Edgar Filing: North American Energy Partners Inc.

Form 6-K for the month of August 2007

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

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

under

the Securities Exchange Act of 1934

For the month of August 2007

Commission File Number 001-33161

NORTH AMERICAN ENERGY PARTNERS INC.

Zone 3 Acheson Industrial Area

2-53016 Highway 60

Acheson, Alberta

Canada T7X 5A7

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F x Form 40-F ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):

Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes ¨ No x

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82-

Included herein:

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

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

SIGNATURES

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


NORTH AMERICAN ENERGY PARTNERS INC.

By:		/s/ Vincent J. Gallant
Name: Title:		Vincent J. Gallant Acting Vice President, Finance and Chief Financial Officer

Date: November 14, 2007

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Expressed in thousands of Canadian dollars)

(Unaudited)

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Balance Sheets

(in thousands of Canadian dollars)


	September 30 2007			March 31, 2007
	(unaudited)
Assets

Current assets:
Cash and cash equivalents	$	—		$	7,895
Accounts receivable		124,048			93,220
Unbilled revenue		72,689			82,833
Inventory		154			156
Asset held for sale		—			8,268
Prepaid expenses and deposits		7,187			11,932
Other assets		5,468			10,164
Future income taxes		21,956			14,593

		231,502			229,061

Future income taxes (note 3(a))		26,007			14,364
Plant and equipment (note 6)		280,490			255,963
Goodwill		200,056			199,392
Intangible assets, net of accumulated amortization of $18,738 (March 31, 2007—$17,608) (notes 3(a) and 7(a))		2,883			600
Deferred financing costs, net of accumulated amortization of $nil (March 31, 2007—$7,595) (note 3(a))		—			11,356

	$	740,938		$	710,736


Liabilities and Shareholders’ Equity

Current liabilities:
Cheques issued in excess of cash deposits	$	4,669		$	—
Revolving credit facility (note 7(a))		—			20,500
Accounts payable		130,057			94,548
Accrued liabilities		21,067			23,393
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		1,979			2,999
Current portion of capital lease obligations		3,224			3,195
Current portion of derivative financial instruments (note 11(b))		4,458			2,669
Future income taxes		14,405			4,154

		179,859			151,458

Deferred lease inducements (note 8)		993			—
Capital lease obligations		5,169			6,514
Senior notes (notes 3(a) and 7(b))		190,860			230,580
Derivative financial instruments (notes 3(a) and 11(b))		104,080			58,194
Future income taxes (note 3(a))		24,243			19,712

		505,204			466,458


Shareholders’ equity:
Common shares (authorized – unlimited number of voting and non-voting common shares; issued and outstanding – 35,752,060 voting common shares (March 31, 2007 – 35,192,260 voting common shares and 412,400 non-voting common shares)) (note 9(a))		297,216			296,198
Contributed surplus (note 9(b))		4,075			3,606
Deficit		(65,557	)		(55,526	)

		235,734			244,278


Guarantee (note 16)
Subsequent event (note 7(a))

	$	740,938		$	710,736

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

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

(in thousands of Canadian dollars, except per share amounts)

(unaudited)


	Three months ended September 30						Six months ended September 30
	2007			2006			2007			2006
Revenue	$	223,575		$	130,066		$	391,202		$	268,166
Project costs		135,266			73,083			229,939			140,092
Equipment costs		42,212			25,598			87,351			49,533
Equipment operating lease expense		3,569			6,369			7,504			13,569
Depreciation		7,318			4,822			16,294			12,134

Gross profit		35,210			20,194			50,114			52,838
General and administrative costs		17,360			10,012			31,987			19,247
Loss on disposal of plant and equipment		576			345			845			458
Loss on disposal of asset held for sale		—			—			316			—
Amortization of intangible assets		182			182			323			365

Operating income before the undernoted		17,092			9,655			16,643			32,768
Interest expense (note 10)		6,196			10,326			12,934			20,494
Foreign exchange (gain) loss		(14,252	)		72			(31,352	)		(13,394	)
Realized and unrealized loss on derivative financial instruments (note 11(a))		21,236			3,786			45,185			11,782
Financing costs		—			53			—			53
Other income		(128	)		(8	)		(236	)		(591	)

Income (loss) before income taxes		4,040			(4,574	)		(9,888	)		14,424
Income taxes (note 12(c)):
Current income taxes		—			(2,712	)		21			(2,844	)
Future income taxes		1,972			2,895			(1,654	)		4,131

Net income (loss) and comprehensive income (loss) for the period		2,068			(4,757	)		(8,255	)		13,137
Deficit, beginning of period – as previously reported		(67,625	)		(58,652	)		(55,526	)		(76,546	)
Change in accounting policy related to financial instruments (note 3(a))		—			—			(1,776	)		—

Deficit, end of period	$	(65,557	)	$	(63,409	)	$	(65,557	)	$	(63,409	)

Net income (loss) per share – basic (note 9(c))	$	0.06		$	(0.26	)	$	(0.23	)	$	0.71

Net income (loss) per share – diluted (note 9(c))	$	0.06		$	(0.26	)	$	(0.23	)	$	0.53

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Statements of Cash Flows

(in thousands of Canadian dollars)

(unaudited)


	Three months ended September 30						Six months ended September 30
	2007			2006			2007			2006
Cash provided by (used in):
Operating activities:
Net income (loss) for the period	$	2,068		$	(4,757	)	$	(8,255	)	$	13,137
Items not affecting cash:
Depreciation		7,318			4,822			16,294			12,134
Write-down of other assets to replacement cost		1,848			—			1,848			—
Amortization of intangible assets		182			182			323			365
Amortization of deferred lease inducements		(52	)		—			(52	)		—
Amortization of deferred financing costs		—			948			—			1,835
Loss on disposal of plant and equipment		576			345			845			458
Loss on disposal of asset held for sale		—			—			316			—
Unrealized foreign exchange (gain) loss on senior notes		(13,864	)		78			(31,014	)		(13,493	)
Amortization of bond issue costs (notes 3(a) and 10)		110			—			507			—
Unrealized loss on derivative financial instruments		20,569			3,019			43,850			10,438
Stock-based compensation expense (note 14)		388			809			747			1,121
Accretion of redeemable preferred shares		—			965			—			1,910
Future income taxes		1,972			2,895			(1,654	)		4,131
Net changes in non-cash working capital (note 12(b))		1,175			(4,768	)		4,825			(14,751	)

		22,290			4,538			28,580			17,285

Investing activities:
Acquisition, net of cash acquired (note 5)		—			(1,496	)		(1,581	)		(1,496	)
Purchase of plant and equipment		(33,352	)		(9,973	)		(43,545	)		(19,309	)
Additions to assets held for sale		—			—			(2,248	)		—
Proceeds on disposal of plant and equipment		226			99			3,916			572
Proceeds on disposal of assets held for sale		—			—			10,200			—
Net changes in non-cash working capital (note 12(b))		17,493			1,678			14,249			1,474

		(15,633	)		(9,692	)		(19,009	)		(18,759	)

Financing activities:
Decrease in revolving credit facility		(20,000	)		—			(20,500	)		—
Repayment of capital lease obligations		(806	)		(848	)		(1,608	)		(1,621	)
Financing costs (note 7(a))		—			(2,403	)		(767	)		(3,021	)
Issue of common shares (note 9(a))		—			139			740			139

		(20,806	)		(3,112	)		(22,135	)		(4,503	)

Decrease in cash and cash equivalents		(14,149	)		(8,266	)		(12,564	)		(5,977	)
Cash and cash equivalents, beginning of period		9,480			45,093			7,895			42,804

Cash and cash equivalents (cheques issued in excess of cash deposits), end of period	$	(4,669	)	$	36,827		$	(4,669	)	$	36,827

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, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

1.	Nature of operations

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

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

2.	Basis of presentation

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

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


• North American Caisson Ltd.		• North American Pipeline Inc.

• North American Construction Ltd.		• North American Road Inc.

• North American Engineering Ltd.		• North American Services Inc.

• North American Enterprises Ltd.		• North American Site Development Ltd.

• North American Industries Inc.		• North American Site Services Inc.

