Six Months Ended September 30,
	2008			2007			2008			2007

Operating activities:
Accounts receivable	$	(12,381	)	$	(13,686	)	$	26,058		$	(31,028	)
Allowance for doubtful accounts		1,291			200			1,300			200
Unbilled revenue		(20,627	)		(15,660	)		(39,277	)		10,144
Inventory		(2,502	)		2			(4,206	)		2
Prepaid expenses and deposits		207			1,061			913			4,745
Other assets		—			(986	)		—			2,848
Accounts payable		(14,553	)		31,244			(22,591	)		21,260
Accrued liabilities		8,958			2,480			(6,095	)		(2,326	)
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		1,265			(3,480	)		8,821			(1,020	)

	$	(38,342	)	$	1,175		$	(35,077	)	$	4,825

Investing activities:
Accounts payable	$	(38,214	)	$	17,493		$	5,259		$	14,249


c)	*Income taxes*

Income tax expense as a percentage of income before income taxes for the three and six months ended September 30, 2008 differs from the statutory rate of 29.38% primarily due to the impact of changes in enacted tax rates and to the benefit from changes in the timing of the reversal of temporary differences. Income tax as a percentage of income before income taxes for the three and six months ended September 30, 2007 differed from the statutory rate of 31.72% primarily due to the impact of the enacted rate changes during the period and the impact of

new accounting standards for the recognition and measurement of financial instruments as certain embedded derivatives are considered capital in nature for income tax purposes.


13.	Segmented information


a)	*General overview*

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


•	Heavy Construction and Mining:

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


•	Piling:

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


•	Pipeline:

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

Certain business units of the Company have been aggregated into the Heavy Construction and Mining segment as they have similar economic characteristics. These business units are considered to have similar economic characteristics based on similarities in the nature of the services provided, the customer base and the similarities in the production process and the resources used to provide these services.


b)	*Results by business segment*


	Heavy
	Construction
Three Months Ended September 30, 2008	and Mining		Piling		Pipeline		Total

Revenues from external customers	$	176,073	$	48,642	$	55,568	$	280,283
Depreciation of plant and equipment		7,512		874		338		8,724
Segment profits		26,525		11,045		7,950		45,520
Segment assets		542,437		142,593		74,968		759,998
Expenditures for segment plant and equipment		18,039		1,325		421		19,785


	Heavy
	Construction
Three Months Ended September 30, 2007	and Mining		Piling		Pipeline		Total

Revenues from external customers	$	149,825	$	42,425	$	31,325	$	223,575
Depreciation of plant and equipment		4,433		871		195		5,499
Segment profits		21,044		11,092		2,408		34,544
Segment assets		467,050		117,862		77,869		662,781
Expenditures for segment plant and equipment		17,071		8,624		4,520		30,215


	Heavy
	Construction
Six Months Ended September 30, 2008	and Mining		Piling		Pipeline		Total

Revenues from external customers	$	365,479	$	91,145	$	82,646	$	539,270
Depreciation of plant and equipment		12,735		1,694		564		14,993
Segment profits		47,928		19,706		16,875		84,509
Segment assets		542,437		142,593		74,968		759,998
Expenditures for segment plant and equipment		66,881		7,155		5,070		79,106


	Heavy
	Construction
Six Months Ended September 30, 2007	and Mining		Piling		Pipeline		Total

Revenues from external customers	$	276,738	$	77,947	$	36,517	$	391,202
Depreciation of plant and equipment		11,113		1,718		303		13,134
Segment profits		40,534		20,339		1,220		62,093
Segment assets		467,050		117,862		77,869		662,781
Expenditures for segment plant and equipment		24,748		8,988		4,878		38,614


c)	*Reconciliations*


i.	Income (loss) before income taxes


							Six Months Ended
	Three Months Ended September 30,						September 30,
	2008			2007			2008			2007
				(Restated						(Restated
				— note 4)						— note 4)

Total profit for reportable segments	$	45,520		$	34,544		$	84,509		$	62,093
Unallocated corporate expenses:
General and administrative expense		(19,345	)		(17,360	)		(38,561	)		(31,987	)
Loss on disposal of plant and equipment		(1,612	)		(576	)		(2,756	)		(845	)
Loss on disposal of assets held for sale		(2	)		—			(24	)		(316	)
Amortization of intangibles		(276	)		(182	)		(554	)		(323	)
Interest expense		(6,440	)		(6,196	)		(12,889	)		(12,934	)
Foreign exchange (loss) gain		(8,236	)		14,252			(6,595	)		31,352
Realized and unrealized loss on derivative financial instruments		(7,618	)		(19,686	)		(5,353	)		(41,200	)
Other income		3			128			21			236
Unallocated equipment (costs) recovery(1)		(1,239	)		666			7,362			(11,979	)

Income (loss) before income taxes	$	755		$	5,590		$	25,160		$	(5,903	)


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


ii.	Total assets


	September 30,		March 31,
	2008		2008

Total assets for reportable segments	$	759,998	$	698,966
Corporate assets:
Cash and cash equivalents		—		32,871
Plant and equipment		33,431		26,785
Future income taxes		18,881		26,416
Other		11,429		8,560

Total corporate assets		63,741		94,632

Total assets	$	823,739	$	793,598

The Company’s goodwill was assigned to the Heavy Construction and Mining, Piling and Pipeline segments in the amounts of $125,447, $41,872, and $32,753, respectively.

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

iii. Depreciation of plant and equipment


	Three Months Ended September 30,				Six Months Ended September 30,
	2008		2007		2008		2007

Total depreciation for reportable segments	$	8,724	$	5,499	$	14,993	$	13,134
Depreciation for corporate assets		1,944		1,819		3,833		3,160

Total depreciation	$	10,668	$	7,318	$	18,826	$	16,294


d)	*Customers*

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


	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

Customer A		27	%		30	%		26	%		29	%
Customer B		13	%		12	%		17	%		13	%
Customer C		10	%		13	%		13	%		15	%
Customer D		15	%		13	%		15	%		13	%
Customer E		20	%		0	%		14	%		6	%

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


14.	Stock-based compensation

Share option plan

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


	Three Months Ended September 30,
	2008						2007
				Weighted Average						Weighted Average
	Number of			Exercise Price			Number of			Exercise Price
	Options			($ per Share)			Options			($ per Share)

Outstanding, beginning of period		1,828,364		$	7.44			1,999,440		$	6.10
Granted		125,000			16.19			—			—
Exercised		(2,000	)		(13.50	)		—			—
Forfeited		(17,200	)		(15.21	)		(72,000	)		(5.00	)

Outstanding, end of period		1,934,164		$	7.93			1,927,440		$	6.14


	Six Months Ended September 30,
	2008						2007
				Weighted Average						Weighted Average
	Number of			Exercise Price			Number of			Exercise Price
	Options			($ per Share)			Options			($ per Share)

Outstanding, beginning of period		2,036,364		$	7.54			2,146,840		$	6.03
Granted		125,000			16.19			—			—
Exercised		(109,000	)		(6.45	)		(147,400	)		(5.00	)
Forfeited		(118,200	)		(11.30	)		(72,000	)		(5.00	)

Outstanding, end of period		1,934,164		$	7.93			1,927,440		$	6.14

At September 30, 2008, the weighted average remaining contractual life of outstanding options is 7.2 years (March 31, 2008 — 7.6 years). At September 30, 2008, the Company had 860,192 exercisable options (March 31, 2008 — 804,192) with a weighted average exercise price of $5.15 (March 31, 2008 — $5.30).

The Company recorded $679 and $933 of compensation expense related to the stock options in the three and six months ended September 30, 2008, respectively (three and six months ended September 30, 2007 — $388 and $747 respectively), with such amount being credited to contributed surplus.

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


	Three Months Ended					Six Months Ended
	September 30,					September 30,
	2008			2007		2008			2007

Number of options granted		125,000			—		125,000			—
Weighted average fair value per option granted ($)		6.43			—		6.43			—
Weighted average assumptions:
Dividend yield		—			—		—			—
Expected volatility		47.26	%		—		47.26	%		—
Risk-free interest rate		3.59	%		—		3.59	%		—
Expected life (years)		6.5			—		6.5			—

Deferred performance share unit plan

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

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

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

The fair value of each unit under the DPSU Plan was estimated on the date of the grant using Black-Scholes option pricing model. The weighted average assumptions used in estimating the fair value of the share options issued under the DPSU Plan at April 1, 2008 are as follows:


Number of units granted	111,020
Weighted average fair value per option granted ($)	12.34
Weighted average assumptions:
Dividend yield	—
Expected volatility	56.25	%
Risk-free interest rate	2.83	%
Expected life (years)	3.00


	Three Months Ended					Six Months Ended
	September 30, 2008					September 30, 2008
				Weighted Average					Weighted Average
	Number of			Exercise Price		Number of			Exercise Price
	Units			($ per Share)		Units			($ per Share)

Outstanding, beginning of period		111,020			—		—			—
Granted		—			—		111,020			—
Exercised		—			—		—			—
Forfeited		(9,384	)		—		(9,384	)		—

Outstanding, end of period		101,636			—		101,636			—

At September 30, 2008, the weighted average remaining contractual life of outstanding DPSUs is 2.50 years. For the three and six months ended September 30, 2008, respectively, the Company granted nil and 111,020 units under the Plan and recorded compensation expense of $29 and $142 respectively which is included in general and administrative costs. As at September 30, 2008, there was approximately $705 of total unrecognized compensation cost related to nonvested share-based payment arrangements under the DPSU Plan, which is expected to be recognized over a weighted average period of 2.50 years.

Directors’ deferred stock unit plan

On November 27, 2007, the Company approved a Directors’ Deferred Stock Unit (“DDSU”) Plan, which became effective January 1, 2008. Under the DDSU Plan, non-employee or officer directors of the Company shall receive 50% of their annual fixed remuneration (which is included in general and administrative expenses in the consolidated statement of operations) 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 DDSUs vest immediately upon grant and are redeemable, in cash, equal to the difference between the market value of the Company’s common stock at maturity and the market value of the Company’s common stock on the grant date (maturity occurs when the director resigns or retires). DDSUs must be redeemed within 60 days following maturity. Directors, who are not US taxpayers, may elect to defer the maturity date until a date no later than December 1st of the calendar year following the year in which the actual maturity date occurred. For the three and six months ended September 30, 2008, the Company recorded a (recovery)/expense of $(38) and $231 respectively (three and six months ended September 30, 2007 — $nil and $nil).


	Three Months Ended		Six Months Ended
	September 30, 2008		September 30, 2008
	Number of Units		Number of Units

Outstanding, beginning of period		20,774		11,822
Granted		17,487		26,439
Exercised		—		—
Forfeited		—		—

Outstanding, end of period		38,261		38,261

At September 30, 2008, the redemption value of these units were $11.01/unit (March 31, 2008 — $16.01/unit).


15.	Seasonality

The Company generally experiences a decline in revenues during the first quarter of each fiscal year due to seasonality, as weather conditions make operations in the Company’s operating regions difficult during this period. The level of activity in the Heavy Construction and Mining and Pipeline segments declines when frost leaves the ground and many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment.

The duration of this period is referred to as “spring breakup” and has a direct impact on the Company’s activity levels. Revenues during the fourth quarter of each fiscal year are typically highest as ground conditions are most favorable in the Company’s operating regions. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters.


16.	Guarantee

At September 30, 2008, in connection with a heavy equipment financing agreement, the Company has guaranteed $2.9 million of debt owed to the equipment manufacturer by a third party finance company. The Company’s guarantee of this indebtedness will expire when the equipment is commissioned, which is expected to be in fiscal 2009. The Company has determined that the fair value of this financial instrument at inception and September 30, 2008 was not significant.


17.	Claims revenue

On June 25, 2008, the Company reached an agreement with a customer to settle all outstanding claims arising from a pipeline project completed in fiscal 2008 for $8,000. The Company had previously recognized claims revenue of $2,744 related to such outstanding claims as at March 31, 2008 and it has recognized the excess of the settlement over previously recognized claims revenue of $5,256 as revenue in the quarter ended June 30, 2008. Claims revenue recognized and billed was $16,167 for the quarter ended September 30, 2008 (2007 — $nil).


18.	Comparative figures

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

The following discussion and analysis is as of November 6, 2008 and should be read in conjunction with the unaudited interim consolidated financial statements for the three and six months ended September 30, 2008 and the audited consolidated financial statements for the fiscal year ended March 31, 2008. These statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP) and, except where otherwise specifically indicated, all dollar amounts are expressed in Canadian dollars. These consolidated financial statements and additional information relating to our business are available on SEDAR at www.sedar.com and EDGAR at www.sec.gov.

November 6, 2008

Table of Contents


Subject		Page

A.	BUSINESS OVERVIEW AND STRATEGY		2
	Business Overview		2
	Operations Overview		3
	Canadian Oil Sands		4
	Oil Sands Outlook		4
	Strategy		5
B.	FINANCIAL RESULTS		7
	Consolidated Results (Three and Six Months)		7
	Analysis of Results		8
	Segment Results (Three and Six Months)		10
	Non-Operating Income and Expense		11
	Summary of Quarterly Results		13
	Consolidated Financial Position		14
	Claims and Change Orders		15
C.	KEY TRENDS		16
	Seasonality		16
	Backlog		16
	Revenue Sources		17
	Contracts		20
	Major Suppliers		21
	Competition		21
D.	OUTLOOK		22
E.	LEGAL AND LABOUR MATTERS		22
	Laws and Regulations and Environmental Matters		22
	Employees and Labour Relations		23
F.	RESOURCES AND SYSTEMS		24
	Outstanding Share Data		24
	Liquidity		24
	Cash Flow and Capital Resources		27
	Capital Commitments		28
	Cash Requirements		29
	Internal Systems and Processes		29
	Significant Accounting Policies		30
	Related Parties		32
	Recently Adopted Accounting Policies		33
	Recent Accounting Pronouncements Not Yet Adopted		34
G.	FORWARD-LOOKING INFORMATION AND RISK FACTORS		34
	Forward-Looking Information		34
	Risk Factors		37
	Quantitative and Qualitative Disclosures about Market Risk		38
H.	GENERAL MATTERS		40
	History and Development of the Company		40
	Additional Information		41

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

Prior Year Comparisons

In preparing the financial statements for the year ended March 31, 2008, we determined that the previously issued interim unaudited consolidated financial statements for the three and six months ended September 30, 2007 did not properly account for an embedded derivative with respect to price escalation features in a supplier maintenance contract.

