UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K/A

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16
under the Securities Exchange Act of 1934

For the month of August 2008

Commission File Number 001-33161

NORTH AMERICAN ENERGY PARTNERS INC.

Zone 3 Acheson Industrial Area
2-53016 Highway 60
Acheson, Alberta
Canada T7X 5A7
(Address of principal executive offices)

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

Form 20-F   o		Form 40-F   þ

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

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

     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   o		No   þ

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

 

 

Documents Included as Part of this Report

1.		Interim consolidated financial statements of North American Energy Partners Inc. for the three months ended June 30, 2008.
2.		Revised 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.

 

Interim Consolidated Financial Statements

For the three months ended June 30, 2008

(Expressed in thousands of Canadian dollars)

(Unaudited)

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Interim Consolidated Balance Sheets

(In thousands of Canadian dollars)

 

 

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Statements of Operations, Comprehensive Income
(Loss) and Retained Earnings (Deficit)
(In thousands of Canadian dollars, except per share amounts)
(Unaudited)

 

 

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Statements of Cash Flows
(In thousands of Canadian dollars)
(Unaudited)

 

 

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

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

 

 

North American Energy Partners Inc. was incorporated under the Canada Business Corporations Act on October 17, 2003. On November 26, 2003, North American Energy Partners Inc. (the “Company”) purchased all the issued and outstanding shares of North American Construction Group Inc. (“NACGI”), including subsidiaries of NACGI, from Norama Ltd. which had been operating continuously in Western Canada since 1953. The Company had no operations prior to November 26, 2003.

 

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

 

 

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

 

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

 

 

 

 

Effective April 1, 2008, the Company prospectively adopted the Canadian Institute of Chartered Accountants (“CICA”) Sections 3862, “Financial Instruments — Disclosures”, which replaces CICA 3861 and provides expanded disclosure requirements that enable users to evaluate the significance of financial instruments on the entity’s financial position and its performance and the nature and extent of risks arising from financial instruments to which the entity is exposed during the period and at the balance sheet, and how the entity manages those risks. This standard harmonizes disclosures with International Financial Reporting Standards. The Company has

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

provided the additional required disclosures in note 10 to its interim consolidated financial statements for the three months ended June 30, 2008.

 

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

 

 

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

 

 

Effective April 1, 2008, the Company retrospectively adopted CICA Section 3031, “Inventories” without restatement. This standard requires inventories to be measured at the lower of cost and net realizable value and provides guidance on the determination of cost, including the allocation of overheads and other costs to inventories, the requirement for an entity to use a consistent cost formula for inventory of a similar nature and use, and the reversal of previous write-downs to net realizable value when there is subsequent increases in the value of inventories. This new standard also clarifies that spare component parts that do not qualify for recognition as property, plant and equipment should be classified as inventory. Effective April 1, 2008, the Company reversed a tire impairment that was previously recorded at March 31, 2008 in other assets of $1,383 with a corresponding decrease to opening deficit of $991 net of future taxes of $392. The Company then reclassified $5,086 of tires and spare component parts from ’other assets’ to ’inventory’. As at June 30, 2008, inventory is comprised of tires and spare component parts of $6,790 and job materials of $110. The Company carries inventory at the lower of weighted average cost and net realizable value. The carrying amount of inventories pledged as security for borrowings under the revolving credit facility is approximately $6,900 as at June 30, 2008.

 

 

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

 

 

 

In February 2008, the CICA issued Handbook Section 3064, (“CICA 3064”) Goodwill and Intangible Assets. CICA 3064, which replaces Section 3062, Goodwill and Intangible Assets, and Section 3450, Research and Development Costs, establishes standards for the recognition, measurement and disclosure of goodwill and

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Accounting Standard IAS 38, Intangible Assets. This new standard is effective for the Company’s interim and annual consolidated financial statements commencing April 1, 2009. The Company is currently evaluating the impact of this standard.

 

 

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

 

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

 

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

 

 

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

 

 

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

 

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

 

 

 

During the three months ended June 30, 2008, additions of plant and equipment included $1,164 for capital leases (three months ended June 30, 2007 — $13). Depreciation of equipment under capital leases of $648 (three months ended June 30, 2007 — $533) is included in depreciation expense.