• North American Mining Inc.		• Griffiths Pile Driving Inc.

• North American Maintenance Ltd.

3.	Accounting policy changes

Financial instruments – recognition and measurement

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

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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


	Increase (decrease)
Deferred financing costs	$	(11,356	)
Intangible assets		1,622
Long-term future income tax asset		2,588
Senior notes		(12,634	)
Derivative financial instruments		7,246
Long-term future income tax liability		18
Opening deficit		1,776

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

•

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

•

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

•

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

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

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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

•

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

•

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

•

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

•

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

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

Financial instruments – disclosure and presentation

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

Comprehensive income and equity

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

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

Accounting changes

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

Accounting policy choice for transaction costs

In June 2007, the CICA issued Emerging Issues Committee Abstract No. 166, “Accounting Policy Choice For Transaction Costs” (“EIC-166”). CICA Handbook Section 3855 requires that when an entity acquires a financial asset or incurs a financial liability classified other than as held-for-trading, it adopts an accounting policy for transaction costs of either: (a) recognizing all transaction costs in net income; or (b) adding transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability to the carrying amount of the financial instrument. EIC-166 clarifies that the same accounting policy choice should be made for all similar instruments classified as other than held-for-trading, but that a different accounting policy choice may be made for financial instruments that are not

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

similar. This guidance was adopted by the Company on April 1, 2007 and did not have a material impact on the consolidated financial statements.

4.	Recent accounting pronouncements not yet adopted

Financial instruments

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

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

Capital disclosures

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

Inventories

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

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

Going concern

In April 2007, the CICA approved amendments to Handbook 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 new requirements of the standard are applicable for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

5.	Acquisition

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


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

	$	1,581

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

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

6.	Plant and equipment


September 30, 2007	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	275,005	$	52,187	$	222,818
Major component parts in use		8,427		3,064		5,363
Other equipment		17,301		6,460		10,841
Licensed motor vehicles		23,457		13,566		9,891
Office and computer equipment		6,221		2,826		3,395
Buildings		17,048		1,276		15,772
Leasehold improvements		5,957		873		5,084
Assets under construction		7,326		—		7,326

	$	360,742	$	80,252	$	280,490


March 31, 2007	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	254,107	$	46,609	$	207,498
Major component parts in use		7,884		2,489		5,395
Other equipment		16,001		5,651		10,350
Licensed motor vehicles		23,345		12,121		11,224
Office and computer equipment		4,841		2,249		2,592
Buildings		16,443		716		15,727
Leasehold improvements		2,992		664		2,328
Assets under construction		849		—		849

	$	326,462	$	70,499	$	255,963

The above amounts include $15,615 (March 31, 2007 – $15,422) of assets under capital lease and accumulated depreciation of $8,448 (March 31, 2007 – $7,302) related thereto. During the three and six months ended September 30, 2007, additions of plant and equipment included $280 and $292, respectively, for capital leases (three and six months ended September 30, 2006 – $1,436 and $3,194 respectively). Depreciation of equipment under capital leases of $613 and $1,146 for the three and six months ended September 30, 2007, respectively, is included in deprecation expense (three and six months ended September 30, 2006 – $712 and $1,342 respectively).

Debt

Revolving credit facility

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

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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

As of September 30, 2007, the Company had no outstanding borrowings under the revolving credit facility and had issued $25.0 million in letters of credit to support bonding requirements and performance guarantees associated with customer contracts and operating leases. Subsequent to September 30, 2007, a letter of credit for $5 million was cancelled by one of the Company’s customers pursuant to the customer contract. The Company’s borrowing availability under the facility was $100.0 million at September 30, 2007.

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

Senior notes


	September 30, 2007			March 31, 2007
Principal outstanding ($US)	$	200,000		$	200,000
Unrealized foreign exchange		(740	)		30,580
Unamortized financing costs and discounts (premiums), net		(3,302	)		—
Fair value of embedded prepayment and early redemption options		(5,098	)		—

	$	190,860		$	230,580

Effective April 1, 2007, the Company adopted CICA Handbook Section 3855. The standards have been applied retroactively without restatement and, accordingly, comparative amounts for prior periods have not been restated.

8.	Deferred lease inducements

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

During the six months ended September 30, 2007, the Company received inducements from a lessor in the form of leasehold improvements to an office facility. Included in accrued liabilities at September 30, 2007 is $524 payable to the lessor as part of this lease agreement.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

9.	Shares

Common shares

Authorized:

Unlimited number of common voting shares

Unlimited number of common non-voting shares

Issued:


	Number of Shares		Amount
*Common voting shares*
Outstanding at March 31, 2007	35,192,260		$	294,136
Issued on exercise of options	147,400			740
Transferred from contributed surplus on exercise of options	—			278
Conversion of common non-voting shares	412,400			2,062

Outstanding at September 30, 2007	35,752,060		$	297,216


*Common non-voting shares*
Outstanding at March 31, 2007	412,400		$	2,062
Conversion to common voting shares	(412,400	)		(2,062	)

Outstanding at September 30, 2007	—		$	—

*Total common shares*	35,752,060		$	297,216

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

Contributed surplus


Balance, March 31, 2007	$	3,606
Stock-based compensation (note 14)		747
Transferred to common shares on exercise of options		(278	)

Balance, September 30, 2007	$	4,075

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

Net income (loss) per share


	Three months ended September 30					Six months ended September 30
	2007		2006			2007			2006
Basic net income (loss) per share
Net income (loss) available to common shareholders	$	2,068	$	(4,757	)	$	(8,255	)	$	13,137
Weighted average number of common shares		35,752,060		18,638,405			35,711,861			18,629,253

Basic net income (loss) per share	$	0.06	$	(0.26	)	$	(0.23	)	$	0.71


Diluted net income (loss) per share
Net income (loss) available to common shareholders	$	2,068	$	(4,757	)	$	(8,255	)	$	13,137
Dilutive effect of NAEPI Series B preferred shares		—		—			—			1,274

Net income (loss), assuming dilution		2,068		(4,757	)		(8,255	)		14,411

Weighted average number of common shares		35,752,060		18,638,405			35,711,861			18,629,253
Dilutive effect of:
NAEPI Series B preferred shares		—		—			—			7,524,400
Stock options		1,116,755		—			—			834,003

Weighted average number of diluted common shares		36,868,815		18,638,405			35,711,861			26,987,656

Diluted net income (loss) per share	$	0.06	$	(0.26	)	$	(0.23	)	$	0.53

For the three months ended September 30, 2006 and the six months ended September 30, 2007, the effect of outstanding stock options and convertible securities on loss per share was anti-dilutive. As such, the effect of outstanding stock options and convertible securities used to calculate the diluted net loss per share has not been disclosed for these periods.

For the three months ended September 30, 2007 and the six months ended September 30, 2006, the effect of outstanding stock options and convertible securities on net income per share was dilutive. Accordingly, the effect of outstanding stock options used to calculate the diluted net income per share has been disclosed for these periods.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

10.

Interest expense


	Three months ended September 30				Six months ended September 30
	2007		2006		2007		2006
Interest on senior notes	$	5,834	$	7,434	$	11,669	$	14,780
Interest on capital lease obligations		152		163		333		317
Interest on NACG Preferred Corp. Series A preferred shares		—		700		—		1,400
Accretion and change in redemption value of NAEPI Series B preferred shares		—		949		—		1,877
Accretion of NAEPI Series A preferred shares		—		17		—		33

Interest on long-term debt		5,986		9,263		12,002		18,407
Amortization of bond issue costs		110		—		507		—
Amortization of deferred financing costs		—		948		—		1,835
Interest on revolving credit facility and other interest		100		115		425		252

	$	6,196	$	10,326	$	12,934	$	20,494

11.