The embedded derivative has been measured at fair value and included in derivative financial instruments on the consolidated balance sheet with changes in fair value recognized in net income. The impact of this restatement on the interim unaudited consolidated balance sheet for the three and six months ended September 30, 2007 is a $0.4 million reduction to future income taxes (long-term assets), a $1.6 million reduction to derivative financial instruments and a $1.1 million improvement to deficit. The impact on the interim consolidated statement of operations and comprehensive income (loss) for the three and six months ended September 30, 2007 is an adjustment to unrealized loss on derivative financial instruments and income tax expense. For the three months ended September 30, 2007, this resulted in an improvement to net income of $1.1 million (restated as net income of $3.2 million) and an improvement to basic and diluted earnings per share of $0.03 per share (restated as $0.09 earnings per share). For the six months ended September 30, 2007, this resulted in decrease to net loss of $2.8 million (restated as a loss of $5.4 million) and a decrease to basic and diluted loss of $0.08 per share (restated as $0.15 loss per share).


A.	Business Overview and Strategy

Business Overview

We are a leading services provider to major oil, natural gas and other natural resource companies, with a primary focus on the Alberta oil sands. We provide a wide range of heavy construction and mining, piling and pipeline installation services, supporting our customers’ operations and capital projects across the lifecycle of their projects. We believe we are the largest provider of contract mining services in the oil sands area.

We provide services to every company in the Alberta oil sands that uses surface mining techniques in its production process. Our principal oil sands customers include all three of the producers that are currently mining bitumen in Alberta: Syncrude Canada Ltd.¹ (Syncrude), Suncor Energy Inc. (Suncor) and Albian Sands Energy Inc.² (Albian). We are also working with customers that are in the development phase of bitumen-mining projects, including Canadian Natural Resources Limited (Canadian Natural) and Fort Hills³. We have long-term relationships with most of our customers. For example, we have been providing services to Syncrude and Suncor since they pioneered oil sands development over 30 years ago.

We provide services that support every stage of the mining project, commencing with the initial capital spend on mine development (project development services) and leading into the operational spend throughout the 30-40 year life of the mine (recurring services). We believe that the recurring services we provide to our customers’ operating oil sands mines are an integral part of their operations and are not discretionary. As at September 30, 2008, approximately 60% of our total fiscal 2009 oil sands business was derived from recurring work and long-term contracts, up from 47% for the comparable period in fiscal 2008, which assist in providing stability to our

¹Joint venture amongst Canadian Oil Sands Limited (37%), Imperial Oil Resources (25%), Petro-Canada Oil and Gas (12%), ConocoPhillips Oil Sands Partnership II (9%), Nexen Oil Sands Partnership (7%), Murphy Oil Company Ltd. (5%) and Mocal Energy Limited (5%).

²Joint venture amongst Shell Canada Limited (60%), Chevron Canada Limited (20%) and Marathon Oil Canada Corporation (20%).

³Joint venture between UTS Energy, Teck Cominco and Petro-Canada

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

operations. We believe that the demand for recurring services will continue to increase as the geographical footprint of existing mines grows, as producers work to increase production levels at existing mines and as new mines come on-line.^*

We believe that we operate the largest fleet of equipment of any contract resource services provider in the oil sands. Our total fleet includes over 825 pieces of diversified heavy construction equipment supported by over 925 ancillary vehicles. While our expertise covers mining, heavy construction, underground services (fire lines, sewer, water etc) for industrial projects, piling and pipeline installation in any location, we have a specific capability operating in the harsh climate and difficult terrain of northern Canada generally and specifically in the oil sands in Alberta.

We believe that our significant oil sands knowledge, experience, long-term customer relationships, equipment capacity and scale of operations differentiate us from our competition. In addition, we believe that these capabilities will enable us to support the anticipated increase in demand for recurring services.^*

While our mining services have been primarily focused on the oils sands, we believe that we have demonstrated our ability to successfully export knowledge and technology gained in the oil sands and put it to work in other resource development projects across Canada. As an example, in fiscal 2008 we successfully completed the development of a diamond mine site in Northern Ontario. This three-year project required us to operate effectively in a remote location in the extreme weather conditions prevalent in northern Canada. As a result of our successful work on this and other similar projects, we believe we have attracted the attention of resource developers and we are currently looking at other potential projects, including those in the high arctic regions.

Operations Overview

Our business is organized into three interrelated, yet distinct, business units: (i) Heavy Construction and Mining, (ii) Piling and (iii) Pipeline. The table below shows the revenues generated by each operating segment for the three and six month periods ended September 30, 2008 and September 30, 2007:


	Three Months Ended September 30,										Six Months Ended September 30,
	2008		% of			2007		%					% of					% of
(Dollars in thousands)	(Q2-FY2009)		Total			(Q2-FY2008)		of Total			2008		Total			2007		Total


Revenue by operating segment:⁽¹⁾
Heavy Construction and Mining	$	176,073		62.8	%	$	149,825		67.0	%	$	365,479		67.8	%	$	276,738		70.7	%
Piling		48,642		17.4	%		42,425		19.0	%		91,145		16.9	%		77,947		19.9	%
Pipeline		55,568		19.8	%		31,325		14.0	%		82,646		15.3	%		36,517		9.3	%

Total	$	280,283		100.0	%	$	223,575		100.0	%	$	539,270		100.0	%	$	391,202		100.0	%


⁽¹⁾		Please refer to “Analysis of Results” for a discussion on segment results.

Our Heavy Construction and Mining segment focuses primarily on providing support for surface mining for oil sands and other natural resources. This includes activities such as:


	•	land clearing, stripping, muskeg removal and overburden removal to expose the mining area;

	•	the supply of labour and equipment to be operated within the customers’ mining fleet directly supporting the mining of ore;

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008


	•	general support services including road building, repair and maintenance for both mine and treatment plant operations, hauling of sand and gravel and relocation of plant;

	•	construction related to the expansion of the operations including site development and construction of infrastructure; and

	•	reclamation of completed mining to stringent environmental standards.

Most of these services are classified as recurring services and represent the majority of services provided by our Heavy Construction and Mining business. We also provide industrial site construction for mega-projects and underground utility installation for plant, refinery and commercial building construction.

Our Piling segment installs all types of driven, drilled and screw piles, caissons, earth retention and stabilization systems. Operating throughout Western Canada, this segment has a solid record of performance on both small and large-scale projects. Our Piling segment also has experience with industrial projects in the oil sands and related petrochemical and refinery complexes and has been involved in the development of commercial and community infrastructure projects.

Our Pipeline segment installs transmission, distribution and gathering systems made of steel, fiberglass and/or plastic pipe in sizes up to 52” in diameter. Penstock installation services are also provided. This segment has successfully completed jobs of varying magnitude for some of Canada’s largest energy companies. Recent projects include the Trans Mountain Expansion (TMX) Anchor Loop pipeline, which included installation of 160 km of large-diameter pipe through extremely challenging and ecologically sensitive terrain. The project, which runs from Hinton Alberta, through Jasper National Park, across the Rocky Mountains and through to Mt. Robson Provincial Park in British Columbia was successfully completed with minimal impact to the environment.

Canadian Oil Sands

Oil sands are grains of sand covered by a thin layer of water and coated by heavy oil or bitumen. Bitumen, because of its structure, does not flow and therefore requires non-conventional extraction techniques to separate it from the sand and other foreign matter. There are currently two main methods of extraction: open pit mining, where bitumen deposits are sufficiently close to the surface to make it economically viable to recover the bitumen by conventional truck and shovel mining methods with the treatment of mined sand in a surface plant; and in-situ, where bitumen deposits are buried too deep for open pit mining to be cost effective. With in-situ extraction operators use Steam Assisted Gravity Drainage (SAGD) injecting steam into the deposit so that the bitumen can be separated from the sand and pumped to the surface. While the SAGD process includes the need for work within our expertise, we currently provide most of our services to companies operating open pit mines to recover bitumen reserves. These customers utilize our services for operational surface mining, site preparation, overburden removal, piling, pipe installation, site maintenance, equipment and labour supply, mine infrastructure development and maintenance and land reclamation.

Oil Sands Outlook

Demand for our services is driven by the development, expansion and ongoing operation of oil sands projects, with ongoing operations having the most significant impact on our business. Approximately 60% of our oil sands-related revenue comes from the provision of recurring services to existing oil sands projects. These recurring services include operational surface mining, overburden removal, labour and equipment supply, mine infrastructure development and maintenance and land reclamation. The balance of our oil sands-related revenue comes from development and expansion projects, which typically involve more capital-intensive projects such as facilities construction. However, as these development and expansion projects are completed, it is expected that the market for our recurring revenue would expand accordingly.

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

Recurring Services Outlook: Recently, oil prices have dropped significantly from the record highs set earlier in 2008 and construction costs have risen sharply leading to a view that oil sands projects could become less viable. Contrary to market views, due to the technology of oil sands processing and the large fixed capital costs and relatively low operating costs, operational oil sands projects (unlike conventional oil projects) are largely unaffected by short-term fluctuations in oil prices. The bitumen separation technology dictates that these projects be designed and operated at steady-state production levels. The high fixed-cost component of total operating costs of a project requires that the process be operated at the maximum capacity of the plant. As a result, we believe that these established oil sands projects are unlikely to make any significant reduction in production capacity as a result of a short term decline in oil price.^*

In addition, as oil sands projects move through their typical 30-40 year life cycle, easy-to-access bitumen deposits are depleted and operators must go greater distances and move more material to access their ore reserves. Over this period, haulage distances progressively extend and the amount of overburden to be removed per cubic meter of exposed oil sand progressively increases. As a result, the total capacity of digging and hauling equipment must increase and consequently, the amount of ancillary equipment and services to run this equipment must also increase. Accordingly, we believe that demand for recurring oil sands services of the type supplied by our business segments will remain robust and will continue growing even if no new oil sand mines are built because the geographical footprint of existing mines must continue to expand normal operations. We also believe that further expansion of our accessible market will occur as new, already announced mines (CNRL, Petro-Canada and Kearl) come on-line. For example oil sands’ mining production has increased from 0.3 million barrels per day to 0.7 million barrels per day since 2001 and is expected to increase to 1.2 million barrels per day by 2012 according to Canadian Association of Petroleum Producers (CAPP)⁴.*

Project Development Outlook: Several oil sands producers have recently updated their near-term capital spending plans in response to increasing development costs and current commodity, equity and credit market conditions. While several customers have deferred decisions about upgrader projects, Suncor has indicated that mine development at its Voyageur mine will proceed, Albian continues to push forward with the development of its Jackpine mine, Canadian Natural is nearing production of first oil at its Horizon mine and Petro-Canada and Kearl have indicated that they are considering an option of continuing to build their mines. Major producers have also reiterated that their investment in the oil sands is driven by expected long-term demand and prices for oil and not by short-term market prices. This is consistent with the minimum three-to-four year development lead time required to build oil sands mines and the 30-40 year operating life of these projects.

Strategy

Our strategy is to be an integrated service provider for the developers and operators of resource-based industries in a broad and often challenging range of environments. Currently we face the additional challenges presented by the world financial crisis and general economic downturn. To help us manage successfully through this period, we are focused on:


	•	cost effective delivery of service to our customers;

	•	cash conservation to ensure liquidity for operational circumstances;

	•	timely invoicing and accounts receivable collection to minimize working capital needs; and

	•	strategic prioritization of our capital expenditures to minimize cash outflows while maintaining the flexibility to take advantage of profitable opportunities.