 

 

 

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

 

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

 

As of June 30, 2008, the Company had outstanding borrowings of $nil under the revolving credit facility and had issued $20.7 million in letters of credit to support bonding requirements and performance guarantees associated

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

with customer contracts and operating leases. The Company’s borrowing availability under the facility was $104.3 million at June 30, 2008.

 

 

 

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

 

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

 

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

 

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

 

As at June 30, 2008, the Company’s effective weighted average interest rate on its 83/4% senior notes, including the effect of financing costs and premiums, net, was approximately 9.42%.

 

 

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

 

At June 30, 2008, estimated undiscounted cash flows required to settle the obligation were $1,454. The credit adjusted risk-free rate assumed in measuring the asset retirement obligation was 8.75%. The Company expects to settle this obligation in 2021.

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

 

 

Authorized:

 

Unlimited number of common voting shares

 

Unlimited number of common non-voting shares

 

Issued:

 

 

 

 

 

 

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

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

 

 

 

 

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

 

 

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

 

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

 

The fair values of amounts due under the revolving credit facility and capital leases are based on management estimates which are determined by discounting cash flows required under the instruments at the interest rate currently estimated to be available for loans with similar terms. Based on these estimates, the fair value of amounts due under the revolving credit facility and capital leases as at June 30, 2008 and March 31, 2008 are not significantly different than their carrying values.

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

The fair values of the Company’s cross-currency and interest rate swap agreements are based on values quoted by the counterparties to the agreements. The fair values of the Company’s embedded derivatives are based on appropriate price modeling commonly used by market participants to estimate fair value. Such modeling includes option pricing models and discounted cash flow analysis, using observable market based inputs to estimate fair value. Fair value determined using valuation models requires the use of assumptions concerning the amount and timing of future cash flows. Fair value amounts reflect management’s best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates and discount rates for time value. It is possible that the assumption used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material.

 

 

 

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

 

 

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

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

 

 

 

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

 

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

 

Market Risk

 

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

 

To manage the exposure related to changes in market risk, the Company uses various risk management techniques including the use of derivative instruments. Such instruments may be used to establish a fixed price for a commodity, an interest-bearing obligation or a cash flow dominated in a foreign currency. Market risk exposures are monitored regularly and tolerances and control processes are in place to monitor that only authorized activities are undertaken.

 

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

 

 

The Company has 83/4% senior notes denominated in U.S. dollars in the amount of US$200 million. In order to reduce its exposure to changes in the U.S. to Canadian dollar exchange rate, the Company entered into a cross-currency swap agreement to manage this foreign currency exposure for both the principal balance due on December 1, 2011 as well as the semi-annual interest payments from the issue date to the maturity date. In conjunction with the cross-currency swap agreement, the Company also entered into a U.S. dollar interest rate swap and a Canadian dollar interest rate swap as discussed in note 10(b)(ii) below. These derivative financial instruments

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

were not designated as hedges for accounting purposes. At June 30, 2008 and March 31, 2008, the notional principal amount of the cross-currency swaps was US$200 million.

 

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

 

With other variables unchanged, a 100 basis point increase (decrease) of the Canadian dollar to the U.S. dollar related to the U.S. dollar denominated senior notes would decrease (increase) net income by approximately $1.7 million. With other variables unchanged, a 100 basis point increase (decrease) in the Canadian to the U.S. dollar related to the cross-currency swap would increase (decrease) net income by approximately $1.9 million. The impact on short-term exposures would be insignificant. There would be no impact to other comprehensive income.

 

 

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

 

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

 

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

 

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

 

As at June 30, 2008, holding all other variables constant, a 1% increase (decrease) to Canadian interest rates would impact the fair value of the interest rate swaps by $7,038 with this change in fair value being recorded in net income. As at June 30, 2008, holding all other variables constant, a 1% increase (decrease) to US interest rates would impact the fair value of the interest rate swaps by $3,292 with this change in fair value being recorded in net income. As at June 30, 2008, holding all other variables constant, a 1% increase (decrease) of Canadian to US interest rate volatility would impact the fair value of the interest rate swaps by $2,105 with this change in fair value being recorded in net income.

 

At June 30, 2008 the Company did not hold any floating rate debt. As at June 30, 2008, holding all other variables constant, a 1% increase (decrease) to interest rates would not have an impact on net income or other comprehensive income. This assumes that the amount and mix of fixed and floating rate debt remains unchanged from that which was held at June 30, 2008.

 

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

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

will be capitalized by the third party finance company. This additional (reduced) cost will impact the Company’s net income through the increased (reduced) operating lease payments in future periods.

