Form 6-K

6-K 1 d6k.htm FORM 6-K Form 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

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

under

the Securities Exchange Act of 1934

For the month of November 2006

Commission File Number 333-135943

NORTH AMERICAN ENERGY PARTNERS INC.

Zone 3 Acheson Industrial Area

2-53016 Highway 60

Acheson, Alberta

Canada T7X 5A7

(Address of principal executive offices)

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

Included herein:

1.	Interim consolidated financial statements of North American Energy Partners Inc. for the three and six months ended September 30, 2006.

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/ Douglas A. Wilkes
Name:		Douglas A. Wilkes
Title:		Vice President, Finance and Chief Financial Officer

Date: November 29, 2006

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Expressed in thousands of Canadian dollars)

(Unaudited)

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Interim Consolidated Balance Sheets

(in thousands of Canadian dollars)


	September 30, 2006			March 31, 2006
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	36,827		$	42,804
Accounts receivable		72,679			67,235
Unbilled revenue		39,413			43,494
Inventory		13			57
Prepaid expenses and deposits (note 5(a))		17,453			1,796
Other assets (note 5(b))		10,435			1,004
Future income taxes		15,626			5,583

		192,446			161,973
Future income taxes		14,139			23,367
Plant and equipment (note 6)		194,455			184,562
Goodwill		199,067			198,549
Intangible assets, net of accumulated amortization of $17,391 (March 31, 2006 - $17,026)		742			772
Deferred financing costs, net of accumulated amortization of $7,839 (March 31, 2006 - $6,004)		18,974			17,788

	$	619,823		$	587,011

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	57,174		$	54,085
Accrued liabilities		31,111			24,603
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		8,431			5,124
Current portion of capital lease obligations		3,811			3,046
Future income taxes		8,911			5,583

		109,438			92,441
Capital lease obligations		8,851			7,906
Senior notes (note 7(a))		290,514			304,007
Derivative financial instruments		74,049			63,611
Redeemable preferred shares (note 9(a))		79,478			77,568
Future income taxes		24,985			23,367

		587,315			568,900

Shareholders’ equity:
Common shares (authorized – unlimited number of voting and non-voting common shares; issued and outstanding – 18,235,360 voting common shares and 412,400 non-voting common shares) (note 9(b))		93,291			93,100
Contributed surplus (note 9(c))		2,626			1,557
Deficit		(63,409	)		(76,546	)

		32,508			18,111

United States generally accepted accounting principles (note 16)
Subsequent events (note 17)

	$	619,823		$	587,011

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Interim Consolidated Statements of Operations and Deficit

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

(unaudited)


	Three months ended September 30						Six months ended September 30
	2006			2005			2006			2005
Revenue	$	130,066		$	124,004		$	268,166		$	228,363
Project costs		73,083			79,212			140,092			145,758
Equipment costs		25,598			14,297			49,533			31,311
Equipment operating lease expense		6,369			3,086			13,569			5,984
Depreciation		4,822			5,493			12,134			10,482

Gross profit		20,194			21,916			52,838			34,828
General and administrative		10,012			6,455			19,247			13,705
Loss (gain) on disposal of plant and equipment		345			(593	)		458			(321	)
Amortization of intangible assets		182			183			365			366

Operating income before the undernoted		9,655			15,871			32,768			21,078
Interest expense (note 10)		10,326			3,292			20,494			53,155
Foreign exchange loss (gain)		72			(16,461	)		(13,394	)		(15,240	)
Realized and unrealized loss on derivative financial instruments		3,786			17,515			11,782			18,797
Financing costs		53			—			53			2,095
Other income		(8	)		(68	)		(591	)		(268	)

Income (loss) before income taxes		(4,574	)		11,593			14,424			(37,461	)
Income taxes (note 8):
Current income taxes		(2,712	)		94			(2,844	)		244
Future income taxes		2,895			—			4,131			—

Net income (loss) for the period		(4,757	)		11,499			13,137			(37,705	)
Deficit, beginning of period		(58,652	)		(103,809	)		(76,546	)		(54,605	)

Deficit, end of period	$	(63,409	)	$	(92,310	)	$	(63,409	)	$	(92,310	)

Net income (loss) per share – basic (note 9(d))	$	(0.26	)	$	0.62		$	0.71		$	(2.03	)

Net income (loss) per share – diluted (note 9(d))	$	(0.26	)	$	0.62		$	0.53		$	(2.03	)

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Consolidated Statements of Cash Flows

(in thousands of Canadian dollars)

(unaudited)


	Three months ended September 30						Six months ended September 30
	2006			2005			2006			2005
Cash provided by (used in):
Operating activities:
Net income (loss) for the period	$	(4,757	)	$	11,499		$	13,137		$	(37,705	)
Items not affecting cash:
Depreciation		4,822			5,493			12,134			10,482
Amortization of intangible assets		182			183			365			366
Amortization of deferred financing costs		948			896			1,835			1,568
Loss on disposal of plant and equipment		345			(593	)		458			(321	)
Unrealized foreign exchange loss (gain) on senior notes		78			(16,333	)		(13,493	)		(15,405	)
Unrealized loss on derivative financial instruments		3,019			16,766			10,438			17,353
Stock-based compensation expense (note 13)		809			135			1,121			323
Accretion and change in redemption value of mandatorily redeemable preferred shares		965			(5,011	)		1,910			36,496
Future income taxes		2,895			—			4,131			—
Decrease (increase) in allowance for doubtful accounts		24			(5	)		24			(72	)
Financing costs		—			—			—			2,095
Net changes in non-cash working capital (note 11(b))		(3,114	)		(3,609	)		(13,301	)		(19,454	)

		6,216			9,421			18,759			(4,274	)

Investing activities:
Acquisition, net of cash acquired (note 3)		(1,496	)		—			(1,496	)		—
Purchase of plant and equipment		(9,973	)		(8,017	)		(19,309	)		(13,795	)
Proceeds on disposal of plant and equipment		99			2,665			572			3,053

		(11,370	)		(5,352	)		(20,233	)		(10,742	)

Financing activities:
Repayment of capital lease obligations		(848	)		(493	)		(1,621	)		(927	)
Financing costs		(2,403	)		(104	)		(3,021	)		(7,485	)
Issuance of 9% senior secured notes		—			—			—			76,345
Repayment of senior secured credit facility		—			—			—			(61,257	)
Issuance of share capital		139			—			139			—
Issuance of NAEPI Series B preferred shares		—			851			—			8,351

		(3,112	)		254			(4,503	)		15,027

Increase (decrease) in cash and cash equivalents		(8,266	)		4,323			(5,977	)		11
Cash and cash equivalents, beginning of period		45,093			13,612			42,804			17,924

Cash and cash equivalents, end of period	$	36,827		$	17,935		$	36,827		$	17,935

Supplemental cash flow information (note 11(a))

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

1.	Nature of operations

NACG Holdings Inc. (the “Company”) was incorporated under the Canada Business Corporations Act on October 17, 2003. The Company had no operations prior to November 26, 2003. The Company completes all forms of civil projects including contract mining, industrial and commercial site development, pipeline and piling installations. NACG Holdings Inc. is a holding company with no active business operations. Substantially all of the business activities and assets shown on the Company’s consolidated balance sheet are conducted and held by its subsidiary, North American Energy Partners Inc. (“NAEPI”). Accordingly, the Company’s earnings and cash flows and its ability to pay dividends are largely dependent upon the earnings and cash flows of NAEPI and the distribution or other payment of such earnings to the Company in the form of dividends. The ability of NAEPI to declare dividends to its ultimate parent, NACG Holdings Inc., is restricted by (a) the terms of the NAEPI Series A preferred shares, (b) the terms of the NAEPI Series B preferred shares, (c) the terms of the NACG Preferred Corp. Series A preferred shares, (d) restrictions contained within the revolving credit facility of NAEPI and (e) terms of the indentures related to the U.S. dollar denominated 8³/4% senior notes of NAEPI and the U.S. dollar denominated 9% senior secured notes of NAEPI. The restricted net assets of the Company are approximately $32.5 million.

On November 28, 2006, immediately prior to the initial public offering of common shares in Canada and the United States (note 17(a)), the Company amalgamated with its wholly-owned subsidiaries, NACG Preferred Corp., and NAEPI. The amalgamated entity continued as North American Energy Partners Inc.

2.	Basis of presentation

These unaudited interim consolidated 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 unaudited interim consolidated financial statements requires the use of estimates and assumptions. In the opinion of management, these unaudited interim consolidated financial statements have been prepared within reasonable limits of materiality. These unaudited interim consolidated 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, 2006 and should be read in conjunction with those consolidated financial statements. Material items that give rise to measurement differences to the consolidated financial statements under United States GAAP are outlined in note 16.

These interim consolidated financial statements include the accounts of the Company, its wholly-owned subsidiary, NACG Preferred Corp.; the wholly-owned subsidiary of NACG Preferred Corp., NAEPI; the wholly-owned subsidiaries of NAEPI, NACG Finance LLC and North American Construction Group Inc. (“NACGI”); the Company’s joint venture, Noramac Ventures Inc. and the following subsidiaries of NACGI:

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)


	% owned
• North American Caisson Ltd.	100	%
• North American Construction Ltd.	100	%
• North American Engineering Ltd.	100	%
• North American Enterprises Ltd.	100	%
• North American Industries Inc.	100	%
• North American Mining Inc.	100	%
• North American Maintenance Ltd.	100	%
• North American Pipeline Inc.	100	%
• North American Road Inc.	100	%
• North American Services Inc.	100	%
• North American Site Development Ltd.	100	%
• North American Site Services Inc.	100	%
• Griffiths Pile Driving Inc.	100	%

3.	Acquisition

On September 1, 2006 the Company acquired all of the shares of Midwest Foundation Technologies Ltd., a piling company specializing in the design and installation of microplile foundations in western Canada, for cash consideration of $1,675. The acquisition 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 (including cash of $179)	$	405
Plant and equipment		554
Intangible assets		335
Goodwill		518
Obligations under capital leases		(137	)

	$	1,675

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

4.	Recent Canadian accounting pronouncements not yet adopted

Financial instruments:

In January 2005, the Canadian Institute of Chartered Accountants (“CICA”) issued Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, 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,

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

specifically April 1, 2007 for the Company. Earlier adoption is permitted. The new standards will require presentation of a separate statement of comprehensive income under specific circumstances. Foreign exchange gains and losses on the translation of the financial statements of self-sustaining subsidiaries previously recorded in a separate section of shareholder’s equity will be presented in comprehensive income. Derivative financial instruments will be recorded in the balance sheet at fair value and the changes in fair value of derivatives designated as cash flow hedges will be reported in comprehensive income. The Company is currently assessing the impact of the new standards.

5.	Prepaid expenses and other assets

Prepaid expenses:


	September 30, 2006		March 31, 2006
Prepaid insurance and property taxes	$	603	$	345
Deposits		16,850		1,451

	$	17,453	$	1,796

Other assets:

Other assets consist of supplies of tires and spare component parts, and are stated at the lower of cost and estimated net realizable value.

6.	Plant and equipment


September 30, 2006	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	186,223	$	37,979	$	148,244
Major component parts in use		6,778		2,501		4,277
Spare major component parts		1,577		—		1,577
Other equipment		13,704		4,953		8,751
Licensed motor vehicles		21,692		10,082		11,610
Office and computer equipment		3,592		1,847		1,745
Buildings		15,991		288		15,703
Leasehold improvements		2,988		455		2,533
Assets under construction		15		—		15

	$	252,560	$	58,105	$	194,455

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)


March 31, 2006	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	174,042	$	31,347	$	142,695
Major component parts in use		4,922		2,091		2,831
Spare component parts		166		—		166
Other equipment		13,074		4,186		8,888
Licensed motor vehicles		18,223		8,410		9,813
Office and computer equipment		3,362		1,493		1,869
Leasehold improvements		2,959		247		2,712
Assets under construction		15,588		—		15,588

	$	232,336	$	47,774	$	184,562

The above amounts include $17,821 (March 31, 2006 – $14,559) of assets under capital leases and accumulated depreciation of $5,821 (March 31, 2006 – $4,479) related thereto. During the three and six months ended September 30, 2006, additions of plant and equipment included $1,436 and $3,194, respectively, for capital leases (three and six months ended September 30, 2005 – $998 and $1,979, respectively). Depreciation of equipment under capital leases of $712 and $1,342 for the three and six months ended September 30, 2006, respectively (three and six months ended September 30, 2005 – $618 and $1,162, respectively), is included in depreciation expense.

Buildings are amortized on a straight-line basis over their estimated useful life of 10 years.

7.	Long-term debt

Senior notes:


	September 30, 2006		March 31, 2006
8³/4% senior unsecured notes due 2011	$	223,060	$	233,420
9% senior secured notes due 2010		67,454		70,587

	$	290,514	$	304,007

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

The 8³/4% senior notes are unsecured senior obligations and rank equally with all other existing and future unsecured senior debt and senior to any subordinated debt that may be issued by NAEPI or any of its subsidiaries. NACG Holdings Inc. is not a guarantor of this debt. The notes are effectively subordinated to all secured debt to the extent of the value of the assets securing such debt.

The 8³/4% senior notes are redeemable at the option of NAEPI, in whole or in part, at any time on or after: December 1, 2007 at 104.375% of the principal amount; December 1, 2008 at 102.188% of the principal amount; December 1, 2009 at 100.00% of the principal amount; plus, in each case, interest accrued to the redemption date. At any time, or from time to time, on or before December 1, 2006

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

NAEPI may, at its option, use the net cash proceeds of one or more public equity offerings, to redeem up to 35% of the principal amount of the 8³/4% senior notes at a redemption price equal to 108.75% of the principal amount of the 8³/4% senior notes redeemed plus accrued and unpaid interest, if any, to the date of redemption; provided that: at least 65% of the principal amount of 8³/4% senior notes remains outstanding immediately after any such redemption; and NAEPI makes such redemption within 90 days after the closing of any such public equity offering. If a change of control occurs, NAEPI will be required to offer to purchase all or a portion of each holder’s 8³/4% senior notes, at a purchase price in cash equal to 101% of the principal amount of the notes offered for repurchase plus accrued interest to the date of purchase.

The 9% senior secured notes were issued on May 19, 2005 in the amount of US$60.481 million (Canadian $76.345 million) by NAEPI. These notes mature on June 1, 2010 and bear interest at 9% payable semi-annually on June 1 and December 1 of each year.

The 9% senior secured notes are senior secured obligations and rank equally with all other existing and future secured debt and senior to any subordinated debt that may be issued by NAEPI or any of its subsidiaries. NACG Holdings Inc. is not a guarantor of this debt. The notes are effectively senior to all existing and future unsecured senior debt including the 8³/4% senior notes and are effectively subordinated to NAEPI’s swap agreements and revolving credit facility to the extent of the value of the assets securing such debt.

The 9% senior secured notes are redeemable at the option of NAEPI, in whole or in part, at any time on or after: June 1, 2008 at 104.50% of the principal amount; June 1, 2009 at 102.25% of the principal amount; June 1, 2010 at 100.00% of the principal amount; plus, in each case, interest accrued to the redemption date. At any time, or from time to time, on or before June 1, 2007 NAEPI may, at its option, use the net cash proceeds of one or more public equity offerings, to redeem up to 35% of the principal amount of the 9% senior secured notes at a redemption price equal to 109.0% of the principal amount of the 9% senior secured notes redeemed plus accrued and unpaid interest, if any, to the date of redemption; provided that: at least 65% of the principal amount of 9% senior secured notes remains outstanding immediately after any such redemption; and NAEPI makes such redemption within 90 days after the closing of any such public equity offering. If a change of control occurs, NAEPI will be required to offer to purchase all or a portion of each holder’s 9% senior secured notes, at a purchase price in cash equal to 101% of the principal amount of the notes offered for repurchase plus accrued interest to the date of purchase.

In connection with the initial public offering of its common shares, the Board of Directors approved the repurchase of the 9% senior secured notes on August 30, 2006. The Company repurchased the 9% senior secured notes at a premium of 109.26% on November 28, 2006 resulting in a loss on extinguishment of approximately $6.3 million and the write-off of deferred financing fees of approximately $4.3 million (both amounts are on a pre-income tax basis) and both charges will be recognized in the three months ended December 31, 2006.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

Revolving credit facility:

On July 19, 2006, the Company amended and restated its existing credit agreement to provide for borrowings of up to $55.0 million (previously $40.0 million), subject to borrowing base limitations, under which revolving loans and letters of credit may be issued (previously up to a limit of $30.0 million). Prime rate revolving loans under the amended and restated agreement will bear interest at the Canadian prime rate plus 2.0% per annum and swing line revolving loans will bear interest at the Canadian prime rate plus 1.5% per annum. Canadian bankers’ acceptances have stamping fees equal to 3.0% per annum and letters of credit are subject to a fee of 3.0% per annum.