⁴Crude Oil Forecast, Markets and Pipeline Expansions June 2008

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

More generally, we are also continuing to:


	•	Increase our recurring revenue base: It is our intention to continue expanding our recurring services business to provide a larger base of stable revenue.^*

	•	Leverage our long-term relationships with customers: We intend to continue to build on our relationships with existing oil sands customers to win a substantial share of the heavy construction and mining, piling and pipeline services outsourced in connection with their projects.^*

	•	Leverage and expand our complementary services: Our complementary service segments, Heavy Construction and Mining, Pipeline and Piling allow us to compete for many different forms of business. We intend to build on our “first-in” position to cross-sell our other services and pursue selective acquisition opportunities that expand our complementary service offerings.^*

	•	Enhance operating efficiencies to improve revenues and margins: We aim to increase the availability and efficiency of our equipment through enhanced maintenance, providing the opportunity for improved revenue, margins and profitability.*

	•	Position for growth: We intend to build on our market leadership position and successful track record with our customers to benefit from future oil sands growth. We intend to use our fleet size and management capability to respond to growth opportunities as they occur.*

	•	Increase our presence outside the oil sands: We intend to increase our presence outside the oil sands and extend our services to other resource industries across Canada. Canada has significant natural resources and we believe that we have the equipment and the experience to assist with developing those natural resources.^*

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008


B.	Financial Results

Consolidated Results (Three and Six Months)


	Three Months Ended September 30,											Six Months Ended September 30,
(Dollars in thousands,				% of					% of					% of						% of
except per share information)	2008			Revenue			2007		Revenue			2008		Revenue			2007			Revenue

							(Restated)										(Restated)

Revenue	$	280,283			100.0	%	$	223,575		100.0	%	$	539,270		100.0	%	$	391,202			100.0	%
Project costs		154,961			55.3	%		135,266		60.5	%		303,592		56.3	%		229,939			58.8	%
Equipment costs		60,787			21.7	%		42,212		18.9	%		106,597		19.8	%		87,351			22.3	%
Equipment operating lease expense		9,586			3.4	%		3,569		1.6	%		18,384		3.4	%		7,504			1.9	%
Depreciation		10,668			3.8	%		7,318		3.3	%		18,826		3.5	%		16,294			4.2	%
Gross profit		44,281			15.8	%		35,210		15.7	%		91,871		17.0	%		50,114			12.8	%
General & administrative costs		19,345			6.9	%		17,360		7.8	%		38,561		7.2	%		31,987			8.2	%
Operating income		23,046			8.2	%		17,092		7.6	%		49,976		9.3	%		16,643			4.3	%
Net (loss) income		(1,222	)		(0.4	)%		3,176		1.4	%		17,874		3.3	%		(5,406	)		(1.4	)%
Per share information
Net (loss) income - basic	$	(0.03	)				$	0.09				$	0.50				$	(0.15	)
Net (loss) income - diluted		(0.03	)					0.09					0.48								(0.15	)
EBITDA⁽¹⁾	$	18,139			6.5	%	$	19,286		8.6	%	$	57,429		10.6	%	$	23,648			6.0	%
Consolidated EBITDA⁽¹⁾		36,226			12.9	%		27,920		12.5	%		72,953		13.5	%		37,590			9.6	%
(as defined within the revolving credit agreement)

⁽¹⁾Non-GAAP Financial measures

The body of generally accepted accounting principles applicable to us is commonly referred to as “GAAP.” A non-GAAP financial measure is generally defined by the Securities and Exchange Commission (SEC) and by the Canadian securities regulatory authorities as one that purports to measure historical or future financial performance, financial position or cash flows, but excludes or includes amounts that would not be so adjusted in the most comparable GAAP measures. EBITDA is calculated as net income (loss) before interest expense, income taxes, depreciation and amortization. Consolidated EBITDA (as defined within the revolving credit agreement) is a measure defined by our revolving credit facility. This measure is defined as EBITDA, excluding the effects of unrealized foreign exchange gain or loss, realized and unrealized gain or loss on derivative financial instruments, non-cash stock-based compensation expense, gain or loss on disposal of plant and equipment and certain other non-cash items included in the calculation of net income (loss). We believe that EBITDA is a meaningful measure of the performance of our business because it excludes items, such as depreciation and amortization, interest and taxes that are not directly related to the operating performance of our business. Management reviews EBITDA to determine whether plant and equipment are being allocated efficiently. In addition, our revolving credit facility requires us to maintain a minimum interest coverage ratio and a maximum senior leverage ratio, which are calculated using Consolidated EBITDA. Non-compliance with these financial covenants could result in our being required to immediately repay all amounts outstanding under our revolving credit facility. EBITDA and Consolidated EBITDA are not measures of performance under Canadian GAAP or U.S. GAAP and our computations of EBITDA and Consolidated EBITDA may vary from others in our industry. EBITDA and Consolidated EBITDA should not be considered as alternatives to operating income or net income as measures of operating performance or cash flows as measures of liquidity. EBITDA and Consolidated EBITDA have important limitations as analytical tools and should

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

not be considered in isolation or as substitutes for analysis of our results as reported under Canadian GAAP or U.S. GAAP. For example, EBITDA and Consolidated EBITDA:


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

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

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

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

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

Consolidated EBITDA (as defined within the revolving credit agreement) 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.

Our use of the term, “Consolidated EBITDA (as defined within the revolving credit agreement)”, replaces the term “Consolidated EBITDA (per bank)” used in prior filings. The definition of Consolidated EBITDA (as defined within the revolving credit agreement) has not changed.

A reconciliation of net income (loss) to EBITDA and Consolidated EBITDA (as defined within the revolving credit agreement) is as follows:


	Three Months Ended September 30,						Six Months Ended September 30,
	2008			2007
(Dollars in thousands)	(Q2-FY2009)			(Q2-FY2008)			2008		2007
				(Restated)					(Restated)

Net (loss) income	$	(1,222	)	$	3,176		$	17,874	$	(5,406	)
Adjustments:
Interest expense		6,440			6,196			12,889		12,934
Income taxes (recovery)		1,977			2,414			7,286		(497	)
Depreciation		10,668			7,318			18,826		16,294
Amortization of intangible assets		276			182			554		323

EBITDA	$	18,139		$	19,286		$	57,429	$	23,648
Adjustments:
Unrealized foreign exchange loss (gain) on senior notes		8,147			(13,864	)		6,316		(31,014	)
Realized and unrealized loss on derivative financial instruments		7,618			19,686			5,353		41,200
Loss on disposal of plant and equipment and assets held for sale		1,614			576			2,780		1,161
Stock-based compensation		708			388			1,075		747
Write-down of other assets to replacement cost		—			1,848			—		1,848

Consolidated EBITDA	$	36,226		$	27,920		$	72,953	$	37,590
(as defined within the revolving credit agreement)

Analysis of Results

Revenues of $280.3 million for the second quarter fiscal 2009 (three months ended September 30, 2008) was $56.7 million, or 25.4%, higher than in the same period in fiscal 2008. For the first half of fiscal 2009 (six months ended September 30, 2008), revenues of $539.3 million were $148.1 million, or 37.8%, higher than in the same period in fiscal 2008. Strong growth in recurring oil sands revenue, higher Pipeline segment revenue as a result of

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

the TMX project and continued improvement in Piling segment revenue all contributed to the year-over-year revenue improvement in both the three and six-month periods.

Gross profit for the three months ended September 30, 2008 increased to $44.3 million, which was $9.1 million, or 25.8%, higher than the same period last year as a result of higher revenue. Gross margin remained stable at 15.8% compared to 15.7% between the two periods with increases in the Heavy Construction and Mining segment and the Pipeline segment margins offsetting a decline in the Piling segment margins as a result of a change in contract mix. Second quarter equipment costs were higher as a result of higher maintenance costs resulting from the carry-over of first quarter planned maintenance activities, higher depreciation driven by the increase in current quarter activity levels and higher operating lease expense as a result of the increase in leased equipment required to support the growth in Heavy Construction and Mining operations.

For the six months ended September 30, 2008, gross profit increased to $91.9 million from $50.1 million, reflecting higher revenue and improved gross margins. Gross margin for the six months ended September 30, 2008, as a percentage of revenue, increased to 17.0%, from 12.8% in the same period in fiscal 2008. This improvement reflects the Pipeline segment’s return to profitability, the partial recovery of losses incurred on a Pipeline segment contract executed in fiscal 2007 and improvements in the management and purchasing of tires (tire expense for the first half of fiscal 2009 was $13.4 million, representing a $4.0 million, or 23.0% reduction from the first half of fiscal 2008). Equipment maintenance costs as a percent of revenue were also lower by 2.5% in the current period reflecting the deferral of certain planned maintenance activity to the early portion of the third quarter as we responded to high demand for our equipment. Equipment leasing expense was also higher as a result of the March 2008 commissioning of a new electric cable shovel at our long-term overburden removal project at the CNRL site along with significant increases to our leased equipment fleet in the latter part of fiscal 2008. Depreciation in the first half of fiscal 2008 included a $3.0 million charge for the accelerated depreciation of equipment that was removed from service, compared to a $0.6 million similar charge in the first half of fiscal 2009. This positive variance for depreciation was offset by increased depreciation expense on a larger equipment fleet in late fiscal 2008 and early fiscal 2009.

Operating income for the three months ended September 30, 2008 increased to $23.0 million, from $17.1 million over the same period in the prior year. The improvement resulted from higher gross profit and a reduction of general and administrative expense (G&A) as a percentage of revenue. The improvement in G&A expense as a percentage of revenue to 6.9%, from 7.8% last year, reflects the benefits of leveraging fixed-costs against a higher revenue base, partially offset by the addition of new employees hired in the last half of fiscal 2008 to support our higher operations activity. Operating income for the six months ended September 30, 2008 increased to $50.0 million, from $16.6 million over the same period in the prior year. The significant improvement reflects higher gross profit and declining G&A expense as a percentage of revenue.

We reported a net loss of $1.2 million (basic loss per share of $0.03) in the second quarter of fiscal 2009, compared to net income of $3.2 million (basic net income per share of $0.09) in the second quarter of fiscal 2008. The reduction in net income reflects the negative impact of a depreciating Canadian dollar on our 83/4% senior notes, the change in value of the embedded prepayment and early redemption option in the 83/4% senior notes, together with non-cash losses on both existing and new embedded derivatives. Excluding these items for both periods, basic earnings per share would have been $0.30 per share, up from $0.20 per share in the second quarter of fiscal 2008.

For the six months ended September 30, 2008, we reported net income of $17.9 million (basic earnings per share of $0.50), representing a $23.3 million increase, or $0.65 per share, from a net loss of $5.4 million (basic loss per share of $0.15) over the same period in the prior year. This improvement reflects strong revenue and gross profit results from all three business segments, partially offset by a first-half foreign exchange loss of $5.5 million, net of tax, compared to foreign exchange gains, net of tax, of $26.6 million during the same period in fiscal 2008 and non-cash losses on derivative financial instruments, net of tax, of $2.5 million, compared to a non-cash losses of $34.0 million, net of tax, during the same period last year. Excluding these items for both periods, basic earnings per

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

share would have been $0.72 per share for the first six months of fiscal 2009, compared to $0.06 per share for the same period in fiscal 2008.

We do not plan to take any steps to realize either losses or gains on changes in foreign exchange or derivative financial instruments.

Segment Results (Three and Six Months)

Segment profits include revenue earned from the performance of our projects, including amounts arising from approved change orders and claims that have met the appropriate accounting criteria for recognition, less all direct project expenses, including direct labour, short-term equipment rentals and materials, payments to subcontractors, indirect job costs and internal charges for use of capital equipment.

Segment results for the three months and six months ended September 30, 2008 compared to the three months and six months ended September 30, 2007, consist of:

Heavy Construction and Mining


	Three Months Ended September 30,										Six Months Ended September 30,
	2008		% of			2007		% of					% of					% of
(Dollars in thousands)	(Q2-FY2009)		Revenue			(Q2-FY2008)		Revenue			2008		Revenue			2007		Revenue


Segment revenue	$	176,073				$	149,825				$	365,479				$	276,738
Segment profit:	$	26,525		15.1	%	$	21,044		14.0	%	$	47,928		13.1	%	$	40,534		14.6	%

The Heavy Construction and Mining segment achieved revenues of $176.1 million in the second quarter of fiscal 2009, a $26.2 million improvement in revenues over the same period in fiscal 2008. For the six months ended September 30, 2008, Heavy Construction and Mining segment revenues of $365.5 million were $88.7 million higher than revenues in the same period last year. Strong demand for our site services work, including site preparation at the Petro-Canada Fort Hills’ project and master services work at Albian’s Jackpine Mine and Muskeg River Mine were the primary factors in the year-over-year increases. With an increasing number of oil sands projects moving into the stable, operational phase of their lifecycles, recurring operational work is becoming an increasingly significant contributor to our revenues. Ongoing operational work represented 70% of Heavy Construction and Mining’s revenues in the second quarter and 69% in the first half of fiscal 2009 compared to 57% and 57%, respectively, over the same periods a year ago. Our second quarter of fiscal 2009 and first-half revenues in fiscal 2009 also benefited from construction work on the Suncor Voyageur and Millennium Naptha Unit sites.

Segment margins improved to 15.1% of revenues for the three months ended September 30, 2008, up from 14.0% during the same period in fiscal 2008. This improvement reflects the larger proportion of higher-margin site services and site preparation work in our project mix. For the six months ended September 30, 2008, margins declined to 13.1% from 14.6% over the same period in fiscal 2008, primarily the result of the negative impact of first quarter production challenges on a single project.

Piling


	Three Months Ended September 30,										Six Months Ended September 30,
	2008		% of			2007		% of					% of					% of
(Dollars in thousands)	(Q2-FY2009)		Revenue			(Q2-FY2008)		Revenue			2008		Revenue			2007		Revenue


Segment revenue	$	48,642				$	42,425				$	91,145				$	77,947
Segment profit:	$	11,045		22.7	%	$	11,092		26.1	%	$	19,706		21.6	%	$	20,339		26.1	%

The Piling segment achieved revenues of $48.6 million in the second quarter of fiscal 2009, an increase of $6.2 million compared to revenues in the same period in fiscal 2008. Piling revenues in the first half of fiscal 2009,

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

climbed to $91.1 million, representing a $13.2 million increase over the same period last year. Work on a major oil sands-related plant and upgrader projects was a significant contributor to the revenue growth in both periods. An increased proportion of lower margin, lower-risk time-and-materials projects resulted in the dilution of second quarter segment margins to 22.7%, from 26.1% in the second quarter of fiscal 2008, and to the year-over-year decline in first-half segment margins to 21.6% from 26.1%.