 

iii.  Credit Risk

 

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

 

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

 

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

 

 

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

 

The Company’s maximum exposure to credit risk for trade accounts receivable is the carrying value of $121,448 as at June 30, 2008 (March 31, 2008 — $157,237), other receivables is the carrying value of $6,106 (March 31, 2008 — $8,765) and unbilled revenue is the carrying value of $89,533 as at June 30, 2008 (March 31, 2008 — $70,883). On a geographic basis as at June 30, 2008, approximately 95% (March 31, 2008 — 89%) of the balance of trade accounts receivable (before considering the allowance for doubtful accounts) was due from customers based in Western Canada.

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

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

 

 

As at June 30, 2008, the Company has recorded an allowance for doubtful accounts of $751 (March 31, 2008 — $742) of which 100% relates to amounts that are more than 61 days past due.

 

The allowance is an estimate of the June 30, 2008 trade receivable balances that are considered uncollectible. Changes to the allowance during the three months ended June 30, 2008 consisted of payments received on outstanding balances of $68 (three months ended June 30, 2007 — $nil), write off of trade accounts receivable balances not collected of $nil (three months ended June 30, 2007 - $nil), and bad debt expense of $77 (three months ended June 30, 2007 — $nil).

 

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

 

 

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

 

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

 

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

 

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

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

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

 

 

 

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

 

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

 

The Company is subject to restrictive covenants under its banking agreements with its principal lenders related to its revolving credit facility (note 6(a)), its capital lease obligations and senior notes (note 6(b)) that are measured on a quarterly basis. These covenants include, but are not limited to a working capital ratio, senior leverage ratio, and interest coverage ratio.

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

 

 

 

 

 

 

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

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

 

 

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

 

 

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

 

 

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

 

 

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

 

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

 

 

 

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

 

 

 

 

 

 

 

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

 

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

 

 

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

 

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

 

 

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

 

 

Share option plan

 

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

 

 

At June 30, 2008, the weighted average remaining contractual life of outstanding options is 7.6 years (March 31, 2008 — 7.6 years). The Company recorded $254 of compensation expense related to the stock options in the three months ended June 30, 2008 (2007 — $359) with such amount being credited to contributed surplus.

 

Deferred performance share unit plan

 

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

 

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

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Notes to the Interim Consolidated Financial Statements — (Continued)

 

assess the participant against the performance criteria and determine the number of DPSUs that have been earned (earned DPSUs).

 

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

 

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

 

 

At June 30, 2008, the weighted average remaining contractual life of outstanding DPSUs is 2.75 years. For the three months ended June 30, 2008, the Company granted 111,020 under the Plan and recorded compensation expense of $113 included in general and administrative costs. As at June 30, 2008, there was approximately $1,256 of total unrecognized compensation cost related to nonvested share-based payment arrangements under the DPSU Plan, which is expected to be recognized over a weighted average period of 2.75 years.

 

Directors’ deferred stock unit plan

 

On November 27, 2007, the Company approved a Directors’ Deferred Stock Unit (“DDSU”) Plan, which became effective January 1, 2008. Under the DDSU Plan, non-employee or officer directors of the Company shall receive 50% of their annual fixed remuneration (which is included in general and administrative expenses in the consolidated statement of operations) in the form of DDSUs and may elect to receive all or a part of their annual fixed remuneration in excess of 50% in the form of DDSUs. The DDSUs vest immediately upon grant and are redeemable, in cash, equal to the difference between the market value of the Company’s common stock at maturity and the market value of the Company’s common stock on the grant date (maturity occurs when the director resigns or retires). DDSUs must be redeemed within 60 days following maturity. Directors, who are not US taxpayers, may elect to defer the maturity date until a date no later than December 1st of the calendar year following the year in which the actual maturity date occurred. As at June 30, 2008, an expense of $269 (June 30, 2007 — $nil) was recorded relating to 20,774 (March 31, 2008 — 11,882) outstanding units that were granted during the year.

 

 

The Company generally experiences a decline in revenues during the first quarter of each fiscal year due to seasonality, as weather conditions make operations in the Company’s operating regions difficult during this period. The level of activity in the Heavy Construction and Mining and Pipeline segments declines when frost leaves the ground and many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment. The duration of this period is referred to as “spring breakup” and has a direct impact on the Company’s activity levels. Revenues during the fourth quarter of each fiscal year are typically highest as ground conditions are most

 

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Notes to the Interim Consolidated Financial Statements — (Continued)

 

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.