Advances under the amended and restated agreement are margined with a borrowing base calculation defined as the aggregate of 60.0% of the net book value of the Company’s plant and equipment, 75.0% of eligible accounts receivable and un-pledged cash in excess of $15.0 million. The sum of all borrowings (including issued letters of credit) and the fair value of the Company’s liability under existing swap agreements must not exceed the borrowing base. The amended and restated credit facility is secured by a first priority lien on substantially all of the Company’s existing and after-acquired property.

The facility contains certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments (including acquisitions), paying dividends or redeeming shares of capital stock. The Company is also required to meet certain financial covenants. Other terms of the agreement, including the expiry date, did not change. The expiry date of the amended and restated revolving credit facility is March 1, 2010.

During the three months ended September 30, 2006, financing fees paid to the creditor and third-party costs of $1,033 incurred in connection with the amended and restated credit agreement were recorded as deferred financing costs. These costs and the existing unamortized deferred financing costs will be deferred and amortized over the term of the amended facility consistent with accounting for the change in the revolving credit facility as a modification. For the six months ended September 30, 2006, financing fees of $1,133 were incurred, of which $1,080 were recorded as deferred financing costs.

As of September 30, 2006, NAEPI had no outstanding borrowings under the revolving credit facility and had issued $18.0 million in letters of credit to support bonding requirements and performance guarantees associated with customer contracts and operating leases. NAEPI’s borrowing availability under the facility, after taking into account the borrowing base limitations, was $37.0 million at September 30, 2006.

8.	Income taxes

Future income tax expense for the six months ended September 30, 2006 includes a recovery of $5,858 resulting from the elimination of the valuation allowance. Management considers the scheduled reversals of future income tax liabilities, the character of income tax assets and available tax planning strategies of the Company and its subsidiaries when evaluating the expected realization of future income tax assets to reflect that it is more likely than not that the future income tax assets will be realized.

The effective tax rate differs from the Company’s statutory rate of 32.12% because of permanent differences relating to certain financing transactions which are not deductible for tax purposes, accruals for certain tax exposure items and the change in the valuation allowance.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

9.	Shares

Redeemable preferred shares:


	September 30, 2006		March 31, 2006
NACG Preferred Corp. Series A preferred shares (i)	$	35,000	$	35,000
NAEPI Series A preferred shares (ii)		408		375
NAEPI Series B preferred shares (iii)		44,070		42,193

	$	79,478	$	77,568

NACG Preferred Corp. Series A preferred shares

Issued:


	Number of Shares	Amount
Outstanding at March 31, 2006	35,000	$	35,000
Issued	—		—
Redeemed	—		—

Outstanding at September 30, 2006	35,000	$	35,000

NACG Preferred Corp. is authorized to issue an unlimited number of Series A preferred shares. The NACG Preferred Corp. Series A preferred shares accrue dividends at a rate of $80.00 per share annually if earnings before interest, taxes, depreciation and amortization (“EBITDA”) for NAEPI is in excess of $75.0 million for the year. The dividends are payable in cash, additional NACG Preferred Corp. Series A preferred shares, or any combination of cash and shares as determined by the Company. The number of shares issuable is .001 of a whole NACG Preferred Corp. Series A preferred share for each $1.00 of dividend declared.

The NACG Preferred Corp. Series A preferred shares, which were issued in connection with the acquisition of NAEPI and were recorded at their guaranteed redemption amount, are redeemable at any time at the option of the Company, and are required to be redeemed on or before November 26, 2012. The redemption price is $1,000.00 per share plus all accrued and unpaid dividends. In the event of a change in control, each holder of NACG Preferred Corp. Series A preferred shares has the right to require the Company to redeem all or any part of such holder’s shares.

On November 28, 2006, the Company acquired the NACG Preferred Corp. Series A preferred shares for a promissory note in the amount of $27.0 million and all accrued dividends at that time were forfeited resulting in a gain on settlement of $8.0 million and the reversal of previously accrued dividends of $1.4 million, both of which will be recognized in the financial statements for the three months ended December 31, 2006.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

ii.

NAEPI Series A preferred shares

Issued:


	Number of Shares	Amount
Outstanding at March 31, 2006	1,000	$	375
Issued	—		—
Accretion	—		33

Outstanding at September 30, 2006	1,000	$	408

NAEPI is authorized to issue an unlimited number of Series A preferred shares. The NAEPI Series A preferred shares are non-voting and are not entitled to any dividends. The NAEPI Series A preferred shares are mandatorily redeemable at $1,000.00 per share on the earlier of (1) December 31, 2011 and (2) an Accelerated Redemption Event, specifically (i) the occurrence of a change of control, or (ii) if there is an initial public offering of common shares, the later of (a) the consummation of the initial public offering or (b) the date on which all of the Company’s 8³/4% senior notes and the Company’s 9% senior secured notes are no longer outstanding. NAEPI may redeem the NAEPI Series A preferred shares, in whole or in part, at $1,000 per share at any time.

The NAEPI Series A preferred shares were issued to one of the counterparties to NAEPI’s swap agreements on May 19, 2005 in connection with obtaining a new revolving credit facility. These shares are not entitled to accrue or receive dividends.

The NAEPI Series A preferred shares were initially recorded at their fair value on the date of issuance, which was estimated to be $321 based on the present value of the required cash flows using the rate implicit at inception. Each reporting period, the accretion of the carrying value to the present value of the redemption amount at each balance sheet date is recorded as interest expense. For the three and six months ended September 30, 2006, the Company recognized $17 and $33, respectively, of accretion as interest expense.

On October 6, 2006, the Board of Directors approved the purchase of the NAEPI Series A preferred shares for $1,000 effective with the consummation of the initial public offering of the Company’s common shares, and these shares were purchased on November 28, 2006 pursuant to affiliate purchase rights under the terms of the Series A preferred shares. Accordingly, the Company will record the additional accretion charge and the extinguishment of the obligation in the three months ended December 31, 2006.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

iii.

NAEPI Series B preferred shares

Issued:


	Number of Shares	Amount
Outstanding at March 31, 2006	75,244	$	42,193
Issued	—		—
Repurchased	—		—
Accretion	—		1,877

Outstanding at September 30, 2006	75,244	$	44,070

NAEPI is authorized to issue an unlimited number of Series B preferred shares. The NAEPI Series B preferred shares are non-voting and are entitled to cumulative dividends at an annual rate of 15% of the issue price of each share. No dividends are payable on NAEPI common shares or other classes of preferred shares (defined as Junior Shares) unless all cumulative dividends have been paid on the NAEPI Series B preferred shares and NAEPI declares a NAEPI Series B preferred share dividend equal to 25% of the Junior Share dividend (except for dividends paid as part of employee and officer arrangements, intercompany administrative charges of up to $1 million annually and tax sharing arrangements). As long as any NAEPI Series A preferred shares remain outstanding and subject to the restrictions contained within the 8³/4% senior notes and the 9% senior secured notes, dividends shall not be paid (but shall otherwise accrue) on the NAEPI Series B preferred shares. Subject to the prior redemption of the NAEPI Series A preferred shares, the NAEPI Series B preferred shares are mandatorily redeemable on the earlier of (1) December 31, 2011 and (2) an Accelerated Redemption Event, specifically (i) a change of control or (ii) if there is an initial public offering of common shares, the later of (a) the consummation of the initial public offering or (b) the date on which all of the Company’s 8³/4% senior notes and the Company’s 9% senior secured notes are no longer outstanding. Subject to the restrictive covenants contained within the indenture agreement for the 9% senior secured notes, the indenture agreement for the 8³/4% senior notes and the revolving credit facility agreement, NAEPI may redeem the NAEPI Series B preferred shares, in whole or in part, at any time.

The payment of dividends and the redemption of the NAEPI Series B preferred shares are prohibited by NAEPI’s revolving credit facility agreement. The payment of dividends and the redemption of the NAEPI Series B preferred shares is also restricted by the indenture agreements governing NAEPI’s 9% senior secured notes and 8³/4% senior notes. Cumulative undeclared dividends on the NAEPI Series B preferred shares amounted to $1,578 at September 30, 2006.

The NAEPI Series B preferred shares were issued to existing non-employee shareholders of the Company for cash proceeds of $7.5 million on May 19, 2005. The NAEPI Series B preferred shares were initially issued to certain non-employee shareholders with the agreement that an

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

offer to purchase these NAEPI Series B preferred shares would also be extended to other existing shareholders of the Company on a pro rata basis to their interest in the common shares of the Company. On August 31, 2005, NAEPI issued 8,218 NAEPI Series B preferred shares for consideration of $851 to certain shareholders of the Company as a result of this offering. On November 1, 2005, NAEPI repurchased and cancelled 8,218 of the NAEPI Series B preferred shares held by the original non-employee shareholders for cash consideration of $851.

On June 15, 2005, the NAEPI Series B preferred shares were split 10-for-1.

Subsequent to initial issuance, an additional 244 NAEPI Series B preferred shares were issued for cash consideration of $24.

The redemption price of the NAEPI Series B preferred shares, as amended on March 30, 2006, is an amount equal to the greater of (i) two times the issue price, less the amount, if any, of dividends previously paid in cash on the NAEPI Series B preferred shares; and (ii) an amount, not to exceed $100 million which, after taking into account any dividends previously paid in cash on such NAEPI Series B preferred shares, provides the holder with a 40% rate of return, compounded annually, on the issue price from the date of issuance.

Prior to the amendment to the terms of the NAEPI Series B preferred shares on March 30, 2006, the NAEPI Series B preferred shares were considered mandatorily redeemable and the Company was required to measure the NAEPI Series B preferred shares at the amount of cash that would be paid under the conditions specified in the contract if settlement occurred at each reporting date prior to the amendment. At March 30, 2006, management estimated the redemption amount to be $42,193.

Concurrent with the amendment to the NAEPI Series B preferred shares, the Company entered into a Put/Call Agreement with the holders of the NAEPI Series B preferred shares. The Put/Call Agreement grants to each holder of the NAEPI Series B preferred shares the right (the “Put/Call Right”) to require the Company to exchange each of the holder’s NAEPI Series B preferred shares for 100 common shares (on a post-split basis – note 17(c)) of the Company. The Put/Call Right may only be exercised upon delivery by the Company of an “Event Notice”, being either: (i) a redemption or purchase call for the redemption or purchase of the NAEPI Series B preferred shares in connection with (A) a redemption on December 31, 2011, or (B) an Accelerated Redemption Event; or (ii) a notice in connection with a Liquidation Event (defined as a liquidation, winding-up or dissolution of NAEPI, whether voluntary or involuntary).

The Put/Call Agreement also grants the Company the right to require the holders of the NAEPI Series B preferred shares to exchange each of their NAEPI Series B preferred shares for 100 common shares (on a post-split basis – note 17(c)) in the capital of the Company upon delivery of a call notice to shareholders within five business days of an Event Notice.

As a result of the March 30, 2006 amendment to the terms of the NAEPI Series B preferred shares and the concurrent execution of the Put/Call Agreement, the Company has accounted for

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

the amendment as a related party transaction at carrying amount. No value was ascribed to the equity classified Put/Call Right as it was a related party transaction. The NAEPI Series B preferred shares are accreted from their carrying value of $42.2 million on the date of amendment to their redemption value of $69.6 million on December 31, 2011 through a charge to interest expense using the effective interest method over the period until December 31, 2011. For the three and six months ended September 30, 2006, the Company recognized $949 and $1,877, respectively, of accretion as interest expense.

On October 6, 2006, the Board of Directors approved the exercise of the call option to acquire all of the issued and outstanding Series B preferred shares in exchange for 7,524,400 common shares of the Company and the option was exercised on November 28, 2006. In the three months ended December 31, 2006, the Company will record the conversion by transferring the carrying value of the Series B preferred shares on the exercise date of approximately $44,692 to share capital.

Common shares:

Authorized:

Unlimited number of common voting shares

Unlimited number of common non-voting shares

Issued:


	Number of Shares ⁽¹⁾	Amount
*Common voting shares*
Outstanding at March 31, 2006	18,207,600	$	91,038
Issued upon exercise of stock options	27,760		139
Transferred from contributed surplus on exercise of stock options	—		52
Redeemed	—		—

Outstanding at September 30, 2006	18,235,360	$	91,229

*Common non-voting shares*
Outstanding at March 31, 2006	412,400		2,062
Issued	—		—
Redeemed	—		—

Outstanding at September 30, 2006	412,400	$	2,062

*Total common shares*	18,647,760	$	93,291

⁽¹⁾	The issued and outstanding common shares have been retroactively adjusted to reflect the Company’s 20-for-1 share split effected on November 3, 2006 (see note 17(c)).

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

Contributed surplus:


Balance, March 31, 2006	$	1,557
Stock-based compensation (note 13)		1,121
Transferred to common shares on exercise of stock options		(52	)

Balance, September 30, 2006	$	2,626

Net income (loss) per share:

Basic net income (loss) per share is computed on the basis of the weighted average number of common shares outstanding. Diluted net income (loss) per share is computed on the basis of the weighted average number of common shares outstanding plus the effect of outstanding stock options using the treasury stock method and the dilutive effect of convertible securities using the if-converted method. For the three months ended September 30, 2006 and the six months ended September 30, 2005 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.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)


	Three months ended September 30					Six months ended September 30
	2006			2005		2006		2005
Basic net income (loss) per share
Net income available to common shareholders	$	(4,757	)	$	11,499	$	13,137	$	(37,705	)
Weighted average number of common shares		18,638,405			18,560,000		18,629,253		18,560,000

Basic net income (loss) per share	$	(0.26	)	$	0.62	$	0.71	$	(2.03	)

Diluted net income (loss) per share
Net income (loss) available to common shareholders	$	(4,757	)	$	11,499	$	13,137	$	(37,705	)
Dilutive effect of NAEPI Series B preferred shares		—			—		1,274		—

Net income (loss), assuming dilution		(4,757	)		11,499		14,411		(37,705	)

Weighted average number of common shares		18,638,405			18,560,000		18,629,253		18,560,000
Dilutive effect of:
NAEPI Series B preferred shares		—			—		7,524,400		—
Stock options		—			117,118		834,003		—

Weighted average number of diluted common shares		18,638,405			18,677,118		26,987,656		18,560,000

Diluted net income (loss) per share	$	(0.26	)	$	0.62	$	0.53	$	(2.03	)

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

10.

Interest expense


	Three months ended September 30					Six months ended September 30
	2006		2005			2006		2005
Interest on senior notes	$	7,434	$	7,389		$	14,780	$	13,924
Interest on senior secured credit facility		—		—			—		564
Interest on capital lease obligations		163		104			317		193
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		(5,025	)		1,877		36,473
Accretion of NAEPI Series A preferred shares		17		14			33		23

Interest on long-term debt		9,263		2,482			18,407		51,177
Amortization of deferred financing costs		948		896			1,835		1,568
Other interest		115		(86	)		252		410

	$	10,326	$	3,292		$	20,494	$	53,155

11.

Other information

Supplemental cash flow information:


	Three months ended September 30				Six months ended September 30
	2006		2005		2006		2005
Cash paid during the period for:
Interest	$	287	$	4,253	$	16,707	$	12,978
Income taxes		152		93		342		244
Cash received during the period for:
Interest		412		55		898		163
Non-cash transactions:
Capital leases		1,436		998		3,194		1,979
Issuance of NAEPI Series A preferred shares		—		—		—		321

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

Net change in non-cash working capital:


	Three months ended September 30						Six months ended September 30
	2006			2005			2006			2005
Operating activities:
Accounts receivable	$	4,032		$	(7,549	)	$	(5,035	)	$	(4,086	)
Unbilled revenue		(1,266	)		(4,757	)		4,109			(11,497	)
Inventory		—			86			44			112
Prepaid expenses and deposits		(13,655	)		908			(15,657	)		(49	)
Other assets		(6,924	)		489			(9,431	)		574
Accounts payable		3,655			(5,715	)		3,073			(9,348	)
Accrued liabilities		9,229			11,441			6,289			4,199
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		1,815			1,488			3,307			641

	$	(3,114	)	$	(3,609	)	$	(13,301	)	$	(19,454	)

Claims revenue

During the three and six months ended September 30, 2006, the Company has recognized $nil and $6.1 million, respectively, in claims revenue (three and six months ended September 30, 2005 - $4.4 million and $9.7 million, respectively).