Pipeline


	Three Months Ended September 30,										Six Months Ended September 30,
	2008		% of			2007		% of					% of					% of
(Dollars in thousands)	(Q2-FY2009)		Revenue			(Q2-FY2008)		Revenue			2008		Revenue			2007		Revenue


Segment revenue	$	55,568				$	31,325				$	82,646				$	36,517
Segment profit:	$	7,950		14.3	%	$	2,408		7.7	%	$	16,875		20.4	%	$	1,220		3.3	%

The TMX project continued to drive revenue growth in the Pipeline segment during both the three-month and six-month periods ended September 30, 2008. Second quarter segment revenues of $55.6 million were $24.2 million higher than revenues in the same period last year, while six-month revenues of $82.7 million were $46.1 million higher. Pipeline margins also improved significantly, with second quarter margins of 14.3% up from 7.7% in the second quarter of fiscal 2008, while first-half margins increased to 20.4% from 3.3%. In comparing margin results for the two corresponding fiscal year periods, it is important to note that first half margins in fiscal 2008 were negatively impacted by the recognition of $2.0 million in additional costs related to a fixed-priced fiscal 2007 contract. Margins for the first half of fiscal 2009 have subsequently benefited from the realization of $5.3 million in related claims revenue, as well as from an unrelated potential claims provision of $0.5 million. Excluding the impact of both the additional costs and the subsequent claims revenue, second quarter segment margin for fiscal 2009 would have been 15.0% compared to 14.7% over the same period in fiscal 2008, while first-half margins would have been 15.0% compared to 8.8% a year ago.

Non-Operating Income and Expense


	Three Months Ended September 30,						Six Months Ended September 30,
	2008			2007
(Dollars in thousands)	(Q2-FY2009)			(Q2-FY2008)			2008			2007
				(Restated)						(Restated)

Interest expense
Interest on senior debt	$	5,834		$	5,834		$	11,669		$	11,669
Interest on revolving credit facility and other interest		158			100			317			425
Interest on capital lease obligations		264			152			545			333
Amortization of deferred bond issue costs		184			110			358			507

Total Interest expense	$	6,440		$	6,196		$	12,889		$	12,934

Foreign exchange loss (gain) on senior notes	$	8,236		$	(14,252	)	$	6,595		$	(31,352	)
Realized and unrealized loss on derivative financial instruments		7,618			19,686			5,353			41,200
Other income		(3	)		(128	)		(21	)		(236	)
Income tax expense (recovery)		1,977			2,414			7,286			(497	)

Interest expense

Total interest expense of $6.4 million in the second quarter of fiscal 2009 increased $0.2 million over the same period last year. Minor increases in interest on the revolving credit facility, the amortization of bond issue costs and small increases in interest on capital lease obligations led to the increase in interest expense.

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

Foreign exchange loss (gain) on senior notes

The foreign exchange gains and losses recognized in the current and prior-year periods relate primarily to changes in the strength of the Canadian dollar against the U.S. dollar on conversion of the US$200 million 83/4% senior notes. The value of the Canadian dollar relative to the U.S. dollar showed a minor decline during the three and six-month periods ended September 30, 2008 with a decrease from $0.9817 CAN/US on June 30, 2008 and $0.9729 CAN/US on March 31, 2008 to $0.9435 CAN/US on September 30, 2008. By comparison, the exchange rate increased from $0.9481 CAN/US on June 30, 2007 and $0.8667 CAN/US on March 31, 2007 to $1.0041 CAN/US on September 30, 2007.

Realized and unrealized gains on derivative financial instruments

The realized and unrealized gains on derivative financial instruments reflect changes in the fair value of the cross-currency and interest rate swaps that we employ to provide an economic hedge for our US dollar denominated 83/4% senior notes. Changes in the fair value of these swaps generally have an offsetting effect to changes in the value of our 83/4% senior notes (and resulting foreign exchange gains and losses), both caused by variations in the Canadian/US foreign exchange rate. However, the valuation of the derivative financial instruments can also be impacted by changes in interest rates and the remaining present value of scheduled interest payments on the 83/4% senior notes, which occur in the first and third quarters of each year until maturity.

Due to our first quarter fiscal 2008 adoption of the CICA standards regarding financial instruments, realized and unrealized gains and losses on derivative financial instruments for the three and six month periods ended September 30, of both fiscal 2008 and 2009 include changes in the fair value of derivatives embedded in our US dollar denominated 83/4% senior notes, in a long-term construction contract and in supplier maintenance agreements. The change in the realized and unrealized value of the cross-currency and interest swaps resulted in a gain of $5.8 million in the current fiscal period compared to a loss of $15.9 million in the same period of the last fiscal year. For the six months ended September 30, 2008, the change in realized and unrealized value of the cross-currency and interest swaps resulted in a gain of $6.2 million in the current fiscal year compared to a loss of $30.2 million in the same period of the prior year. The balance of the realized and unrealized gains and losses on derivative financial instruments resulted from gains on derivatives embedded in our 83/4% senior notes, in a long-term construction contract and in supplier maintenance agreements.

With respect to the early redemption provision in the 83/4% senior notes, the process to determine the fair value of the implied derivative was to compare the rate on the notes to the best financial alternative. The fair value determined as at April 1, 2007 resulted in a positive adjustment to opening retained earnings. The change in fair value in future periods is recognized as a charge to earnings. Changes in fair value result from changes in long-term bond interest rates during a period. The valuation process presumes a 100% probability of our implementing the inferred transaction and does not permit a reduction in the probability if there are other factors that would impact the decision.

With respect to the long-term construction contract, there is a provision that requires an adjustment to billings to our customer to reflect actual exchange rate and price index changes as against the contract amount. 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.

With respect to the supplier maintenance contract, there is a provision that requires a price adjustment to reflect actual Canadian versus US dollar exchange rate and the United States government published Producers’ Price Index for Mining Machinery and Equipment (US-PPI) changes versus the contract amount. The embedded derivative instrument takes into account the impact of fluctuations in these measures on costs.

During the second quarter of fiscal 2009, we entered into a supplier maintenance contract with a provision that requires a price adjustment to reflect the actual Canadian versus US dollar exchange rate and US-PPI changes

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

versus the contract amount. The embedded derivative instrument takes into account the impact of fluctuations in these measures on costs. This embedded derivative resulted in a charge of $7.4 million ($5.6 million after tax) for the three months ended September 30, 2008.

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

Income tax expense (recovery)

For the three months ended September 30, 2008, we recorded income tax expense of $2.0 million compared to $2.4 million (restated) for the same period last year. Timing effects related to the use of non capital tax losses resulted in a higher tax charge for the three months ended September 30, 2008. For the six months ended September 30, 2008, we recorded income tax expense of $7.3 million, compared to a recovery of $0.5 million (restated) for the same period last year.

For the three and six month periods ended September 30, 2008, income tax expense as a percentage of income before income taxes differs from the statutory rate of 29.38% primarily due to the impact of changes in enacted tax rates and to the impact of the benefit from changes in the timing of the reversal of temporary differences during the period. For the three and six month periods ended September 30, 2007, income tax expense as a percentage of income before income taxes differed from the statutory rate of 31.72% primarily due to the impact of enacted rate changes during the period and the impact of new accounting standards for the recognition and measurement of financial instruments. Under the new accounting standards, certain embedded derivatives are considered capital in nature for income tax purposes.

Summary of Quarterly Results


	Fiscal 2009					Fiscal 2008									Fiscal 2007
	Q2			Q1		Q4		Q3		Q2		Q1			Q4		Q3
(Dollars in millions, except per share amounts)	30-Sep-08			30-Jun-08		31-Mar-08		31-Dec-07		30-Sep-07		30-Jun-07			31-Mar-07		31-Dec-06
										(Restated)		(Restated)
Revenue	$	280.3		$	259.0	$	323.6	$	274.9	$	223.6	$	167.6		$	205.4	$	155.9
Gross profit		44.3			47.6		62.6		50.6		35.2		14.9			13.6		26.0
Operating income (loss)		23.0			26.9		42.6		33.2		17.1		(0.4	)		4.5		13.8
Net (loss) income		(1.2	)		19.1		22.7		25.4		3.2		(8.6	)		1.3		6.6
EPS - Basic⁽¹⁾	$	(0.03	)	$	0.53	$	0.63	$	0.71	$	0.09	$	(0.24	)	$	0.04	$	0.27
EPS - Diluted⁽¹⁾		(0.03	)		0.52		0.62		0.69		0.09		(0.24	)		0.04		0.26


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

As discussed previously, a number of factors have the potential to contribute to variations in our quarterly results between periods, including weather, capital spending by our customers on large oil sands projects, our ability to manage our project-related business so as to avoid or minimize periods of relative inactivity and the strength of the Western Canadian economy. For a more detailed discussion regarding seasonality and its impact on our business see “Key Trends”.

The timing of large projects can influence quarterly revenues. For example, Pipeline segment revenues were $76.7 million in the third quarter of fiscal 2008 (up $61.5 million compared to the same period in fiscal 2007),

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

$87.5 million in the fourth quarter of 2008 (up $62.0 million compared to the same period in fiscal 2007), $27.1 million in the first quarter of fiscal 2009 (up $21.9 million compared to the same period in fiscal 2008) and $55.6 million in the second quarter of fiscal 2009 (up $24.2 million compared to the same period in fiscal 2008). The Heavy Construction and Mining segment experienced increased revenues from the second quarter of fiscal 2008 through the first quarter of fiscal 2009 related to the execution of work at Suncor Millennium Naphtha Unit project under our five-year site services agreement, the construction of an aerodrome for Albian during the third and fourth quarters of fiscal 2008 and increased demand under our master service agreements with Albian and Syncrude. Timing of work under the site services agreements can vary based on our customers’ production and project activities.

In addition to revenue variability, gross margins can be negatively impacted by the timing of maintenance costs. Timing of these costs is dependant on when management can make the equipment available for service without adversely affecting billable equipment hours.

Profitability also varies from period-to-period as a result of claims and change orders. Claims and change orders are a normal aspect of the contracting business but can cause variability in profit margin due to the unmatched recognition of costs and revenues. For further explanation see “Claims and Change Orders”. During the first quarter of fiscal 2009, a $5.3 million claim was recognized causing gross margins for the Pipeline segment to increase above what they would otherwise have been. The additional costs relating to the claim were incurred in fiscal 2007 and in the first quarter of fiscal 2008.

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 income as certain costs, which are generally fixed, including general and administrative expenses, are spread over higher revenue levels. Net income and EPS are also subject to operating leverage as provided by fixed interest expense.

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

Consolidated Financial Position


	As at September 30,			As at March 31,
	2008			2008
(Dollars in thousands)	(Q2-FY2009)			(Q4-FY2008)			% Change

Current assets	$	273,884		$	291,086			(5.9	)%
Current liabilities		(173,581	)		(183,353	)		(6.6	)%
Net working capital		100,303			107,733			(4.8	)%
Plant and equipment		335,762			281,039			19.5	%
Total assets		823,739			793,598			3.8	%
Capital Lease obligations (including current portion)		17,202			14,776			16.4	%
Total long-term financial liabilities⁽¹⁾		321,698			301,497			6.7	%


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

At September 30, 2008, net working capital (current assets less current liabilities) was $100.3 million compared to $107.7 million at March 31, 2008, a decrease of $7.4 million. Negative cash flow decreased our overall cash balance from $32.9 million to nil. Collections improved on both trade receivables (reduced by $12.0 million since March 31, 2008) and holdbacks (reduced by $12.1 million since March 31, 2008) offset by increased unbilled revenue (up by $39.3 million since March 31, 2008). The increase in unbilled revenue relates to delays by some of

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

our large customers in processing change orders and progress payment certificates. We are working with our customers to address these delays. Equipment purchases of $10.3 million, which are scheduled to be paid after the quarter end, increased the balance of accounts payable for the period.

For the six months ended September 30, 2008, plant and equipment, net of depreciation, increased by $54.7 million, compared to the corresponding figure on March 31, 2008. This reflects the capital investment of $80.7 million during the period, offset by equipment disposals of $8.0 million (net book value) and depreciation.

Total long-term financial liabilities increased by $20.2 million between September 30, 2008 and March 31, 2008 due largely to a $13.6 million increase in the carrying amount of our 83/4% senior notes, a $10.0 million drawdown on the revolving credit facility and a $9.2 million increase in embedded derivatives from existing and new supplier maintenance agreements. This was partially offset by a $5.4 million reduction in the value of the derivative financial instruments from the long-term revenue construction contract and a reduction of $7.6 million related to the cross-currency and interest rate swap agreement.

Claims and Change Orders

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


	•	client requirements, specifications and design;

	•	materials and work schedules; and

	•	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.

As a result of certain projects experiencing some of the changes discussed above, at September 30, 2008, we had approximately $1.9 million in costs for claims and unsigned change orders from project inception, with no associated increase in contract value or revenue. We are working with our customers to come to resolution on additional amounts, if any, to be paid to us in respect to these additional costs.

In June 2008, the Pipeline segment successfully settled a claim related to a project completed in fiscal 2007. The claim was settled for $8.0 million, of which $5.3 million was recognized as revenue in the first quarter of fiscal 2009. The balance of $2.7 million was previously recognized as revenue in fiscal 2008.

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008


C.	Key Trends

Seasonality

A number of factors contribute to variations in our quarterly results, including weather, capital spending by our customers on large oil sands projects, our ability to manage our project-related business so as to avoid or minimize periods of relative inactivity and the strength of the Western Canadian economy.

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. Profitability also varies from period-to-period due to claims and change orders. Claims and change orders are a normal aspect of the contracting business but can cause variability in profit margin between quarters due to the unmatched recognition of costs in one quarter and revenues in a separate quarter. For further explanation see “Claims and Change Orders.”