 

 

At June 30, 2008, in connection with a heavy equipment financing agreement, the Company has guaranteed $4.5 million of debt owed to the equipment manufacturer by a third party finance company. The Company’s guarantee of this indebtedness will expire when the equipment is commissioned, which is expected to be November 1, 2008. The Company has determined that the fair value of this financial instrument at inception and June 30, 2008 was not significant.

 

 

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

 

 

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

NORTH AMERICAN ENERGY PARTNERS INC.

 

Revised Management’s Discussion and Analysis

For the three months ended June 30, 2008

 

The following discussion and analysis is as of August 13, 2008 and should be read in conjunction with the unaudited interim consolidated financial statements for the three months ended June 30, 2008 and the audited consolidated financial statements for the fiscal year ended March 31, 2008. These statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP) and, except where otherwise specifically indicated, all dollar amounts are expressed in Canadian dollars. The consolidated financial statements and additional information relating to our business are available on SEDAR at www.sedar.com and EDGAR at www.sec.gov.

 

The first quarter fiscal 2009 Management’s Discussion and Analysis has been refiled to reflect a correction of the backlog figures on pages 13 and 14.

 

August 13, 2008

 

Table of Contents

 

 

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Management’s Discussion and Analysis — (Continued)

 

Prior Year Comparisons

 

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

 

The embedded derivative has been measured at fair value and included in derivative financial instruments on the consolidated balance sheet with changes in fair value recognized in net income. The impact of this restatement on the Interim Consolidated Balance Sheet for the three months ended June 30, 2007 is an immaterial change to future income taxes (long-term assets), derivative financial instruments and retained earnings (all adjustments less than $0.1 million). The impact on the interim consolidated financial statements for the three months ended June 30, 2007 is an adjustment to unrealized loss on derivative financial instruments and income tax expense. This resulted in an improvement to net income of $1.7 million (restated as a loss of $8.6 million)

 

 

We are a leading resource services provider to major oil, natural gas and other natural resource companies, with a primary focus on the Alberta oil sands. We provide a wide range of heavy construction and mining, piling and pipeline installation services to our customers across the entire lifecycle of their projects. We are the largest provider of contract mining services in the oil sands area and we believe we are one of the largest piling foundations installer in Western Canada. In addition, we believe that we operate the largest fleet of equipment of any contract resource services provider in the oil sands. Our total fleet includes over 845 pieces of diversified heavy construction equipment supported by over 925 ancillary vehicles. While our expertise covers heavy earth moving, site preparation, underground industrial piping, piling and pipeline installation in any location, we have a specific capability operating in the harsh climate and difficult terrain of the oil sands and northern Canada.

 

We believe that our significant knowledge, experience, equipment capacity and scale of operations in the oil sands differentiate us from our competition. We provide services to every company in the Alberta oil sands that uses surface mining techniques in their production. These surface mining techniques account for over 65% of total oil sands production. We also provide site construction services for in-situ producers, which use horizontally drilled wells to inject steam into deposits and pump bitumen to the surface.

 

Our principal oil sands customers include all three of the producers that are currently mining bitumen in Alberta: Syncrude Canada Ltd. (Syncrude), Suncor Energy Inc. (Suncor) and Albian Sands Energy Inc. (Albian), a joint venture amongst Shell Canada Limited, Chevron Canada Limited and Marathon Oil Canada Corporation. We are also working with customers that are in the process of developing bitumen-mining projects, including Canadian Natural Resources Limited (Canadian Natural) and Fort Hills (a joint venture between UTS Energy, Teck Cominco and Petro-Canada).

 

We have long-term relationships with most of our customers. For example, we have been providing services to Syncrude and Suncor since they pioneered oil sands development over 30 years ago. Approximately 39% of our revenues in fiscal 2008 were derived from recurring work and long-term contracts, which assist in providing stability in our operations.

 

We believe that we have demonstrated our ability to successfully export knowledge and technology gained in the oil sands and put it to work in other resource development projects across Canada. As an example, our Heavy Construction and Mining division successfully completed the development of a diamond mine site in 2008. This three-year project required us to operate effectively in a remote location under difficult weather conditions. As a

 

NORTH AMERICAN ENERGY PARTNERS INC.