12.

Segmented information

General overview:

The Company conducts business in three business segments: Mining and Site Preparation, Piling and Pipeline.

•

Mining and Site Preparation:

The Mining and Site Preparation 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.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

Results by business segment:


Three months ended September 30, 2006	Mining and Site Preparation		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

Three months ended September 30, 2005	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	93,536	$	22,115	$	8,353	$	124,004
Depreciation of plant and equipment		2,238		426		164		2,828
Segment profits		9,508		4,833		1,773		16,114
Segment assets		337,192		80,277		41,526		458,995
Expenditures for segment plant and equipment		8,203		58		—		8,261

Six months ended September 30, 2006	Mining and Site Preparation		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

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)


Six months ended September 30, 2005	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	176,031	$	42,301	$	10,031	$	228,363
Depreciation of plant and equipment		4,585		858		252		5,695
Segment profits		20,110		7,938		1,875		29,923
Segment assets		337,192		80,277		41,526		458,995
Expenditures for segment plant and equipment		11,317		249		—		11,566

Reconciliations

Income (loss) before income taxes:


	Three months ended September 30						Six months ended September 30
	2006			2005			2006			2005
Total profit for reportable segments	$	22,182		$	16,114		$	54,944		$	29,923
Unallocated corporate expenses		(24,448	)		(10,905	)		(37,981	)		(72,900	)
Unallocated equipment (costs) revenue		(2,308	)		6,384			(2,539	)		5,516

Income (loss) before income taxes	$	(4,574	)	$	11,593		$	14,424		$	(37,461	)

ii.

Total assets:


	September 30, 2006		March 31, 2006
Total assets for reportable segments	$	486,026	$	460,771
Corporate assets		133,797		126,240

Total assets	$	619,823	$	587,011

The Company’s goodwill was assigned to the Mining and Site Preparation, Piling and Pipeline segments in the amounts of $125,447, $40,867, and $32,753, respectively.

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

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

Customers:

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


	Three months ended September 30				Six months ended September 30
	2006		2005		2006		2005
Customer A	20	%	38	%	18	%	36	%
Customer B	13	%	15	%	12	%	15	%
Customer C	0	%	0	%	10	%	0	%
Customer D	10	%	1	%	10	%	1	%
Customer E	14	%	4	%	9	%	4	%
Customer F	6	%	11	%	7	%	12	%

This revenue by major customer was earned in the Mining and Site Preparation, Piling and Pipeline segments.

13.

Stock-based compensation plan

Under the 2004 Share Option Plan, Directors, Officers, employees and service providers to the Company are eligible to receive stock options to acquire common shares in the Company. The stock options expire 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 per cent vest on each of the five following award date anniversaries. After retroactive application of the 20-for-1 share split disclosed in note 17(c), the maximum number of common shares issuable under this plan may not exceed 2,300,000, of which 69,160 are still available for issue as at September 30, 2006.


	Three months ended September 30
	2006					2005
	Number of options ⁽¹⁾		Weighted average exercise price ($ per share) ⁽¹⁾			Number of options ⁽¹⁾		Weighted average exercise price ($ per share) ⁽¹⁾
Outstanding, beginning of period	2,070,840		$	5.00		1,484,840		$	5.00
Granted	187,760			16.75		—			—
Exercised	(27,760	)		(5.00	)	—			—
Forfeited	—			—		(64,000	)		(5.00	)

Outstanding, end of period	2,230,840		$	5.99		1,420,840		$	5.00

⁽¹⁾	The number of options and the weighted average exercise price per share have been retroactively adjusted to reflect the impact of the 20-for-1 share split disclosed in note 17(c).

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)


	Six months ended September 30
	2006					2005
	Number of options ⁽¹⁾		Weighted average exercise price ($ per share) ⁽¹⁾			Number of options ⁽¹⁾		Weighted average exercise price ($ per share) ⁽¹⁾
Outstanding, beginning of period	2,066,360		$	5.00		1,524,840		$	5.00
Granted	315,520			11.99		—			—
Exercised	(27,760	)		(5.00	)	—			—
Forfeited	(123,280	)		(5.00	)	(104,000	)		(5.00	)

Outstanding, end of period	2,230,840		$	5.99		1,420,840		$	5.00

⁽¹⁾	The number of options and the weighted average exercise price per share have been retroactively adjusted to reflect the impact of the 20-for-1 share split disclosed in note 17(c).

At September 30, 2006, the weighted average remaining contractual life of outstanding options is 7.9 years (March 31, 2006 – 8.2 years). The Company recorded $809 and $1,121 of compensation expense related to the stock options in the three and six months ended September 30, 2006, respectively (three and six months ended September 30, 2005 – $135 and $323, respectively), with such amount being credited to contributed surplus.

As a result of the filing of a preliminary prospectus on July 21, 2006 with the various Canadian and U.S. securities commissions in preparation for the public sale of common shares, the Company is no longer eligible to use the minimum value method for measuring stock-based compensation. Accordingly, the Company considered the effect of expected volatility in its assumptions using the Black-Scholes option pricing model for options granted after this date. The Company determined its expected volatility based on a statistical analysis of historical volatility for a peer group of companies, which was prepared by an independent valuation firm.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

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


	Three months ended September 30			Six months ended September 30
	2006		2005	2006		2005
Number of options granted ⁽¹⁾	187,760		—	315,520		—
Weighted average fair value per option granted ($) ⁽¹⁾	7.63		—	5.78		—
Weighted average assumptions
Dividend yield	nil	%	—	nil	%	—
Expected volatility	41.56	%	—	24.73	%	—
Risk-free interest rate	4.08	%	—	4.30	%	—
Expected life (years)	6.4		—	7.9		—

⁽¹⁾	The number of options and the weighted average fair value per option granted have been retroactively adjusted to reflect the impact of the 20-for-1 share split disclosed in note 17(c).

The Company offered to accelerate the vesting of 222,080 options held by certain members of its Board of Directors, providing for the options to become immediately exercisable on the condition that such options be exercised by September 30, 2006. On July 31, 2006, 27,760 options were exercised pursuant to this offer resulting in additional compensation cost of $24 for the three and six months ended September 30, 2006. The vesting period remained unchanged for stock options held by Directors that did not accept the Company’s offer.

14.

Seasonality

The Company generally experiences a decline in revenues during the first quarter of each fiscal year due to seasonality, as weather conditions make operations in the Company’s operating regions difficult during this period. The level of activity in the Mining and Site Preparation 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.

15.

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.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

16.

United States generally accepted accounting principles (“U.S. GAAP”)

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


	Three months ended September 30						Six months ended September 30
	2006			2005			2006			2005
Net income (loss) - Canadian GAAP	$	(4,757	)	$	11,499		$	13,137		$	(37,705	)
Capitalized interest (a)		—			143			249			302
Depreciation of Capitalized interest (a)		(33	)		—			(77	)		—
Amortization using effective interest method (b)		115			180			250			223
Realized and unrealized loss (gain) on derivative financial instruments (c)		220			(406	)		61			(406	)
Difference between accretion of Series B preferred shares under Canadian GAAP and U.S. GAAP (d)		95			—			185			—

Income (loss) before income taxes		(4,360	)		11,416			13,805			(37,586	)
Income taxes:
Deferred income taxes		(165	)		—			(529	)		—

Net income (loss) – U.S. GAAP	$	(4,525	)	$	11,416		$	13,276		$	(37,586	)

Basic net income (loss) per share – U.S. GAAP	$	(0.24	)	$	0.62		$	0.71		$	(2.03	)

Diluted net income (loss) per share – U.S. GAAP	$	(0.24	)	$	0.61		$	0.49		$	(2.03	)

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

The cumulative effect of these adjustments on the consolidated shareholder’s equity of the Company is as follows:


	September 30, 2006			March 31, 2006
Shareholders’ equity – Canadian GAAP	$	32,508		$	18,111
Capitalized interest (a)		1,096			847
Depreciation of capitalized interest (a)		(77	)		—
Amortization using effective interest method (b)		840			590
Realized and unrealized loss on derivative financial instruments (c)		(423	)		(484	)
Excess of fair value of amended Series B preferred shares over carrying value of original Series B preferred shares (d)		(3,707	)		(3,707	)
Cumulative difference between accretion of Series B preferred shares under Canadian GAAP and U.S. GAAP (d)		185			—
Deferred income taxes		(529	)		—

Shareholders’ equity – U.S. GAAP	$	29,893		$	15,357

A continuity of each component of the Company’s shareholders’ equity under U.S. GAAP for the three months ended September 30, 2006 is as follows:


	Common shares		Contributed surplus			Deficit			Total
Opening balance June 30, 2006 – U.S. GAAP	$	93,100	$	1,869		$	(61,499	)	$	33,470
Net income		—		—			(4,525	)		(4,525	)
Stock based compensation		—		809			—			809
Share issuance		139		—			—			139
Reclassification on exercise of stock options		52		(52	)		—			—

Closing balance – U.S. GAAP	$	93,291	$	2,626		$	(66,024	)	$	29,893

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

A continuity of each component of the Company’s shareholders’ equity under U.S. GAAP for the six months ended September 30, 2006 is as follows:


	Common shares		Contributed surplus			Deficit			Total
Opening balance – U.S. GAAP	$	93,100	$	1,557		$	(79,300	)	$	15,357
Net income		—		—			13,276			13,276
Stock based compensation		—		1,121			—			1,121
Share issuance		139		—			—			139
Reclassification on exercise of stock options		52		(52	)		—			—

Closing balance – U.S. GAAP	$	93,291	$	2,626		$	(66,024	)	$	29,893

The areas of material difference between Canadian and U.S. GAAP and their impact on the Company’s consolidated financial statements are described below:

Capitalization of interest:

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

Deferred charges:

Under Canadian GAAP, the Company defers and amortizes debt issuance costs on a straight-line basis over the stated term of the related debt. Under U.S. GAAP, the Company is required to amortize financing costs over the stated term of the related debt using the effective interest method resulting in a consistent interest rate over the term of the debt in accordance with Accounting Principles Board Opinion No. 21 (“APB 21”).

Derivative financial instruments:

Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts and debt instruments) be recorded in the balance sheet as either an asset or liability measured at its fair value. On November 26, 2003, the Company issued 8³/4% senior notes for US$200 million (Canadian $263 million) and on May 19, 2005 the Company issued 9% senior secured notes for US$60.4 million (Canadian $76.3 million). Both of these issuances included certain contingent embedded derivatives which provided for the acceleration of redemption by the holder at a premium in certain instances. These embedded derivatives met the criteria for bifurcation from the debt contract and separate measurement at fair value. The embedded derivatives have been measured at fair value and classified as part of the carrying amount of the senior notes on the consolidated balance sheet, with changes in

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

the fair value being recorded in net income (loss) as realized and unrealized (gain) loss on derivative financial instruments for the period under U.S. GAAP. Under Canadian GAAP, separate accounting of embedded derivatives from the host contract is not permitted by CICA Emerging Issues Committee Abstract No. 117.

NAEPI Series B preferred shares:

Under Canadian GAAP, the Company classifies the Series B preferred shares as a liability and accretes the carrying amount of $42.2 million on their amendment date (March 30, 2006) to the December 31, 2011 redemption value of $69.6 million using the effective interest method. Under U.S. GAAP, the Company recognized the fair value of the amended Series B preferred shares as minority interest as such amount was recognized as temporary equity in the accounts of NAEPI in accordance with Emerging Issues Task Force Topic D-98 (“EITF D-98”). Under U.S. GAAP, the Company accretes the initial fair value of the amended Series B preferred shares of $45.9 million recorded on their amendment date (March 30, 2006) to the December 31, 2011 redemption value of $69.6 million using the effective interest method, which is consistent with the treatment of the NAEPI Series B preferred shares as temporary equity in the financial statements of NAEPI. The accretion charge is recognized as a charge to minority interest (as opposed to retained earnings in the accounts of NAEPI) under U.S. GAAP and interest expense in the Company’s financial statements under Canadian GAAP.

Reporting comprehensive income:

Statement of Financial Accounting Standards No. 130, “Reporting Comprehensive Income” (“SFAS 130”) establishes standards for the reporting and display of comprehensive income and its components in a full set of general purpose financial statements. Comprehensive income equals net income (loss) for the period as adjusted for all other non-owner changes in shareholders’ equity. The only component of comprehensive income (loss) is the net income (loss) for the periods.

Stock-based compensation:

Up until April 1, 2006, the Company followed the provisions of Statement of Financial Accounting Standards No. 123, “Stock-Based Compensation” for U.S. GAAP purposes. As the Company uses the fair value method of accounting for all stock-based compensation payments under Canadian GAAP there were no differences between Canadian and U.S. GAAP prior to April 1, 2006. On April 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (“SFAS 123R”). As the Company used the minimum value method for purposes of complying with Statement of Financial Accounting Standards No. 123, it was required to adopt SFAS 123(R) prospectively.

The methodology for determining the expense to be recognized in each period that is prescribed by SFAS 123(R) differs from that prescribed by Canadian GAAP. Canadian GAAP permits accounting for forfeitures of share-based payments as they occur while U.S. standards require an estimate of forfeitures to be made at the date of grant and thereafter until the requisite service period has been completed or the awards are cancelled. The required adjustment under U.S. GAAP to account for estimated forfeitures was not significant for all periods presented.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

During the three months ended June 30, 2006, the Company granted 6,388 stock options to an employee and director. In determining the grant-date fair value of these stock options, the Company included an expected volatility of 40%. The additional compensation cost for these stock options under U.S. GAAP was not significant.

United States accounting pronouncements recently adopted:

The impact of the adoption of SFAS 123(R) is described in note 16(f).

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”) which replaces Accounting Principles Board Opinion No. 20 “Accounting Changes” and Statement of Financial Accounting Standards No. 3, “Reporting Accounting Changes in Interim Financial Statements – An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 was effective for the Company for accounting changes and corrections of errors made by the Company in its fiscal year beginning on April 1, 2006. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

Recent United States accounting pronouncements not yet adopted:

Statement of Financial Accounting Standards No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (“SFAS 155”) was issued February 2006. This Statement is effective for all financial instruments acquired, issued, or subject to a remeasurement (new basis) event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The fair value election provided for in paragraph 4(c) of this Statement may also be applied upon adoption of this Statement for hybrid financial instruments that had been bifurcated under paragraph 12 of Statement 133 prior to the adoption of this Statement. This states that an entity that initially recognizes a host contract and a derivative instrument may irrevocably elect to initially and subsequently measure that hybrid financial instrument, in its entirety, at fair value with changes in fair value recognized in earnings. SFAS 155 is applicable for all financial instruments acquired or issued in the Company’s 2008 fiscal year although early adoption is permitted. The Company is currently reviewing the impact of this statement.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109” (“FIN 48”) which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition requirements. The Company is currently reviewing the impact of this Interpretation.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS 157”) was issued September 2006. The Statement provides guidance for using fair value to measure assets and liabilities. The Statement also expands disclosures about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurement on earnings. This Statement applies under other accounting pronouncements that require or permit fair value measurements. This Statement does not expand the use of fair value measurements in any new circumstances. Under this Statement, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. SFAS 157 is effective for the Company for fair value measurements and disclosures made by the Company in its fiscal year beginning on April 1, 2008. The Company is currently reviewing the impact of this statement.

In September 2006, the U.S. Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. It establishes an approach that requires quantification of financial statements misstatements based on the effects of the misstatements on each of the Company’s financial statements and the related financial statement disclosures. SAB 108 is effective for the Company’s annual financial statements for the current fiscal year ending March 31, 2007. The Company is currently reviewing the impact of this pronouncement.

17.

Subsequent events

The Company filed a registration statement dated November 21, 2006 in the United States and a final prospectus dated November 22, 2006 in Canada regarding the initial public offering of 8,750,000 voting common shares and the secondary offering of 3,750,000 voting common shares for $18.38 per share (U.S.$16.00 per share). On November 22, 2006, and November 28, 2006 the Company’s common shares commenced trading on the New York Stock Exchange and the Toronto Stock Exchange, respectively. The Company received net proceeds of $143.4 million related to the initial public offering (gross proceeds of $160.8 million, less underwriting discounts and costs and offering expenses of $17.4 million). In addition, the underwriters have an option to purchase a maximum of 937,500 additional common shares from the Company and 937,500 additional common shares from the selling shareholders to cover over-allotments.