During the higher activity periods we have experienced improvements in operating income due to operating leverage. General and administrative costs are generally fixed and we see these costs decrease as a percentage of revenue when our project volume increases. Net income and EPS are also subject to operating leverage as provided by fixed interest expense. However, we have experienced earnings variability in all periods due to the recognition of realized and unrealized non-cash gains and losses on derivative financial instruments and foreign exchange primarily driven by changes in the Canadian and U.S. dollar exchange rates.

Backlog

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

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

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 cost-plus and time-and-material contracts performed under master service agreements where scope is not clearly defined. While contracts exist for a range of services to be provided under these service agreements, the work scope and value are not clearly defined. For the three months ended September 30, 2008, the total amount of revenue earned under our master services agreements with undefined scope was approximately $91.2 million (approximately $180.5 million for the six months ended September 30, 2008).

Our estimated backlog by segment and contract type as at September 30, 2008 and 2007 was:


	As at September 30,
	2008		2007
By Segment	Q2-FY2009		Q2-FY2008
(Dollars in millions)

Heavy Construction & Mining	$	676.1	$	646.4
Piling		11.1		24.7
Pipeline		12.9		163.3

Total	$	700.1	$	834.4

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008


	As at September 30,
	2008		2007
By Contract Type	Q2-FY2009		Q2-FY2008
(Dollars in millions)

Unit-Price	$	678.8	$	661.7
Lump-Sum		8.4		9.4
Time & Materials, Cost-Plus		12.9		163.3

Total	$	700.1	$	834.4

A contract with a single customer represented approximately $621.4 million of the September 30, 2008 backlog compared to $780.0 million of the June 30, 2008 backlog. The reduction in contract value includes $106.8 million as a result of the elimination of diesel fuel revenue (at zero margin) from the contract. The reduction also represents a previously agreed-upon reduction in contract production volumes at the client’s request. Although provisions in the contract provide for compensation for volume reductions, we waived a portion of this requirement specifically relating to equipment ownership costs as we were able to profitably redeploy the equipment on a temporary basis to service demand from other clients, to the benefit of all parties.

We expect that approximately $224.3 million of total backlog will be performed and realized in the 12 months ending September 30, 2009.^*

Revenue Sources

We have experienced steady growth in master services agreements as oil sands projects are planned and move into the operational phase. While there is no long-term commitment from customers regarding this work as described below, we expect demand under this type of agreement will continue to grow through the remainder of fiscal 2009 as we continue to provide services to Syncrude and Suncor and benefit from the progress at the Albian sites.^*

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

The following table sets out our revenues broken down into each major revenue category:

+ In previously filed documents the revenue graphs were presented on a quarterly basis. The above graph depicts the information on a trailing twelve months basis.

Recurring Services Revenue. Recurring services revenue is derived from long-term contracts and master services agreements as described below:


	•	Long-term contracts. This category of revenue consists of revenue generated from long-term contracts (greater than one year) with total contract values greater than $20 million. These contracts are for work that supports the operations of our customers and include long-term contracts for overburden removal and reclamation. Revenue in this category is typically generated under unit-price contracts and is included in our calculation of backlog. This work is generally funded from our customers’ operating budgets.

	•	Master Services Agreements. This category of revenue is generated from the master services agreements in place with Syncrude and Albian. This revenue is also generated by supporting the operations of our customers and is therefore considered to be recurring. This revenue is not guaranteed under contract and is not included in our calculation of backlog. This revenue is primarily generated under time-and-materials contracts. This work is generally funded from our customers’ operating or maintenance capital budgets.

Project Development Revenue. Project development revenue is typically generated supporting capital construction projects and is therefore considered to be non-recurring. This revenue can be generated under lump-sum, unit-price, time-and-materials and cost-plus contracts. It can be included in backlog if generated under lump-sum, unit-price or time-and-materials contracts and scope is defined. This work is generally funded from our customers’ capital budgets.

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

+ In previously filed documents the revenue graphs were presented on a quarterly basis. The above graph depicts the information on a trailing twelve months basis.

An increase in recurring services and capital projects increased our oil sands work volumes during fiscal 2008 and during the first quarter of fiscal 2009. The pipeline installation project for Kinder Morgan increased our revenues in the conventional oil and gas sector. Minerals mining work slowed at the end of fiscal 2008 and through the first quarter of fiscal 2009 as we completed work on the DeBeers diamond mine project.

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

+ In previously filed documents the revenue graphs were presented on a quarterly basis. The above graph depicts the information on a trailing twelve months basis.

Contracts

We complete work under the following types of contracts: cost-plus, time-and-materials, unit-price and lump-sum. Each type of contract contains a different level of risk associated with its formation and execution.

Time-and-materials. A time-and-materials contract involves using the components of a cost-plus job to calculate rates for the supply of labour and equipment. In this regard, all components of the rates are fixed and we are compensated for each hour of labour and equipment supplied. The risk associated with this type of contract is the estimation of the rates and incurrence of expenses in excess of a specific component of the agreed-upon rate. Any cost overrun in this type of contract must come out of the fixed margin included in the rates.

Unit-price. A unit-price contract is utilized in the execution of projects with large repetitive quantities of work and is commonly utilized for site preparation, mining and pipeline work. We are compensated for each unit of work we perform (for example, cubic meters of earth moved, lineal meters of pipe installed or completed piles). Within the unit-price contract, there is an allowance for labour, equipment, materials and subcontractors’ costs. Once these costs are calculated, we add any site and corporate overhead costs along with an allowance for the margin we want to achieve. The risk associated with this type of contract is in the calculation of the unit costs with respect to completing the required work.

Lump-sum. A lump-sum contract is utilized when a detailed scope of work is known for a specific project. Thus, the associated costs can be readily calculated and a firm price provided to the customer for the execution of the work. The risk lies in the fact that there is no escalation of the price if the work takes longer or more resources are required than were estimated in the established price, as the price is fixed regardless of the amount of work required to complete the project.

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

Cost-plus. A cost-plus contract is a contract in which all the work is completed based on actual costs incurred to complete the work. These costs include all labour, equipment, materials and any subcontractors’ costs. In addition to these direct costs, all site and corporate overhead costs are charged to the job. An agreed-upon fee in the form of a fixed percentage is then applied to all costs charged to the project. This type of contract is utilized where the project involves a large amount of risk or the scope of the project cannot be readily determined.

Major Suppliers

We have long-term relationships with the following equipment suppliers: Finning International Inc. (45 years), Wajax Industries (20 years) and Brandt Tractor Ltd. (30 years). Finning is a major Caterpillar heavy equipment dealer for Canada. Wajax is a major Hitachi equipment supplier to us for both mining and construction equipment. We purchase or rent John Deere equipment, including excavators, loaders and small bulldozers, from Brandt Tractor. In addition to the supply of new equipment, each of these companies is a major supplier for equipment rentals, parts and service labour. We are continuing to work with our equipment suppliers to reduce the lead time required for placing heavy equipment orders to allow us to react quickly to increased demand for our services from our customers.

Tire supply remains a challenge for our haul truck fleet. We prefer to use radial tires from proven manufacturers but the shortage of supply has forced us to use bias tires and source radial tires from new manufacturers. Bias tires have a shorter usage life and are of a lower quality than radial tires. This affects operations as we are forced to reduce operating speeds and loads to compensate for the quality of the tires. We continue to reduce our inventory of bias tires for the 150-ton haul trucks, acquiring radial tires for these trucks as required. Tires for the 240-ton haul trucks continue to be in short supply. To address this shortfall, we are purchasing bias tires from new manufacturers and radial tires from non-dealer sources at a large premium above dealer prices. We were able to negotiate a five-year contract with Bridgestone Firestone Canada Inc. to secure a tire allotment for select tire sizes for the 240-ton to 320-ton haul trucks, which will alleviate some of the shortage. We are continuing negotiations with Bridgestone to improve the security of tire supply. We have also been successful in acquiring radial tires with new trucks as they are delivered and expect to continue this practice in fiscal 2009 and fiscal 2010. Suppliers have improved overall tire supply, but we believe the tire shortage will remain an issue for the foreseeable future.^*

Competition

Our industry is highly competitive in each of our markets. Historically, the majority of our new business was awarded to us based on past client relationships without a formal bidding process, in which, typically, a small number of pre-qualified firms submit bids for the project work. Recently, in order to generate new business with new customers, we have had to participate in formal bidding processes. As new major projects arise, we expect to have to participate in bidding processes on a meaningful portion of the work available to us on these projects. Factors that impact competition include price, safety, reliability, scale of operations, equipment and labour availability and quality of service. Most of our clients and potential clients in the oil sands area operate their own heavy mining equipment fleet. However, these operators have historically outsourced a significant portion of their mining and site preparation operations and other construction services.^*

Our principal competitors in the Heavy Construction and Mining segment include Klemke Mining Corporation, Cow Harbour Construction Ltd., Cross Construction Ltd., Ledcor Construction Limited, Peter Kiewit and Sons Co., Tercon Contractors Ltd., Sureway Construction Ltd. and Thompson Bros. (Construction) Ltd. In underground utilities installation (a part of our Heavy Construction and Mining segment), Voice Construction Ltd., Ledcor Construction Limited and I.G.L. Industrial Services are our major competitors. The main competition

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

to our deep foundation piling operations comes from Agra Foundations Limited, Double Star Co. and Ruskin Construction Ltd. The primary competitors in the pipeline installation business include Ledcor Construction Limited, Washcuk Pipe Line Construction Ltd. and Willbros.

In the public sector, we compete against national firms and there is usually more than one competitor in each local market. Most of our public sector customers are local governments that are focused on serving only their local regions. Competition in the public sector continues to increase and we typically choose to compete on projects only where we can utilize our equipment and operating strengths to secure profitable business.


D.	Outlook

The provision of recurring oil sands services such as mining, overburden removal, labour supply, mine infrastructure development and maintenance and land reclamation is the core of our business, representing approximately 60% of our oil sands revenue and 42% of our consolidated revenues as at September 30, 2008. To date, demand for these services has been unaffected by recent commodity, equity and credit market conditions and has, in fact, increased because of the growing pool of operational oil sands mines. Unlike conventional oil operations, existing oil sands operations are largely unaffected by short-term fluctuations in oil prices due to their immense fixed capital costs and relatively low operating costs. Furthermore, these projects need to be operated at full capacity to maintain a competitive unit production cost. Going forward, demand for recurring services is expected to continue growing at a strong pace as the geographical footprints of existing mines grow, a natural progression of the mining process and as expansion and new mines come on-line.^*

Our heavy construction and piling business could experience some near-term reduction in demand due to announced delays in oil sands-related upgrader projects. While current economic uncertainties could also have a moderating effect on commercial construction activities in Western Canada, infrastructure spending is expected to remain robust, particularly in Alberta, which has committed $120 billion to infrastructure improvements over the next 20 years.^*

As previously announced, we expect our Pipeline segment revenues will decline sharply in the third quarter as the TMX project has now been successfully completed. We are currently looking at several new pipeline opportunities.^*

Overall, we believe the growing opportunities for recurring services, our strong market position and stable financial position will enable us to manage effectively through the current economic uncertainty.^*


E.	Legal and Labour Matters

Laws and Regulations and Environmental Matters

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


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

	•	building and similar codes and zoning ordinances;

	•	laws and regulations relating to consumer protection; and

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

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

We believe we have all material required permits and licenses to conduct our operations and are in substantial compliance with applicable regulatory requirements relating to our operations. Our failure to comply with the applicable regulations could result in substantial fines or revocation of our operating permits.

Our operations are subject to numerous federal, provincial and municipal environmental laws and regulations, including those governing the release of substances, the remediation of contaminated soil and groundwater, vehicle emissions and air and water emissions. These laws and regulations are administered by federal, provincial and municipal authorities, such as Alberta Environment, Saskatchewan Environment, the British Columbia Ministry of Environment and other governmental agencies. The requirements of these laws and regulations are becoming increasingly complex and stringent and meeting these requirements can be expensive.

The nature of our operations and our ownership or operation of property exposes us to the risk of claims with respect to environmental matters and there can be no assurance that material costs or liabilities will not be incurred with such claims. For example, some laws can impose strict, joint and several liability on past and present owners or operators of facilities at, from or to which a release of hazardous substances has occurred, on parties who generated hazardous substances that were released at such facilities and on parties who arranged for the transportation of hazardous substances to such facilities. If we were found to be a responsible party under these statutes, we could be held liable for all investigative and remedial costs associated with addressing such contamination, even though the releases were caused by a prior owner or operator or third party. We are not currently named as a responsible party for any environmental liabilities on any of the properties on which we currently perform or have performed services. However, our leases typically include covenants which obligate us to comply with all applicable environmental regulations and to remediate any environmental damage caused by us to the leased premises. In addition, claims alleging personal injury or property damage may be brought against us if we cause the release of or any exposure to, harmful substances.

Our construction contracts require us to comply with all environmental and safety standards set by our customers. These requirements cover such areas as safety training for new hires, equipment use on site, visitor access on site and procedures for dealing with hazardous substances.