Derivative financial instruments

Realized and unrealized loss on derivative financial instruments


	Three months ended September 30					Six months ended September 30
	2007			2006		2007		2006
Realized and unrealized loss on cross-currency and interest rate swaps	$	15,852		$	3,786	$	30,173	$	11,782
Unrealized loss on embedded price escalation clauses in long-term revenue construction contract		5,590			—		11,591		—
Unrealized loss (gain) on embedded prepayment and early redemption options on senior notes		(206	)		—		3,421		—

	$	21,236		$	3,786	$	45,185	$	11,782

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

Fair value of derivative financial instruments


September 30, 2007	Derivative financial instruments			Senior notes
Cross-currency and interest rate swaps	$	89,701		$	—
Embedded price escalation clauses in long-term revenue construction contract		18,837			—
Embedded prepayment and early redemption options on senior notes		—			(5,098	)

Total fair value of derivative financial instruments		108,538			(5,098	)
Less: current portion		(4,458	)		—

	$	104,080		$	(5,098	)


April 1, 2007	Derivative financial instruments			Senior notes
Cross-currency and interest rate swaps	$	60,863		$	—
Embedded price escalation clauses in long-term construction contracts		7,246			—
Embedded prepayment and early redemption options on senior notes		—			(8,519	)

Total fair value of derivative financial instruments		68,109			(8,519	)
Less: current portion		(2,669	)		—

	$	65,440		$	(8,519	)

12.

Other information

Supplemental cash flow information


	Three months ended September 30				Six months ended September 30
	2007		2006		2007		2006
Cash paid during the period for:
Interest	$	252	$	287	$	13,762	$	16,707
Income taxes		—		152		22		342
Cash received during the period for:
Interest		78		412		184		898
Non-cash transactions:
Capital leases		280		1,436		292		3,194
Lease inducements		69		—		1,045		—

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

Net change in non-cash working capital


	Three months ended September 30						Six months ended September 30
	2007			2006			2007			2006
Operating activities:
Accounts receivable	$	(13,686	)	$	4,032		$	(31,028	)	$	(5,035	)
Allowance for doubtful accounts		200			24			200			24
Unbilled revenue		(15,660	)		(1,266	)		10,144			4,109
Inventory		2			—			2			44
Prepaid expenses and deposits		1,061			(13,655	)		4,745			(15,657	)
Other assets		(986	)		(6,924	)		2,848			(9,431	)
Accounts payable		31,244			1,977			21,260			1,599
Accrued liabilities		2,480			9,229			(2,326	)		6,289
Billings in excess of costs and estimated earnings		(3,480	)		1,815			(1,020	)		3,307

	$	1,175		$	(4,768	)	$	4,825		$	(14,751	)

Investing activities:
Accounts payable	$	17,493		$	1,678		$	14,249		$	1,474

	$	17,493		$	1,678		$	14,249		$	1,474

Income taxes

Income tax expense as a percentage of income before income taxes for the three and six months ended September 30, 2007 differs from the statutory rate of 31.72% primarily due to the impact of the enacted rate changes during the period and the impact of new accounting standards for the recognition and measurement of financial instruments as certain embedded derivatives are considered capital in nature for income tax purposes. Income tax as a percentage of income before income taxes for the six months ended September 30, 2006 differed from the statutory rate of 32.12% primarily due to the elimination of the valuation allowance of $5,858 that was recorded during that period offset by permanent differences relating to certain financing transactions which are not deductible for tax purposes and accruals for certain tax exposure items.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

13.

Segmented information

General overview

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

•

Heavy Construction and Mining:

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

•

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.

Results by business segment


Three months ended September 30, 2007	Heavy Construction 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


Three months ended September 30, 2006	Heavy Construction and Mining		Piling		Pipeline		Total
Revenues from external customers	$	100,245	$	26,953	$	2,868	$	130,066
Depreciation of plant and equipment		2,321		737		26		3,084
Segment profits		12,535		9,240		407		22,182
Segment assets		356,406		87,203		42,417		486,026
Expenditures for segment plant and equipment		4,920		2,981		781		8,682

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)


Six months ended September 30, 2007	Heavy Construction 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


Six months ended September 30, 2006	Heavy Construction and Mining		Piling		Pipeline		Total
Revenues from external customers	$	211,632	$	50,230	$	6,304	$	268,166
Depreciation of plant and equipment		7,271		1,384		157		8,812
Segment profits		38,627		15,251		1,066		54,944
Segment assets		356,406		87,203		42,417		486,026
Expenditures for segment plant and equipment		10,420		4,310		781		15,511

Reconciliations

Income (loss) before income taxes


	Three months ended September 30						Six months ended September 30
	2007			2006			2007			2006
Total profit for reportable segments	$	34,544		$	22,182		$	62,093		$	54,944
Unallocated corporate expenses		(31,728	)		(24,448	)		(60,561	)		(37,981	)
Over allocated (unallocated) equipment costs		1,224			(2,308	)		(11,420	)		(2,539	)

Income (loss) before income taxes	$	4,040		$	(4,574	)	$	(9,888	)	$	14,424

ii.

Total assets


	September 30, 2007		March 31, 2007
Total assets for reportable segments	$	662,781	$	621,636
Corporate assets		78,157		89,100

Total assets	$	740,938	$	710,736

The Company’s goodwill was assigned to the Heavy Construction and Mining, Piling and Pipeline segments in the amounts of $125,447, $41,856 and $32,753, respectively.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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

Customers

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


	Three months ended September 30				Six months ended September 30
	2007		2006		2007		2006
Customer A	29	%	9	%	30	%	14	%
Customer B	15	%	18	%	13	%	20	%
Customer C	13	%	12	%	12	%	13	%
Customer D	13	%	6	%	13	%	6	%
Customer E	6	%	10	%	5	%	—
Customer F	—		10	%	—		10	%

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

14.

Stock-based compensation plan

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


	Three months ended September 30
	2007					2006
	Number of options		Weighted average exercise price ($ per share)			Number of options		Weighted average exercise price ($ per share)
Outstanding, beginning of period	1,999,440		$	6.10		2,070,840		$	5.00
Granted	—			—		187,760			16.75
Exercised	—			—		(27,760	)		(5.00	)
Forfeited	(72,000	)		(5.00	)	—			—

Outstanding, end of period	1,927,440		$	6.14		2,230,840		$	5.99

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)


	Six months ended September 30
	2007					2006
	Number of options		Weighted average exercise price ($ per share)			Number of options		Weighted average exercise price ($ per share)
Outstanding, beginning of period	2,146,840		$	6.03		2,066,360		$	5.00
Granted	—			—		315,520			11.99
Exercised	(147,400	)		(5.00	)	(27,760	)		(5.00	)
Forfeited	(72,000	)		(5.00	)	(123,280	)		(5.00	)

Outstanding, end of period	1,927,440		$	6.14		2,230,840		$	5.99

At September 30, 2007, the weighted average remaining contractual life of outstanding options is 7.3 years (March 31, 2007 – 7.7 years). The Company recorded $388 and $747 of compensation expense related to the stock options in the three and six months ended September 30, 2007, respectively (three and six months ended September 30, 2006 – $809 and $1,121 respectively), with such amount being credited to contributed surplus.

15.

Seasonality

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

16.

Guarantee

At September 30, 2007, in connection with a heavy equipment financing agreement, the Company has guaranteed a $3.8 million debt owed to the equipment manufacturer by a third party finance company. The Company’s guarantee of this indebtedness will expire when the equipment is commissioned, which is expected to be December 31, 2007. The Company has determined that the fair value of this financial instrument at inception and September 30, 2007 was minimal.

17.

Comparative figures

Certain of the comparative figures have been reclassified to conform to the current period’s presentation.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

The following discussion and analysis is as of November 14, 2007 and should be read in conjunction with the attached unaudited interim consolidated financial statements for the three and six months ended September 30, 2007 and the audited consolidated financial statements included in our annual report on Form 20-F for the fiscal year ended March 31, 2007, which have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). Additional information relating to our business is available on SEDAR at www.sedar.com and EDGAR at www.sec.gov. Except where otherwise specifically indicated, all dollar amounts are expressed in Canadian dollars.