On November 28, 2006, prior to the consummation of the offering, the Company, NACG Preferred Corp. and NAEPI amalgamated and continued as North American Energy Partners Inc. The voting common shares of the new entity, North American Energy Partners Inc., were the shares offered in the initial public and secondary offering.

On November 28, 2006, prior to the amalgamation referred to above, the Company acquired the NACG Preferred Corp. Series A preferred shares for a promissory note in the amount of $27.0 million and all accrued dividends at that time were forfeited.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

On November 28, 2006, prior to the amalgamation referred to above, the Company repurchased the NAEPI Series A preferred shares for their redemption value of $1.0 million and cancelled the consulting and advisory services agreement with The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp. (collectively, the “Sponsors”), under which the Company had received ongoing consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. The consideration paid for the cancellation of the consulting and advisory services agreement on the closing of the offering was $2.0 million, which will be recognized as an expense in the financial statements for the three months ended December 31, 2006. Under the consulting and advisory services agreement, the Sponsors also received a fee of $804, 0.5% of the aggregate gross proceeds to the Company from the offering.

On November 28, 2006, each holder of NAEPI Series B preferred shares received 100 common shares of the Company for each NAEPI Series B preferred share held, as a result of the Company exercising its conversion option under the Put/Call Agreement.

The net proceeds from the offering, after deducting underwriting fees and estimated offering expenses, together with borrowings under the Company’s revolving credit facility:

•

were used to repurchase all of the Company’s outstanding 9% senior secured notes due 2010 for $74.7 million plus accrued interest of $3.0 million on November 28, 2006. The notes were redeemed at a premium of 109.26% resulting in a pre-tax loss on extinguishment of approximately $6.3 million and a pre-tax write-off of deferred financing fees of approximately $4.3 million and both charges will be recognized in the financial statements for the three months ended December 31, 2006;

•

were used to repay the promissory note in respect of the repurchase of the NACG Preferred Corp. Series A preferred shares of $27.0 million as described above; and

•

will be used to purchase certain equipment currently under operating leases for approximately $45.0 million.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

The reorganization and initial public offering had the following pro forma effect on basic net income (loss) per share and diluted net income (loss) per share for the three and six months ended September 30:


	Three months ended September 30					Six months ended September 30
	2006			2005		2006		2005
Pro forma basic net income (loss) per share
Net income available to common shareholders	$	(4,757	)	$	11,499	$	13,137	$	(37,705	)

Actual weighted average number of common shares		18,638,405			18,560,000		18,629,253		18,560,000
Conversion of NAEPI Series B preferred shares		7,524,400			7,524,400		7,524,400		7,524,400
Issued in connection with the initial public offering		8,750,000			8,750,000		8,750,000		8,750,000

Pro forma weighted average number of common shares		34,912,805			34,834,400		34,903,653		34,834,400

Pro forma basic net income (loss) per share	$	(0.14	)	$	0.33	$	0.38	$	(1.08	)

Pro forma diluted net income (loss) per share
Net income (loss) available to common shareholders	$	(4,757	)	$	11,499	$	13,137	$	(37,705	)

Pro forma weighted average number of common shares		34,912,805			34,834,400		34,903,653		34,834,400
Dilutive effect of:
Stock options		—			117,118		834,003		—

Pro forma weighted average number of diluted common shares		34,912,805			34,951,518		35,737,656		34,834,400

Pro forma diluted net income (loss) per share	$	(0.14	)	$	0.33	$	0.37	$	(1.08	)

On October 6, 2006, the Company approved the Amended and Restated 2004 Share Option Plan. The amended plan was approved by the shareholders on November 3, 2006 and became effective on the closing of the offering described in note 17(a) above. Option grants under the amended option plan may be made to Directors, Officers, employees and service providers selected by the Compensation Committee of the Company’s Board of Directors. The Compensation Committee may provide that any options granted will vest immediately or in increments over a period of time. Options to be granted under the amended option plan will have an exercise price of not less than the volume weighted average trading price of the common shares on the Toronto Stock Exchange or the New York Stock Exchange at the time of grant. The amended option plan provides that up to 10% of the Company’s issued and outstanding common shares from time to time may be reserved for issuance or issued from treasury under the amended option plan.

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

Notes to the Interim Consolidated Financial Statements

For the three and six months ended September 30, 2006

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

(Unaudited)

In the event of certain change of control events as defined in the amended option plan, all outstanding options will become immediately vested and exercisable. The amended option plan provides that the Company’s Board of Directors can make certain specified amendments to the option plan subject to receipt of shareholder and regulatory approval, and further authorizes the Board of Directors to make all other amendments to the plan, subject only to regulatory approval but without shareholder approval. The amendments the Board of Directors may make without shareholder approval include amendments of a housekeeping nature, changes to the vesting provisions of an option or the option plan, changes to the termination provisions of an option or the option plan which do not entail an extension beyond the original expiry date, the discontinuance of the option plan, and the addition of provisions relating to phantom share units, such as restricted share units and deferred share units which result in participants receiving cash payments, and the terms governing such features.

The amended option plan provides that each option includes a cashless exercise alternative which provides a holder of an option with the right to elect to receive cash in lieu of purchasing the number of shares under the option. Notwithstanding such right, the amended option plan provides that the Company may elect, at its sole discretion, to stock settle the option.

All outstanding options granted under the 2004 Stock Option Plan (note 13) will remain outstanding after the amended and restated plan becomes effective.

On November 3, 2006, the Board of Directors and common shareholders approved a 20-for-1 share split of the Company’s voting and non-voting common shares. All information relating to the conversion of the NAEPI Series B preferred shares (note 17(a)), the issued and outstanding common shares (note 9(b)), basic and diluted net income (loss) per share data (note 9(d)), and stock options (note 13) have been adjusted retroactively to reflect the impact of the share split in these financial statements. The share split was effective November 3, 2006.

Subsequent to September 30, 2006, one of the Company’s customers disclosed a going concern uncertainty in its interim financial statements. Revenues from this customer for the three and six months ended September 30, 2006 were $10,119 and $17,081, respectively. At September 30, 2006, the Company has $4,958 in accounts receivable and $2,274 in unbilled revenue from this customer, of which $2.0 million remains uncollected as of November 28, 2006. On November 21, 2006, this customer announced that it had priced a public offering of $30 million of debt securities which is scheduled to close on or about December 5, 2006. The Company is unable to assess how this financing may impact the customer’s business or ability to satisfy its accounts payable. However, based on the available information, the Company believes that any non-recoverable amount due from this customer will not be material and no provision has been provided against amounts receivable from this customer in the financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holding Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

November 29, 2006

The following discussion should be read in conjunction with the attached unaudited interim consolidated financial statements for the three and six months ended September 30, 2006 and audited consolidated financial statements for the year ended March 31, 2006. This document contains forward-looking statements. The Company’s forward-looking statements involve known and unknown risks, uncertainties 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,” “believes,” “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: the effectiveness of our internal controls; our ability to comply with the terms of our credit agreement or our indentures, or in the event of our breach of such terms, our ability to receive waivers or amendments from the lenders under our credit agreement or the trustee under our indentures; potential alternative financing arrangements; our ability to continue to bid successfully on new projects and accurately forecast costs associated with unit-price or lump sum contracts; our ability to obtain surety bonds as required by some of our customers; decreases in outsourcing work by our customers; changes in oil and gas prices; shut-downs or cutbacks at major businesses that use our services; changes in laws or regulations, third party relations and approvals, and decisions of courts, regulators and governmental bodies that may adversely affect our business or the business of the customers we serve; our ability to purchase or lease equipment; our ability to hire and retain a skilled labor force; provincial, regional and local economic, competitive and regulatory conditions and developments; technological developments; capital markets conditions; inflation rates; foreign currency exchange rate fluctuations; interest rates; weather conditions; the timing and success of business development efforts; and our ability to successfully identify and acquire new businesses and assets and integrate them into our existing operations and the other risk factors set forth herein under “Risk Factors.” You are cautioned not to put undue reliance on any forward-looking statements, and we undertake no obligation to update those statements.

Common Share Offering and Amalgamation

We filed a registration statement dated November 21, 2006 in the United States and a final prospectus dated November 22, 2006 in Canada regarding the initial public offering of 8,750,000 voting common shares and the secondary offering of 3,750,000 voting common shares for $18.38 per share (U.S.$16.00 per share). On November 22, 2006, and November 28, 2006, our common shares commenced trading on the New York Stock Exchange and the Toronto Stock Exchange, respectively. We received net proceeds of $143.4 million related to the initial public offering (gross proceeds of $160.8 million, less underwriting discounts and costs and offering expenses of $17.4 million). In addition, the underwriters have an option to purchase a maximum of 937,500 additional common shares from the Company and 937,500 additional common shares from the selling shareholders to cover over-allotments.

On November 28, 2006, prior to the consummation of the offering, the NACG Holdings Inc. amalgamated with its wholly-owned subsidiary, NACG Preferred Corp., and North American Energy Partners Inc. The amalgamated entity continued as North American Energy Partners Inc. The voting common shares of the new entity, North American Energy Partners Inc., were the shares offered in the initial public and secondary offering.

On November 28, 2006, prior to the amalgamation referred to above, we repurchased the NAEPI Series A preferred shares for their redemption value of $1.0 million and cancelled the consulting and advisory services agreement with The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp. (collectively, the “Sponsors”), under which we had received ongoing consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. The consideration paid for the cancellation of the consulting and advisory services agreement on the closing of the offering was $2.0 million, which will be recognized as an expense in the financial statements three months ended December 31, 2006. Under the consulting and advisory services agreement, the Sponsors also received a fee of $804, 0.5% of our aggregate gross proceeds from the offering.

On November 28, 2006, each holder of NAEPI Series B preferred shares received 100 common shares of the Company for each NAEPI Series B preferred share held, as a result of us exercising our conversion option under the Put/Call Agreement.

The net proceeds from the offering, after deducting underwriting fees and estimated offering expenses, together with borrowings under our revolving credit facility:

•

were used to repurchase all of our outstanding 9% senior secured notes due 2010 for $74.7 million plus accrued interest of $3.0 million on November 28, 2006. The notes were redeemed at a premium of 109.26% resulting in a loss on extinguishment of approximately $6.3 million and the write-off of deferred financing fees of approximately $4.3 million (both amounts are on a pre-income tax basis) and both charges will be recognized in the three months ended December 31, 2006;

•

were used to repay the promissory note in respect of the repurchase of the NACG Preferred Corp. Series A preferred shares of $27.0 million as described above; and

•

will be used to purchase certain equipment currently under operating leases for approximately $45.0 million.

Overview

We provide services primarily to major oil and natural gas, and other natural resource companies operating in western Canada. These services are offered through three operating segments: Mining and Site Preparation, Piling and Pipeline.

The Mining and Site Preparation operating segment, accounting for 77.0% and 78.9% of revenues for the three and six months ended September 30, 2006, respectively, is involved in a variety of activities, including: surface mining for oil sands and other natural resources, including overburden removal, hauling sand and gravel and supplying labor and equipment to support customers’ mining

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

operations; construction of infrastructure associated with mining operations and reclamation activities; clearing, stripping, excavating and grading for mining operations and industrial site construction for mega-projects; and underground utility installation for plant, refinery and commercial construction.

The Piling operating segment, accounting for 20.8% and 18.7% of revenues for the three and six months ended September 30, 2006, respectively, installs all types of driven and drilled piles, caissons and earth retention and stabilization systems for industrial projects primarily focused in the oil sands and related petrochemical or refinery complexes, as well as commercial buildings and infrastructure projects.

The Pipeline operating segment, accounting for 2.2% and 2.4% of revenues for the three and six months ended September 30, 2006, respectively, installs transmission and distribution pipe made of various materials for oil, natural gas and water.

Description of Components of Statement of Operations

Revenue

Revenue includes all amounts earned from the performance of our projects, including amounts arising from change orders and claims. For a description of our revenue recognition policy, refer to note 2(c) to our consolidated financial statements for the year ended March 31, 2006.

Project costs

Included in project costs are all direct expenses incurred in the execution of our projects, including direct labor, short-term equipment rentals, materials and subcontractor expenses.

Equipment costs

Included in equipment costs are parts, shop labor and overhead related to the maintenance of our equipment fleet. Equipment insurance premiums and demobilization costs are also included in equipment costs.

Operating lease expense

Lease payments on plant and equipment, other than payments on capital leases, are recorded as operating lease expense.

Depreciation

Depreciation includes amortization of our plant and equipment. For a description of our depreciation policy, please see note 2(g) to our consolidated financial statements for the year ended March 31, 2006.

General and administrative

General and administrative expenses include administrative and other expenses that are not directly attributable to the execution of our contracts. These would include, but are not limited to, management and administrative salaries and wages; non-equipment related insurance, professional fees, office and computer expenses, travel and stock based compensation.

Amortization of intangible assets

Amortization of intangible assets includes the amortization of our intangible assets, being customer contracts, trade names, non-competition agreements and employee arrangements.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

Interest expense

Interest expense includes the interest on our 9% senior secured notes, 8 3/4% senior notes, revolving credit facility and capital lease obligations. Interest expense also includes amortization of deferred financing costs, the change in redemption value of the Series B preferred shares until March 30, 2006 and the accretion of the Series A preferred shares and Series B preferred shares (subsequent to March 30, 2006) to their redemption values.

Foreign exchange gain

Foreign exchange gain includes realized and unrealized foreign currency gains or losses on our 9% senior secured notes and 8 3/4% senior notes, as well as miscellaneous currency gains or losses realized on the settlement of payables in the normal course of operations.

Financing costs

Costs incurred in the course of financing or refinancing debt obligations, and which cannot be deferred for accounting purposes, are included in financing costs. Deferred financing costs associated with debt that has been retired are also written off and recorded as financing costs.

Realized and unrealized loss on derivative financial instruments

The foreign currency risk relating to both the principal and interest payments on the 8 3/4% senior notes has been managed with a cross currency and interest rate swaps which went into effect concurrent with the issuance of the same notes. The swaps on the 8 3/4% senior notes do not qualify for hedge accounting under CICA Accounting Guideline 13 and are remeasured at fair value each reporting period and the changes in fair value are recorded under the caption “Realized and unrealized loss on derivative financial instruments” in our consolidated financial statements. For more information regarding our derivative financial instruments, refer to note 19(c) to our consolidated financial statements for the year ended March 31, 2006.

Other Income

Other income is non-operating revenue resulting from interest income and other miscellaneous income sources.