Capital expenditures relating to environmental matters during the fiscal years ended March 31, 2006, 2007 and 2008 were not material. We do not currently anticipate any material adverse effect on our business or financial position as a result of future compliance with applicable environmental laws and regulations. Future events, however, such as changes in existing laws and regulations or their interpretation, more vigorous enforcement policies of regulatory agencies or stricter or different interpretations of existing laws and regulations may require us to make additional expenditures which may or may not be material.^*

Employees and Labour Relations

As of September 30, 2008, we had over 325 salaried employees and over 2,100 hourly employees. Our hourly workforce will fluctuate according to the seasonality of our business from an estimated low of 1,500 employees in the spring to a high of approximately 2,400 employees over the winter. We also utilize the services of subcontractors in our construction business. An estimated 8% to 10% of the construction work we do is performed by subcontractors. Approximately 2,000 employees are members of various unions and work under collective bargaining agreements. The majority of our work is done through employees governed by our mining overburden collective bargaining agreement with the International Union of Operating Engineers Local 955, the primary term of which expires on October 31, 2009. A small portion of our employees work under an industrial collective bargaining agreement with the Alberta Road Builders and Heavy Construction Association and the International Union of Operating Engineers Local 955, the primary term of which expires February 28, 2009. In June 2008, we

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

signed an agreement with the International Union of Operating Engineers Local 955 covering the small group of employees working in our Acheson shop, which will expire June 30, 2011. We are subject to other industry and specialty collective agreements under which we complete work and the primary terms of all of these agreements are currently in effect. We believe that our relationships with all our employees, both union and non-union, are satisfactory. We have not experienced a strike or lockout.^*


F.	Resources and Systems

Outstanding Share Data

We are authorized to issue an unlimited number of common voting shares and an unlimited number of common non-voting shares. As at November 6, 2008, there were 36,038,476 common voting shares outstanding (36,038,476 as at September 30, 2008). In comparison, 35,929,476 common voting shares were outstanding as at March 31, 2008.

Liquidity

Liquidity requirements

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

We maintain a significant equipment and vehicle fleet comprised of units with remaining useful lives covering a variety of time spans. It is important to adequately maintain our large revenue-producing fleet in order to avoid equipment downtime, which can impact our revenue stream and inhibit our ability to satisfactorily perform on our projects. Once units reach the end of their useful lives, they are replaced as it becomes cost prohibitive to continue to maintain them. As a result, we are continually acquiring new equipment both to replace retired units and to support our growth as we take on new projects. In order to maintain a balance of owned and leased equipment, we have financed a portion of our heavy construction fleet through operating leases. In addition, we continue to lease our motor vehicle fleet through our capital lease facilities.

We require between $30 million and $40 million annually for sustaining capital expenditures and our total capital requirements typically range from $125 million to $200 million depending on our growth capital requirements. Due to the long lead time for the delivery of heavy equipment orders from our equipment suppliers, in any given year the timing in the delivery of equipment orders could potentially bring forward capital expenditures into the current fiscal year or move capital expenditures into the next fiscal year. We typically finance approximately 30% to 50% of our total capital requirements through our operating lease facilities, 5% to 10% through our capital lease facilities and the remainder out of cash flow from operations. We believe our operating and capital lease facilities and cash flow from operations will be sufficient to meet these requirements. Our equipment is currently split between owned (40%), leased (40%) and rented equipment (20%). This mix allows us to respond to variations in construction activity and still maintain positive cash flow from operations. Approximately 50% of our leased fleet is specific to one long term overburden removal project.^*

Our long-term debt includes US$200 million of 83/4% senior notes due in December 2011. The foreign currency risk relating to both the principal and interest portions of these senior notes has been managed with a cross-currency swap and interest rate swaps, which went into effect concurrent with the issuance of the notes on November 26, 2003. The swap agreements are an economic hedge but have not been designated as hedges for accounting purposes. Interest totaling $13.0 million on the 83/4% senior notes and the swap is payable semi-annually in June and December of each year until the notes mature on December 1, 2011. The US$200 million principal

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

amount was hedged at C$1.315=US$1.000, resulting in a principal repayment of $263 million due on December 1, 2011. There are no principal repayments required on the 83/4% senior notes until maturity.

One of our major contracts allows the customer to require that we provide up to $50 million in letters of credit. As at September 30, 2008, we had $20.0 million in letters of credit outstanding in connection with this contract. Any change in the amount of the letters of credit required by this customer must be requested by November 1st for an issue date of January 1st each year, for the remaining life of the contract.

Sources of liquidity

Our principal sources of cash are funds from operations and borrowings under our $125 million revolving credit facility. As of September 30, 2008, we had approximately $94.2 million of available borrowings under the revolving credit facility after taking into account $10.0 million drawn on the revolving credit facility and $20.8 million of outstanding and undrawn letters of credit to support performance guarantees associated with customer contracts.

Revolving credit facility

We entered into an amended and restated credit agreement on June 7, 2007 with a syndicate of lenders that provides us with a $125.0 million revolving credit facility. Our revolving credit facility provides for an original principal amount of up to $125.0 million under which revolving loans may be made and under which letters of credit may be issued. The facility will mature on June 7, 2010, subject to possible extension. The credit facility is secured by a first priority lien on substantially all of our and our subsidiaries’ existing and after-acquired property (tangible and intangible) including, without limitation, accounts receivable, inventory, equipment, intellectual property and other personal property and real property, whether owned or leased, and a pledge of the shares of our subsidiaries, subject to various exceptions.

The facility bears interest on each prime loan at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined within the revolving 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 prime and U.S. 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.

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

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

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

The credit facility may be prepaid in whole or in part without penalty, except for bankers’ acceptances, which will not be 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.

Working capital fluctuations effect on cash

The seasonality of our work may result in a slow down in cash collections between December and early February, which may result in an increase in our working capital requirements. Our working capital is also significantly affected by the timing of completion of projects. In some cases, our customers are permitted to withhold payment of a percentage of the amount owing to us for a stipulated period of time (such percentage and time period usually defined by the contract and in some cases provincial legislation). This amount acts as a form of security for our customers and is referred to as a holdback. We are only entitled to collect payment on holdbacks once substantial completion of the contract is performed, there are no outstanding claims by subcontractors or others related to work performed by us and we have met the time period specified by the contract (usually 45 days after completion of the work). As at September 30, 2008, holdbacks totaled $22.9 million, down from $35.0 million as at March 31, 2008. Holdbacks represent 16.5% of our total accounts receivable as at September 30, 2008 (21.0% as at March 31, 2008). This decrease is attributable to the seasonal reduction of revenue compared to the previous two quarters and the collection of holdbacks outstanding as at March 31, 2008, including the DeBeers holdback for $11.0 million. As at September 30, 2008, we carried $16.5 million in holdbacks for three large customers.

Debt Ratings

In December 2007 Standard & Poor’s upgraded our debt rating to B+ (from B) with a stable outlook following a review of our current and prospective business risk and financial risk profiles. Our 83/4% senior notes are also rated B+ with a recovery rating of “4” indicating an expectation for an average of (30% — 50%) recovery in the event of a payment default.

In December 2007 Moody’s maintained our debt rating at B2 with a stable outlook (the upgrade to B2 was issued in December 2006 following our IPO). Moody’s rates our 83/4% senior notes at B3 with a loss given default rating of 5.

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

Cash Flow and Capital Resources

Operating activities


	Three Months Ended September 30,						Six Months Ended September 30,
	2008			2007
(Dollars in thousands)	(Q2-FY2009)			(Q2-FY2008)			2008			2007
				(Restated)						(Restated)

Cash provided by (used in) operating activities	$	(9,110	)	$	22,290		$	24,231		$	28,580
Cash (used in) investing activities		(51,093	)		(15,633	)		(65,425	)		(19,009	)
Cash provided by (used in) financing activities		8,871			(20,806	)		8,323			(22,135	)

Net (decrease) in cash and cash equivalents	$	(51,332	)	$	(14,149	)	$	(32,871	)	$	(12,564	)

Cash provided by operating activities for the second quarter of fiscal 2009 was an outflow of $9.1 million compared to an inflow of $22.3 million for the same period last fiscal year. For the six months ended September 30, 2008, cash provided by operating activities was an inflow of $24.2 million compared to a cash inflow of $28.6 million for the same period last fiscal year. Operating activities in both the three month period and six month period ended September 30, 2008 were affected by delays by several large customers in processing change orders and progress payment certificates. We are working with our customers to address these delays and expect to be current with change orders and progress payment certificates by the end of the third quarter.^*

Investing activities

Sustaining capital expenditures are those that are required to keep our existing fleet of equipment at its optimal useful life through capital maintenance or replacement. Growth capital expenditures relate to equipment additions required to perform larger or a greater number of projects.

During the second quarter of fiscal 2009, we invested $8.8 million in sustaining capital expenditures, compared with $10.0 million in the second quarter of fiscal 2008, and invested $7.4 million in growth capital expenditures, compared with $23.4 million in the second quarter of fiscal 2008, for total capital expenditures of $16.2 million compared with $33.4 million in the second quarter of fiscal 2008. The payment of $38.2 million for capital expenditures incurred for the previous period ended June 30, 2008 led to a decrease in accounts payable related to investing activities for the period ended September 30, 2008. Proceeds of $3.3 million from asset disposals in the second quarter of fiscal 2009, compared with $0.2 million in the second quarter of fiscal 2008, lessened the effect of capital purchases resulting in net cash invested of $51.1 million for the second quarter of fiscal 2009, compared with $15.6 million in the second quarter of fiscal 2008.

Capital expenditures funded by capital leases, not included in “Cash (used in) investing activities”, added $2.7 million to the reported sustaining capital expenditure and $1.2 million to the reported growth capital expenditure for the three months ended September 30, 2008. This compares to an addition of $0.3 million in capital leases in growth capital expenditure and nil capital leases in sustaining capital expenditure for the same period of fiscal 2008. Operating leases used to fund equipment purchases added $4.8 million in the second quarter of fiscal 2009 (not reflected in capital expenditures) compared to $13.2 million in the second quarter of fiscal 2008.

For the six months ended September 30, 2008, we invested $13.1 million in sustaining capital expenditures, compared with $16.1 million in the same period of fiscal 2008 and invested $62.4 million in growth capital expenditures, compared with $27.4 million for the same period in fiscal 2008, for total capital expenditures of $75.5 million, compared with $43.5 million in the same period in fiscal 2008. Proceeds from asset disposals of $4.8 million and net change in non-cash working capital of $5.3 million in the six months ended September 30,

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

2008, compared with $14.1 million and $14.3 million respectively in the same period in fiscal 2008 lessened the effect of capital purchases. Net investment activities were $65.4 million for the six months ended September 30, 2008, compared with $19.0 million for the six months ended September 30, 2007.

Capital expenditures funded by capital leases, not included in “Cash (used in) investing activities”, added $2.9 million to the reported sustaining capital expenditure and $2.2 million to the reported growth capital expenditure for the six months ended September 30,2008. This compares to an addition of $0.3 million in capital leases in growth capital expenditure and nil capital leases in sustaining capital expenditure for the same period of fiscal 2008. Operating leases used to fund equipment purchases added $26.1 million for the six months ended September 30, 2008 (not reflected in capital expenditures) compared to $13.2 million in the six months ended September 30, 2007.

Financing activities

Financing activities in the second quarter of fiscal 2009 resulted in a cash inflow of $8.9 million due to a $10.0 million drawdown on the revolving credit facility partially offset by repayment of capital leases. Cash outflow in the second quarter of fiscal 2008 of $20.8 million was largely a result of $20.0 million of repayments to the revolving credit facility.

Financing activities for the six months ended September 30, 2008 resulted in a cash inflow of $8.3 million due to a $10.0 million drawdown on the revolving credit facility and share issues related to the exercise of stock options which were partially offset by the repayment of capital leases. Cash outflow for the six months ended September 30, 2007 of $22.1 million was a result of a $20.5 million repayment to the revolving credit facility, repayment of capital lease obligations and financing costs partially offset by the issuance of common shares.

Capital Commitments

Contractual Obligations and Other Commitments

Our principal contractual obligations relate to our long-term debt, capital and operating leases and supplier contracts. The following table summarizes our future contractual obligations, excluding interest payments unless otherwise noted, as of September 30, 2008.


			Fiscal Year
			Remaining								2013 and
(Dollars in millions)	Total		2009		2010		2011		2012		Thereafter

Revolving Credit Facility	$	10.0	$	0.0	$	0.0	$	10.0	$	0.0	$	0.0
Senior notes(a)		263.0		0.0		0.0		0.0		263.0		0.0
Capital lease obligations (including interest)		19.0		3.1		5.5		4.7		4.1		1.7
Operating leases		108.6		19.0		33.0		23.5		16.3		16.8
Supplier contracts		34.0		2.7		6.0		8.2		9.8		7.3

Total Contractual Obligations	$	434.6	$	24.8	$	44.5	$	46.4	$	293.2	$	25.8


(a)		We have entered into cross-currency and interest rate swaps, which represent an economic hedge of the 83/4% senior notes. At maturity, we will be required to pay $263.0 million in order to retire these senior notes and the swaps. This amount reflects the fixed exchange rate of C$1.315=US$1.00 established as of November 26, 2003, the inception date of the swap contracts. At September 30, 2008, the carrying value of the derivative financial instruments for the 83/4% senior notes was $74.1 million, inclusive of the interest components.

Off-Balance Sheet Arrangements

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

Cash Requirements

As of September 30, 2008, our cash balance of nil was $32.9 million lower than our cash balance on March 31, 2008, as a result of the timing of capital expenditures and deferral in invoicing for certain high volume customers that slowed cash collections. These deferrals resulted from delays by some large customers in approving change orders and progress payment certificates. We are working closely with these customers to receive the approvals for work completed and we anticipate that we will be current with our change orders by the end of the third quarter of fiscal 2009. In the event that we require additional funding, we believe that any such funding requirements would be satisfied by the funds available from our revolving credit facility.^*

Internal Systems and Processes

Overview of information systems

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

The proper identification of costs is a critical part of our ability to recognize revenues and provide accurate management information for decision-making. We continue to focus resources to address this in our ERP system through the automation of transactional activities. Throughout fiscal 2008 we concentrated on the development of better cost tracking tools through the implementation of a procure-to-pay process in our ERP system. We continue to work on improving the process for tracking and reporting equipment and maintenance costs. We are seeing some improvements in the identification and tracking of our procurement costs.

We are currently performing a user-needs analysis and comparing this to the functionality of our ERP system. We extended the analysis into the second quarter of fiscal 2009 to determine if we can implement additional modules or commence a review of industry-specific software to supplement our existing ERP functionality. The results of this analysis is to be completed in the third quarter of fiscal 2009 at which time we will begin plans for the implementations based on the recommendations.

In the first quarter of fiscal 2009 we reorganized the financial reporting team and recruited for both technical expertise and financial reporting experience. We are now in the process of improving our financial reporting processes.

Evaluation of Disclosure Controls and Procedures

Management has evaluated whether there were changes in our internal controls over financial reporting during the three month and six month periods ended September 30, 2008 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. No material changes were identified.

As of March 31, 2008, we identified material weaknesses in internal controls over financial reporting as described below. We did not maintain effective processes and controls related to the following:


	•	Specific to complex and non routine transactions and period end controls: There was a lack of sufficient accounting and finance personnel with an appropriate level of technical accounting knowledge and training commensurate with the complexity of our financial accounting and reporting requirements. Complex and non routine financial reporting matters that would be affected by this deficiency include the identification of embedded derivatives and preparation of our US GAAP reconciliation note. Additionally, we did not

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008


		adequately perform period end controls related to the review and approval of account analysis, verification of inputs and reconciliations. The accounts that would be affected by these deficiencies are cash, senior notes, contributed surplus, stock-based compensation expense, foreign exchange and related financial statement disclosures.


	•	Specific to revenue recognition: A formal process to track claims and unapproved change orders and sufficient monitoring controls over the completeness and accuracy of forecasts, including the consideration of project changes subsequent to the end of each reporting period, were not effectively implemented. The accounts that would be affected by these deficiencies are revenue, project costs, unbilled revenue and billings in excess of costs incurred and estimated earnings on uncompleted contracts.

	•	Specific to accounts payable and procurement: We did not have an effectively implemented procurement process to track purchase commitments, reconcile vendor accounts and accurately accrue costs not invoiced by vendors at each reporting date. The accounts that would be affected by these deficiencies are accounts payable, accrued liabilities, unbilled revenue, billings in excess of costs incurred and estimated earnings on uncompleted contracts, revenue, project costs, equipment costs, general and administrative costs and other expenses.

As of September 30, 2008, progress has been made on our remediation plans but these material weaknesses have not been remediated. For a discussion of our remediation plans, which are ongoing, and for a discussion of the risks associated with such weaknesses, please see our most recent annual Management’s Discussion and Analysis.

Significant Accounting Policies

Critical Accounting Estimates

Certain accounting policies require management to make significant estimates and assumptions about future events that affect the amounts reported in our financial statements and the accompanying notes. Therefore, the determination of estimates requires the exercise of management’s judgment. Actual results could differ from those estimates and any differences may be material to our financial statements.

Revenue recognition

Our contracts with customers fall under the following contract types: cost-plus, time-and-materials, unit-price and lump-sum. While contracts are generally less than one year in duration, we do have several long-term contracts. The mix of contract types varies year-by-year. For the second quarter of fiscal 2009, our revenue mix was made up of 75.1% time-and-materials contracts, 16.7% unit-price contracts and 8.2% lump-sum contracts.

Profit for each type of contract is included in revenue when its realization is reasonably assured. Estimated contract losses are recognized in full when determined. Claims and unapproved change orders are included in total estimated contract revenue only to the extent that contract costs related to the claim or unapproved change order have been incurred, when it is probable that the claim or unapproved change order will result in a bona fide addition to contract value and the amount of revenue can be reliably estimated.

The accuracy of our revenue and profit recognition in a given period is dependent, in part, on the accuracy of our estimates of the cost to complete each unit-price and lump-sum project. Our cost estimates use a detailed “bottom-up” approach, using inputs such as labour and equipment hours, detailed drawings and material lists. These estimates are updated monthly. We have noted a material weakness related to our procurement processes as previously identified in the fiscal year-end March 31, 2008 Management’s Discussion and Analysis. To address these weaknesses we implemented monitoring and review controls to assist with the determination of our cost estimates. These controls require a significant review of our payable activities after the month-end to ensure that we have identified project costs in the correct period. Given the time delay in identifying costs, we may misstate

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

revenues. However, we believe our experience allows us to produce materially reliable estimates. Our projects can be highly complex and in almost every case, the profit margin estimates for a project will either increase or decrease to some extent from the amount that was originally estimated at the time of the related bid. Because we have many projects of varying levels of complexity and size in process at any given time, these changes in estimates can offset each other without materially impacting our profitability. However, sizable changes in cost estimates, particularly in larger, more complex projects, can have a significant effect on profitability. Factors that can contribute to changes in estimates of contract cost and profitability include, without limitation:^*


	•	site conditions that differ from those assumed in the original bid, to the extent that contract remedies are unavailable;

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

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

	•	the availability and proximity of materials;

	•	unfavorable weather conditions hindering productivity;

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

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

The foregoing factors, as well as the stage of completion of contracts in process and the mix of contracts at different margins, may cause fluctuations in gross profit between periods and these fluctuations may be significant. These changes in cost estimates and revenue recognition impact all three business segments.

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

Costs related to change orders and claims are recognized when they are incurred. Change orders are included in total estimated contract revenue when it is probable that the change order will result in a bona fide addition to contract value and can be reliably estimated. Claims are included in total estimated contract revenue only to the extent that contract costs related to the claim have been incurred and when it is probable that the claim will result in a bona fide addition to contract value and can be reliably estimated. Those two conditions are satisfied when (1) the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained providing a reasonable basis to support the claim, (2) additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our performance, (3) costs associated with the claim are identifiable and reasonable in view of the work performed and (4) evidence supporting the claim is objective and verifiable. No profit is recognized on claims until final settlement occurs. This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries.

Plant and equipment

The most significant estimates in accounting for plant and equipment are the expected useful life of the asset and the expected residual value. Most of our property, plant and equipment have long lives that can exceed 20 years

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

with proper repair work and preventative maintenance. Useful life is measured in operating hours, excluding idle hours and a depreciation rate is calculated for each type of unit. Depreciation expense is determined monthly based on daily actual operating hours. In determining the estimates of these useful lives, we take into account industry trends and company-specific factors, including changing technologies and expectations for the in-service period of certain assets. On an annual basis, we re-assess our existing estimates of useful lives to ensure they match the anticipated life of the equipment from a revenue-producing perspective. If technological change happens more quickly or in a different way than anticipated, we might have to reduce the estimated life of plant and equipment, which could result in a higher depreciation expense in future periods or we may record an impairment charge to write down the value of plant and equipment.

Another key estimate is the expected cash flows from the use of an asset and the expected disposal proceeds in applying CICA Section 3063 “Impairment of Long-Lived Assets” and Section 3475 “Disposal of Long-Lived Assets and Discontinued Operations”. These standards require the recognition of an impairment loss for a long-lived asset when changes in circumstances cause its carrying value to exceed the total undiscounted cash flows expected from its use. An impairment loss, if any, is determined as the excess of the carrying value of the asset over its fair value.

Allowance for doubtful accounts receivable

We regularly review our accounts receivable balances for each of our customers and we write down these balances to their expected realizable value when outstanding amounts are determined not to be fully collectible. This generally occurs when our customer has indicated an inability to pay, we were unable to communicate with our customer over an extended period of time and we have considered other methods to obtain payment without success. We determine estimates of the allowance for doubtful accounts on a customer-by-customer evaluation of collectability at each reporting date, taking into consideration the following factors: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition and historical experience.

Goodwill impairment

Impairment is tested at the reporting unit level by comparing the reporting unit’s carrying amount to its fair value. The process of determining fair value is subjective and requires us to exercise judgment in making assumptions about future results, including revenue and cash flow projections at the reporting unit level and discount rates. We previously tested goodwill annually on December 31. For fiscal year 2008, we completed the goodwill impairment testing on October 1, 2007. This change in timing was made to reduce conflict between the impairment testing and our financial reporting close process for the fiscal period ending December 31 of each calendar year. It is our intention to continue to complete subsequent goodwill impairment testing on October 1 of each calendar year going forward. This change in accounting policy was applied on a retrospective basis and had no impact on the consolidated financial statements.

Related Parties

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

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

Recently Adopted Accounting Policies

Financial Instruments — Disclosure and Presentation

Effective April 1, 2008, we prospectively adopted the Canadian Institute of Chartered Accountants (CICA) Handbook Section 3862, “Financial Instruments — Disclosures”, which replaces disclosure guidance in CICA Handbook Section 3861 and provides expanded disclosure requirements that enable users to evaluate the significance of financial instruments on our financial position and our performance and the nature and extent of risks arising from financial instruments to which we are exposed during the period and at the balance sheet date, and how we manage those risks. This standard harmonizes disclosures with International Financial Reporting Standards. We have provided the additional required disclosures in note 10 to our interim consolidated financial statements for the three and six months ended September 30, 2008.

Effective April 1, 2008, we adopted CICA Handbook Section 3863, “Financial Instruments Presentation”, which carries forward presentation guidance in CICA Handbook Section 3861. This Section establishes standards for presentation of financial instruments and non-financial derivatives. It deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, gains and losses, and the circumstances in which financial assets and financial liabilities are offset. The adoption of this standard did not have a material impact on the presentation of financial instruments in our financial statements.

Capital Disclosures

Effective April 1, 2008, we prospectively adopted CICA Handbook Section 1535, “Capital Disclosures”, which requires disclosure of qualitative and quantitative information that enables users to evaluate our objectives, policies and processes for managing capital. We have provided the additional required disclosures in note 11 to our interim consolidated financial statements for the three and six months ended September 30, 2008.

Inventories

Effective April 1, 2008, we retrospectively adopted CICA Handbook Section 3031, “Inventories” without restatement of prior periods. This standard requires inventories to be measured at the lower of cost and net realizable value and provides guidance on the determination of cost, including the allocation of overheads and other costs to inventories, the requirement for an entity to use a consistent cost formula for inventory of a similar nature and use, and the reversal of previous write-downs to net realizable value when there are subsequent increases in the value of inventories. This new standard also clarifies that spare component parts that do not qualify for recognition as property, plant and equipment should be classified as inventory. To adopt this new standard we reversed a tire impairment of $1.4 million that was previously recorded at March 31, 2008 in other assets with a corresponding decrease to opening deficit of $1.0 million net of future taxes of $0.4 million. We then reclassified $5.1 million of tires and spare component parts from ‘other assets’ to ‘inventory’. As at September 30, 2008, inventory is comprised of tires and spare component parts of $9.3 million and job materials of $0.1 million. We carry inventory at the lower of weighted average cost and net realizable value. The carrying amount of inventories pledged as security for borrowings under the revolving credit facility is $9.4 million as at September 30, 2008. The adoption of this standard did not have a significant impact on net income (loss) for the three and six months ended September 30, 2008.

Going Concern

Effective April 1, 2008, we prospectively adopted CICA Section 1400, “General Standards of Financial Statement Presentation”. These amendments require us to assess our ability to continue as a going concern. When we are aware of material uncertainties related to events or conditions that may cast doubt on our ability to continue

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

as a going concern, those concerns must be disclosed. In assessing the appropriateness of the going concern assumption, the standard requires us to consider all available information about the future, which is at least, but not limited to, twelve months from the balance sheet date. The adoption of this standard did not have a material impact on the presentation and disclosures in our consolidated financial statements.

Recent Accounting Pronouncements Not Yet Adopted

Goodwill and Other Intangible Assets

In February 2008, the CICA issued Section 3064, “Goodwill and Other Intangible Assets”, replacing Section 3062, “Goodwill and Other Intangible Assets” and Section 3450, “Research and Development Costs”. The new pronouncement establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. This new standard will be effective for our interim and annual consolidated financial statements commencing April 1, 2009. We are currently evaluating the impact of adopting the standard.


G.	Forward-Looking Information and Risk Factors

Forward-Looking Information

This document contains forward-looking information that is based on expectations and estimates as of the date of this document. Our forward-looking information is information that is subject to known and unknown risks and other factors that may cause future actions, conditions or events to differ materially from the anticipated actions, conditions or events expressed or implied by such forward-looking information. Forward-looking information is information that does not relate strictly to historical or current facts, and can be identified by the 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 operational spending throughout the 30-40 year life of a mine and our ability to provide services through such period;

	(b)	new development and expansion projects will be completed and the market for our recurring services will expand accordingly;

	(c)	operational oil sands projects will continue to be largely unaffected by fluctuations in oil prices;

	(d)	the expected continued rapid growth of operators in the oil sands business, their planned projects and our intention and capacity to pursue and win business opportunities from these projects;

	(e)	our intention to increase our fleet size to be ready to meet the challenges from the projected growth in oil sands projects;

	(f)	that acquisition opportunities will materialize that will allow us to expand our complementary service offerings which we will be able to cross-sell with our existing services;

	(g)	our intention to build on our relationships with our existing oil sands customers to win a substantial share of the heavy construction and mining, piling and pipeline services outsourced in connection with these projects;

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008


	(h)	our intention to increase our presence outside the oil sands and extend our services to other resource industries across Canada;

	(i)	the success of the enhancements to maintenance practices resulting in improved availability through reduced repair time and increased utilization of our equipment with a consequent improvement in our revenue, margins and profitability;

	(j)	the amount of our backlog expected to be performed and realized in the twelve months ending September 30, 2009;

	(k)	the expected growth in master services agreements through 2009 and our continued work with Syncrude, Suncor and Shell;

	(l)	the arrival of new major projects and our required participation for work on these projects;

	(m)	the continued development of the oil sands and the expectation that it will drive a significant portion of our 2009 revenue;

	(n)	the anticipated increased demand for our services with customers such as at Suncor’s Voyageur site and at Petro-Canada’s Fort Hills site;

	(o)	demand for our piling services remaining strong in fiscal 2009;

	(p)	the anticipated temporary slowdown in our pipeline activity once the TMX project concludes in November 2008 and significant long-term opportunities for this division;

	(q)	our expectation of being current with our change-orders by the end of the third quarter of fiscal 2009;

	(r)	our operating and capital lease facilities and cash flow from operations are sufficient to meet capital expenditure requirements;

	(s)	our ability to produce materially reliable estimates; and

	(t)	our experience allows us to produce materially reliable estimates.

The forward-looking information in paragraphs (a), (b), (d), (e), (f), (k), (l), (m), (o), and (p) rely on certain market conditions and demand for our services and are based on the assumptions that: despite the slow down in the global economy and tightening of credit conditions combined with short term declines in oil prices, which will slow capital development of Canada’s natural resources, in particular the oil sands, we still expect to see strong demand for our recurring services as the oil sands continue to be an economically viable source of energy; our customers and potential customers continue to invest in the oil sands and other natural resources developments; our customers and potential customers will continue to outsource the type of activities for which we are capable of providing service; and the Western Canadian economy continues to develop with additional investment in public construction; and are subject to the following risks and uncertainties that:


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

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

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

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

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008


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

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

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

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

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

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

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


	•	our ability to grow our operations in the future may be hampered by our inability to obtain long lead time equipment and tires, which are currently in limited supply;

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

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

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

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

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

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

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

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

	•	many of our senior officers have either recently joined the company or have just been promoted and have only worked together as a management team for a short period of time.

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

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

Risk Factors

For the second quarter of fiscal 2009 and for the six months ended September 30, 2008, other than noted below, there has been no significant change in our risk factors from those described in our Management’s Discussion and Analysis for the fiscal year ended March 31, 2008. For a detailed discussion of these risk factors, see “Risk Factors” in our Management’s Discussion and Analysis for the fiscal year ended March 31, 2008, available on SEDAR at www.sedar.com.

Anticipated new major capital projects in the oil sands may not materialize.

Notwithstanding the National Energy Board’s estimates regarding new capital investment and growth in the Canadian oil sands, planned and anticipated capital projects in the oil sands may not materialize. The underlying assumptions on which the capital projects are based are subject to significant uncertainties, and actual capital investments in the oil sands could be significantly less than estimated. Projected investments in new capital projects may be postponed or cancelled for any number of reasons, including among others:


	•	reductions in available credit for customers to fund capital projects;

	•	changes in the perception of the economic viability of these projects;

	•	shortage of pipeline capacity to transport production to major markets;

	•	lack of sufficient governmental infrastructure to support growth;

	•	delays in issuing environmental permits or refusal to grant such permits;

	•	shortage of skilled workers in this remote region of Canada; and

	•	cost overruns on announced projects.

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

Due to the amount of capital investment required to build an oil sands project, or construct a significant capital expansion to an existing project, investment decisions by oil sands operators are based upon long-term views of the economic viability of the project. Economic viability is dependent upon the anticipated revenues the capital project will produce, the anticipated amount of capital investment required and the anticipated fixed cost of operating the

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

project. The most important consideration is the customer’s view of the long-term price of oil which is influenced by many factors, including the condition of developed and developing economies and the resulting demand for oil and gas, the level of supply of oil and gas, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political conditions in oil producing nations, including those in the Middle East, war or the threat of war in oil producing regions and the availability of fuel from alternate sources. If our customers believe the long-term outlook for the price of oil is not favorable, or believe oil sands projects are not viable for any other reason, they may delay, reduce or cancel plans to construct new oil sands capital projects or capital expansions to existing projects. Recently, the market price of oil decreased significantly. In addition, the slowing world economy could lead to lower international demand for oil, which could continue to suppress oil prices. As a result of these developments, many of our customers may decide to scale back their capital development plans and may be forced to significantly reduce their capital expenditures on oil sands projects. Delays, reductions or cancellations of major oil sands projects would adversely affect our prospects for revenues from capital projects and could have an adverse impact on our financial condition and results of operations.

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

Most of our customers are Canadian energy companies. A downturn in the Canadian energy industry could cause our customers to slow down or curtail their future capital expansions which would, in turn, reduce our revenue from those customers on their capital projects. Such a delay or curtailment could have an adverse impact on our financial condition and results of operations. In addition, a reduction in the number of new oil sands capital projects by customers would also likely result in increased competition among oil sands service providers, which could also reduce our ability to successfully bid for new capital projects.

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

Outsourced mining and site preparation services constitute a large portion of the work we perform for our customers. For example, our mining and site preparation project revenues constituted approximately 63%, 75% and 74% of our revenues in each of fiscal years 2008, 2007 and 2006 respectively. The election by one or more of our customers to perform some or all of these services themselves, rather than outsourcing the work to us, could have a material adverse impact on our business and results of operations. Certain customers perform some of this work internally and may choose to expand on the use of internal resources to complete this work. The recent tightening of the credit market and worldwide economic downturn may result in our customers reducing their capital spending.

Quantitative and Qualitative Disclosures about Market Risk

Foreign currency risk

We are subject to currency exchange risk as our 83/4% senior notes are denominated in US dollars and all of our revenues and most of our expenses are denominated in Canadian dollars. To manage the foreign currency risk and potential cash flow impact on our $200 million in US dollar-denominated notes, we have entered into currency swap and interest rate swap agreements. These financial instruments consist of three components: a US dollar interest rate swap; a US dollar-Canadian dollar cross-currency basis swap; and a Canadian dollar interest rate swap. The US dollar interest rate swap can be cancelled at the counterparty’s option at any time after December 1, 2007 if the counterparty pays a cancellation premium. The premium is equal to 2.1875% if exercised between December 1, 2008 and December 1, 2009; and repurchased at par if cancelled after December 1, 2009.

Exchange rate fluctuations may also cause the price of goods to increase or decrease for us. For example, a decrease in the value of the Canadian dollar compared to the US dollar would proportionately increase the cost of equipment and parts which are sold to us or priced in US dollars.

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

The impact of the exchange rate fluctuation may also affect any embedded derivatives included in our revenue or parts and maintenance contracts with price escalators tied to either foreign exchange rates or foreign cost indices.

Interest rate risk

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

In conjunction with the cross-currency swap agreement we entered into a US dollar interest rate swap and a Canadian dollar interest rate swap with the net effect of economically converting the 8.75% rate payable on the 83/4% senior notes into a fixed rate of 9.765% for the duration that the 83/4% senior notes are outstanding. On May 19, 2005 in connection with our new revolving credit facility at that time, this fixed rate was increased to 9.889%. These derivative financial instruments were not designated as a hedge for accounting purposes.

At September 30, 2008 and March 31, 2008, the notional principal amounts of the interest rate swaps were US$200 million and Canadian $263 million.

As at September 30, 2008, holding all other variables constant, a 1% increase (decrease) to Canadian interest rates would impact the fair value of the interest rate swaps by $6.7 million with this change in fair value being recorded in net income. As at September 30, 2008, holding all other variables constant, a 1% increase (decrease) to US interest rates would impact the fair value of the interest rate swaps by $2.7 million with this change in fair value being recorded in net income. As at September 30, 2008, holding all other variables constant, a 1% increase (decrease) to Canadian to US interest rate volatility would impact the fair value of the interest rate swaps by $1.8 million with this change in fair value being recorded in net income.

Inflation

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

Credit risk

Credit risk is the risk of financial loss to us if a customer or counterparty to a financial instrument fails to meet its contractual obligations. We are exposed to credit risk through our cash and cash equivalents, accounts receivable and unbilled revenue. We manage the credit risk associated with our cash and cash equivalents by holding our funds with reputable financial institutions. Credit risk for trade and other accounts receivables and unbilled revenue are managed through established credit monitoring activities. We review our trade receivable accounts regularly for collectability and payment performance.

We have a concentration of customers in the oil and gas sector. The concentration risk is mitigated by the customers being large investment grade organizations. Customers outside of the oil and gas sector, who are more vulnerable to changes in economic conditions, are more closely monitored for changes in their payment behavior and credit worthiness. Losses related to trade accounts receivable have historically been insignificant or specific to customers outside of the oil and gas sector. Decisions to extend credit to new customers are approved by management.

Availability or increased cost of leasing

A portion of our equipment fleet is currently leased from third parties. Further, we anticipate leasing substantial amounts of equipment to support ongoing growth opportunities in the upcoming year. Other future projects may

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

require us to lease additional equipment. If equipment lessors are unable or unwilling to provide us with the equipment or significantly increase the cost of leasing equipment that we need to perform our work, our growth prospects will be materially adversely affected. To mitigate this risk we have secured increased leasing ability with some of our existing equipment lessors. A major supplier recently expanded our leasing capacity by approximately 30%. Our current lease commitments with this supplier now represent 50% of the total capacity available. We are actively pursuing new lessor relationships to dilute our exposure to the loss of one or more of our lessors.


H.	General Matters

History and Development of the Company

NACG Holdings Inc. (Holdings) was formed in October 2003 in connection with the Acquisition discussed below. Prior to the Acquisition, Holdings had no operations or significant assets and the Acquisition was primarily a change of ownership of the businesses acquired.

On October 31, 2003, two wholly owned subsidiaries of Holdings, as the buyers, entered into a purchase and sale agreement with Norama Ltd. and one of its subsidiaries, as the sellers. On November 26, 2003, pursuant to the purchase and sale agreement, Norama Ltd. sold to the buyers the businesses comprising North American Construction Group in exchange for total consideration of approximately $405.5 million, net of cash received and including the impact of certain post-closing adjustments (the Acquisition). The businesses we acquired from Norama Ltd. have been in operation since 1953. Subsequent to the Acquisition, we have operated the businesses in substantially the same manner as prior to the Acquisition.

On November 28, 2006, prior to the consummation of the initial public offering (IPO) discussed below, Holdings amalgamated with its wholly-owned subsidiaries, NACG Preferred Corp and North American Energy Partners Inc. The amalgamated entity continued under the name North American Energy Partners Inc. The voting common shares of the new entity, North American Energy Partners Inc., were the shares sold in the IPO and related secondary offering. On November 28, 2006, we completed the IPO in the United States and Canada of 8,750,000 voting common shares and a secondary offering of 3,750,000 voting common shares for $18.38 per share (U.S. $16.00 per share).

On November 22, 2006, our common shares commenced trading on the New York Stock Exchange and on the Toronto Stock Exchange on an “if, as and when issued” basis. On November 28, 2006, our common shares became fully tradable on the Toronto Stock Exchange.

Net proceeds from the IPO were $140.9 million (gross proceeds of $158.5 million, less underwriting discounts and costs and offering expenses of $17.6 million). On December 6, 2006, the underwriters exercised their option to purchase an additional 687,500 common shares from us. The net proceeds from the exercise of the underwriters’ option were $11.7 million (gross proceeds of $12.6 million, less underwriting fees of $0.9 million). Total net proceeds were $152.6 million (total gross proceeds of $171.1 million less total underwriting discounts and costs and offering expenses of $18.5 million).

As of September 30, 2008, our authorized capital consists of an unlimited number of voting and non-voting common shares, of which 36,038,476 voting common shares were issued and outstanding (35,929,476 as at March 31, 2008).

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

North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2008

Additional Information

Additional information relating to us, including our Annual Information Form dated June 20, 2008, can be found on the Canadian Securities Administrators System for Electronic Document Analysis and Retrieval (SEDAR) database at www.sedar.com and the website of the Securities and Exchange Commission at www.sec.gov.

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

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


1.	I have reviewed the interim filings (as this term is defined in Multilateral Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings) of North American Energy Partners Inc., (the “issuer”) for the interim period ending September 30, 2008;

2.	Based on my knowledge, 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;

3.	Based on my knowledge, 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 and for the periods presented in the interim filings;

4.	The issuer’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures and internal control over financial reporting for the issuer, and we have:


	(a)	designed such disclosure controls and procedures, or caused them to be designed under our supervision, to provide reasonable assurance that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which the interim filings are being prepared; and

	(b)	designed such internal control over financial reporting, 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.	I have caused the issuer to disclose in the interim MD&A any change in the issuer’s internal control over financial reporting that occurred during the issuer’s most recent interim period that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting.

Date: November 6, 2008

/s/ Rodney J. Ruston

Name: Rodney J. Ruston


Title:	President and Chief Executive Officer

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

I, Peter Dodd, the Chief Financial Officer of North American Energy Partners Inc., certify that:


1.	I have reviewed the interim filings (as this term is defined in Multilateral Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings) of North American Energy Partners Inc., (the “issuer”) for the interim period ending September 30, 2008;

2.	Based on my knowledge, 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;

3.	Based on my knowledge, 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 and for the periods presented in the interim filings;

4.	The issuer’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures and internal control over financial reporting for the issuer, and we have:


	(a)	designed such disclosure controls and procedures, or caused them to be designed under our supervision, to provide reasonable assurance that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which the interim filings are being prepared; and

	(b)	designed such internal control over financial reporting, 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.	I have caused the issuer to disclose in the interim MD&A any change in the issuer’s internal control over financial reporting that occurred during the issuer’s most recent interim period that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting.

Date: November 6, 2008

/s/ Peter Dodd

Name: Peter Dodd


Title:	Chief Financial Officer