This document contains forward-looking statements. Our forward-looking statements are subject to known and unknown risks and other factors that may cause future actions, conditions or events to differ materially from the anticipated actions, conditions or events expressed or implied by such forward-looking statements. Forward-looking statements are those that do not relate strictly to historical or current facts, and can be identified by the use of the future tense or other forward-looking words such as “believe”, “expect”, “anticipate”, “intend”, “plan”, “estimate”, “should”, “may”, “objective”, “projection”, “forecast”, “continue”, “strategy”, “position” or the negative of those terms or other variations of them or comparable terminology. Forward-looking statements included in this document include statements regarding: financial resources; capital spending; the outlook for our business; and our results generally. Factors that could cause actual results to vary from those in the forward-looking statements include but are not limited to those risk factors set forth in our annual report on Form 20-F for the fiscal year ended March 31, 2007 and changes in internal controls noted herein. You are cautioned not to put undue reliance on any forward-looking statements and we undertake no obligation to update such statements.

November 14, 2007

Prior Year Comparisons

On November 28, 2006 we completed an initial public offering (“IPO”) of common shares in Canada and the U.S. We became publicly traded on the Toronto Stock Exchange and New York Stock Exchange under the symbol “NOA”. Prior to the consummation of the IPO, the predecessor company was amalgamated with its parent companies and we undertook certain transactions that resulted in changes to our capital structure. Upon completion of the IPO, we used the proceeds to undertake additional transactions which further changed our capital structure. As a result, comparisons of current periods to prior periods are impacted by the amalgamation and capital restructuring transactions. For a description of the amalgamation and IPO transactions see note 2 in our annual report on Form 20-F for the fiscal year ended March 31, 2007.

Consolidated Financial Highlights


	Three Months Ended Sept 30,
	2007		% of Revenue		2006			% of Revenue
(in thousands)
Revenue	$	223,575	100.0	%	$	130,066		100.0	%
Gross profit		35,210	15.7	%		20,194		15.5	%
Operating income		17,092	7.6	%		9,655		7.4	%
Net income (loss)		2,068	0.9	%		(4,757	)	-3.7	%
Per unit/share information
Net Income (loss)-basic	$	0.06			$	(0.26	)
Net Income (loss)-diluted		0.06				(0.26	)

As we anticipated, our second quarter (three months ended September 30, 2007) financial results improved significantly, driven by very strong top-line growth and enhanced operating performance. Consolidated revenue for the second quarter grew to $223.6 million, increasing 71.9% over the same period last year. Consolidated gross profit rose to $35.2 million year-over-year, reflecting increased sales and higher profit margins. Gross profit margin expanded slightly to 15.7% from 15.5%, primarily reflecting stronger project margins in the Heavy Construction and Mining segment. Second quarter net income also improved, climbing to $2.1 million from a net loss of $4.8 million last year.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

Overview and Outlook

We provide construction and mining services primarily to major oil and natural gas and other natural resource companies operating in Canada. We offer these services through our three operating segments: Heavy Construction and Mining, Piling and Pipeline. Demand for all of our services grew in the second quarter as we benefited from the continuing development of the Alberta oil sands and our expanding relationships with oil sands producers, Western Canada’s strong economy and the launch of a major pipeline contract.

Of our three divisions, Heavy Construction and Mining is our largest, accounting for 67.0% and 60.9% of consolidated revenues and segment profits, respectively, for the second quarter. This division performed particularly well in the second quarter as we supported the initial development, expansion and operation of a number of oil sands mining projects. We also continued to benefit from the project at the Victor diamond mine being constructed for De Beers Canada (De Beers) in northern Ontario, which includes provision of winter road construction and maintenance and overburden removal services.

Our Piling division, accounting for 19.0% and 32.1% of consolidated revenues and segment profits, respectively, for the second quarter, also achieved strong growth with gains driven both by oil sands development and by Western Canada’s strong economy, which has supported a high level of commercial and industrial construction activity. In addition, the Piling division has realized benefits from the introduction of Continuous Flight Auger (“CFA”) technology into Canada, the acquisition of Midwest Foundation Technologies Inc. (“Midwest Micropile”) in September, 2006 and the opening of a new branch office in Saskatoon in May, 2007.

Our Pipeline division, accounting for 14.0% and 7.0% of consolidated revenues and segment profits, respectively, for the second quarter, achieved significantly improved performance compared to the second quarter of last year and the previous two quarters. The improvement reflects the initiation of a $185 million pipeline contract with Kinder Morgan Canada (“Kinder Morgan”) for construction of its TMX Anchor Loop project offset by the completion of a fixed-price project that was challenged by poor weather, difficult ground conditions and changing work scope and led to losses. We are working with our client, who has agreed in principle that a contract change is warranted, to resolve cost overruns related to the changed working conditions. In addition, we have now changed our Pipeline contract strategy to move away from fixed-price contracts. Going forward, our Pipeline segment will focus primarily on cost-reimbursable contracts and we will only undertake fixed-price contracts on those occasions when we perceive the risk to be very low. The Kinder Morgan project is not a fixed-price contract.

Going forward, we expect our operating performance will improve as a result of the strong market demand for our services and a number of internal initiatives undertaken and/or completed during 2006 and 2007. These initiatives include the restructuring of our management team, the strengthening of our financial and operating controls, the implementation of a major business improvement project aimed at increasing productivity and equipment utilization and the change in contract strategy for our Pipeline segment.

On October 25, 2007, the Alberta government announced increases to the Alberta royalty rates affecting natural gas, conventional oil and oil sands producers. The announced increases were significant but lower than increases recommended to the government by the Royalty Review Panel. While some of our customers have announced their intentions to reduce oil and gas investment in Alberta as a result of the increased royalties, to date, the areas affected by these investment reductions does not include oil sands mining projects. Given the long-term nature and capital investment requirement to develop an oil sands mining operation, we anticipate the risk that the royalty changes will cause our customers to cancel, delay or reduce the scope of any significant mining developments presently underway is limited. We are continuing to experience increasing requests for services under existing contracts with our major oil sands customers, in spite of the recent royalty changes. Our recent acquisitions of new equipment ideally suited to heavy earth moving in the oil sands area, together with the addition of a significant number of new employees, has strengthened our ability to bid competitively and profitably into this expanding market and we have secured contract wins on many of these new projects.

In our Heavy Construction and Mining operating segment, our strategy is to retain our position as the leading mining and construction contractor in the Alberta oil sands in order to benefit from the increasing heavy construction and mining service requirements in the region. We continue to evaluate opportunities to expand our presence outside of the oil sands through bidding on other Canadian resource opportunities. Our significant involvement with De Beers Canada at its Victor diamond mine in northern Ontario is the first of such projects resulting from this expansion strategy.

The development of the oil sands continues to contribute to a strong Alberta economy. The commercial and industrial construction

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

industry is benefiting from Alberta’s strong economic conditions, generating new opportunities for our piling services in addition to the growth in the oil sands. We anticipate that our Piling business will continue to enjoy strong demand for the balance of the year as a result of the oil sands development and continued strong construction activity in major western Canadian centers.

The current and planned production from the oil sands has resulted in a need for additional pipeline capacity in Western Canada. This has created a number of opportunities to provide construction services to the companies building new pipelines and expanding existing pipelines. Our contract with Kinder Morgan is for the first of three pipeline expansion phases in their Trans Mountain Expansion (TMX) project. Phase one, the Anchor Loop project, establishes us in the large-inch pipeline construction market and improves our competitive position within the rapidly expanding market of large pipeline construction projects.

Consolidated Operations


	Three Months Ended Sept 30,									Six Months Ended Sept 30,
	2007		% of Revenue		2006			% of Revenue		2007			% of Revenue		2006		% of Revenue
(in thousands except per share amounts)
Revenue	$	223,575	100.0	%	$	130,066		100.0	%	$	391,202		100.0	%	$	268,166	100.0	%
Gross profit		35,210	15.7	%		20,194		15.5	%		50,114		12.8	%		52,838	19.7	%
General & administrative costs		17,360	7.8	%		10,012		7.7	%		31,987		8.2	%		19,247	7.2	%
Operating income		17,092	7.6	%		9,655		7.4	%		16,643		4.3	%		32,768	12.2	%
Net income (loss)		2,068	0.9	%		(4,757	)	-3.7	%		(8,255	)	-2.1	%		13,137	4.9	%
Per unit/share information
Net Income (loss)-basic	$	0.06			$	(0.26	)			$	(0.23	)			$	0.71
Net Income (loss)-diluted		0.06				(0.26	)				(0.23	)				0.53
EBITDA(1)	$	17,736	7.9	%	$	10,756		8.3	%	$	19,663		5.0	%	$	47,417	17.7	%
Consolidated EBITDA(1)		27,920	12.5	%		15,774		12.1	%		37,590		9.6	%		47,285	17.6	%

(1)

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

•

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

•

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

•

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

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

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

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


	Three Months Ended Sept 30,						Six Months Ended Sept 30,
	2007			2006			2007			2006
Net income (loss)	$	2,068		$	(4,757	)	$	(8,255	)	$	13,137
Adjustments:
Interest expense		6,196			10,326			12,934			20,494
Income taxes		1,972			183			(1,633	)		1,287
Depreciation		7,318			4,822			16,294			12,134
Amortization of intangible assets		182			182			323			365

EBITDA	$	17,736		$	10,756		$	19,663		$	47,417

EBITDA	$	17,736		$	10,756		$	19,663		$	47,417
Adjustments:
Unrealized foreign exchange (gain ) loss on senior notes		(13,864	)		78			(31,014	)		(13,493	)
Realized and unrealized loss on derivative financial instruments		21,236			3,786			45,185			11,782
Loss on disposal of equipment and asset held for sale		576			345			1,161			458
Stock-based compensation		388			809			747			1,121
Write down of other assets to replacement cost		1,848			—			1,848			—

Consolidated EBITDA	$	27,920		$	15,774		$	37,590		$	47,285

Second quarter revenue increased to $223.6 million, a 71.9% increase over the same period last year. While improvements were achieved in all operating segments, most of the $93.5 million increase was driven by higher Heavy Construction and Mining activity levels in the oil sands as well as by initiation of a major contract in our Pipeline division. Revenue for the first half (six months ended September 30, 2007) increased 45.9% to $391.2 million compared to the same period last year. This strong year-over-year increase reflects growth in all segments, with Heavy Construction and Mining accounting for the largest share of the $123.0 million increase.

Second quarter gross profit increased to $35.2 million, up 74.4% from last year. As a percentage of revenue, gross profit increased to 15.7% from 15.5% due to higher project margins in Heavy Construction and Mining and proportionately lower equipment costs. Gross profit margin for the first half decreased to 12.8% of revenue from 19.7% last year reflecting higher equipment costs, a first quarter loss on disposal of surplus equipment recorded as depreciation and a first half loss on a fixed-price pipeline contract. Equipment costs reflect higher parts costs, primarily for large haul truck tires due to the worldwide imbalance in supply and demand, a situation that we believe will continue through calendar year 2010. In addition, the prior year’s first half gross profit margin was higher than normal due to the settlement of a $6.1 million claim.

Second quarter operating income increased to $17.1 million, up 77.0% from the prior year as higher general and administrative costs partially offset gross profit improvements. General and administrative costs increased $7.3 million to $17.4 million in the second quarter but remained at 7.8% of revenue, the same as the prior-year period. First half operating income decreased 49.2% to $16.6 million primarily due to lower gross profit as discussed above and higher general and administrative costs. Higher general and administrative costs are a result of increased employee costs, compensation related to our growing employee base and the implementation of information systems upgrades and reporting and controls enhancements. General and administrative costs for the first half also include discretionary bonuses for past service and professional fees relating to our secondary offering, both recognized in the first quarter.

Second quarter net income improved to $2.1 million, compared to a net loss of $4.8 million, in the same period in the prior year. For the first half, a net loss of $8.3 million was incurred compared to net income of $13.1 million last year. This reflects the impact to operating income discussed above and the adoption of the new Canadian accounting standards in the first quarter, that require us to account for changes in the fair value of embedded derivative financial instruments in various contracts and to modify the method of amortizing deferred financing costs. These changes resulted in an incremental non-cash charge to net income of approximately $15 million in the first half.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

Segment Operations

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


	Three Months Ended Sept 30,								Six Months Ended Sept 30,
	2007		% of Total		2006		% of Total		2007		% of Total		2006		% of Total
(dollars in thousands)
Revenue by operating segment:
Heavy Construction and Mining	$	149,825	67.0	%	$	100,245	77.1	%	$	276,738	70.8	%	$	211,632	78.9	%
Piling		42,425	19.0	%		26,953	20.7	%		77,947	19.9	%		50,230	18.7	%
Pipeline		31,325	14.0	%		2,868	2.2	%		36,517	9.3	%		6,304	2.4	%

Total	$	223,575	100.0	%	$	130,066	100.0	%	$	391,202	100.0	%	$	268,166	100.0	%

Segment profit:
Heavy Construction and Mining	$	21,044	60.9	%	$	12,535	56.5	%	$	40,534	65.3	%	$	38,627	70.3	%
Piling		11,092	32.1	%		9,240	41.7	%		20,339	32.8	%		15,251	27.8	%
Pipeline		2,408	7.0	%		407	1.8	%		1,220	1.9	%		1,066	1.9	%

Total	$	34,544	100.0	%	$	22,182	100.0	%	$	62,093	100.0	%	$	54,944	100.0	%

Equipment hours by operating segment:
Heavy Construction and Mining		269,077	83.0	%		222,997	94.2	%		518,503	86.1	%		454,142	94.5	%
Piling		18,375	5.7	%		11,085	4.7	%		38,069	6.3	%		21,200	4.4	%
Pipeline		36,519	11.3	%		2,629	1.1	%		45,638	7.6	%		5,374	1.1	%

Total		323,971	100.0	%		236,711	100.0	%		602,210	100.0	%		480,716	100.0	%

Heavy Construction and Mining

Heavy Construction and Mining second quarter revenue improved to $149.8 million, a 49.5% increase compared to the same period last year. The growth in revenue was primarily due to the execution of work at Suncor Energy Inc.’s (Suncor) Millennium Naphtha Unit project under our five-year site services agreement and the construction of an aerodrome for Albian Sands Energy Inc. (Albian), along with increased demand under our master service agreements with Albian and Syncrude Canada Ltd. (Syncrude). Revenue for the first half was $276.7 million, up 30.8%, reflecting increased demand from all of our major oil sands customers and the production ramp up under our 10-year mining contract with Canadian Natural Resources Ltd. (Canadian Natural).

Second quarter segment profit increased to $21.0 million, up 67.9% from the prior year. Improved execution and a more profitable mix of contracts resulted in segment profit margin improving to 14.0% in the current year from 12.5% in the prior year. Segment profit for the first half was $40.5 million, a 4.9% improvement, however, profit margin decreased to 14.6% from 18.3% reflecting the benefit of a $6.1 million claim settlement in the prior year.

In order to respond to our customers’ needs and to broaden our overall service offering, the Heavy Construction and Mining division has recently entered into a number of construction contracts where, in addition to providing our traditional services, we will also act as the general contractor. In this expanded role we will supervise a variety of subcontractors, procure supplies and materials for projects, and coordinate with other contractors. These services, although additive to revenues and earnings, are performed at lower margins than heavy equipment work but require only limited capital expenditures.

Piling

Piling revenue in the second quarter increased to $42.4 million, a 57.4% growth over last year, reflecting strong business activity in Calgary and our work for Shell Canada Ltd.’s (Shell) Scotford upgrader expansion in the Edmonton region. First half Piling revenue was $77.9 million, a 55.2% increase over the same period in the prior year, mainly attributable to the same factors that contributed to the second quarter growth.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

Second quarter segment profit rose to $11.1 million, 20.0% above the same period last year, reflecting higher volumes. This profit increase brought first half Piling profit to $20.3 million, a 33.4% improvement year-over-year. Segment profit margin declined to 26.1% in both the second quarter and first half from 34.3% in the second quarter and 30.4% in the first half of last year. This profit margin decrease is due to a higher proportion of flow-through costs in the current year’s projects, particularly materials for driven steel piling. In addition, there has been a shift by some of our customers away from the use of higher margin fixed-price contracts to cost reimbursable contracts.

Pipeline

Pipeline revenue reached $31.3 million in the second quarter, compared to $2.9 million last year, as we initiated work on Kinder Morgan’s TMX Anchor Loop project and completed the final phase of an outstanding fixed-price contract. The significant improvement in second quarter revenue boosted first half revenue to $36.5 million, over five times the $6.3 million of revenue earned in the first half of the prior year.

Second quarter profit was $2.4 million reflecting a profit margin of 7.7%, compared to profit of $0.4 million and profit margin of 14.2% during the same period last year. In the first half, the Pipeline segment reported profit of $1.2 million and a margin of 3.3%, compared to profit of $1.1 million and margin of 16.9% in the first half last year. The second quarter change in margin reflects previously unidentified costs of approximately $2 million that were required to complete the division’s remaining fixed-price contract. The loss resulted from the customer enforcing a contractual right to have us commence work prior to renegotiating changes to contract pricing flowing from project scope changes. The contract was completed in the second quarter and we are working with our client to resolve these and prior year impacts related to changed scope and working conditions.

Non-operating expenses (income)


	Three Months Ended Sept 30,						Six Months Ended Sept 30,
	2007			2006			2007			2006
(in thousands)
Interest expense
Interest on senior debt	$	5,834		$	7,434		$	11,669		$	14,780
Accretion mandatorily redeemable preferred shares		—			1,666			—			3,310
Interest on capital lease obligations		152			163			333			317
Amortization of deferred bond issue costs		110			—			507			—
Amortization of deferred financing costs		—			948			—			1,835
Interest on revolving credit facility and other interest		100			115			425			252

Total Interest expense	$	6,196		$	10,326		$	12,934		$	20,494

Foreign exchange loss (gain)	$	(14,252	)	$	72		$	(31,352	)	$	(13,394	)
Realized and unrealized loss on derivative financial instruments		21,236			3,786			45,185			11,782
Other income		(128	)		(8	)		(236	)		(591	)
Income tax (recovery) expense		1,972			183			(1,633	)		1,287

Total interest expense decreased by $4.1 million in the second quarter and by $7.6 million in the first half compared to the same periods last year primarily due to the retirement of the senior secured 9% notes with proceeds from our IPO and the exchange of the Series B preferred shares for common shares as part of the amalgamation that occurred prior to the IPO.

Substantially all of the foreign exchange gains recognized in the current and prior-year periods relate to the strengthening of the Canadian versus the U.S. dollar on conversion of the US$200.0 million of 8³/4% senior notes.

We recorded a realized and unrealized loss on derivative financial instruments of $21.2 million in the second quarter and $45.2 million in the first half compared to $3.8 million and $11.8 million, respectively, in the comparable periods last year. We employ derivative financial instruments to provide an economic hedge for our 8³/4% senior notes. The gain or loss primarily reflects changes in the fair value of these derivatives. See “Liquidity and Capital Resources – Liquidity Requirements” for further information regarding these derivative financial instruments. The change in the fair value of the derivative instrument associated with the economic hedge resulted in a $15.9 million loss during the second quarter and a $30.2 million loss in the first half with the balance of the change

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

resulting from the adoption of a new Canadian accounting standard regarding financial instruments, as discussed below.

Effective April 1, 2007, we adopted the new Canadian CICA Handbook Section 3855 “Financial Instruments – Recognition and Measurements” which resulted in the recognition of derivatives embedded in our senior 8³/4% notes and a long-term construction contract as follows:

•

Our 8³/4% senior notes include certain embedded derivatives, notably optional redemption and change of control redemption rights. These embedded derivatives met the criteria for separation from the debt contract and separate measurement at fair value. Upon adoption of Section 3855, we recorded a reduction in the carrying amount of our 8³/4% senior notes of $8.5 million together with related impacts on retained earnings and future income taxes on April 1, 2007. The change in the fair value of these embedded derivatives resulted in a benefit to earnings of $0.2 million in the second quarter and a $3.4 million charge to earnings in the first half.

•

A long-term construction contract contains a price escalation feature that represents an embedded foreign currency and price index derivative that meets the criteria for separation from the host contract and separate measurement at fair value. Upon adoption of Section 3855, we recorded a liability of $7.2 million together with related impacts on retained earnings and future income taxes on April 1, 2007. The change in the fair value of the liability resulted in a charge to earnings of $5.6 million in the second quarter and $11.6 million in the first half.

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 that 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 customer contract, there is a provision that requires an adjustment to billings to our customer to reflect actual exchange rate and price index changes versus 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.

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

We recorded an income tax expense of $2.0 million in the second quarter and an income tax recovery of $1.6 million in the first half, as compared to an income tax expense of $0.2 million and $1.3 million for the corresponding periods last year. Income tax expense as a percentage of income before tax for the first half differs from the statutory rate of 31.72% primarily due to the impact of the enacted rate changes during the year and the new accounting standards for the recognition, measurement and disclosure of financial instruments as certain embedded derivatives are considered capital in nature for income tax purposes. Income tax expense as a percentage of income before tax for the first half last year differs from the statutory rate of 32.12% primarily due to the elimination of the valuation allowance of $5.9 million that was recorded during that period offset by permanent differences relating to certain financing transactions which are not deductible for tax purposes and accruals for certain tax exposure items.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

Comparative Quarterly Results


	Fiscal Year 2008					Fiscal Year 2007									Fiscal Year 2006
	Q2		Q1			Q4		Q3		Q2			Q1		Q4		Q3
(dollars in millions, except per share amounts)
Revenue	$	223.6	$	167.6		$	205.3	$	155.9	$	130.1		$	138.1	$	142.3	$	121.5
Gross profit		35.2		14.9			13.6		26.0		20.2			32.6		31.7		13.8
Operating income		17.1		(0.4	)		4.5		13.8		9.7			23.1		22.4		5.9
Net income (loss)		2.1		(10.3	)		1.4		6.6		(4.8	)		17.9		13.7		2.1
EPS—Basic ⁽¹⁾	$	0.06	$	(0.29	)	$	0.04	$	0.27	$	(0.26	)	$	0.96	$	0.73	$	0.11
EPS—Diluted ⁽¹⁾		0.06		(0.29	)		0.04		0.26		(0.26	)		0.71		0.73		0.11
Equipment hours		323,971		278,239			268,565		239,341		236,711			248,297		231,633		221,355

(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.

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

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

Consolidated Financial Position


(in thousands)	September 30, 2007			March 31, 2007			% Change
Current assets	$	231,502		$	229,061		1.1	%
Current liabilities		(179,859	)		(151,458	)	18.8	%
Net working capital		51,643			77,603		-33.5	%
Plant and equipment		280,490			255,963		9.6	%
Total assets		740,938			710,736		4.2	%
Capital Lease obligations (including current portion)		8,393			9,709		-13.6	%
Total long-term financial liabilities ⁽¹⁾		(300,109	)		(295,288	)	1.6	%

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

At September 30, 2007, we had net working capital (current assets less current liabilities) of $51.6 million compared to $77.6 million at March 31, 2007. The $26.0 million decrease in net working capital resulted largely from higher-than-normal accounts payable balances due to continuing weaknesses in our procurement processes and controls and our inability to process and pay supplier invoices in a timely manner (see also Risk Factors section).

Plant and equipment, net of depreciation, increased by $24.5 million in the first half primarily due to the purchase of additional haul trucks and piling rigs in the second quarter, partially offset by the disposal of surplus equipment and other assets in the first quarter.

Capital lease obligations, including the current portion, decreased by $1.3 million between these same periods due to repayments.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

Liquidity and Capital Resources


	Three Months Ended Sept 30,						Six Months Ended Sept 30,
	2007			2006			2007			2006
(in thousands)
Cash provided by operating activities	$	22,290		$	4,538		$	28,580		$	17,285
Cash used in investing activities		(15,633	)		(9,692	)		(19,009	)		(18,759	)
Cash provided by financing activities		(20,806	)		(3,112	)		(22,135	)		(4,503	)

Net increase (decrease) in cash and cash equivalents	$	(14,149	)	$	(8,266	)	$	(12,564	)	$	(5,977	)

Operating activities

Cash provided by operating activities was $22.3 million in the second quarter and $28.6 million in the first half, compared to $4.5 million and $17.3 million, respectively, in the comparable periods last year. The higher cash generated in the current year periods reflect a net decrease in non-cash working capital of $1.2 million and a net decrease of $4.8 million in the second quarter and first half, respectively, due to higher second quarter accounts payable balances in the current year, as discussed above. This compares to net increases in non-cash working capital of $4.8 million and $14.8 million in the same respective periods last year.

Investing activities

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

Total capital expenditures in the second quarter were $33.4 million, including $12.1 million in sustaining and $21.3 million in growth, compared to total capital expenditures of $10.0 million last year, including $0.8 million in sustaining and $9.2 million in growth. This brings total capital expenditures for the first half to $43.6 million, including $16.1 million in sustaining and $27.4 million in growth, compared to $19.3 million last year, including $1.4 million in sustaining and $17.9 million in growth. Offsetting capital expenditures in the first half of the current year were a net decrease in non-cash working capital of $17.5 million in the second quarter and $14.2 million in the first half related to the higher accounts payable balances discussed above and proceeds of $14.1 million from the disposal of lower utilization equipment and other assets, the majority of which was disposed of in the first quarter.

Financing activities

Financing activities in the second quarter resulted in a cash outflow of $20.8 million, reflecting the repayment of borrowings under our revolving credit facility.

Liquidity Requirements

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

Our long-term debt includes US$200 million of 8³/4% senior notes due in 2011. The foreign currency risk relating to both the principal and interest portions of these senior notes has been managed with a cross-currency swap and interest rate swaps, which went into effect concurrent with the issuance of the notes on November 26, 2003. The swap agreement is an economic hedge but has not been designated as a hedge 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 $200 million US principle amount was hedged at C$1.315=US$1.000, resulting in a principle 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, 2007, we had $25 million in letters of credit outstanding in connection with this contract. This customer has recently reduced this requirement by $5 million and we now have $20 million in letters of credit outstanding in connection with this contract, effective November 8, 2007. Any change in the amount of the letters of credit required by this customer must be requested by November 1^st for an issue date of January 1^st, each year for the remaining life of the contract.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

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 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.

Our cash requirements during the first half increased due to continued growth and additional operating and capital expenditures associated with new projects.

We expect our sustaining capital expenditures to range from $35.0 million to $45.0 million per year over the next two years. We expect our total capital expenditures for the current year to range from $75.0 million to $85.0 million. It is our belief that working capital and our operating lease facilities will be sufficient to meet these requirements.

Sources of Liquidity

Our principal sources of cash are funds from operations and borrowings under our revolving credit facility. Our revolving credit facility provides for borrowings up to $125.0 million under revolving loans and letters of credit. As of September 30, 2007, we had approximately $100 million of available borrowings under the revolving credit facility after taking into account the $25 million of outstanding and undrawn letters of credit to support performance guarantees associated with a single customer contract as discussed above. The indebtedness under the revolving credit facility is secured by a first priority lien on substantially all of our existing and after-acquired property.

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

Consolidated EBITDA is defined in the credit facility as the sum, without duplication, of (1) consolidated net income, (2) consolidated interest expense, (3) provision for taxes based on income, (4) total depreciation expense, (5) total amortization expense, (6) costs and expenses incurred by us in entering into the credit facility, (7) accrual of stock-based compensation expense to the extent not paid in cash or if satisfied by the issue of new equity, (8) the non-cash currency translation losses or mark-to-market losses on any hedge agreement or any embedded derivative and (9) 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)-(9), to the extent deducted in the calculation of consolidated net income, less other non-cash currency translation gains or mark-to-market gains on any hedge agreement or any embedded derivative to the extent added in the calculation of consolidated net income items added in the calculation of consolidated net income (other than any such non-cash item to the extent it will result in the receipt of cash payments in any future period), all of the foregoing as determined on a consolidated basis for us in conformity with Canadian GAAP.

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

Backlog

Backlog is a measure of the amount of secured work we have outstanding and as such is an indicator of future revenue potential. Backlog is not a GAAP measure. 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.

We work with our customers using cost-plus, time-and-materials, unit-price and lump-sum contracts, and the mix of contract types varies year-by-year. For the first half, our revenue consisted of 42.5 % time-and-materials, 47.4% unit-price and 10.1% lump-sum. Our definition of backlog results in the exclusion of cost-plus and time-and-material contracts performed under master service agreements where scope is not clearly defined. While contracts exist for a range of services to be provided, the work scope and value are not clearly defined under those contracts. For the first half, the total amount of all cost-plus and time-and-material based revenue was $166.4 million.

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


By Segment	September 30,				By Contract Type	September 30,
	2007		2006			2007		2006
Heavy Construction & Mining	$	646.4	$	745.6	Unit-Price	$	661.7	$	771.7
Piling		24.7		8.3	Lump-Sum		9.4		2.3
Pipeline		163.3		20.1	Time-and-Material		163.3		—

Total	$	834.4	$	774.0	Total	$	834.4	$	774.0

A contract with a single customer represented approximately $611.7 of the September 30, 2007 backlog. It is expected that approximately $319.2 of the backlog will be performed and realized in the 12 months ending September 30, 2008.

Claims and Unapproved Change Orders

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

•

Client requirements, specifications and design;

•

Materials and work schedules; 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 management consider changes in cost estimates that have occurred up to the release of the financial statements and reflect the impact of these changes in the financial statements. Conversely, potential revenue associated with increases in cost estimates is not included in financial statements until an agreement is reached with the client or specific criteria for the recognition of revenue from unapproved change orders and claims are met. This can, and often does, lead to costs being recognized in one period and revenue being recognized in subsequent periods.

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

As a result of certain projects experiencing the changed conditions discussed above, at September 30, 2007 we had recognized approximately $20.8 million in additional contract costs from project inception to date, with no associated increase in contract value.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

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.

Contractual Obligations and Other Commitments

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


	Payments due by fiscal year
	Total		2008		2009		2010		2011		2012 and after
(in millions)
Senior notes ⁽¹⁾	$	199.2	$	—	$	—	$	—	$	—	$	199.2
Capital leases (including interest)		9.2		3.7		2.8		1.9		0.6		0.2
Operating leases		50.3		16.4		17.9		12.7		3.2		0.1
Supplier contracts ⁽²⁾		36.7		5.3		5.3		7.5		9.6		9.6

Total contractual obligations	$	295.4	$	25.4	$	26.0	$	22.1	$	13.4	$	209.1

(1)

As at September 30, 2007, the exchange rate was C$0.996=US$1.000, resulting in a value of C$199.2 million upon conversion of the principle balance of the US$200 million 8³/4% senior notes. 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 of the swap contracts. At September 30, 2007, the carrying value of the derivative financial instruments was $89.7 million, inclusive of the interest components.

(2)	This contract can be terminated by either party with 30 days notice.

Off-Balance Sheet Arrangements

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

Outstanding Share Data

We are authorized to issue an unlimited number of voting common shares and an unlimited number of non-voting common shares. As at September 30, 2007, 35,752,060 voting common shares were outstanding compared to 35,192,260 voting common shares and 412,400 non-voting common shares as at March 31, 2007.

Stock-Based Compensation

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

Impairment of Goodwill

In accordance with Canadian Institute of Chartered Accountants' Handbook Section 3062, “Goodwill and Other Intangible Assets'', we review our goodwill for impairment annually or whenever events or changes in circumstances suggest that the carrying amount may not be recoverable. We are required to test our goodwill for impairment at the reporting unit level and we have determined that we have three reporting units. The test for goodwill impairment is a two-step process:

•

Step 1 – We compare the carrying amount of each reporting unit to its fair value. If the carrying amount of a reporting unit exceeds its fair value, we have to perform the second step of the process. If not, no further work is required.

•

Step 2 – We compare the implied fair value of each reporting unit's goodwill to its carrying amount. If the carrying amount of a reporting unit's goodwill exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

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

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 first half, our revenue consisted of 42.5% time-and-materials, 47.4% unit-price and 10.1% lump-sum.

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

The accuracy of our revenue and profit recognition in a given period is dependent, in part, on the accuracy of our estimates of the cost to complete each unit-price and lump-sum project. Our cost estimates use a detailed "bottom up'' approach. We believe our experience allows us to produce materially reliable estimates. However, our projects can be highly complex, and in almost every case, the profit margin estimates for a project will either increase or decrease to some extent from the amount that was originally estimated at the time of the related bid. Because we have many projects of varying levels of complexity and size in process at any given time, these changes in estimates can offset each other without materially impacting our profitability. However, sizable changes in cost estimates, particularly in larger, more complex projects, can have a significant effect on profitability.

Factors that can contribute to changes in estimates of contract cost and profitability include, without limitation:

•

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

•

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

•

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

•

the availability and proximity of materials;

•

unfavorable weather conditions hindering productivity;

•

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

•

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

The foregoing factors, as well as the stage of completion of contracts in process and the mix of contracts at different margins, may cause fluctuations in gross profit between periods, and these fluctuations may be significant.

Plant and equipment

The most significant estimate in accounting for plant and equipment is the expected useful life of the asset and the expected residual value. Most of our property, plant and equipment have long lives which can exceed 20 years with proper repair work and preventative maintenance. Useful life is measured in operated hours, excluding idle hours, and a depreciation rate is calculated for each type of unit. Depreciation expense is determined monthly based on daily actual operating hours.

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

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

Goodwill

Impairment is tested at the reporting unit level by comparing the reporting unit's carrying amount to its fair value. The process of determining fair 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.

Financial instruments

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

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

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


	Increase (decrease)
Deferred financing costs	$	(11,356	)
Intangible assets		1,622
Long-term future income tax asset		2,588
Senior notes		(12,634	)
Derivative financial instruments		7,246
Long-term income tax liability		18
Opening deficit		1,776

The details of the transitional adjustments are noted below.

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


	Three Months Ended Sept 30, 2007			Six Months Ended Sept 30, 2007
Decrease in interest expense due to change in method of amortizing deferred financing costs and discounts (premiums), net	$	(343	)	$	(679	)
Increase in unrealized foreign exchange gain on senior notes		445			(305	)
Increase in unrealized loss on derivative financial instruments		5,384			15,012

	$	5,486		$	14,028

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

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

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

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

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

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

•

Embedded derivatives:

We determined that the issuer’s early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in the senior notes that provides for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to the par value over the term of the notes using the effective interest method and is recognized as interest expense. At transition on April 1, 2007, we recorded the fair value of $8.5 million related to these embedded derivatives and a corresponding decrease in opening deficit of $7.3 million, net of future income taxes of $1.2 million. The impact of the bifurcation of these embedded derivatives at issuance of the senior notes resulted in an increase in senior notes of $5.7 million and an increase in opening deficit of $4.0 million, net of income taxes of $1.7 million after applying the effective interest method to the premium resulting from the bifurcation of these embedded derivatives on April 1, 2007.

We also have foreign exchange rate and price index escalation/de-escalation clauses in a long-term construction contract that qualify as an embedded derivative. These amounts must be separated for reporting in accordance with the new standards. As at April 1, 2007, we separated the fair value of the embedded derivative liability of $7.2 million from the long-term construction contract, resulting in a corresponding increase to opening deficit of $5.2 million, net of future income taxes of $2.0 million.

•

Effective interest method:

We incurred underwriting commissions and expenses relating to our senior notes offering. Previously, these costs were classified as deferred assets under deferred financing costs and amortized on a straight-line basis over the term of the debt. The new standard requires us to reclassify the costs as a reduction in the cost of debt and to use the effective interest rate method to amortize the deferred amounts to interest expense. As at April 1, 2007, we reclassified $9.7 million of unamortized costs from deferred financing costs to long-term debt and recorded an adjustment to the unamortized cost balance as if the effective interest rate method had been used since inception. Transaction costs incurred in connection with the Company’s revolving credit facility of $1,622 were reclassified from deferred financing costs to intangible assets on April 1, 2007 and these costs continue to be amortized on a straight-line basis over the term of the facility.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

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

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

Risk Factors

For the six month period ended September 30, 2007, there has been no significant change in our risk factors from those described in our Prospectus dated July 31, 2007 and Management’s Discussion and Analysis for the year ended March 31, 2007 other than those noted below. In addition, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to affect, our internal control over financial reporting. As discussed in the Prospectus dated July 31, 2007 and our Management’s Discussion and Analysis for the year ended March 31, 2007, we have identified a number of significant weaknesses (as defined under Canadian auditing standards) in our financial reporting process and internal controls. Due to our continuing material weakness in our procurement processes and controls and IT general controls combined with processing delays caused by our upgrade of our ERP system, we were unable to process and pay supplier invoices in a timely manner during the three months ended September 30, 2007. As a result, accounts payable and accrued liabilities balances increased to higher levels as compared to March 31, 2007. Management is addressing this issue in the near term by allocating additional staff to effectively process supplier invoices and to implement additional controls to ensure all material liabilities have been recorded. Simultaneously, we are continuing to design and implement a new system of sound procurement processes that will efficiently and effectively track purchase commitments, reconcile vendor accounts and accurately accrue costs yet to be invoiced by vendors at each reporting date.

In addition, during the quarter ended June 30, 2007, we were required to implement new Canadian accounting standards regarding financial instruments. In order to record the related transactions, very complex and non-routine accounting and valuation procedures were undertaken. On review, we determined that we did not apply certain of these procedures correctly. This, therefore, represents a weakness in internal control as it had the potential to result in a material misstatement of the financial statements. This weakness will be addressed in the future by engaging third-party experts; however, there can be no assurance that we will be able to generate accurate financial reports in a timely manner. Failure to do so would cause us to breach the reporting requirements of Canadian and U.S. securities regulations in the future as well as the covenants applicable to our indebtedness. This could, in turn, have a material adverse effect on our business and financial condition. Until we establish and maintain effective internal controls and procedures for financial reporting, we may not have appropriate measures in place to eliminate financial statement inaccuracies and avoid delays in financial reporting.

In our Management’s Discussion and Analysis for the three months ended June 30, 2007, we identified a risk for labour disruptions commencing on or about August 23, 2007 as a result of unsettled labour negotiations. On September 10, 2007, the outstanding labour agreements were either ratified or forced into binding arbitration rendering any strike activity illegal under the collective bargaining agreement. In light of these developments, the risk of a labour disruption impacting us in a material way in the near future is not a significant risk.

Recently Adopted Canadian Accounting Pronouncements

Financial instruments

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

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

Equity

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

Accounting changes

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

Accounting policy choice for transaction costs

Recent Canadian accounting pronouncements not yet adopted

Financial Instruments

In March 2007, the CICA issued Handbook Section 3862, “Financial Instruments—Disclosures”, which replaces CICA 3861 and provides expanded disclosure requirements that provide additional detail by financial assets and liability categories. The standard 3863 harmonizes disclosures with International Financial Reporting Standards. The standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for us. We are currently evaluating the impact of this standard.

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

Capital disclosures

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

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

Inventories

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

Going concern

In April 2007, the CICA approved amendments to Handbook 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 new requirements of the standard are applicable for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 us. We are currently evaluating the impact of this standard.

U.S. Generally Accepted Accounting Principles

Our consolidated financial statements have been prepared in accordance with Canadian GAAP, which differs in certain material respects from U.S. GAAP. The nature and effect of these differences are set out in note 27 to our annual consolidated financial statements.

Quantitative and Qualitative Disclosures Regarding Market Risk

Foreign currency risk

We are subject to currency exchange risk as our 8³/4% senior notes are denominated in U.S. dollars and all of our revenues and most of our expenses are denominated in Canadian dollars. To manage the foreign currency risk and potential cash flow impact on our $200 million in U.S. dollar-denominated notes, we have entered into currency swap and interest rate swap agreements. These financial instruments consist of three components: a U.S. dollar interest rate swap; a U.S. dollar-Canadian dollar cross-currency basis swap; and a Canadian dollar interest rate swap. The cross currency and interest rate swap agreements can be cancelled at the counterparty’s option at any time after December 1, 2007 if the counterparty pays a cancellation premium. The premium is equal to 4.375% of the US$200 million if exercised between December 1, 2007 and December 1, 2008; 2.1875% if exercised between December 1, 2008 and December 1, 2009; and repurchased at par if cancelled after December 1, 2009.

Interest rate risk

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

Inflation

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

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2007

Additional Information

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