Income taxes

Income and capital taxes, as well as the impact of changes in our future income tax assets and liabilities are included in income taxes.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

Consolidated and Financial Results


	Three Months Ended September 30										Six Months Ended September 30
	2006					2005					2006					2005
	(In Millions)										(In Millions)
Revenue	$	130.1		100.0	%	$	124.0		100.0	%	$	268.1		100.0	%	$	228.4		100.0	%
Project costs		73.1		56.2	%		79.2		63.9	%		140.1		52.3	%		145.8		63.8	%
Equipment costs		25.6		19.7	%		14.3		11.5	%		49.5		18.5	%		31.3		13.7	%
Operating lease expense		6.4		4.9	%		3.1		2.5	%		13.6		5.1	%		6.0		2.6	%
Depreciation		4.8		3.7	%		5.5		4.4	%		12.1		4.5	%		10.5		4.6	%

Gross profit		20.2		15.5	%		21.9		17.7	%		52.8		19.7	%		34.8		15.2	%
General and administrative		10.0		7.7	%		6.5		5.2	%		19.2		7.2	%		13.7		6.0	%
Loss on disposal of plant and equipment		0.3		0.2	%		(0.6	)	-0.5	%		0.5		0.2	%		(0.3	)	-0.1	%
Amortization of intangible assets		0.2		0.2	%		0.2		0.2	%		0.4		0.1	%		0.4		0.2	%

Operating income		9.7		7.5	%		15.9		12.8	%		32.8		12.2	%		21.1		9.2	%
Interest expense		10.3		7.9	%		3.3		2.7	%		20.5		7.6	%		53.2		23.3	%
Foreign exchange loss (gain)		0.1		0.1	%		(16.5	)	-13.3	%		(13.4	)	-5.0	%		(15.2	)	-6.7	%
Realized and unrealized loss on derivative financial instruments		3.8		2.9	%		17.5		14.1	%		11.8		4.4	%		18.8		8.2	%
Financing costs		0.1		0.1	%		—		0.0	%		0.1		0.0	%		2.1		0.9	%
Other income		—		0.0	%		(0.1	)	-0.1	%		(0.6	)	-0.2	%		(0.3	)	-0.1	%

Income (loss) before income taxes		(4.6	)	-3.5	%		11.6		9.4	%		14.4		5.4	%		(37.5	)	-16.4	%
Income taxes		0.2		0.2	%		0.1		0.1	%		1.3		0.5	%		0.2		0.1	%

Net income (loss)	$	(4.8	)	-3.7	%	$	11.5		9.3	%	$	13.1		4.9	%	$	(37.7	)	-16.5	%

EBITDA(1)	$	10.7		8.2	%	$	20.6		16.6	%	$	47.4		17.7	%	$	26.6		11.6	%

Consolidated EBITDA(1)	$	15.7		12.1	%	$	21.3		17.2	%	$	47.3		17.6	%	$	28.9		12.7	%

Segmented Results of Operations
Revenue by operating segment:
Mining and site preparation	$	100.2		77.0	%	$	93.5		75.4	%	$	211.7		78.9	%	$	176.1		77.1	%
Piling		27.0		20.8	%		22.1		17.8	%		50.2		18.7	%		42.3		18.5	%
Pipeline		2.9		2.2	%		8.4		6.8	%		6.3		2.4	%		10.0		4.4	%

Total	$	130.1		100.0	%	$	124.0		100.0	%	$	268.2		100.0	%	$	228.4		100.0	%

Profit by operating segment:
Mining and site preparation	$	12.5		56.3	%	$	9.5		59.0	%	$	38.6		70.2	%	$	20.1		67.2	%
Piling		9.3		41.9	%		4.8		29.8	%		15.3		27.8	%		7.9		26.4	%
Pipeline		0.4		1.8	%		1.8		11.2	%		1.1		2.0	%		1.9		6.4	%

Total	$	22.2		100.0	%	$	16.1		100.0	%	$	55.0		100.0	%	$	29.9		100.0	%

Equipment hours by operating segment:
Mining and site preparation		222,997		94.2	%		217,317		90.0	%		454,142		94.5	%		392,031		93.3	%
Piling		11,085		4.7	%		9,636		0.0	%		21,200		4.4	%		17,088		4.1	%
Pipeline		2,629		1.1	%		7,696		3.3	%		5,374		1.1	%		11,280		2.7	%

Total		236,711		100.0	%		234,649		93.3	%		480,716		100.0	%		420,399		100.1	%

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

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 and loss or gain on disposal of plant and equipment. We believe that Consolidated 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 Consolidated EBITDA to determine whether capital assets are being allocated efficiently. In addition, our revolving credit facility contains financial covenants based on a definition of Consolidated EBITDA. Non-compliance with this financial covenant could result in our being required to immediately repay all amounts outstanding under our revolving credit facility. We are required to maintain a minimum rolling twelve month Consolidated EBITDA through December 31, 2006 of $65.5 million, with this minimum amount increasing periodically until maturity. The Company’s Consolidated EBITDA for the twelve months ended September 30, 2006 is in excess of $65.5 million. However, Consolidated EBITDA is not a measure of performance under Canadian GAAP or U.S. GAAP and our computations of Consolidated EBITDA may vary from others in our industry. Consolidated EBITDA should not be considered as an alternative to operating income or net income as a measure of operating performance or cash flow as a measure of liquidity. Consolidated EBITDA has important limitations as an analytical tool, and you should not consider it in isolation, or as a substitute 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 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.

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


	For the Three Months Ended September 30						For the Six Months Ended September 30
	2006			2005			2006			2005
	(In Millions)						(In Millions)
Net income (loss)	$	(4.8	)	$	11.5		$	13.1		$	(37.7	)
Adjustments:
Interest expense		10.3			3.3			20.5			53.2
Amortization of intangible assets		0.2			0.2			0.4			0.4
Depreciation		4.8			5.5			12.1			10.5
Income taxes		0.2			0.1			1.3			0.2

EBITDA		10.7			20.6			47.4			26.6

EBITDA		10.7			20.6			47.4			26.6
Adjustments:
Unrealized foreign exchange (gain) loss on senior notes		0.1			(16.3	)		(13.5	)		(15.4	)
Loss on disposal of plant and equipment		0.3			(0.6	)		0.5			(0.3	)
Stock-based compensation		0.8			0.1			1.1			0.3
Realized and unrealized loss on derivative financial instruments		3.8			17.5			11.8			18.8

Consolidated EBITDA	$	15.7		$	21.3		$	47.3		$	30.0

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

For the Three and six Months Ended September 30, 2006 Compared to the Three and six Months Ended September 30, 2005

Revenue. Revenue increased by $6.1 million, or 4.9%, from $124.0 million for the three months ended September 30, 2005 to $130.1 million for the three months ended September 30, 2006. Revenue increased by $39.7 million, or 17.4%, from $228.4 million for the six months ended September 30, 2005 to $268.1 million for the six months ended September 30, 2006.

•

Mining and Site Preparation. Mining and Site Preparation revenue increased by $6.7 million, or 7.2%, from $93.5 million for the three months ended September 30, 2005 to $100.2 million for the three months ended September 30, 2006. For the six months ended September 30, 2006 revenue increased by $35.6 million, or 20.2%, from $176.1 million for the six months ended September 30, 2005 to $211.7 million. The increase was primarily due to increased activity in fiscal 2007 related to a large site preparation project for Shell and the continued ramp up on the CNRL overburden removal project in the Fort McMurray region. Additionally, there was a claim settlement arising from a site preparation project completed during fiscal 2005 in which $6.1 million was recognized as revenue for the six months ended September 30, 2006.

•

Piling. Piling revenue increased by $4.9 million, or 22.2%, from $22.1 million for the three months ended September 30, 2005 to $27.0 million for the three months ended September 30, 2006 and increased by $7.9 million, or 18.7%, from $42.3 million for the six months ended September 30, 2005 to $50.2 million for the six months ended September 30, 2006. The increase was primarily due to a higher volume of projects in the Fort McMurray and Calgary regions because of strong economic environment and construction activities.

•

Pipeline. Pipeline revenue decreased by $5.5 million, or 65.5%, from $8.4 million for the three months ended September 30, 2005 to $2.9 million for the three months ended September 30, 2006 and decreased by $3.7 million, or 37.0%, from $10.0 million for the six months ended September 30, 2005 to $6.3 million for the six months ended September 30, 2006. The reduction is due to reduced work from the primary segment customer, Encana.

Project costs. Project costs decreased by $6.1 million, or 7.7%, from $79.2 million for the three months ended September 30, 2005 to $73.1 million for the three months ended September 30, 2006 and decreased by $5.7 million, or 3.9%, from $145.8 million for the six months ended September 30, 2005 to $140.1 million for the six months ended September 30, 2006. The decrease in project costs compared to the increase in revenue is primarily due to improved margins for the mining and site preparation division and the piling division. As a percentage of revenue, project costs were 56.2% and 52.3% in the three and six months ended September 30, 2006, respectively, as compared to 63.9% and 63.8% in the three and six months ended September 30, 2005, respectively. This improvement was primarily due to better margins on site preparation and piling projects.

Equipment costs. Equipment costs increased by $11.3 million, or 79.0%, from $14.3 million for the three months ended September 30, 2005 to $25.6 million for the three months ended September 30, 2006 and increased by $18.2 million, or 58.1%, from $31.3 million for the six months ended September 30, 2005 to $49.5 million for the six months ended September 30, 2006. The increase was primarily due to increased fleet size and activity levels; higher repair and maintenance costs caused by increased usage of larger equipment, increased cost of parts and overhead and shop costs. As a percentage of revenue, equipment costs were 19.7% and 18.5% during the three and six months ended September 30, 2006, respectively, as compared to 11.5% and 13.7% during the three and six months ended September 30, 2005, respectively.

Equipment operating lease expense. Operating lease expense increased by $3.3 million, or 106.5%, from $3.1 million for the three months ended September 30, 2005 to $6.4 million for the three months ended September 30, 2006 and increased by $7.6 million, or 126.7%, from $6.0 million for the six months ended September 30, 2005 to $13.6 million for the six months ended September 30, 2006. The increase was primary due to the addition of new leased equipment to support new projects, including the 10-year CNRL overburden project.

Depreciation. Depreciation expense decreased by $0.7 million, or 12.7%, from $5.5 million for the three months ended September 30, 2005 to $4.8 million for the three months ended September 30, 2006 and increased by $1.6 million, or 15.2%, from $10.5 million for the six months ended September 30, 2005 to $12.1 million for the six months ended September 30, 2006. The decrease for the

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

three months ended September 30, 2006 was primarily due to the greater utilization of leased equipment resulting in lower depreciation of owned equipment. The increase for the six months ended September 30, 2006 was primarily due to the additional equipment hours related to higher activity levels, as our heavy equipment fleet is depreciated based on operated hours. As a percentage of revenue, depreciation decreased to 3.7% and 4.5% for the three and six months ended September 30, 2006, respectively, from 4.4% and 4.6% from the respective prior year reporting periods, primarily due to our use of more leased equipment relative to owned equipment.

Gross profit. Gross profit decreased by $1.7 million, or 7.8%, from $21.9 million for the three months ended September 30, 2005 to $20.2 million for the three months ended September 30, 2006. For the six months ended gross profit increased by $18.0 million, or 51.7%, from $34.8 million for the six months ended September 30, 2005 to $52.8 million. As a percentage of revenue, gross profit decreased to 15.5% for the three months ended September 30, 2006 from 17.7% for the three months ended September 30, 2005, primarily due to the increase in equipment costs and operating lease expense which has been partially offset by the increase in revenue and improved project performance. As a percentage of revenue, gross profit increased to 19.7% for the six months ended September 30, 2006 from 15.2% for the six months ended September 30, 2005, primarily due to the increase in revenue, improved project performance and the recognition of $6.1 million of claim revenue which has been partially offset by the increase in equipment costs, operating lease expense and depreciation.

Segment profit

•

Mining and Site Preparation. Mining and Site Preparation operating segment profit increased by $3.0 million and $18.5 million over the three and six months ended September 30, 2005, respectively. This was primarily due to increased project activity and better margins compared to prior period’s project work, as discussed above. Additionally, there was a claim settlement arising from a site preparation project completed during fiscal 2005 in which $6.1 million was recognized as revenue for the six months ended September 30, 2006.

•

Piling. Piling operating segment profit increased $4.5 million and $7.4 million over the three and six months ended September 30, 2005, respectively. This was due to increased volume and higher margin work primarily in the Fort McMurray and Calgary regions as discussed above.

•

Pipeline. Pipeline operating segment profit decreased by $1.4 million and $0.8 million compared to the three and six months ended September 30, 2005, respectively. This is primarily due to reduced work from the primary segment customer, Encana.

General and administrative expenses. General and administrative expenses increased by $3.5 million, or 53.8%, from $6.5 million for the three months ended September 30, 2005 to $10.0 million for the three months ended September 30, 2006 and increased by $5.5 million, or 40.1%, from $13.7 million for the six months ended September 30, 2005 to $19.2 million for the six months ended September 30, 2006. The increase was primarily due to increased salaries as a result of bonus accruals resulting from our improved financial performance and higher professional fees for audit, legal and general consulting requirements compared to the three and six months ended September 30, 2005. As a percentage of revenue, general and administrative expenses were 7.7% and 7.2% for the three and six months ended September 30, 2006, respectively, compared to 5.2% and 6.0% for the three and six months ended September 30, 2005, respectively.

Amortization of intangible assets. Amortization of intangible assets was the same as the prior year period at $0.2 million and $0.4 million for the three and six months ended September 30, 2006. The amortization of intangible assets during the three months ended September 30, 2006 and 2005 was related to trade names.

Operating income. Operating income decreased by $6.2 million, or 39.0%, from $15.9 million for the three months ended September 30, 2005 to $9.7 million for the three months ended September 30, 2006 and increased by $11.7 million, or 55.5%, from $21.1 million for the six months ended September 30, 2005 to $32.8 million for the six months ended September 30, 2006. The decrease for the three months ended September 30, 2006 was primarily due to the $3.5 million increase in general and administrative expenses and the $1.7 million decrease in gross profit. There was also a $0.9 million decrease due to a $0.6 million profit on disposal of plant and equipment for the three months ended September 30, 2005 being realized compared to a $0.3 million loss on disposal of plant and equipment for the three months ended September 30, 2006. The increase for the six months ended September 30, 2006 was primarily due to the $18.0 million increase in gross profit, partially offset by the $5.5 million increase in general and administrative expenses. There has also been a $0.8 million decrease due to a $0.5 million profit on disposal of plant and equipment being realized for the six months ended September 30, 2005 compared to a $0.3 million loss on disposal of plant and equipment for the six months ended September 30, 2006.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

Interest expense. Interest expense increased by $7.0 million, or 212.1%, from $3.3 million for the three months ended September 30, 2005 to $10.3 million for the three months ended September 30, 2006. The increase was primarily due to the change in the redemption value of the Series B preferred shares recorded in fiscal 2006 offset by accretion expense recorded in fiscal 2007, which resulted in reduction of interest expense of $5.0 million for the three months ended September 30, 2005. As a result of the amendment of the Series B preferred shares on March 30, 2006, interest expense is now being accreted from the carrying value of the Series B shares on that date of $42.2 million to their redemption amount of $69.6 million in 2011. The company recorded $0.9 million of accretion as interest expense on the amended Series B preferred shares for the three months ended September 30, 2006.

Interest expense decreased by $32.7 million, or 61.5%, from $53.2 million for the six months ended September 30, 2005 to $20.5 million for the six months ended September 30, 2006. The reduction in interest expense for the six months ended September 30, 2006 was primarily due to the issuance of the Series B preferred shares in May 2005 and the requirement to record changes in the redemption value of the Series B preferred shares from the date of issuance to September 30, 2005 as interest expense. The shares were issued on May 19, 2005 for cash proceeds of $7.5 million and by the end of September 30, 2005 the redemption value was $44.8 million, resulting in interest expense of $36.5 million for the six months ended September 30, 2005. The company recorded $1.9 million of accretion as interest expense on the amended Series B preferred shares for the six months ended September 30, 2006.

Foreign exchange gain. We recognized a foreign exchange loss of $0.1 million for the three months ended September 30, 2006 as compared to a gain of $16.5 million for the three months ending September 30, 2005 and we recognized a gain of $13.4 million for the six months ended September 30, 2006 as compared to a gain of $15.2 million for the prior period ending September 30, 2005. Substantially all of the gain in the three and six months ended September 30, 2005 and the six months ended September 30, 2006 relates to the exchange difference between the Canadian and U.S. dollar on translation of the US$60.5 million of 9% senior secured notes issued in May 2005 and the US$200.0 million of 8 3/4% senior notes. In the three months ended September 30, 2006 there was very little variation in the Canadian/U.S. dollar exchange rate.

Realized and unrealized loss on derivative financial instruments. The realized and unrealized loss on derivative financial instruments totaled $3.8 million and $11.8 million for the three and six months ended September 30, 2006, respectively. The loss relates primary to the change in the fair value of the derivatives, which are economic hedges related to our 8 3/4% senior notes. The realized and unrealized loss on the derivative financial instruments totaled $17.5 million and $18.8 million for the three and six months ended September 30, 2005, respectively.

Financing costs. Financing costs were $0.1 million for the three and six months ended September 30, 2006 compared to nil and $2.1 million for the three and six ended September 30, 2005, respectively. The prior fiscal year to date financing costs was a result of $1.8 million of deferred financing costs relating to the previous senior secured credit facility being written off in the three months ended June 30, 2005.

Income taxes. Income tax expense was $0.2 million and $1.3 million for the three and six months ended September 30, 2006, respectively, as compared to $0.1 million and $0.2 million for the three and six months ended September 30, 2005, respectively. The Company’s effective income tax rate differs from the statutory rate of 33.62% in fiscal 2006 primarily due to the recognition of a valuation allowance recorded against its net future income tax asset given the uncertainty of recognizing the benefit of the net future tax asset. The Company’s effective income tax rate differs from the statutory rate of 32.12% in fiscal 2007 primarily due to permanent differences relating to certain financing transactions which were not deductible for tax purposes, accruals for certain tax exposure items and the reversal of the valuation, allowance that existed at the end of fiscal 2006, which was recorded in the three months ended June 30, 2006.

Comparative Quarterly Results

A number of factors contribute to variations in our results between periods, such as weather, customer capital spending on large oil sands and natural gas related 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.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006


	Fiscal Year 2007					Fiscal Year 2006									Fiscal Year 2005
	Q 2			Q 1		Q 4		Q 3		Q 2		Q 1			Q 4			Q 3
	(In millions of dollars, except earning per share calculation (EPS) and equipment hours)
Revenue(1)	$	130.1		$	138.1	$	142.3	$	121.5	$	124.0	$	104.4		$	122.7		$	81.0
Gross profit		20.2			32.6		31.7		13.8		21.9		12.9			24.0			(5.7	)
Net income (loss)		(4.8	)		17.9		13.7		2.1		11.5		(49.2	)		(0.1	)		(32.4	)
EPS - basic		(0.26	)		0.96		0.73		0.11		0.62		(2.65	)		(0.01	)		(1.75	)
EPS - diluted		(0.26	)		0.71		0.73		0.11		0.47		(2.65	)		(0.01	)		(1.75	)
Equipment hours		236,711			248,297		231,633		221,355		234,649		185,751			241,727			191,555

(1)

Effective April 1, 2005, the Company changed its accounting policy regarding the recognition of revenue on claims. This change in accounting policy has been applied retroactively. Prior to April 1, 2005, revenue from claims was included in total contract revenue when awarded or received. After April 1, 2005, claims are included in total contract revenue, only to the extent that contract costs related to the claim have been incurred and when it is probable that the claim will result in a bona fide addition to contract value and can be reliably estimated.

Consolidated Financial Position

At September 30, 2006, we had net working capital of $83.0 million compared to $69.5 million at March 31, 2006. The increase resulted from an increase in prepaid expenses and deposits of $15.7 million due to deposits on tires, an increase in accounts receivable of $5.4 million, an increase in other assets of $9.4 million, and increases in future income tax balances of $6.7 million. These increases were partially offset by a reduction in cash and cash equivalents and unbilled revenue of $6.0 million and $4.1 million, respectively, as well as an increase in accounts payable, accrued liabilities and billings in excess of cost incurred and estimated earnings on uncompleted contracts of $3.1 million, $6.5 million and $3.3 million, respectively.

Plant and equipment net of depreciation increased by $9.9 million at September 30, 2006 from March 31, 2006 as additional large construction equipment was acquired exceeding depreciation charges for the period.

Capital lease obligations, including the current portion, increased by $1.7 million at September 30, 2006 from March 31, 2006 due to the addition of new leased vehicles and a drill rig to support new projects exceeding required repayments.

Liquidity and Capital Resources

Operating activities

Operating activities for the three months ended September 30, 2006 resulted in a net increase in cash of $6.2 million compared to $9.4 million for the three months ended September 30, 2005. The reduced cash generated is due to the decrease in net income, which has been partially offset by increased add back of non-cash operating expenses and unfavorable movements in net non-cash working capital.

Operating activities for the six months ended September 30, 2006 resulted in a net increase in cash of $18.8 million compared to a decrease of $4.3 million for the six months ended September 30, 2005. The increased cash generated is due to the increase in net income, which has been partially offset by reduced add back of non-cash operating expenses and favorable movements in net non-cash working capital.

Investing activities

During the three and six months ended September 30, 2006, we invested $0.8 million and $1.4 million, respectively (three and six months ended September 30, 2005 – $4.9 million and $6.2 million, respectively), in sustaining capital expenditures and $9.2 million and $17.9 million, respectively (three and six months ended September 30, 2005 – $3.1 million and $13.1 million, respectively), in growth capital expenditures, for total capital expenditures of $10.0 million and $19.3 million, respectively (three and six months ended September 30, 2005 – $8.0 million and $13.8 million, respectively).

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

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

Financing activities

Financing activities during the three and six months ended September 30, 2006 resulted in a cash outflow of $3.1 million and $4.5 million, respectively, primarily as a result of financing costs in preparation of the company’s initial public offering and capital lease payments. Financing activities during the three and six months ended September 30, 2005 resulted in a net cash inflow of $0.3 million and $15.0 million, respectively. This six month change was a result of the proceeds we received from the issuance of the US$60.5 million of 9% senior secured notes and $7.5 million of Series B preferred shares, both issued May 19, 2005, which were used to repay the amount outstanding under our senior secured credit facility and to pay for the fees and expenses related to the refinancing.

In connection with our initial public offering of common shares on November 28, 2006, we received net proceeds of $143.4 million (gross proceeds of $160.8 million, less underwriting discounts and costs and offering expenses of $17.4 million).

On November 28, 2006, prior to our amalgamation with our wholly-owned subsidiaries, NACG Preferred Corp. and North American Energy Partners Inc., we acquired the NACG Preferred Corp. Series A preferred shares for a promissory note in the amount of $27.0 million and all accrued dividends at that time were forfeited.

On November 28, 2006, prior to the amalgamation referred to above, we acquired the NAEPI Series A preferred shares for their redemption value of $1.0 million and cancelled the consulting and advisory services agreement with The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp. (collectively, the “Sponsors”), under which we had received ongoing consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. The consideration paid for the cancellation of the consulting and advisory services agreement on the closing of the offering was $2.0 million. Under the consulting and advisory services agreement, the Sponsors also received a fee of $804, 0.5% of the aggregate gross proceeds to us from the offering.

The net proceeds from the offering, after deducting underwriting fees and estimated offering expenses, together with borrowings under our revolving credit facility, are being used to purchase certain equipment currently under operating leases of approximately $45.0 million, to repurchase all of our outstanding 9% senior secured notes due 2010 for approximately $75.9 million plus accrued interest of approximately $3.1 million, to repay the promissory note in respect of the acquisition of the NACG Preferred Corp. Series A preferred shares of $27.0 million as described above and to pay the $2.0 million fee to terminate the advisory services agreement with the Sponsors.

Liquidity Requirements

Our primary uses of cash are to purchase plant and equipment, fulfill debt repayment and interest payment obligations and finance working capital requirements.

We have outstanding US$200 million of 8³/4% senior notes due 2011. The foreign currency risk relating to both the principal and interest payments on the 8³/4% senior notes has been managed with a cross-currency swap and interest rate swaps which went into effect concurrent with the issuance on November 26, 2006. Interest of US$8.8 million is payable semi-annually in June and December of each year until the notes mature on December 1, 2011. The swap agreements are economic hedges of the changes in the Canadian dollar-U.S. dollar exchange rate, but they do not meet the criteria to qualify for hedge accounting. There are no principal payments required on the 8³/4% senior notes until maturity.

Our US$60.5 million of 9% senior secured notes were issued on May 19, 2005 pursuant to a private placement. On November 28, 2006, we repurchased all of the outstanding 9% senior secured notes.

One of our major contracts allows the customer to request up to $50 million in letters of credit. While this level has not been requested to date, we would either have to lower other letters of credit or cash collateralize other obligations to provide this amount of letters of credit.

We maintain a significant equipment and vehicle fleet comprised of units with various remaining useful lives. Once units reach the end of their useful lives, it becomes cost prohibitive to continue to maintain them and, therefore, they must be replaced. As a result, we are continually acquiring new equipment to replace retired units and to expand the fleet to meet growth as new projects are awarded to us. It is important to adequately maintain the 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. In order to maintain a balance of owned and leased equipment, we have financed a portion of large pieces of heavy construction equipment through operating leases. In addition, we continue to lease a portion of our motor vehicle fleet.

Our cash requirements during the three months ended September 30, 2006 increased due to continued growth and additional operating and capital expenditures associated with new projects. Our cash requirements for fiscal 2007 include funding operating lease obligations, debt and interest repayment obligations and working capital as activity levels are expected to continue to increase. In addition, we will require capital to finance further vehicle and equipment acquisitions for new projects.

We expect our sustaining capital expenditures to range from $25 million to $30 million per year over the next two years. We expect our total capital expenditures in fiscal 2007 to range from $50 million to $60 million, which does not include any payout of current operating leases. It is our belief that working capital 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. On July 19, 2006, we amended and restated our revolving credit facility to provide for borrowings of up to $55.0 million (previously $40.0 million), subject to borrowing base limitations, under which revolving loans and letters of credit may be issued (previously up to a limit of $30.0 million). As of September 30, 2006, we had approximately $37.0 million of available borrowings under the revolving credit facility

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

after taking into account $18.0 million of outstanding and undrawn letters of credit to support bonding requirements and performance guarantees associated with customer contracts and operating leases. Prime rate revolving loans under the amended and restated agreement will bear interest at the Canadian prime rate plus 2.0% per annum and swing line revolving loans will bear interest at the Canadian prime rate plus 1.5% per annum. Canadian bankers’ acceptances have stamping fees equal to 3.0% per annum and letters of credit are subject to a fee of 3.0% per annum. The indebtedness under the revolving credit facility, including the liability under the swaps used to manage the foreign currency risk on the 8³/4% senior notes, is secured by substantially all of our assets and those of our subsidiaries.

Our revolving credit facility contains covenants that restrict our activities, including restrictions on creating liens, engaging in mergers, consolidations and sales of assets, incurring additional indebtedness, giving guaranties, engaging in different businesses, making loans and investments, making certain capital expenditures and making certain dividend, debt and other restricted payments. Under the revolving credit facility, we also are required to satisfy certain financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum Consolidated EBITDA requirement. Consolidated EBITDA is defined in the credit facility as the sum, without duplication, of (1) consolidated net income, (2) consolidated interest expense, (3) provisions 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, and (8) other non-cash items (other than any such non-cash item to the extent it represents an accrual of or reserve for cash expenditures in any future period), but only, in the case of clauses (2)-(8), to the extent deducted in the calculation of consolidated net income, less other non-cash items added in the calculation of consolidated net income (other than any such non-cash item to the extent it will result in the receipt of cash payments in any future period), all of the foregoing as determined on a consolidated basis for us in conformity with GAAP. The required minimum trailing twelve month Consolidated EBITDA through December 31, 2006 is $65.5 million, and this minimum amount increases periodically until the credit facility matures. We believe Consolidated EBITDA as defined in the credit facility is an important measure of our liquidity.

The Series B preferred shares were initially issued for net cash proceeds of $7.5 million on May 19, 2005 to existing NACG Holdings Inc. common shareholders. For additional information on the Series B preferred shares, see note 14(a) (ii) to our consolidated financial statements for the year ended March 31, 2006.

Between March 31, 2004 and May 19, 2005, it was necessary to obtain a series of waivers and amend our then-existing credit agreement to avoid or to cure our default of various covenants contained in that credit agreement. We ultimately replaced that credit agreement with a new credit agreement on May 19, 2005, which we replaced with our current amended and restated credit agreement on July 19, 2006.

Our inability to file our financial statements for the periods ended December 31, 2004, March 31, 2005 and September 30, 2005 with the SEC within the deadlines imposed by covenants in the indentures governing our 8³/4% senior notes and our 9% senior secured notes caused us to not be in compliance with such covenants. In each case, we filed our financial statements before the lack of compliance became an event of default under the indentures.

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 and as a result, the definition and determination 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 did not measure this amount in prior periods.

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 six months ended September 30, 2006, our contract revenue consisted of 15% cost-plus, 38% time-and-materials, 35% unit-price and 12% lump sum. Our definition of backlog results in cost-plus and time-and-material contracts performed under master service agreements, being excluded from the calculation of backlog because, while a contract exists, the work scope and value are not clearly defined under such contracts. For the six months ended September, 2006, the total amount of all cost-plus and time-and-material based revenue was $144.4 million (53% of total revenues).

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

Our backlog as at September 30, 2006 is: (in millions of dollars)

By Segment


Mining & Site Preparation	$	745.6
Piling		8.3
Pipeline		20.1

Total	$	774.0

By Contract Type


Unit Price	$	771.7
Lump Sum		2.3

Total	$	774.0

A contract with a single customer represented $556.0 million of this backlog. It is expected that $183.9 million of the backlog will be performed and realized in the 12 months ended September 30, 2007.

Contractual Obligations and Other Commitments

Our principal contractual obligations relate to our long-term debt (8³/4% senior notes and 9% senior secured notes), preferred shares, and capital and operating leases. The following table summarizes our future contractual obligations, excluding interest payments unless otherwise noted, as of September 30, 2006.


	Payments Due by Fiscal Year
	Total		2007		2008		2009		2010		2011 and After
	(In millions)
Long-term debt (a)	$	290.4	$	—	$	—	$	—	$	—	$	290.4
NAEPI Series A preferred shares(b)		1.0		—		—		—		—		1.0
NACG Pref Corp Series A Preferred Shares(b)		35.0										35.0
Series B preferred shares(b)		69.6		—		—		—		—		69.6
Capital leases (including interest)		13.8		4.3		3.9		3.2		1.9		0.5
Operating leases		61.8		12.7		20.4		12.5		10.9		5.3

Total contractual obligations	$	471.6	$	17.0	$	24.3	$	15.7	$	12.8	$	401.8

(a)

Includes $223.1 million related to our 8³/4% senior notes and $67.5 million related to our 9% senior secured 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, 2006 the carrying value of the derivative financial instruments was $74.0 million. On November 28, 2006 we repurchased all of the outstanding 9% senior secured notes.

(b)	Reflected at redemption value.

Off-Balance Sheet Arrangements

As of September 30, 2006, we had $18.0 million of outstanding, undrawn letters of credit issued under our revolving credit facility.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

Stock-Based Compensation

Some of our directors, officers, employees and service providers have been granted options to purchase common shares of the Company under the stock-based compensation plan. In September 2006, we granted 187,760 options with an exercise price of $16.75 per share. In September 2006, we had a valuation performed by an unrelated valuation specialist, which valued the common shares at $16.10 per share. The plan and outstanding balances are disclosed in note 11 to our interim consolidated financial statements for the three and six months ended September 30, 2006.

Critical Accounting Policies and 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 the contracts are generally less than one year in duration, we do have several long-term contracts.

•

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

•

Time-and-materials. A time-and-materials contract involves using the components of a cost-plus job to calculate rates for the supply of labor and equipment. In this regard, all components of the rates are fixed and we are compensated for each hour of labor and equipment supplied. The risk associated with this type of contract is the estimation of the rates and incurring expenses in excess of a specific component of the agreed upon rate. Therefore, any cost overrun must come out of the fixed margin included in the rates. Revenue is recognized as the labor, equipment, materials, subcontract costs and other services are supplied to the customer.

•

Unit-price. A unit-price contract is utilized in the execution of projects with large repetitive quantities of work and is commonly utilized for site preparation, mining and pipeline work. We are compensated for each unit of work we perform (for example, cubic meters of earth moved, lineal meters of pipe installed or completed piles). Within the unit price contract, there is an allowance for labor, equipment, materials and any subcontractor’s costs. Once these costs are calculated, we add any site and corporate overhead costs along with an allowance for the margin we want to achieve. The risk associated with this type of contract is in the calculation of the unit costs with respect to completing the required work. Typically these contracts permit cost escalation to allow for recovery of costs from changing conditions and other unforeseen events. Revenue on unit-price contracts is recognized using the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total cost.

•

Lump sum. A lump sum contract is utilized when a detailed scope of work is known for a specific project. Thus, the associated costs can be readily calculated and a firm price provided to the customer for the execution of the work. The risk lies in the fact that there is no escalation of the price if the work takes longer or more resources are required than were estimated in the established price. The price is fixed regardless of the amount of work required to complete the project. Revenue on lump sum contracts is recognized using the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total cost.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

The mix of contract types varies year-by-year. For the three months ended September 30, 2006, our contract revenue consisted of 13% cost-plus, 33% time-and-materials, 35% unit-price and 19% lump sum. For the six months ended September 30, 2006, our contract revenue consisted of 15% cost-plus, 38% time-and-materials, 35% unit-price and 12% 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. Change orders are included in total estimated contract revenue when it is probable that the change order will result in a bona fide addition to contract value and can be reliably estimated. Revenue in excess of costs from unpriced change orders, extra work and variations in the scope of work is recognized after both the costs are incurred or services are provided and realization is assured beyond a reasonable doubt. Claims are included in total estimated contract revenue, only to the extent that contract costs related to the claim have been incurred, when it is probable that the claim will result in a bona fide addition to contract value and the amount of revenue can be reliably estimated. Costs incurred for bidding and obtaining contracts are expensed as incurred.

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 progress at any given time, these changes in estimates can offset each other without materially impacting our profitability. However, large changes in cost estimates, particularly in the bigger, 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 plant and equipment has a long life 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 each day based on actual operated hours.

Another key estimate is the expected cash flows from the use of an asset and the expected disposal proceeds in applying CICA 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 to be held and used 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. Equally important is the expected fair value of assets that are available-for-sale.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

Goodwill

We perform our annual goodwill impairment test on December 31 of each year, and more frequently if events or changes in circumstances indicate that an impairment loss may have been incurred. 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 values 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.

Derivative financial instruments

We use derivative financial instruments to manage economic risks from fluctuations in exchange rates and interest rates. These instruments include cross-currency swap agreements and interest rate swap agreements. These instruments are only used for risk management purposes. We do not hold or issue derivative financial instruments for trading or speculative purposes. Derivative financial instruments are subject to standard credit terms and conditions, financial controls, management and risk monitoring procedures.

Our derivative financial instruments are recorded on the balance sheet at fair value, which is determined based on values quoted by the counterparties to the agreements.

Series B Preferred Shares

Prior to our amendment of the terms of the Series B preferred shares on March 30, 2006, the definition of the redemption price of the Series B preferred shares included a calculation tied to the fair value of the common shares of North American Energy Partners Inc. Under the redemption price, any increase or decrease in the fair value of North American Energy Partners’ common shares resulted in a corresponding increase or decrease in the redemption value of the series B preferred shares based on 25% of the change in fair value of the common shares and, as a consequence, fluctuations in interest expense. The amendment eliminated this calculation from the definition of redemption price. As a result, the Series B preferred shares are now accreted from $42.2 million to their December 31, 2011 redemption value of $69.6 million, with corresponding periodic charges to interest expense. Please see note 14 (a) to our consolidated financial statements for the year ended March 31, 2006 for more information on the Series B Preferred Shares.

Recent Canadian Accounting Pronouncements Not Yet Adopted

Financial instruments

In January 2005, the CICA issued Handbook Section 3855, “Financial Instruments — Recognition and Measurement”, 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 for the fiscal year beginning April 1, 2007 for us. Earlier adoption is permitted. The new standards will require presentation of a separate statement of comprehensive income under specific circumstances. Foreign exchange gains and losses on the translation of the financial statements of self-sustaining subsidiaries previously recorded in a separate section of shareholder’s equity will be presented in comprehensive income. Derivative financial instruments will be recorded in the balance sheet at fair value and the changes in fair value of derivatives designated as cash flow hedges will be reported in comprehensive income. We are currently assessing the impact of the new standards.

U.S. Generally Accepted Accounting Principles

Our interim 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 15 to our interim consolidated financial statements three months ended September 30, 2006.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

United States accounting pronouncements recently adopted

Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (“SFAS 123R”) requires companies to recognize in the income statement, the grant-date fair value of stock options and other equity-based compensation issued to employees. The fair value of liability-classified awards is remeasured subsequently at each reporting date through the settlement date, while the fair value of equity- classified awards is not subsequently remeasured. The revised standard is effective for non-public companies beginning with the first annual reporting period that begins after December 15, 2005, which in our case was the period beginning April 1, 2006. We have used the fair value method under Statement 123 since its inception. We adopted SFAS 123(R) prospectively since we used the minimum value method for purposes of complying with Statement 123. The adoption of this standard did not have a significant impact on our consolidated financial statements.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”) which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and Statement of Financial Accounting Standards No. 3, “Reporting Accounting Changes in Interim Financial Statements — An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 was effective for accounting changes and corrections of errors made in our fiscal years beginning April 1, 2006. The adoption of SFAS 154 did not have a material impact on the Company’s consolidated financial statements.

Recent United States accounting pronouncements not yet adopted

Statement of Financial Accounting Standards No. 155, “Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140” (“SFAS 155”) was issued February 2006. This Statement is effective for all financial instruments acquired, issued, or subject to a remeasurement (new basis) event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The fair value election provided for in paragraph 4(c) of this Statement may also be applied upon adoption of this Statement for hybrid financial instruments that had been bifurcated under paragraph 12 of Statement 133 prior to the adoption of this Statement. This states that an entity that initially recognizes a host contract and a derivative instrument may irrevocably elect to initially and subsequently measure that hybrid financial instrument, in its entirety, at fair value with changes in fair value recognized in earnings. SFAS 155 is applicable for all financial instruments acquired or issued in our 2008 fiscal year although early adoption is permitted. We are currently reviewing the impact of this Statement.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (“FIN 48”) which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition requirements. The Company is currently reviewing the impact of this interpretation. FIN 48 is effective for fiscal years beginning after December 15, 2006, specifically, April 1, 2007 for the Company.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

quantifying a current misstatement. It establishes an approach that requires quantification of financial statements misstatements based on the related financial statement disclosures. SAB 108 is effective for the Company’s annual financial statements for the current fiscal year ending March 31, 2007. The Company is currently reviewing the impact of this pronouncement.

Risk Factors

Anticipated major projects in the oil sands may not materialize.

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

•

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

•

shortage of pipeline capacity to transport production to major markets;

•

lack of sufficient governmental infrastructure to support growth;

•

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

•

cost overruns on announced projects.

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

Due to the amount of capital investment required to build an oil sands project, or construct a significant expansion to an existing project, investment decisions by oil sands operators are based upon long-term views of the economic viability of the project. Economic viability is dependent upon the anticipated revenues the project will produce, the anticipated amount of capital investment required and the anticipated cost of operating the project. One of the most important considerations is the price of oil. The long-term outlook for the price of oil is influenced by many factors, including the condition of developed and developing economies and the resulting demand for oil and gas, the level of supply of oil and gas, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political conditions in oil producing nations, including those in the Middle East, war or the threat of war in oil producing regions and the availability of fuel from alternate sources. If our customers believe the long-term outlook for the price of oil is not favorable or believes oil sands projects are not viable for any other reason, they may delay, reduce or cancel plans to construct new oil sands projects or expansions to existing projects. Delays, reductions or cancellations of major oil sands projects could have a material adverse impact on our financial condition and results of operations.

Insufficient pipeline and refining capacity could cause our customers to delay, reduce or cancel plans to construct new oil sands projects or expansions to existing projects, which would, in turn, reduce our revenue from those customers.

For our customers to operate successfully in the oil sands, they must be able to transport the bitumen produced to upgrading facilities and transport the upgraded oil to refineries. Some oil sands projects have upgraders at the mine site and others transport bitumen to upgraders located elsewhere. While current pipeline and upgrading capacity is sufficient to upgrade current bitumen production and transport such production to refineries, future increases in production from new oil sands projects and expansions to existing projects will require increased upgrading and pipeline capacity. If these increases do not materialize, whether due to inadequate economics for the sponsors of such projects, shortages of labor or materials or any other reason, our customers may be unable to efficiently deliver increased production to market and may therefore delay, reduce or cancel planned capital investment. Such delays, reductions or cancellations of major oil sands projects would adversely affect our prospects and could have a material adverse impact on our financial condition and results of operations.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

Lack of sufficient governmental infrastructure to support the growth in the oil sands region could cause our customers to delay, reduce or cancel their future expansions, which would, in turn, reduce our revenue from those customers.

The development in the oil sands region has put a great strain on the existing government infrastructure, necessitating substantial improvements to accommodate the growth in the region. The local government having responsibility for a majority of the oil sands region has been exceptionally impacted by this growth and is not currently in a position to provide the necessary additional infrastructure. In an effort to delay further development until infrastructure funding issues are resolved, the local governmental authority has sought to intervene in two recent hearings considering applications by major oil sands companies to the Energy Utility Board (EUB) for approval to expand their operations and may take similar action with respect to any future applications. The EUB has issued conditional approval for the expansion in respect of one of the hearings despite intervention by the local government authority, and a decision in the second hearing is pending. The EUB has indicated that it believes that additional infrastructure investment in the oil sands region is needed and that there is a short window of opportunity to make these investments in parallel with continued oil sands development. If the necessary infrastructure is not put in place, future growth of our customers’ operations could be delayed, reduced or canceled which could in turn adversely affect our prospects and could have a material adverse impact on our financial condition and results of operations.

Shortages of qualified personnel or significant labor disputes could adversely affect our business.

Alberta, and in particular the oil sands area, has had and continues to have a shortage of skilled labor and other qualified personnel. New mining projects in the area will only make it more difficult for us and our customers to find and hire all the employees required to work on these projects. We are continuously seeking ways to hire the people we need, including more project managers, trades people and other employees with the required skills. We have expanded our efforts to find qualified candidates outside of Canada who might relocate to our area. In addition, we have undertaken more extensive training of existing employees and we are enhancing our use of technology and developing programs to provide better working conditions. We believe the labor shortage, which affects us and all of our major customers, will continue to be a challenge for everyone in the mining and oil and gas industries in western Canada for the foreseeable future. If we are not able to recruit and retain enough employees with the appropriate skills, we may be unable to maintain our customer service levels, and we may not be able to satisfy any increased demand for our services. This, in turn, could have a material adverse effect on our business, financial condition and results of operations. If our customers are not able to recruit and retain enough employees with the appropriate skills, they may be unable to develop projects in the oil sands area.

Substantially all of our hourly employees are subject to collective bargaining agreements to which we are a party or are otherwise subject. Any work stoppage resulting from a strike or lockout could have a material adverse effect on our business, financial condition and results of operations. In addition, our customers employ workers under collective bargaining agreements. Any work stoppage or labor disruption experienced by our key customers could significantly reduce the amount of our services that they need.

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

Oil sands development projects require substantial capital expenditures. In the past, several of our customers’ projects have experienced significant cost overruns, impacting their returns. As new projects are contemplated or built, if cost overruns continue to challenge our customers, they could reassess future projects and expansions which could adversely affect the amount of work we receive from our customers.

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

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

Global demand for tires of the size and specifications we require is exceeding the available supply. For example, we currently have four trucks that we cannot utilize because we cannot get tires of the appropriate size and specifications. We expect the supply/demand imbalance for certain tires to continue for several years. Our inability to procure tires to meet the demands for our existing fleet as well as to secure tires to meet new demand for our services could have an adverse effect on our ability to grow our business.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

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

We receive most of our revenues from providing services to a small number of major oil sands mining companies. Revenue from our five largest customers represented approximately 57% and 59% of our total revenue for the three and six months ended September 30, 2006, respectively (three and six months ended September 30, 2005 – 58% and 56%, respectively), and those customers are expected to continue to account for a significant percentage of our revenues in the future. For the three months ended September 30, 2006, Customer A, Customer E and Customer B were our three largest customers, accounting for 20%, 14% and 13%, respectively, of our total revenue. For the six months ended September 30, 2006, Customer A, Customer B and Customer C were our three largest customers, accounting for 18%, 12% and 10%, respectively, or out total revenue. For the last five fiscal years, the majority of our revenues in our pipeline business resulted from work performed for EnCana. If we lose or experience a significant reduction of business from one or more of our significant customers, we may not be able to replace the lost work with work from other customers. Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the work which we are to perform under the contract. Our contracts generally allow the customer to terminate the contract without cause. The loss of or significant reduction in business with one or more of our major customers, whether as a result of completion of a contract, early termination or failure or inability to pay amounts owed to us, could have a material adverse effect on our business and results of operations.

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

Most of our customers are Canadian energy companies. A downturn in the Canadian energy industry could cause our customers to slow down or curtail their current production and future expansions which would, in turn, reduce our revenue from those customers. Such a delay or curtailment could have a material adverse impact on our financial condition and results of operations.

Lump sum and unit-price contracts expose us to losses when our estimates of project costs are too low or when we fail to perform within our cost estimates.

Approximately 55% and 47% of our revenue for the three and six months ended September 30, 2006, respectively (three and six months ended September 30, 2005 – 60% and 61%, respectively), was derived from lump sum and unit-price contracts. See “Management’s Discussion and Analysis — Critical Accounting Policies and Estimates — Revenue Recognition.” Lump sum and unit-price contracts require us to guarantee the price of the services we provide and thereby expose us to losses if our estimates of project costs are lower than the actual project costs we incur. Our profitability under these contracts is dependent upon our ability to accurately predict the costs associated with our services. The costs we actually incur may be affected by a variety of factors beyond our control. Factors that may contribute to actual costs exceeding estimated costs and which therefore affect profitability include, without limitation:

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site conditions differing from those assumed in the original bid;

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scope modifications during the execution of the project;

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

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the availability and proximity of materials;

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unfavorable weather conditions hindering productivity;

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inability or failure of our customers to perform their contractual commitments;

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

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

When we are unable to accurately estimate the costs of lump sum and unit-price contracts, or when we incur unrecoverable cost overruns, the related projects result in lower margins than anticipated or may incur losses, which could adversely impact our results of operations, financial condition and cash flow.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

Until we establish and maintain effective internal controls over financial reporting, we cannot assure you that we will have appropriate procedures in place to eliminate future financial reporting inaccuracies and avoid delays in financial reporting.

We have financial reporting obligations arising from the indentures governing our 8 3/4% senior notes and 9% senior secured notes. We have had continuing problems providing accurate and timely financial information and reports and have restated our financial statements three times since the beginning of our 2005 fiscal year. In April of 2005, we had to restate our financial statements for the first and second quarters of fiscal 2005 to properly account for costs incurred in those quarters. During fiscal 2006, we had to restate our financial statements for each period after November 26, 2003 to eliminate the impact of hedge accounting with respect to the derivative financial instruments. We also had to restate our financial statements for the first quarter of fiscal 2006 to correct the accounting for various aspects of the refinancing transactions which occurred in May 2005. Each of these restatements resulted in our inability to file our financial statements within the deadlines imposed by covenants in the indentures governing our 8 3/4% senior notes and 9% senior secured notes.

In connection with the audit of our fiscal 2006 financial statements, our auditors identified a number of significant weaknesses (as defined under Canadian auditing standards) in our financial reporting processes and internal controls. As a result, 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 U.S. and Canadian 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.

If, as of the end of our 2008 fiscal year, we are unable to assert that our internal control over financial reporting is effective, or if our auditors are unable to confirm our assessment, investors could lose confidence in our reported financial information, and the trading price of our common shares and our business could be adversely affected.

We are in the process of documenting, and plan to test during the current and next fiscal year, our internal control procedures in order to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act. Commencing with our fiscal year ending March 31, 2008, the Sarbanes-Oxley Act requires an annual assessment by management of the effectiveness of our internal control over financial reporting and an attestation report by our independent auditors addressing this assessment. We cannot be certain at this time that we will be able to comply with all of our reporting obligations and successfully complete the procedures, certification and attestation requirements of Section 404 of the Sarbanes-Oxley Act in a timely manner. During the course of our testing we may identify deficiencies that we may not be able to remedy in time to meet the deadline imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. Effective internal control over financial reporting is important to help produce reliable financial reports and to prevent financial fraud. If we are unable to assert that our internal control over financial reporting is effective as of the end of our 2008 fiscal year, or if our independent auditors are unable to attest that our management’s report is fairly stated or are unable to express an opinion on management’s evaluation or on the effectiveness of our internal controls, we could be subject to heightened regulatory scrutiny, investors could lose confidence in our reported financial information and the trading price of our common shares and our ability to maintain confidence in our business could be adversely affected.

Our substantial debt could adversely affect us, make us more vulnerable to adverse economic or industry conditions and prevent us from fulfilling our debt obligations.

We have a substantial amount of debt outstanding and significant debt service requirements. As of September 30, 2006, we had outstanding, less future income taxes, approximately $453.0 million of long-term debt, including approximately $76.3 million of long-term secured indebtedness and capital leases. On November 28, 2006 we repurchased all of the outstanding 9% senior secured notes. We also have cross-currency and interest rate swaps with a balance sheet liability of $74.0 million as of September 30, 2006 and which are secured equally and ratably with our revolving credit facility. We also had $18.0 million of outstanding, undrawn letters of credit, which reduce the amount of available borrowings under our revolving credit facility. Our substantial indebtedness could have serious consequences, such as:

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limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements, potential growth or other purposes;

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limiting our ability to use operating cash flow in other areas of our business;

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limiting our ability to post surety bonds required by some of our customers;

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placing us at a competitive disadvantage compared to competitors with less debt;

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increasing our vulnerability to, and reducing our flexibility in planning for, adverse changes in economic, industry and competitive conditions; and

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increasing our vulnerability to increases in interest rates because borrowings under our revolving credit facility and payments under some of our equipment leases are subject to variable interest rates.

The potential consequences of our substantial indebtedness make us more vulnerable to defaults and place us at a competitive disadvantage. Further, if we do not have sufficient earnings to service our debt, we would need to refinance all or part of our existing debt, sell assets, borrow more money or sell securities, none of which we can guarantee we will be able to achieve on commercially reasonable terms, if at all.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in our business or take certain actions.

Our revolving credit facility and the indentures governing our notes limit, among other things, our ability and the ability of our subsidiaries to:

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incur or guarantee additional debt, issue certain equity securities or enter into sale and leaseback transactions;

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pay dividends or distributions on our shares or repurchase our shares, redeem subordinated debt or make other restricted payments;

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incur dividend or other payment restrictions affecting certain of our subsidiaries;

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issue equity securities of subsidiaries;

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make certain investments or acquisitions;

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create liens on our assets;

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enter into transactions with affiliates;

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consolidate, merge or transfer all or substantially all of our assets; and

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transfer or sell assets, including shares of our subsidiaries.

Our revolving credit facility and some of our equipment lease programs also require us, and our future credit facilities may require us, to maintain specified financial ratios and satisfy specified financial tests, some of which become more restrictive over time. Our ability to meet these financial ratios and tests can be affected by events beyond our control, and we may be unable to meet those tests.

As a result of these covenants, our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be significantly restricted, and we may be prevented from engaging in transactions that might otherwise be considered beneficial to us. The breach of any of these covenants could result in a default under our revolving credit facility or any future credit facilities or under the indentures governing our notes. Upon the occurrence of an event of default under our revolving credit facility or future credit facilities, the lenders could elect to stop lending to us or declare all amounts outstanding under such credit facilities to be immediately due and payable. Similarly, upon the occurrence of an event of default under the indentures governing our notes, the outstanding principal and accrued interest on the notes may become immediately due and payable. If amounts outstanding under such credit facilities and indentures were to be accelerated, or if we were not able to borrow under our revolving credit facility, we could become insolvent or be forced into insolvency proceedings.

Our inability to file our financial statements for the periods ended December 31, 2004, March 31, 2005 and September 30, 2005 with the SEC within the deadlines imposed by covenants in the indentures governing our 8 ³/4% senior notes and our 9% senior secured notes caused us to be out of compliance with such covenants. In each case, we filed these financial statements before the lack of compliance became an event of default under the indentures.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

We may not be able to generate sufficient cash flow to meet our debt service and other obligations due to events beyond our control.

Our ability to generate sufficient operating cash flow to make scheduled payments on our indebtedness and meet other capital requirements will depend on our future operating and financial performance. Our future performance will be impacted by a range of economic, competitive and business factors that we cannot control, such as general economic and financial conditions in our industry or the economy generally.

A significant reduction in operating cash flows resulting from changes in economic conditions, increased competition, reduced work or other events could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to service our debt and other obligations. If we are unable to service our indebtedness, we will be forced to adopt an alternative strategy that may include actions such as selling assets, restructuring or refinancing our indebtedness, seeking additional equity capital or reducing capital expenditures. We may not be able to effect any of these alternative strategies on satisfactory terms, if at all, or they may not yield sufficient funds to make required payments on our indebtedness.

Currency rate fluctuations could adversely affect our ability to borrow under our revolving credit facility and to repay our 8 3/4% senior notes and 9% senior secured notes and may affect the cost of goods we purchase.

Our ability to borrow under our revolving credit facility is limited, in part, by the derivative financial instruments recorded as liabilities. If the Canadian dollar increases in value against the U.S. dollar, as it has in the recent past, the derivative financial instruments under the swap agreements will increase, which may adversely affect our liquidity or even cause a default under our revolving credit facility if the derivative financial instruments recorded as liabilities were to increase to the extent that the amount of outstanding borrowings and letters of credit would exceed the reduced availability under our revolving credit facility.

We have entered into cross-currency and interest rate swaps that represent economic hedges of our 8 3/4% senior notes, which are denominated in U.S. dollars. The current exchange rate between the Canadian and U.S. dollars as compared to the rate implicit in the swap agreement has resulted in a large liability on the balance sheet under the caption “derivative financial instruments.” If the Canadian dollar increases in value or remains at its current value against the U.S. dollar, then if we repay the 8 3/4% senior notes prior to their maturity in 2011, we will have to pay this liability.

Substantially all of our revenues and costs are incurred in Canadian dollars. However, the obligation represented by our 9% senior secured notes is denominated in U.S. dollars. If the Canadian dollar loses value against the U.S. dollar while other factors remain constant, our ability to pay interest and principal on these notes may be diminished.

Exchange rate fluctuations may also cause the price of goods to increase or decrease for us. For example, a decrease in the value of the Canadian dollar compared to the U.S. dollar would proportionately increase the cost of equipment which is sold to us or priced in U.S. dollars. Between January 1, 2006 and September 30, 2006, the Canadian dollar/U.S. dollar exchange rate varied from a high of 0.9099 U.S dollars per Canadian dollar to a low of 0.8528 U.S. dollars per Canadian dollar per U.S. dollar.

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

We are at times required to post a bid or performance bond issued by a financial institution, known as a surety, to secure our performance commitments. The surety industry experiences periods of unsettled and volatile markets, usually in the aftermath of substantial loss exposures or corporate bankruptcies with significant surety exposure. Historically, these types of events have caused reinsurers and sureties to reevaluate their committed levels of underwriting and required returns. If for any reason, whether because of our financial condition, our level of secured debt or general conditions in the surety bond market, our bonding capacity becomes insufficient to satisfy our future bonding requirements, our business and results of operations could be adversely affected.

Some of our customers require letters of credit to secure our performance commitments. Our revolving credit facility provides for the issuance of letters of credit up to $55.0 million, and at September 30, 2006, we had $18.0 million of issued letters of credit outstanding. One of our major contracts allows the customer to request up to $50.0 million in letters of credit. While this level has not been requested to date, we would either have to lower other letters of credit or cash collateralize other obligations to provide this amount of letters of credit. If we were unable to provide letters of credit in the amount requested by this customer, we could lose business from such customer and our business and cash flow would be adversely affected. In addition, the company that provides our surety bonds currently requires $10.0 million of security in the form of either letters of credit, cash collateralization or a combination thereof. If our capacity to issue letters of credit under our revolving credit facility and our cash on hand are insufficient to satisfy our customers and surety, our business and results of operations could be adversely affected.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

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

Outsourced mining and site preparation services constitute a large portion of the work we perform for our customers. For example, our mining and site preparation project revenues constituted approximately 80% of our revenues in each of the three and six months ending September 30, 2006 and September 30, 2005. The election by one or more of our customers to perform some or all of these services themselves, rather than outsourcing the work to us, could have a material adverse impact on our business and results of operations.

Our operations are subject to weather-related factors that may cause delays in our completion of projects.

Because our operations are located in western Canada and northern Ontario, we are often subject to extreme weather conditions. While our operations are not significantly affected by normal seasonal weather patterns, extreme weather, including heavy rain and snow, can cause us to delay the completion of a project, which could adversely impact our results of operations.

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

A portion of our equipment fleet is currently leased from third parties. Further, we anticipate leasing substantial amounts of equipment to perform the work on contracts for which we have been engaged in the upcoming year, particularly the overburden removal contract with CNRL. Other projects on which we are engaged in the future may require us to lease additional equipment. If equipment lessors are unable or unwilling to provide us with the equipment we need to perform our work, our results of operations will be materially adversely affected.

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

We compete with a broad range of companies in each of our markets. Many of these competitors are substantially larger than we are. In addition, we expect the anticipated growth in the oil sands region will attract new and sometimes larger competitors to enter the region and compete against us for projects. This increased competition may adversely affect our ability to be awarded new business.

Approximately 80% of the major projects that we pursue are awarded to us based on bid proposals, and projects are typically awarded based in large part on price. We often compete for these projects against companies that have substantially greater financial and other resources than we do and therefore can better bear the risk of underpricing projects. We also compete against smaller competitors that may have lower overhead cost structures and, therefore, may be able to provide their services at lower rates than we can. Our business may be adversely impacted to the extent that we are unable to successfully bid against these companies. The loss of existing customers to our competitors or the failure to win new projects could materially and adversely affect our business and results of operations.

A significant amount of our revenue is generated by providing non-recurring services.

More than 72% of our revenue for the three and six months ended September 30, 2006, respectively, was derived from projects which we consider to be non-recurring. This revenue primarily relates to site preparation and piling services provided for the construction of extraction, upgrading and other oil sands mining infrastructure projects. Future revenues from these types of services will depend upon customers expanding existing mines and developing new projects.

Penalty clauses in our customer contracts could expose us to losses if total project costs exceed original estimates or if projects are not completed by specified completion date milestones.

A portion of our revenue is derived from contracts which have performance incentives and penalties depending on the total cost of a project as compared to the original estimate. We could incur significant penalties based on cost overruns. In addition, the total project cost as defined in the contract may include not only our work, but also work performed by other contractors. As a result, we could incur penalties due to work performed by others over which we have no control. We may also incur penalties if projects are not completed by specified completion date milestones. These penalties, if incurred, could have a significant impact on our profitability under these contracts.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

Demand for our services may be adversely impacted by regulations affecting the energy industry.

Our principal customers are energy companies involved in the development of the oil sands and in natural gas production. The operations of these companies, including their mining operations in the oil sands, are subject to or impacted by a wide array of regulations in the jurisdictions where they operate, including those directly impacting mining activities and those indirectly affecting their businesses, such as applicable environmental laws. As a result of changes in regulations and laws relating to the energy production industry, including the operation of mines, our customers’ operations could be disrupted or curtailed by governmental authorities. The high cost of compliance with applicable regulations may cause customers to discontinue or limit their operations, and may discourage companies from continuing development activities. As a result, demand for our services could be substantially affected by regulations adversely impacting the energy industry.

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

Our operations are subject to numerous environmental protection laws and regulations that are complex and stringent. We regularly perform work in and around sensitive environmental areas such as rivers, lakes and forests. Significant fines and penalties may be imposed on us or our customers for non- compliance with environmental laws and regulations, and our contracts generally require us to indemnify our customers for environmental claims suffered by them as a result of our actions. In addition, some environmental laws impose strict, joint and several liability for investigative and remediation costs in relation to releases of harmful substances. These laws may impose liability without regard to negligence or fault. We also may be subject to claims alleging personal injury or property damage if we cause the release of, or any exposure to, harmful substances.

We own or lease, and operate, several properties that have been used for a number of years for the storage and maintenance of equipment and other industrial uses. Fuel may have been spilled, or hydrocarbons or other wastes may have been released on these properties. Any release of substances by us or by third parties who previously operated on these properties may be subject to laws which impose joint and several liability for clean-up, without regard to fault, on specific classes of persons who are considered to be responsible for the release of harmful substances into the environment.

Failure by our customers to obtain required permits and licenses may affect the demand for our services.

The development of the oil sands requires our customers to obtain regulatory or other permits and licenses from various governmental licensing bodies. Our customers may not be able to obtain all necessary permits and licenses that may be required for the development of the oil sands on their properties. In such a case, our customers’ projects will not proceed, thereby adversely impacting demand for our services.

Our projects expose us to potential professional liability, product liability, warranty or other claims.

We install deep foundations, often in congested and densely populated areas, and provide construction management services for significant projects. Notwithstanding the fact that we generally will not accept liability for consequential damages in our contracts, any catastrophic occurrence in excess of insurance limits at projects where our structures are installed or services are performed could result in significant professional liability, product liability, warranty or other claims against us. Such liabilities could potentially exceed our current insurance coverage and the fees we derive from those services. A partially or completely uninsured claim, if successful and of a significant magnitude, could result in substantial losses.

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

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

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

Aboriginal peoples may make claims against our customers or their projects regarding the lands on which their projects are located.

Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada. Any claims that may be asserted against our customers, if successful, could have an adverse effect on our customers which may, in turn, negatively impact our business.

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

The majority of our work is generated from the development, expansion and ongoing maintenance of oil sands mining, extraction and upgrading facilities. Unplanned shutdowns of these facilities due to events outside our control or the control of our customers, such as fires, mechanical breakdowns and technology failures, could lead to the temporary shutdown or complete cessation of projects in which we are working. When these events have happened in the past, our business has been adversely affected. Our ability to maintain revenues and margins may be affected to the extent these events cause reductions in the utilization of equipment.

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

We recently made several significant changes to our senior management team. In May 2005, we hired a new Chief Executive Officer and promoted our Vice President, Operations to Chief Operating Officer. In January 2005 we hired a new Treasurer, who is now our Vice President, Supply Chain. In June 2006, we hired a new Vice President, Human Resources, Health, Safety and Environment. In September 2006, we hired a new Chief Financial Officer. As a result of these and other recent changes in senior management, many of our officers have only worked together as a management team for a short period of time and do not have a long history with us. Because our senior management team is responsible for the management of our business and operations, failure to successfully integrate our senior management team could have an adverse impact on our business, financial condition and results of operations.

Quantitative and Qualitative Disclosures Regarding Market Risk

Foreign currency risk

We are subject to currency exchange risk as our 8 3/4% senior notes are denominated in U.S. dollars and all of our revenues and most of our expenses are denominated in Canadian dollars. We have entered into cross currency swap and interest rate swap agreements to manage the foreign currency risk on the 8 3/4% senior notes. The hedging instrument consists 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 that results in us mitigating our exposure to the variability of cash flows caused by currency fluctuations relating to the US$200 million senior notes. The hedges 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 0.000% if cancelled after December 1, 2009.

Interest rate risk

We are subject to interest rate risk in connection with our revolving credit facility. The facility bears interest at variable rates based on the Canadian prime rate plus 2% or Canadian bankers’ acceptance rate plus 3%. Assuming our revolving credit facility was fully drawn at $55 million, excluding the $18 million of outstanding letters of credit at September 30, 2006, each 1.0% increase or decrease in the applicable interest rate would change the interest cost by $0.4 million per year. In the future, we may enter into interest rate swaps involving the exchange of floating for fixed rate interest payments to reduce interest rate volatility.

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three and six months ended September 30, 2006

We also lease equipment with a variable lease payment tied to prime rates. At September 30, 2006, for each 1.0% annual fluctuation in this rate, annual lease expense will change by $0.2 million.

Inflation

The rate of inflation has not had a material impact on our operations as many of our contracts contain a provision for annual escalation. If inflation remains at its recent levels, it is not expected to have a material impact on our operations in the foreseeable future if we are able to pass cost increases along to our customers.

Outlook

We have developed a strong business foundation through our relationships with the key organizations in the Canadian oil sands area of Alberta (Syncrude, Canadian Natural Resources Limited (CNRL), Suncor, Albian Sands, etc.) coupled with the long-term overburden work at removal CNRL. Our ability to build on this solid foundation continues to be enhanced as world economic growth underpins high prices in the oil and gas industries.

Activity in the Fort McMurray area remains very high and a number of high profile projects have been announced, including the acceleration of CNRL’s expansion plans, Shell’s Jackpine Mine, Petro-Canada/UTS Fort Hills project and Suncor Voyageur.

Over the last twelve months ended September 30, 2006, our financial performance has improved as a result of completing a number of initiatives. The management team has been restructured and a number of processes strengthened the financial and operating controls have been implemented. Concurrent with these changes, we launched a major business improvement initiative and re-organization aimed at increasing productivity and equipment utilization. These initiatives, coupled with the acquisition of new equipment ideally suited to heavy earth moving in the oil sands area, have strengthened our ability to bid competitively and profitably into the expanding market.

With respect to the Mining and Site Preparation operating segment, we are actively pursuing a strategy of retaining our leading position as a provider of mining and construction services in the Fort McMurray oil sands area while concurrently reducing risk by bidding into opportunities in resource areas outside the oil sands and in other Canadian provinces. Significant work at DeBeers’ Victor diamond project in Northern Ontario supports this strategy. Our Piling segment remains a strong business, and given the high level of construction in the western provinces alone, it is expected to continue to be robust in the foreseeable future. While the Pipeline segment activity for the six months ended September 30, 2006 was lower than the corresponding period a year ago, recently awarded projects and a multitude of announced projects scheduled for completion in this business area over the next two years bode well for us to secure valuable work in the coming months.

We are not aware of any events, trends, uncertainties, demands or commitments that would materially affect our forecasted revenues, profitability, liquidity or capital resources or that would cause reported financial information not to be indicative of future operating results or financial condition.