 

Management’s Discussion and Analysis — (Continued)

 

result of our successful work on this project, we believe we have attracted the attention of resource developers and we are currently looking at other potential projects, including those in the high arctic regions.

 

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

 

Our Pipeline division installs penstocks as well as steel, fiberglass, and plastic pipe in sizes up to 52” in diameter. This division is experienced with jobs of varying magnitude for some of Canada’s largest energy companies. Our experience includes the recent construction of a new pipeline that goes through the Rocky Mountains, from Alberta to British Columbia. Undertaken as part of Kinder Morgan’s Trans Mountain Expansion (TMX), this project involves the construction of a 160 kilometer pipeline through ecologically sensitive environments, including Jasper National Park, with minimal impact to the environment.

 

Oil sands are grains of sand covered by a thin layer of water and coated by heavy oil, or bitumen. Bitumen, because of its structure, does not flow, and therefore requires non-conventional extraction techniques to separate it from the sand and other foreign matter. There are currently two main methods of extraction: open pit mining, where bitumen deposits are sufficiently close to the surface to make it economically viable to recover the bitumen by treating mined sand in a surface plant; and in-situ, where bitumen deposits are buried too deep for open pit mining to be cost effective, and operators instead inject steam into the deposit so that the bitumen can be separated from the sand and pumped to the surface. We currently provide most of our services to companies operating open pit mines to recover bitumen reserves. These customers utilize our services for surface mining, site preparation, overburden removal, piling, pipe installation, site maintenance, equipment and labor supply and land reclamation.

 

Demand for our services is primarily driven by the development, expansion and operation of oils sands projects. The oils sands operators’ capital investment decisions are driven by a number of factors, with what we believe is one of the most important being the expected long-term price of oil. The development, expansion and operation of oils sands projects and related public infrastructure spending play a key role in influencing our business activities.

 

On October 25, 2007, the Alberta government announced increases to the Alberta royalty rates affecting natural gas, conventional oil and oil sands producers. The announced increases were significant but lower than increases recommended to the government by the Royalty Review Panel. While some of our customers have announced their intentions to reduce oil and gas investment in Alberta as a result of the increased royalties, to date, the areas affected by these investment reductions do not include oil sands mining projects. Given the long-term nature and capital investment requirement to develop an oil sands mining operation, we anticipate that there is limited risk that the royalty changes will cause our customers to cancel, delay or reduce the scope of any significant mining developments currently underway.*

 

We are continuing to experience increasing requests for services under existing contracts with our major oil sands customers in spite of the recent royalty changes. Our recent acquisitions of new equipment ideally suited to heavy earth moving in the oil sands area, together with the addition of a significant number of new employees, has

 

 

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

 

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Management’s Discussion and Analysis — (Continued)

 

strengthened our ability to bid competitively and profitably into this expanding market and we have secured contracts on many of these new projects.

 

According to the Canadian Association of Petroleum Producers (CAPP), approximately $55.2 billion was invested in the oil sands from 1998 through 2006. According to the Canadian Energy Research Institute’s (CERI) November 2007 report, “Canadian Oil Sands Supply Costs and Development Projects (2007 — 2027)”, an additional $228 billion of capital expenditures will be required between 2007 and 2015 to achieve production levels projected under their “constrained” scenario. According to the CERI, as of November 2007, there were 23 mining and upgrader projects in various stages, ranging from announcement to construction, with start-up dates through 2014. Beyond 2014, several new multi-billion dollar projects and a number of smaller multimillion dollar projects are being considered by various oil sands operators. We intend to pursue business opportunities from these projects.*

 

Our strategy is to be an integrated service provider for the developers of resource-based industries in a broad and often challenging range of environments. This strategy is focused on the following priorities:

 

 

 

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

 

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Management’s Discussion and Analysis — (Continued)

 

 

As discussed above we provide our services through three interrelated yet distinct business units: (i) Heavy Construction and Mining, (ii) Piling and (iii) Pipeline. Our services include initial advice and consulting to customers as they develop plans to exploit resources. We believe that we have the skills and equipment to build infrastructure in new locations or to expand existing sites for heavy construction projects. We are currently involved in assisting with on-site mining services, overburden removal and plant upgrades. We are also able to respond to customer needs for site reclamation services once a site’s resources are depleted.

 

The table below shows the revenues generated by each operating segment for the three month periods ended June 30, 2006 through June 30, 2008: