UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16
under the Securities Exchange Act of 1934
For the month of February 2006
Commission File Number 333-111396
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 if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨
Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.
Yes ¨ No x
If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): .
Included herein:
1. | Interim consolidated financial statements of North American Energy Partners Inc. for the three and six months ended September 30, 2005 and 2004 (Restated). |
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/ Chris Hayman | |
Name: Title: | Chris Hayman Vice President, Finance |
Date: February 28, 2006
NORTH AMERICAN ENERGY PARTNERS INC.
Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Expressed in thousands of Canadian dollars)
(unaudited)
NORTH AMERICAN ENERGY PARTNERS INC.
Interim Consolidated Balance Sheets
(in thousands of Canadian dollars)
December 31, 2005 | March 31, 2005 | |||||||
(unaudited | ) | |||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 31,796 | $ | 17,922 | ||||
Accounts receivable | 69,896 | 57,745 | ||||||
Unbilled revenue | 35,649 | 41,411 | ||||||
Inventory | 555 | 134 | ||||||
Prepaid expenses | 2,398 | 1,862 | ||||||
Future income taxes | 8,049 | 15,100 | ||||||
148,343 | 134,174 | |||||||
Property, plant and equipment (note 4) | 182,487 | 177,089 | ||||||
Goodwill | 198,549 | 198,549 | ||||||
Intangible assets, net of accumulated amortization of $16,844 (March 31, 2005—$16,296) | 954 | 1,502 | ||||||
Deferred financing costs, net of accumulated amortization of $5,005 (March 31, 2005—$3,368) (note 5) | 18,688 | 15,354 | ||||||
$ | 549,021 | $ | 526,668 | |||||
Liabilities and Shareholder’s Equity | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 66,988 | $ | 59,090 | ||||
Accrued liabilities | 10,662 | 15,201 | ||||||
Billings in excess of costs on uncompleted contracts | 5,602 | 1,325 | ||||||
Current portion of capital lease obligations | 2,243 | 1,771 | ||||||
Future income taxes | 8,049 | 15,100 | ||||||
93,544 | 92,487 | |||||||
Senior secured credit facility (note 6(a)) | — | 61,257 | ||||||
Capital lease obligations | 5,963 | 5,454 | ||||||
Senior notes (note 6(b)) | 303,695 | 241,920 | ||||||
Derivative financial instruments (note 11(c)) | 63,035 | 51,723 | ||||||
Mandatorily redeemable preferred shares (note 7(a)) | 43,927 | — | ||||||
Advances from parent company | 282 | 288 | ||||||
510,446 | 453,129 | |||||||
Shareholder’s equity: | ||||||||
Common shares (note 7(b)) | 127,500 | 127,500 | ||||||
Contributed surplus (notes 7(c) and 13) | 1,250 | 634 | ||||||
Deficit | (90,175 | ) | (54,595 | ) | ||||
38,575 | 73,539 | |||||||
United States generally accepted accounting principles (note 14) | ||||||||
$ | 549,021 | $ | 526,668 | |||||
See accompanying notes to unaudited interim consolidated financial statements.
NORTH AMERICAN ENERGY PARTNERS INC.
Interim Consolidated Statements of Operations and Deficit
(in thousands of Canadian dollars)
(unaudited)
Three months ended December 31 | Nine months ended December 31 | |||||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||
Revenue | $ | 121,524 | $ | 80,992 | $ | 349,887 | $ | 234,532 | ||||||||
Project costs | 81,988 | 66,721 | 228,458 | 167,644 | ||||||||||||
Equipment costs | 15,848 | 12,946 | 46,447 | 36,556 | ||||||||||||
Operating lease expense | 4,316 | 1,698 | 10,300 | 3,185 | ||||||||||||
Depreciation | 5,525 | 5,286 | 16,007 | 14,946 | ||||||||||||
107,677 | 86,651 | 301,212 | 222,331 | |||||||||||||
Gross profit (loss) | 13,847 | (5,659 | ) | 48,675 | 12,201 | |||||||||||
General and administrative (note 10) | 8,178 | 5,354 | 21,878 | 15,349 | ||||||||||||
(Gain) loss on disposal of property, plant and equipment | (453 | ) | 260 | (774 | ) | 509 | ||||||||||
Amortization of intangible assets | 183 | 484 | 548 | 2,971 | ||||||||||||
Operating income (loss) | 5,939 | (11,757 | ) | 27,023 | (6,628 | ) | ||||||||||
Interest expense (note 8(a)) | 8,287 | 7,617 | 61,442 | 22,822 | ||||||||||||
Foreign exchange loss (gain) | 897 | (11,902 | ) | (14,343 | ) | (21,344 | ) | |||||||||
Other income | (82 | ) | (38 | ) | (350 | ) | (261 | ) | ||||||||
Financing costs (note 5) | — | — | 2,095 | — | ||||||||||||
Realized and unrealized (gain) loss on derivative financial instruments | (5,432 | ) | 23,255 | 13,365 | 36,801 | |||||||||||
3,670 | 18,932 | 62,209 | 38,018 | |||||||||||||
Income (loss) before income taxes | 2,269 | (30,689 | ) | (35,186 | ) | (44,646 | ) | |||||||||
Income taxes: | ||||||||||||||||
Current income taxes | 150 | 888 | 394 | 2,531 | ||||||||||||
Future income taxes | — | 850 | — | (4,975 | ) | |||||||||||
150 | 1,738 | 394 | (2,444 | ) | ||||||||||||
Net income (loss) for the period | 2,119 | (32,427 | ) | (35,580 | ) | (42,202 | ) | |||||||||
Deficit, beginning of period | (92,294 | ) | (22,057 | ) | (54,595 | ) | (12,282 | ) | ||||||||
Deficit, end of period | $ | (90,175 | ) | $ | (54,484 | ) | $ | (90,175 | ) | $ | (54,484 | ) | ||||
See accompanying notes to unaudited interim consolidated financial statement
NORTH AMERICAN ENERGY PARTNERS INC.
Interim Consolidated Statements of Cash Flows
(in thousands of Canadian dollars)
(unaudited)
Three months ended December 31 | Nine months ended December 31 | |||||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||
Cash provided by (used in): | ||||||||||||||||
Operating activities: | ||||||||||||||||
Net income (loss) for the period | $ | 2,119 | $ | (32,427 | ) | $ | (35,580 | ) | $ | (42,202 | ) | |||||
Items not affecting cash: | ||||||||||||||||
Depreciation | 5,525 | 5,286 | 16,007 | 14,946 | ||||||||||||
Amortization of intangible assets | 183 | 484 | 548 | 2,971 | ||||||||||||
Amortization of deferred financing costs | 884 | 668 | 2,452 | 1,922 | ||||||||||||
Financing costs | — | — | 2,095 | — | ||||||||||||
(Gain) loss on disposal of property, plant and equipment | (453 | ) | 260 | (774 | ) | 509 | ||||||||||
Unrealized foreign exchange loss (gain) on senior notes | 835 | (11,920 | ) | (14,570 | ) | (21,860 | ) | |||||||||
Unrealized (gain) loss on derivative financial instruments | (6,041 | ) | 22,588 | 11,312 | 34,812 | |||||||||||
Increase (decrease) in allowance for doubtful accounts | 28 | 13 | (44 | ) | (99 | ) | ||||||||||
Stock-based compensation expense (note 13) | 293 | 79 | 616 | 307 | ||||||||||||
Change in redemption value and accretion of mandatorily redeemable preferred shares | (406 | ) | — | 36,090 | — | |||||||||||
Future income taxes | — | 850 | — | (4,975 | ) | |||||||||||
Net changes in non-cash working capital (note 8(c)) | 16,736 | (1,362 | ) | (3,878 | ) | (3,914 | ) | |||||||||
19,703 | (15,481 | ) | 14,274 | (17,583 | ) | |||||||||||
Investing activities: | ||||||||||||||||
Purchase of property, plant and equipment | (10,067 | ) | (6,081 | ) | (23,289 | ) | (20,494 | ) | ||||||||
Net changes in non-cash working capital (note 8(c)) | 3,622 | — | 4,212 | — | ||||||||||||
Proceeds on disposal of property, plant and equipment | 2,085 | 357 | 5,138 | 491 | ||||||||||||
(4,360 | ) | (5,724 | ) | (13,939 | ) | (20,003 | ) | |||||||||
Financing activities: | ||||||||||||||||
Increase in senior secured credit facility | — | 10,000 | — | 10,000 | ||||||||||||
Repayment of senior secured credit facility | — | (1,500 | ) | (61,257 | ) | (4,500 | ) | |||||||||
Repayment of capital lease obligations | (572 | ) | (373 | ) | (1,499 | ) | (811 | ) | ||||||||
Advances (to) from parent company | — | — | (6 | ) | 288 | |||||||||||
Issuance of 9% senior secured notes | — | — | 76,345 | — | ||||||||||||
Issuance of Series B mandatorily redeemable preferred shares | 16 | — | 8,367 | — | ||||||||||||
Repurchase of Series B mandatorily redeemable preferred shares | (851 | ) | — | (851 | ) | — | ||||||||||
Financing costs | (75 | ) | (8 | ) | (7,560 | ) | (642 | ) | ||||||||
(1,482 | ) | 8,119 | 13,539 | 4,335 | ||||||||||||
Increase (decrease) in cash and cash equivalents | 13,861 | (13,086 | ) | 13,874 | (33,251 | ) | ||||||||||
Cash and cash equivalents, beginning of period | 17,935 | 16,430 | 17,922 | 36,595 | ||||||||||||
Cash and cash equivalents, end of period | $ | 31,796 | $ | 3,344 | $ | 31,796 | $ | 3,344 | ||||||||
See accompanying notes to unaudited interim consolidated financial statement
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
1. | Nature of operations |
North American Energy Partners 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. The Company is a wholly-owned subsidiary of NACG Preferred Corp. which in turn is a wholly-owned subsidiary of NACG Holdings Inc.
2. | Basis of presentation |
These unaudited interim consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) 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. Except as noted below, 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, 2005 and should be read in conjunction with those financial statements. Material items that give rise to measurement differences in these unaudited interim consolidated financial statements under United States GAAP are outlined in note 14.
These interim consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, NACG Finance LLC and North American Construction Group Inc. (“NACGI”), the Company’s joint venture (note 8(d)), and the following subsidiaries:
% 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% |
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
3. | Accounting policy changes |
a) | Revenue recognition: |
Effective April 1, 2005, the Company amended its accounting policy regarding the recognition of revenue on claims. This change in accounting policy has been applied retroactively. Once contract performance is underway, the Company will often experience changes in conditions, client requirements, specifications, designs, materials and work schedule. Generally, a “change order” will be negotiated with the customer to modify the original contract to approve both the scope and price of the change. Occasionally, however, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change becomes a point of dispute between the Company and a customer, the Company will then consider it as a claim.
Costs related to change orders and claims are recognized when they are incurred. Change orders are included in total estimated contract revenue when it is probable that the change order will result in a bona fide addition to contract value and can be reliably estimated.
Prior to April 1, 2005, revenue from claims was included in total estimated contract revenue when awarded or received. After April 1, 2005, claims are included in total estimated contract revenue, only to the extent that contract costs related to the claim have been incurred and when it is probable that the claim will result in a bona fide addition to contract value and can be reliably estimated. Those two conditions are satisfied when (1) the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained providing a reasonable basis to support the claim, (2) additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our performance, (3) costs associated with the claim are identifiable and reasonable in view of work performed and (4) evidence supporting the claim is objective and verifiable. No profit is recognized on claims until final settlement occurs. This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries.
The change in policy resulted in a decrease in claims revenue and unbilled revenue of approximately $4,200 for the three months ended December 31, 2005 and an increase in claims revenue and unbilled revenue of approximately $5,500 for the nine months ended December 31, 2005, but did not result in any adjustments to prior periods.
b) | Vendor rebates: |
In April 2005, the Company adopted the amended Canadian Accounting Standard EIC-144, “Accounting by a Customer (Including a Reseller) for Certain Consideration Received from a Vendor.” EIC-144 requires companies to recognize the benefit of non-discretionary rebates for achieving specified cumulative purchasing levels as a reduction of the cost of purchases over the relevant period, provided the rebate is probable and reasonably estimable. Otherwise, the rebates would be recognized
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
as purchasing milestones are achieved. The implementation of this new standard did not have a material impact on the Company’s consolidated financial statements.
c) | Recent Canadian accounting pronouncements not yet adopted: |
i) | 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 will be effective for interim and annual financial statements commencing in fiscal 2007. 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.
ii) | Non-monetary transactions: |
In June 2005, the CICA replaced Handbook Section 3830, “Non-monetary Transactions”, with the new Handbook Section 3831, “Non-monetary Transactions”. The requirements of the new standard apply to non-monetary transactions initiated in periods beginning on or after January 1, 2006, though earlier adoption is permitted as of periods beginning on or after July 1, 2005. The standard requires all non-monetary transactions to be measured at fair market value unless:
• | the transaction lacks commercial substance; |
• | the transaction is an exchange of production or property held for sale in the ordinary course of business for production or property to be sold in the same line of business to facilitate sales to customers other than the parties to the exchange; |
• | neither the fair value of the assets or services received nor the fair value of the assets or services given up is reliably measurable; or |
• | the transaction is a non-monetary, non-reciprocal transfer to owners that represents a spin-off or other form of restructuring or liquidation. |
The Company does not expect the adoption of this standard to have a material impact on its results of operations or financial position.
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
4. | Property, plant and equipment |
December 31, 2005 | Cost | Accumulated depreciation | Net book value | ||||||
Heavy equipment | $ | 168,964 | $ | 27,850 | $ | 141,114 | |||
Major component parts in use | 4,989 | 1,761 | 3,228 | ||||||
Spare component parts | 292 | — | 292 | ||||||
Other equipment | 13,212 | 3,802 | 9,410 | ||||||
Licensed motor vehicles | 17,924 | 7,352 | 10,572 | ||||||
Office and computer equipment | 3,182 | 1,336 | 1,846 | ||||||
Leasehold improvements | 2,741 | 156 | 2,585 | ||||||
Assets under construction | 13,440 | — | 13,440 | ||||||
$ | 224,744 | $ | 42,257 | $ | 182,487 | ||||
March 31, 2005 | Cost | Accumulated depreciation | Net book value | ||||||
Heavy equipment | $ | 165,296 | $ | 17,966 | $ | 147,330 | |||
Major component parts in use | 4,659 | 1,182 | 3,477 | ||||||
Spare component parts | 841 | — | 841 | ||||||
Other equipment | 12,088 | 2,473 | 9,615 | ||||||
Licensed motor vehicles | 16,043 | 4,670 | 11,373 | ||||||
Office and computer equipment | 2,088 | 791 | 1,297 | ||||||
Assets under construction | 3,156 | — | 3,156 | ||||||
$ | 204,171 | $ | 27,082 | $ | 177,089 | ||||
Leasehold improvements are amortized on a straight-line basis over the term of the lease.
The above amounts include $11,055 (March 31, 2005 – $8,637) of assets under capital lease and accumulated depreciation of $3,735 (March 31, 2005 – $1,968) related thereto. During the three months ended December 31, 2005, additions of property, plant and equipment included $501 of assets that were acquired by means of capital leases (three months ended December 31, 2004 – $1,561). For the nine months ended December 31, 2005, $2,480 of assets were acquired by means of capital leases (nine months ended December 31, 2004 – $3,652). For the three months ended December 31, 2005, depreciation of equipment under capital leases of $640 (three months ended December 31, 2004 – $654) is included in depreciation expense. For the nine months ended December 31, 2005, depreciation of equipment under capital leases was $1,790 (nine months ended December 31, 2004 – $1,805).
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
5. | Deferred financing costs |
For the three months ended December 31, 2005, financing costs of $75 were incurred in connection with the issuance of the 9% senior secured notes and revolving credit facility (note 6) and were recorded as deferred financing costs.
For the nine months ended December 31, 2005, financing costs of $7,560 were incurred in connection with the issuance of the 9% senior secured notes and revolving credit facility and were recorded as deferred financing costs. In addition, financing costs of $321 were incurred in connection with the issuance of the mandatorily redeemable Series A preferred shares.
In connection with the repayment of the senior secured credit facility on May 19, 2005, the Company wrote off deferred financing costs of $1,774 (note 6(a)).
Amortization of deferred financing costs of $884 was recorded for the three months ended December 31, 2005 (three months ended December 31, 2004 – $668). Amortization of deferred financing costs of $2,452 was recorded for the nine months ended December 31, 2005 (nine months ended December 31, 2004 – $1,922).
6. | Long-term debt |
a) | Senior secured credit facility: |
December 31, 2005 | March 31, 2005 | |||||
Revolving credit facility | $ | — | $ | 20,007 | ||
Term credit facility | — | 41,250 | ||||
$ | — | $ | 61,257 |
The Company refers to the revolving credit facility and the term loan collectively as the “senior secured credit facility.”
On May 19, 2005, the Company repaid its entire indebtedness under the senior secured credit facility using the net proceeds from the issuance of the 9% senior secured notes (note 6(b)) and the Series B mandatorily redeemable preferred shares (note 7(a)).
b) | Senior notes: |
December 31, 2005 | March 31, 2005 | |||||
8 3/4% senior notes due 2011 | $ | 233,180 | $ | 241,920 | ||
9% senior secured notes due 2010 | 70,515 | — | ||||
$ | 303,695 | $ | 241,920 |
The 8 3/4% 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 and bear interest at 8 3/4% payable semi-annually on June 1 and December 1 of each year.
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
The 8 3/4% 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. The notes are effectively subordinated to all secured debt to the extent of the value of the assets securing such debt.
The 8 3/4% 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 104.375% 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 the Company 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 8 3/4% senior notes at a redemption price equal to 108.75% of the principal amount of the 8 3/4% 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 8 3/4% senior notes remains outstanding immediately after any such redemption; and the Company makes such redemption within 90 days after the closing of any such public equity offering. If a change of control occurs, the Company will be required to offer to purchase all or a portion of each holder’s 8 3/4% senior notes, at a purchase price in cash equal to 101% of the principal amount of notes repurchased 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). 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 Company has not hedged its exposure to changes in the U.S. to Canadian dollar exchange rate resulting from the issuance of these notes.
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 the Company. The notes are effectively senior to all existing and future unsecured senior debt including the 8 3/4% senior notes and are effectively subordinated to the Company’s swap agreements and new 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 the Company, 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 the Company 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 the Company makes such redemption within 90 days after the closing of any such public equity offering. If a change of control occurs, the Company 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 notes repurchased plus accrued interest to the date of purchase.
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
c) | Revolving credit facility: |
On May 19, 2005, the Company entered into a new revolving credit facility with a syndicate of lenders. The new revolving facility provides for borrowings of up to $40.0 million, subject to borrowing base limitations, under which revolving loans may be made and letters of credit, up to a limit of $30.0 million, may be issued. The facility bears interest at the Canadian prime rate plus 2% or Canadian bankers’ acceptance rate plus 3%. The indebtedness under the revolving credit facility is secured by substantially all of the Company’s assets and those of its subsidiaries, including accounts receivable, inventory and property, plant and equipment, and a pledge of the Company’s capital stock and that of its subsidiaries.
In connection with the new revolving credit facility, the Company was required to amend its existing swap agreements to increase the effective rate of interest on its 8 3/4% senior notes from 9.765% to 9.889% (note 11(c)) and issue to one of the counterparties to the swap agreements $1.0 million of Series A redeemable preferred shares (note 7(a)).
As of December 31, 2005, the Company had no outstanding borrowings under the revolving credit facility and had issued $23 million in letters of credit to support bonding requirements and performance guarantees associated with customer contracts. The Company’s borrowing availability under the facility, after taking into account the borrowing base limitations, was $4,857 at December 31, 2005.
7. | Shares |
a) | Mandatorily redeemable preferred shares: |
Authorized:
i. | Unlimited number of Series A Preferred Shares |
The Series A Preferred shares are non-voting and are not entitled to any dividends. The Series A preferred shares are mandatorily redeemable at $1,000 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 8 3/4% senior unsecured notes and the Company’s 9% senior secured notes are no longer outstanding. The Company may redeem the Series A preferred shares, in whole or in part, at $1,000 per share at any time.
ii. | Unlimited number of Series B Preferred Shares |
The 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 common shares or other classes of preferred shares (defined as Junior Shares) unless all cumulative dividends have been paid on the Series B preferred shares and the Company declares a 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
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
sharing arrangements). As long as any Series A preferred shares remain outstanding and subject to the restrictions contained within the 8 3/4% senior unsecured notes and the 9% senior secured notes, dividends shall not be paid (but shall otherwise accrue) on the Series B preferred shares. Subject to the prior redemption of the Series A preferred shares, the 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 8 3/4% senior unsecured 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 8 3/4% senior unsecured notes and the credit facility agreement, the Company may redeem the Series B preferred shares, in whole or in part, at any time.
The payment of dividends and the redemption of the Series B mandatorily redeemable preferred shares are prohibited by the Company’s revolving credit facility agreement. The payment of dividends and the redemption of the Series B mandatorily redeemable preferred shares is also restricted by the indenture agreements governing the Company’s 9% senior secured notes and 8 3/4% senior unsecured notes.
The redemption price of the Series B preferred shares is an amount equal to the greatest of (i) two times the issue price, less the amount, if any, of dividends previously paid in cash on the Series B preferred shares; (ii) an amount, not to exceed $100 million which, after taking into account any dividends previously paid in cash on such Series B preferred shares, provides the holder with a 40% rate of return, compounded annually, on the issue price from the date of issuance; and (iii) an amount, not to exceed $100 million, which is equal to 25% of the arm’s length fair market value of the common shares without taking into account the Series B preferred shares.
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
Issued:
Number of Shares | Amount | ||||||
Series A Preferred Shares | |||||||
Outstanding at March 31, 2005 | — | $ | — | ||||
Issued | 1,000 | 321 | |||||
Accretion | — | 9 | |||||
Outstanding at June 30, 2005 | 1,000 | 330 | |||||
Accretion | — | 14 | |||||
Outstanding at September 30, 2005 | 1,000 | 344 | |||||
Accretion | — | 15 | |||||
Outstanding at December 31, 2005 | 1,000 | 359 | |||||
Series B Preferred Shares | |||||||
Outstanding at March 31, 2005 | — | $ | — | ||||
Issued | 75,000 | 7,500 | |||||
Change in redemption amount | — | 41,498 | |||||
Outstanding at June 30, 2005 | 75,000 | 48,998 | |||||
Issued | 8,218 | 851 | |||||
Change in redemption amount | — | (5,025 | ) | ||||
Outstanding at September 30, 2005 | 83,218 | 44,824 | |||||
Issued | 163 | 16 | |||||
Repurchased | (8,218 | ) | (851 | ) | |||
Change in redemption amount | — | (421 | ) | ||||
Outstanding at December 31, 2005 | 75,163 | 43,568 | |||||
Total Mandatorily Redeemable Preferred Shares | $ | 43,927 | |||||
The Series A preferred shares were issued to one of the counterparties to the Company’s swap agreements on May 19, 2005 in connection with the new revolving credit facility. These shares are not entitled to accrue or receive dividends and are required to be redeemed on or before December 31, 2011 for $1.0 million.
The 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 Company will accrete the carrying value to the present value of the redemption amount at the balance sheet date and record the accretion as interest expense. For the three months ended December 31, 2005, the Company recognized $15 of accretion as interest expense. For the nine months ended December 31, 2005, the Company recognized $38 of accretion as interest expense. The carrying value of the Series A preferred shares is $359 at December 31, 2005.
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
The Series B preferred shares were issued to existing non-employee shareholders of the Company’s ultimate parent company, NACG Holdings Inc., for cash proceeds of $7.5 million on May 19, 2005. Each reporting period, the Company is required to measure the Series B mandatorily redeemable preferred shares at the amount of cash that would be paid under the conditions specified in the contract if settlement occurred at the reporting date. At December 31, 2005, management estimates the redemption amount to be $43.6 million. As a result, the Company has recognized the decrease in the carrying value of $0.4 million since September 30, 2005 as a decrease in interest expense for the three months ended December 31, 2005. For the nine months ended December 31, 2005, interest expense has been increased by $36.1 million due to the change in the carrying value of the Series B preferred shares from their initial fair value recorded at their issuance date.
On May 19, 2005, the Series B preferred shares were initially issued to certain non-employee shareholders with the agreement that an offer to purchase these Series B preferred shares would also be extended to other existing shareholders of NACG Holdings Inc. on a pro rata basis to their interest in the common shares. On August 31, 2005, the Company issued 8,218 Series B preferred shares for consideration of $851 to certain shareholders of NACG Holdings Inc. as a result of this offering. On November 1, 2005, the Company repurchased and cancelled 8,218 of the Series B preferred shares held by the original non-employee shareholders for cash consideration of $851.
On June 15, 2005, the Series B preferred shares were split 10-for-1.
During the three months ended December 31, 2005, 163 Series B preferred shares were issued for cash consideration of $16.
b) | Common shares: |
Authorized:
Unlimited number of common voting shares.
Issued:
Number of Shares | Amount | ||||
Outstanding at March 31, 2005 | 100 | $ | 127,500 | ||
Issued | — | — | |||
Redeemed | — | — | |||
Outstanding at December 31, 2005 | 100 | $ | 127,500 | ||
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
c) | Contributed surplus: |
Balance, March 31, 2005 | $ | 634 | |
Stock-based compensation | 188 | ||
Balance, June 30, 2005 | 822 | ||
Stock-based compensation | 135 | ||
Balance, September 30, 2005 | 957 | ||
Stock-based compensation (note 13) | 293 | ||
Balance, December 31, 2005 | $ | 1,250 | |
8. | Other information |
a) | Interest expense: |
Three months ended December 31 | Nine months ended December 31 | ||||||||||||
2005 | 2004 | 2005 | 2004 | ||||||||||
Interest on senior notes | $ | 7,597 | $ | 5,770 | $ | 21,522 | $ | 17,435 | |||||
Interest on senior secured credit facility | — | 759 | — | 2,191 | |||||||||
Interest on capital lease obligations | 113 | 75 | 307 | 157 | |||||||||
Change in redemption value of Series B preferred shares | (421 | ) | — | 36,052 | — | ||||||||
Accretion of Series A preferred shares | 15 | — | 38 | — | |||||||||
Interest on long-term debt | 7,304 | 6,604 | 57,919 | 19,783 | |||||||||
Amortization of deferred financing costs | 884 | 668 | 2,452 | 1,922 | |||||||||
Other interest | 99 | 345 | 1,071 | 1,117 | |||||||||
$ | 8,287 | $ | 7,617 | $ | 61,442 | $ | 22,822 | ||||||
b) | Supplemental cash flow information: |
Three months ended December 31 | Nine months ended December 31 | |||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||
Cash paid during the period for: | ||||||||||||
Interest | $ | 16,007 | $ | 13,830 | $ | 29,252 | $ | 29,584 | ||||
Income taxes | 150 | 225 | 463 | 3,408 | ||||||||
Cash received during the period for: | ||||||||||||
Interest | 74 | 32 | 237 | 305 | ||||||||
Income taxes | 2 | — | 2 | — | ||||||||
Non-cash transactions: | ||||||||||||
Capital leases | 501 | 1,561 | 2,480 | 3,652 | ||||||||
Series A preferred shares | — | — | 321 | — |
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
c) | Net change in non-cash working capital: |
Three months ended December 31 | Nine months ended December 31 | |||||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||
Operating activities: | ||||||||||||||||
Accounts receivable | $ | (8,023 | ) | $ | (18,801 | ) | $ | (12,107 | ) | $ | (11,885 | ) | ||||
Unbilled revenue | 17,259 | 13,519 | 5,762 | 2,963 | ||||||||||||
Inventory | (533 | ) | 392 | (421 | ) | 307 | ||||||||||
Prepaid expenses | (487 | ) | (1,151 | ) | (536 | ) | (590 | ) | ||||||||
Accounts payable | 14,712 | 11,700 | 4,847 | 16,262 | ||||||||||||
Accrued liabilities | (9,828 | ) | (7,021 | ) | (5,700 | ) | (10,971 | ) | ||||||||
Billings in excess of costs and estimated earnings | 3,636 | — | 4,277 | — | ||||||||||||
$ | 16,736 | $ | (1,362 | ) | $ | (3,878 | ) | $ | (3,914 | ) | ||||||
Investing activities: | ||||||||||||||||
Accounts payable | $ | 2,532 | $ | — | $ | 3,051 | $ | — | ||||||||
Accrued liabilities | 1,090 | — | 1,161 | — | ||||||||||||
$ | 3,622 | $ | — | $ | 4,212 | $ | — | |||||||||
d) | Investment in joint venture: |
The Company has determined that the joint venture in which it participates is a variable interest entity (“VIE”) as defined by AcG-15 and that the Company is the primary beneficiary. Accordingly, the joint venture has been consolidated on a prospective basis effective January 1, 2005. During the fourth quarter of fiscal 2005, the arrangement of this joint venture was amended such that the Company is responsible for all of its activities and revenues. As a result, no minority interest has been recorded.
The Company’s transactions with the joint venture eliminate on consolidation.
December 31, 2005 | March 31, 2005 | |||||
Assets | ||||||
Accounts receivable | $ | 23,375 | $ | 11,749 | ||
Unbilled revenue | 11,909 | 20,932 | ||||
$ | 35,284 | $ | 32,681 | |||
Liabilities | ||||||
Bank indebtedness | $ | 1,093 | $ | — | ||
Accounts payable | 15,869 | 5,065 | ||||
Accrued liabilities | 952 | 2,050 | ||||
Billings in excess of costs on uncompleted projects | 2,320 | — | ||||
Venturer’s equity | 15,050 | 25,566 | ||||
$ | 35,284 | $ | 32,681 | |||
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
Three months ended December 31 | Nine months ended December 31 | ||||||||||||||
2005 | 2004 | 2005 | 2004 | ||||||||||||
Revenue | $ | 53,434 | $ | 4,025 | $ | 138,565 | $ | 7,631 | |||||||
Project costs | 53,894 | 4,107 | 130,746 | 8,840 | |||||||||||
Net income (loss) | $ | (460 | ) | $ | (82 | ) | $ | 7,819 | $ | (1,209 | ) | ||||
Three months ended December 31 | Nine months ended December 31 | |||||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||
Cash provided by (used in): | ||||||||||||||||
Operating activities | $ | 17,624 | $ | (3,292 | ) | $ | 17,242 | $ | (4,668 | ) | ||||||
Investing activities | — | — | — | — | ||||||||||||
Financing activities | (19,019 | ) | 3,290 | (18,335 | ) | 5,061 | ||||||||||
$ | (1,395 | ) | $ | (2 | ) | $ | (1,093 | ) | $ | 393 | ||||||
9. | Segmented information |
a) | 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.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
b) | Results by business segment: |
For the three months ended December 31, 2005 | Mining and Site Preparation | Piling | Pipeline | Total | ||||||||
Revenues from external customers | $ | 89,773 | $ | 20,998 | $ | 10,753 | $ | 121,524 | ||||
Depreciation of property, plant and equipment | 2,384 | 374 | 188 | 2,946 | ||||||||
Segment profits | 4,749 | 6,337 | 3,071 | 14,157 | ||||||||
Segment assets | 324,561 | 85,079 | 44,113 | 453,753 | ||||||||
Expenditures for segment property, plant and equipment | 7,605 | 118 | 49 | 7,772 |
For the three months ended December 31, 2004 | Mining and Site Preparation | Piling | Pipeline | Total | ||||||||||
Revenues from external customers | $ | 63,872 | $ | 13,319 | $ | 3,801 | $ | 80,992 | ||||||
Depreciation of property, plant and equipment | 2,618 | 562 | 40 | 3,220 | ||||||||||
Segment profits | (9,183 | ) | 2,320 | 390 | (6,473 | ) | ||||||||
Segment assets | 299,211 | 79,470 | 45,204 | 423,885 | ||||||||||
Expenditures for segment property, plant and equipment | 2,784 | 27 | 773 | 3,584 |
For the nine months ended December 31, 2005 | Mining and Site Preparation | Piling | Pipeline | Total | ||||||||
Revenues from external customers | $ | 265,805 | $ | 63,299 | $ | 20,783 | $ | 349,887 | ||||
Depreciation of property, plant and equipment | 6,846 | 1,233 | 1,218 | 9,297 | ||||||||
Segment profits | 27,087 | 14,275 | 5,106 | 46,468 | ||||||||
Segment assets | 324,561 | 85,079 | 44,113 | 453,753 | ||||||||
Expenditures for segment property, plant and equipment | 18,922 | 367 | 49 | 19,338 |
For the nine months ended December 31, 2004 | Mining and Site Preparation | Piling | Pipeline | Total | |||||||||
Revenues from external customers | $ | 173,250 | $ | 43,957 | $ | 17,325 | $ | 234,532 | |||||
Depreciation of property, plant and equipment | 7,231 | 1,860 | 122 | 9,213 | |||||||||
Segment profits | (130 | ) | 9,100 | 2,378 | 11,348 | ||||||||
Segment assets | 299,211 | 79,470 | 45,204 | 423,885 | |||||||||
Expenditures for segment property, plant and equipment | 15,418 | 85 | 773 | 16,276 |
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
c) | Reconciliations: |
i. | Loss before income taxes: |
Three months ended December 31 | Nine months ended December 31 | |||||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||
Total profit for reportable segments | $ | 14,157 | $ | (6,473 | ) | $ | 46,468 | $ | 11,348 | |||||||
Unallocated corporate expenses | (12,100 | ) | (24,795 | ) | (84,591 | ) | (56,277 | ) | ||||||||
Unallocated equipment revenue (cost) | 212 | 579 | 2,937 | 283 | ||||||||||||
Income (loss) before income taxes | $ | 2,269 | $ | (30,689 | ) | $ | (35,186 | ) | $ | (44,646 | ) | |||||
ii. | Total assets: |
December 31, 2005 | March 31, 2005 | |||||
Total assets for reportable segments | $ | 453,753 | $ | 439,350 | ||
Corporate assets | 95,268 | 87,318 | ||||
Total assets | $ | 549,021 | $ | 526,668 | ||
The Company’s goodwill was assigned to the Mining and Site Preparation, Piling and Pipeline segments in the amounts of $125,447, $40,349, 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.
d) | Customers: |
The following customers accounted for 10% or more of total revenues:
Three months ended December 31 | Nine months ended December 31 | |||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||
Customer A | 40 | % | 5 | % | 38 | % | 4 | % | ||||
Customer B | 12 | % | 22 | % | 14 | % | 32 | % | ||||
Customer C | 8 | % | 17 | % | 11 | % | 8 | % | ||||
Customer D | 1 | % | 18 | % | 3 | % | 15 | % |
This revenue by major customer was earned in all three business segments: Mining and Site Preparation, Pipeline and Piling.
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
10. | Related party transactions |
All related party transactions described below are measured at the exchange amount of consideration established and agreed to by the related parties.
a) | Transactions with Sponsors: |
The Sterling Group, L.P. (“Sterling”), Genstar Capital, L.P., Perry Strategic Capital Inc., and Stephens Group, Inc., (the “Sponsors”), entered into an agreement with NACG Holdings Inc. and certain of its subsidiaries, including the Company, to provide consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. As compensation for these services an advisory fee of $100 for the three months ended December 31, 2005 (three months ended December 31, 2004 – $100) is payable to the Sponsors, as a group. For the nine months ended December 31, 2005, $300 is payable to the Sponsors pursuant to this agreement (nine months ended December 31, 2004 – $300). Additionally, 7,500 Series B preferred shares were issued to the above Sponsor group in exchange for cash of $7.5 million (see note 7(a)).
b) | Office rent: |
Pursuant to several office lease agreements, for the three months ended December 31, 2005 the Company paid $178 (three months ended December 31, 2004 – $237) to a company owned, indirectly and in part, by one of the Directors. For the nine months ended December 31, 2005 the company paid $772 (nine months ended December 31, 2004 – $645).
11. | Financial instruments |
The Company is exposed to market risks related to interest rate and foreign currency fluctuations. To mitigate these risks, the Company uses derivative financial instruments such as foreign currency and interest rate swap contracts.
a) | Fair value: |
The fair values of the Company’s cash and cash equivalents, accounts receivable, unbilled revenue, accounts payable, and accrued liabilities approximate their carrying amounts.
The fair value of the senior secured credit facility, senior notes and capital lease obligations (collectively “the debt”) are based on management estimates which are determined by discounting cash flows required under the debt at the interest rate currently estimated to be available for loans with similar terms. Based on these estimates, the fair value of the Company’s senior secured credit facility, and capital lease obligations as at December 31, 2005 are not significantly different than their carrying values as they bear interest at floating rates. The market value of the 9% senior secured notes as at December 31, 2005 is $73,540 compared to a carrying value of $70,515. The market value of the 8 3/4% notes as at December 31, 2005 is $218,644 compared to a carrying value of $233,180.
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
b) | Interest rate risk: |
The Company is subject to interest rate risk on the revolving credit facility and capital lease obligations. At December 31, 2005, for each 1% annual fluctuation in the interest rate, the annual cost of financing will change by approximately $70.
The Company also leases equipment with a variable lease payment component that is tied to prime rates. At December 31, 2005, for each 1% annual fluctuation in these rates, annual lease expense will change by approximately $244.
c) | Foreign currency risk and derivative financial instruments: |
The Company has 8 3/4% senior unsecured 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, concurrent with the closing of the acquisition on November 26, 2003, 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 through the whole period beginning from the issuance 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 with the net effect of converting the 8.75% rate payable on the senior unsecured notes into a fixed rate of 9.765% for the duration that the senior unsecured notes are outstanding. On May 19, 2005 in connection with the Company’s new revolving credit facility, this fixed rate was increased to 9.889%. These derivative financial instruments do not qualify for hedge accounting. The Company’s derivative financial instruments are carried on the interim consolidated balance sheet at fair value (December 31, 2005 – $63,035; March 31, 2005 – $51,723).
At December 31, 2005, the notional principal amount of the cross-currency swap was US$200 million. The notional principal amounts of the interest rate swaps were US$200 million and Canadian $263 million.
The Company has not hedged its exposure to changes in the U.S. to Canadian dollar exchange rate resulting from the issuance of the 9% senior secured notes.
d) | Operating leases: |
The Company is subject to foreign currency risk on U.S. dollar operating lease commitments as the Company has not entered into a cross-currency swap agreement to hedge this foreign currency exposure.
e) | Credit risk: |
Reflective of its normal business, a majority of the Company’s accounts receivable is due from large companies operating in the resource sector. The Company regularly monitors the activity and balances in these accounts to manage its credit risk and provides an allowance for any doubtful accounts.
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
At December 31, 2005, the following customers represented 10% or more of accounts receivable and unbilled revenue:
December 31, 2005 | March 31, 2005 | |||||
Customer A | 35 | % | 33 | % | ||
Customer B | 5 | % | 11 | % |
12. | Commitments |
The annual future minimum lease payments in respect of operating leases for the next five years and thereafter are as follows:
For the year ending December 31, | |||
2006 | $ | 18,961 | |
2007 | 16,757 | ||
2008 | 7,484 | ||
2009 | 5,969 | ||
2010 and thereafter | 3,082 | ||
$ | 52,253 | ||
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 NACG Holdings Inc. The stock options expire in ten years 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. The maximum number of common shares issuable under this plan may not exceed 105,000, of which 5,070 are still available for issue as at December 31, 2005.
Number of options | Weighted average exercise price $ per share | |||||
Outstanding at March 31, 2005 | 76,242 | $ | 100.00 | |||
Granted | 35,888 | 100.00 | ||||
Exercised | — | — | ||||
Forfeited | (12,200 | ) | 100.00 | |||
Outstanding at December 31, 2005 | 99,930 | $ | 100.00 | |||
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
At December 31, 2005, the weighted average remaining contractual life of outstanding options is 8.6 years.
The Company recorded $293 of compensation expense related to the stock options in the three months ended December 31, 2005 (three months ended December 31, 2004 – $79) with such amount being credited to contributed surplus. For the nine months ended December 31, 2005 the Company recorded $616 of compensation expense related to the stock options (nine months ended December 31, 2004 – $307).
The fair value of each option granted by NACG Holdings Inc. was estimated on the date of the grant using the Black-Scholes option-pricing model with the following assumptions:
Three months ended December 31 | Nine months ended December 31 | |||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||
Number of options granted | 15,888 | 5,000 | 35,888 | 19,112 | ||||||||
Weighted average fair value per option granted ($) | 54.39 | 35.60 | 69.57 | 36.76 | ||||||||
Weighted average assumptions | ||||||||||||
Dividend yield | nil | % | nil | % | nil | % | nil | % | ||||
Expected volatility | nil | % | nil | % | nil | % | nil | % | ||||
Risk-free interest rate | 4.13 | % | 4.16 | % | 4.16 | % | 4.26 | % | ||||
Expected life (years) | 10 | 10 | 10 | 10 |
14. | United States generally accepted accounting principles (“U.S. GAAP”) |
These interim consolidated financial statements have been prepared in accordance with Canadian GAAP which differs in certain respects from U.S. GAAP. For the periods presented herein, material issues that could give rise to measurement differences in the interim consolidated financial statements are as follows:
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.
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. 12 (“APB 12”). As a result, the net income under U.S. GAAP for the three months ended December 31, 2005 and the net loss under U.S. GAAP for the nine months ended December 31, 2005 would have been reduced by $155 and $319, respectively, using the effective interest method.
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
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. SFAS 130 requires that all items that are not required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement. The only components of comprehensive earnings (loss) are the net earnings (loss) for the period.
Stock-based compensation:
The Company uses the fair value method of accounting for all stock-based compensation payments under Canadian GAAP. As a result, there are no differences between Canadian GAAP and Statement of Financial Accounting Standards No. 123 (“SFAS 123”).
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 8 3/4% 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. While initially nominal value was ascribed at issuance, they 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 the fair value being recorded in net earnings 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 EIC-117.
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
Effect of Canadian – U.S. GAAP Differences:
The effect of material differences between Canadian and U.S. GAAP on the Company’s reported loss is set out below:
Three months ended December 31 | Nine months ended December 31 | |||||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||
Net income (loss) (as reported) | $ | 2,119 | $ | (32,427 | ) | $ | (35,580 | ) | $ | (42,202 | ) | |||||
Capitalized interest | 252 | — | 502 | — | ||||||||||||
Amortization using effective interest method | 155 | — | 319 | — | ||||||||||||
Realized and unrealized loss on derivative financial instruments | (169 | ) | — | (575 | ) | — | ||||||||||
Income (loss) before income taxes | 2,357 | (32,427 | ) | (35,334 | ) | (42,202 | ) | |||||||||
Income taxes: | ||||||||||||||||
Deferred income taxes | — | — | — | — | ||||||||||||
Net income (loss) – U.S. GAAP | $ | 2,357 | $ | (32,427 | ) | $ | (35,334 | ) | $ | (42,202 | ) | |||||
The cumulative effect of these adjustments on the consolidated shareholder’s equity of the Company is as follows:
December 31, 2005 | March 31, 2005 | ||||||
Shareholder’s equity (as reported) – Canadian GAAP | $ | 38,575 | $ | 73,539 | |||
Capitalized interest | 502 | — | |||||
Amortization using effective interest method | 319 | — | |||||
Realized and unrealized loss on derivative financial instruments | (575 | ) | — | ||||
Shareholder’s equity – U.S. GAAP | $ | 38,821 | $ | 73,539 | |||
United States accounting pronouncements recently adopted:
In November 2004, the FASB issued Statement on Financial Accounting Standards No. 151, “Inventory Costs” (“SFAS 151”). This standard requires the allocation of fixed production overhead costs be based on the normal capacity of the production facilities and unallocated overhead costs recognized as an expense in
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
the period incurred. In addition, other items such as abnormal freight, handling costs and wasted materials require treatment as current period charges rather than a portion of the inventory cost. This standard is effective for fiscal 2006 of the Company. The adoption of this standard did not have a material impact on the Company’s financial statements.
In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (“FIN 47”), which requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective for fiscal years ending after December 15, 2005. The adoption of this standard did not have a material impact on the Company’s financial statements.
Statement on Financial Accounting Standards No. 153, “Exchanges of Non-monetary Assets – an Amendment of APB Opinion 29” (“SFAS 153”), was issued in December 2004. Accounting Principles Board (“APB”) Opinion 29 is based on the principle that exchanges of non-monetary assets should be measured based on the fair value of assets exchanged. SFAS 153 amends APB Opinion 29 to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. The standard is effective for the Company for non-monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005, beginning July 1, 2005 for the Company. The adoption of this standard did not have a material impact on the Company’s financial statements.
Recent United States accounting pronouncements not yet adopted:
Statement on 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 alternative to use the intrinsic value method of APB Opinion 25 is eliminated with this revised standard. The Company is currently evaluating the impact of this revised standard. The revised standard is effective for non-public companies beginning with the first annual reporting period that begins after December 15, 2005, in the case of the Company beginning April 1, 2006. Since the Company uses the minimum value method for purposes of complying with Statement 123, it is required to adopt SFAS 123R prospectively.
In May 2005, the FASB issued Statement on Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”) which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and SFAS 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 change 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 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 and is required to be adopted by the Company in its fiscal year beginning on April 1, 2006. The Company is currently evaluating the effect that the adoption of SFAS 154
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2005
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
will have on its consolidated results of operations and financial condition but does not expect it to have a material impact.
NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
Management’s Discussion and Analysis
For the Three and Nine Months Ended December 31, 2005
The following discussion should be read in conjunction with the attached interim consolidated financial statements for the three and nine months ended December 31, 2005. This document contains forward-looking statements. Such 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.
Overview
We provide services primarily to major oil and natural gas, petrochemical, 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 is involved in a variety of activities, including: surface mining for oilsands and other natural resources; overburden removal; hauling sand and gravel; supplying labor and equipment to support customers’ mining operations; construction of infrastructure associated with mining operations and reclamation activities; clearing, stripping, excavating, and grading for mining operations and industrial site construction mega-projects; and underground utility installation for plant, refinery, and commercial building construction. The Piling operating segment installs all types of driven and drilled piles, caissons, and earth retention and stabilization systems for industrial projects primarily focused on the oil sands and related petrochemical or refinery complexes, as well as commercial buildings and infrastructure projects. The Pipeline operating segment installs transmission and distribution pipes made of steel, plastic, and fibreglass materials in sizes up to, and including, 52 inches in diameter for oil and natural gas transmission.
We and our predecessor company, Norama Ltd., the company we acquired on November 26, 2003, have been operating for over 50 years and operate the largest equipment fleet of any resource services provider in western Canada. In serving our customers, we operate over 460 pieces of heavy construction equipment and over 540 support vehicles. Our fleet size provides flexibility in scheduling and completing contract services on a timely basis
NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
and allows us to undertake long-term, large-scale projects with major operators in oilsands development and other energy sectors.
Consolidated Financial Results
Three months ended December 31 | Nine months ended December 31 | |||||||||||||||||||||||||||
(in millions of Canadian dollars) | 2005 | 2004 | 2005 | 2004 | ||||||||||||||||||||||||
Revenue | $ | 121.5 | 100.0 | % | $ | 81.0 | 100.0 | % | $ | 349.9 | 100.0 | % | $ | 234.5 | 100.0 | % | ||||||||||||
Project costs | 82.1 | 67.6 | % | 66.7 | 82.3 | % | 228.5 | 65.3 | % | 167.6 | 71.5 | % | ||||||||||||||||
Equipment costs | 15.8 | 13.0 | % | 12.9 | 15.9 | % | 46.4 | 13.3 | % | 36.6 | 15.6 | % | ||||||||||||||||
Operating lease expense | 4.3 | 3.5 | % | 1.7 | 2.1 | % | 10.3 | 2.9 | % | 3.1 | 1.3 | % | ||||||||||||||||
Depreciation | 5.5 | 4.5 | % | 5.3 | 6.5 | % | 16.0 | 4.6 | % | 15.0 | 6.4 | % | ||||||||||||||||
Gross profit | 13.8 | 11.4 | % | (5.6 | ) | -6.9 | % | 48.7 | 13.9 | % | 12.2 | 5.2 | % | |||||||||||||||
General and administrative | 8.2 | 6.7 | % | 5.3 | 6.5 | % | 22.0 | 6.3 | % | 15.4 | 6.6 | % | ||||||||||||||||
(Gain) loss on disposal of property, plant and equipment | (0.5 | ) | -0.4 | % | 0.3 | 0.4 | % | (0.8 | ) | -0.2 | % | 0.5 | 0.2 | % | ||||||||||||||
Amortization of intangible assets | 0.2 | 0.2 | % | 0.5 | 0.6 | % | 0.5 | 0.1 | % | 3.0 | 1.3 | % | ||||||||||||||||
Operating income | 5.9 | 4.9 | % | (11.7 | ) | -14.4 | % | 27.0 | 7.7 | % | (6.7 | ) | -2.9 | % | ||||||||||||||
Interest expense | 8.2 | 6.7 | % | 7.6 | 9.4 | % | 61.4 | 17.5 | % | 22.8 | 9.7 | % | ||||||||||||||||
Foreign exchange loss (gain) | 0.9 | 0.7 | % | (11.9 | ) | -14.7 | % | (14.3 | ) | -4.1 | % | (21.3 | ) | -9.1 | % | |||||||||||||
Other income | (0.1 | ) | -0.1 | % | — | 0.0 | % | (0.4 | ) | -0.1 | % | (0.3 | ) | -0.1 | % | |||||||||||||
Financing costs | — | 0.0 | % | — | 0.0 | % | 2.1 | 0.6 | % | — | 0.0 | % | ||||||||||||||||
Realized and unrealized (gain) loss on derivative financial instruments | (5.4 | ) | -4.4 | % | 23.3 | 28.8 | % | 13.4 | 3.8 | % | 36.8 | 15.7 | % | |||||||||||||||
Income (loss) before income taxes | $ | 2.3 | 1.9 | % | $ | (30.7 | ) | -37.9 | % | $ | (35.2 | ) | -10.1 | % | $ | (44.7 | ) | -19.1 | % | |||||||||
Revenue
Revenue for the three and nine months ended December 31, 2005 increased by $40.5 million (50.0 percent) and $115.4 million (49.2 percent), respectively, from the same periods in the prior year. The increases are primarily due to a number of new mining and site preparation projects, including the large site preparation and underground utility installation and overburden removal projects for Canadian Natural Resources Ltd. (“CNRL”) and the mining project for Grande Cache Coal Corporation, and increased piling activity. Revenue from these new projects in the current periods more than offset the declines in revenue primarily due to the substantial completion of the Syncrude UE1 site grading project and the Opti/Nexen Long Lake project.
Project costs
Project costs for the three months ended December 31, 2005 increased by $15.4 million (23.1 percent) from the same period in the prior year primarily due to higher activity levels. As a percentage of revenue, project costs were 67.6 percent in the three months ended December 31, 2005 as compared to 82.3 percent in the comparative period. This is primarily due to poor performance on certain site preparation projects in the prior year and more efficient management of costs.
Project costs for the nine months ended December 31, 2005 increased by $60.9 million (36.3 percent) from the same period in the prior year primarily due to higher activity levels and changes in job mix of labour and equipment. As a percentage of revenue, project costs were 65.3 percent in the nine months ended December 31, 2005 as compared to 71.5 percent in the comparative period. The decline is primarily due to poor performance on certain site preparation projects in the prior year and a changing project work mix between labour and equipment.
2
NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
Equipment costs
Equipment costs for the three months ended December 31, 2005 increased by $2.9 million (22.5 percent) from the same period in the prior year primarily due to higher operated hours due to increased activity levels.
Equipment costs for the nine months ended December 31, 2005 increased by $9.8 million (26.8 percent) from the same period in the prior year primarily due to increased activity levels and higher repair and maintenance costs.
Operating lease expense
Operating lease expense for the three and nine months ended December 31, 2005 increased by $2.6 million (152.9 percent) and $7.2 million (232.3 percent), respectively, from the corresponding periods in the prior year. This is primarily due to the addition of new leased equipment to support new projects, including the CNRL overburden project.
Depreciation
Depreciation expense for the three and nine months ended December 31, 2005 increased by $0.2 million (3.8 percent) and $1.0 million (6.7 percent), respectively, from the corresponding periods in the prior year. The increase was primarily due to the increase in equipment hours related to higher activity levels, as our heavy equipment fleet is depreciated based on operated hours.
General and administrative expenses
General and administrative expenses for the three months ended December 31, 2005 increased by $2.9 million (54.7 percent) from the corresponding period in the prior year. The increase was primarily attributable to: increased salaries; higher consulting costs; and increased professional fees.
General and administrative expenses for the nine months ended December 31, 2005 increased by $6.6 million (42.9 percent) from the same period in the prior year. The increase was primarily due to increased professional fees and salaries.
Amortization of intangible assets
The amortization of intangible assets in both the current and comparative periods was related to the customer contracts in progress, trade names, non-competition agreement, and employee arrangements that were acquired in the acquisition on November 26, 2003. Substantially all of the cost of the intangible assets has been amortized as of December 31, 2005 as the majority of the cost relates to customer contracts in progress that were amortized at a rapid rate due to their short-term nature.
Amortization of intangible assets for the three months ended December 31, 2005 was $0.2 million, a decrease of $0.3 million (60.0 percent) from the same period in the prior year. For the nine months ending December 31, 2005, amortization of intangible assets was $0.5 million, a decrease of $2.5 million (83.3 percent) over the prior year.
Interest expense
Interest expense for the three months ended December 31, 2005 increased by $0.6 million (7.9 percent) from the corresponding period in the prior year. Increased interest due to the issuance of US$60.5 million of 9% senior secured notes in the current fiscal year and changes in the redemption value of Series B mandatorily redeemable preferred shares issued in the current fiscal year were partially offset by a decrease in interest expense due to the full repayment of the senior secured credit facility in the current fiscal year.
3
NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
For the nine months ended December 31, 2005, interest expense increased by $38.6 million (169.3 percent) from the prior year. Increased interest due to the issuance of US$60.5 million of 9% senior secured notes in the current fiscal year, the accretion of the Series A mandatorily redeemable preferred shares issued in the current fiscal year and changes in the redemption value of the Series B mandatorily redeemable preferred shares issued in the current fiscal year were in excess of the decrease to interest expense due to full repayment of the senior secured credit facility in the current year.
Foreign exchange loss
The foreign exchange loss for the three months ended December 31, 2005 was $0.9 million as compared to a gain of $11.9 million in the comparative period, a difference of 107.6 percent. Substantially all of the loss in the current period is due 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 May 19, 2005 and the US$200.0 million of 8 3/4% senior notes. 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 swap and interest rate swaps which went into effect concurrent with the issuance of the same notes. The swaps on the 8 3/4% notes do not qualify for hedge accounting under 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 (gain) loss on derivative financial instruments” in our consolidated financial statements. The foreign exchange gain for the three months ended December 31, 2004 related primarily to the US $200 million of 8 3/4% notes.
The foreign exchange gain for the nine months ended December 31, 2005 was $14.3 million as compared to a gain of $21.3 million from the comparative period prior year. Substantially all of the gain in the current period related 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 the current period and the US$200 million of 8 3/4% senior notes, while the gain in the comparative period related only to the US$200 million of 8 3/4% senior notes.
Financing costs
Financing costs of $0.3 million were recorded in the nine months ended December 31, 2005 representing the issuance of the Series A mandatory redeemable preferred shares. In addition, we wrote-off $1.8 million of deferred financing costs related to the previous senior secured credit facility that was repaid in the quarter ending June 30, 2005.
Realized and unrealized gain and loss on derivative financial instruments
The realized and unrealized gain on the cross-currency and interest rate swap agreements, which do not qualify for hedge accounting, was $5.4 million for the three months ended December 31, 2005. For the nine months ended December 31, 2005, the realized and unrealized loss on these derivative financial instruments was $13.4 million. These losses relate primarily to the mark-to-market changes in the fair value of the derivatives in the current periods. The realized and unrealized losses on the derivative financial instruments were $23.3 million and $36.8 million for the respective comparative periods. The realized loss for the three months ended December 31, 2005 was $0.6 million, compared to a realized loss of $0.7 million in the three months ended December 31, 2004. For the nine months ended December 31, 2005, the realized loss was $2.1 million, while the realized loss was $2.0 million in the comparative period.
4
NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
Comparative Quarterly Results
A number of factors contribute to variations in our results between periods, such as: weather, customer capital spending on large oilsands 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.
Fiscal Year 2006 | Fiscal Year 2005 | Fiscal Year 2004 | ||||||||||||||||||||||||||||
(in millions of Canadian dollars, except equipment hours) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | ||||||||||||||||||||||
Revenue | $ | 121.5 | $ | 124.0 | $ | 104.4 | $ | 122.8 | $ | 81.0 | $ | 82.7 | $ | 70.9 | $ | 102.4 | ||||||||||||||
Gross profit | 13.8 | 21.9 | 12.9 | 24.0 | (5.6 | ) | 9.8 | 8.1 | 19.8 | |||||||||||||||||||||
Net income (loss) | 2.1 | 11.6 | (49.1 | ) | (0.1 | ) | (32.4 | ) | (4.7 | ) | (5.1 | ) | (2.6 | ) | ||||||||||||||||
Equipment hours | 231,625 | 251,904 | 202,327 | 241,727 | 191,555 | 193,205 | 137,434 | 188,557 |
The higher revenues experienced over the recent four quarters compared to prior periods primarily resulted from new mining and site preparation projects, including the CNRL site preparation and underground utility installation projects and Grande Cache Coal mining services project, higher activity in the piling division and summer pipeline work.
Segmented Results of Operations
We report our operations under three operating segments: Mining and Site Preparation, Piling and Pipeline.
Selected Segmented Information
Three months ended December 31 | Nine months ended December 31 | |||||||||||||||||||||||||
(in millions of Canadian dollars, except equipment hours) | 2005 | 2004 | 2005 | 2004 | ||||||||||||||||||||||
Revenue by operating segment | ||||||||||||||||||||||||||
Mining and Site Preparation | $ | 89.7 | 73.8 | % | $ | 63.9 | 78.9 | % | $ | 265.8 | 76.0 | % | $ | 173.3 | 73.9 | % | ||||||||||
Piling | 21.0 | 17.3 | % | 13.3 | 16.4 | % | 63.3 | 18.1 | % | 43.9 | 18.7 | % | ||||||||||||||
Pipeline | 10.8 | 8.9 | % | 3.8 | 4.7 | % | 20.8 | 5.9 | % | 17.3 | 7.4 | % | ||||||||||||||
Total | $ | 121.5 | 100.0 | % | $ | 81.0 | 100.0 | % | $ | 349.9 | 100.0 | % | $ | 234.5 | 100.0 | % | ||||||||||
Profit by operating segment | ||||||||||||||||||||||||||
Mining and Site Preparation | $ | 4.8 | 33.8 | % | $ | (9.2 | ) | 141.5 | % | $ | 27.1 | 58.2 | % | $ | (0.1 | ) | (0.9 | )% | ||||||||
Piling | 6.3 | 44.4 | % | 2.3 | -35.4 | % | 14.3 | 30.8 | % | 9.1 | 79.8 | % | ||||||||||||||
Pipeline | 3.1 | 21.8 | % | 0.4 | -6.1 | % | 5.1 | 11.0 | % | 2.4 | 21.2 | % | ||||||||||||||
Total | $ | 14.2 | 100.0 | % | $ | (6.5 | ) | 100.0 | % | $ | 46.5 | 100.0 | % | $ | 11.4 | 100.0 | % | |||||||||
Equipment hours by operating segment | ||||||||||||||||||||||||||
Mining and Site Preparation | 215,681 | 93.1 | % | 175,970 | 91.9 | % | 641,540 | 93.5 | % | 460,891 | 88.3 | % | ||||||||||||||
Piling | 8,357 | 3.6 | % | 13,013 | 6.8 | % | 25,466 | 3.7 | % | 45,929 | 8.8 | % | ||||||||||||||
Pipeline | 7,587 | 3.3 | % | 2,572 | 1.3 | % | 18,870 | 2.8 | % | 15,374 | 2.9 | % | ||||||||||||||
Total | 231,625 | 100.0 | % | 191,555 | 100.0 | % | 685,856 | 100.0 | % | 522,194 | 100.0 | % | ||||||||||||||
Mining and Site Preparation
Revenue for the three and nine months ended December 31, 2005 increased by $25.8 million (40.4 percent) and $92.5 million (53.4 percent), respectively, from the same periods in the prior year primarily due to activity in the current periods related to the large site preparation and underground utility installation and overburden removal project for CNRL and the mining services project for Grande Cache Coal Corporation. Revenue generated by these projects in the current periods more than offset the decline in revenue resulting from the substantial completion of the Syncrude UE1 and Opti/Nexen Long Lake projects.
5
NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
Segment profits for the three and nine months ended December 31, 2005 increased by $14.0 million (152.2 percent) and $27.2 million, respectively, from the comparative periods in the prior year due to the higher volume of work in the current periods and unusually poor results in the comparative periods related to two relatively large projects that were completed or substantially completed in the prior year.
Piling
Piling revenue for the three and nine months ended December 31, 2005 increased by $7.7 million (57.9 percent) and $19.4 million (44.2 percent), respectively, from the comparative prior periods primarily due to a higher volume of projects in the Vancouver, Regina, and Fort McMurray regions because of strong economic and construction activity, as well as the addition of several large piling projects, including projects for Flint Infrastructure Services Ltd. and Suncor Energy.
Profit for the Piling operating segment increased by $4.0 million (173.9 percent) and $5.2 million (57.1 percent) for the three and nine months ended December 31, 2005, respectively, as compared to the comparative prior period due to the higher volume of work performed in the current periods.
Pipeline
Pipeline operating segment revenue for the three months ended December 31, 2005 increased by $7.0 million (184.2 percent) from the comparative prior period primarily due to an increase in work performed in projects with CNRL. Profit for this operating segment for the three months ended December 31, 2005 increased by $2.7 million (675.0 percent) from the comparative prior period primarily as a result of the higher activity in the current period.
Revenue for this segment for the nine months ended December 31, 2005 increased by $3.5 million (20.2 percent) from the comparative prior period due to an increase in work performed for our major pipeline customer in the current period and CNRL. Segment profit for the nine months ended December 31, 2005 increased by $2.7 million (112.5 percent) from the comparative prior period primarily as a result of the higher activity in the current period.
Consolidated Financial Position
At December 31, 2005, we had net working capital of $54.8 million compared to a net working capital position of $41.7 million at March 31, 2005. The increase was primarily due to increased work in progress generating higher invoicing and accounts receivable by $12.2 million, and an increase in cash and cash equivalents of $13.9 million, partially offset by a total increase of $12.2 million in accounts payable and billings in excess of costs on uncompleted projects.
Property, plant and equipment net of depreciation increased by $5.4 million at December 31, 2005 from March 31, 2005 primarily due to the expansion of our head office and the on-going construction of a shop to support the maintenance requirements of our 10-year overburden removal project for CNRL. A portion of the increase also resulted from equipment purchases to replace retired equipment.
Capital lease obligations, including the current portion, increased by $1.0 million at December 31, 2005 from the balance at March 31, 2005 due to the addition of new leased vehicles to support new projects.
6
NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
Impairment of Goodwill
In accordance with Canadian Institute of Chartered Accountants’ Handbook Section 3062, “Goodwill and Other Intangible Assets”, we review our goodwill for impairment annually or whenever events or changes in circumstances suggest that the carrying amount may not be recoverable. We are required to test our goodwill for impairment at the reporting unit level and we have determined that we have three reporting units. The test for goodwill impairment is a two-step process:
• | Step 1 – We compare the carrying amount of each reporting unit to its fair value. If the carrying amount of a reporting unit exceeds its fair value, we have to perform the second step of the process. If not, no further work is required. |
• | Step 2 – We compare the implied fair value of each reporting unit’s goodwill to its carrying amount. If the carrying amount of a reporting unit’s goodwill exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess. |
We completed this test during the quarter ended December 31, 2005 and were not required to record an impairment loss on goodwill.
Liquidity and Capital Resources
Operating activities
Operating activities for the three months ended December 31, 2005 resulted in a net increase of cash totalling $19.7 million mainly due to increased earnings, combined with a decrease in unbilled revenue and higher accounts payable. Cash used in operating activities for the three months ended December 31, 2004 was $15.5 million.
Operating activities for the nine months ended December 31, 2005 resulted in a net increase in cash of $14.3 million. Increased earnings and accounts payable were partially offset by an increase in accounts receivable. The net usage of cash in operating activities for the nine months ended December 31, 2004 was $17.6 million primarily due to an increase in unbilled revenue due to billing delays and poor performance from the Opti/Nexen Long Lake project.
Investing activities
During the three months ended December 31, 2005, we invested $2.2 million in sustaining capital expenditures and $7.9 million in growth capital expenditures compared to $1.5 million and $4.6 million, respectively, during the same period in the prior year. In addition, we financed new equipment by way of capital leases totalling $0.5 million during the three months ended December 31, 2005 compared to $1.6 million during the same period in the prior year.
During the nine months ended December 31, 2005, we invested $7.0 million in sustaining capital expenditures, $16.3 million in growth capital expenditures, and $2.5 million in new equipment capital leases. In the nine months ended December 31, 2004, we invested $4.6 million in sustaining capital expenditures, $15.9 million in growth capital expenditures, and $3.7 million in new vehicle capital leases.
We expect our future sustaining capital expenditures to range from $5.0 million to $7.0 million per year, not including replacement capital expenditures. Sustaining capital expenditures are those that are required to maintain our existing fleet of equipment at its optimum average age. Growth capital expenditures relate to equipment additions required to perform increased sizes or numbers of projects.
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NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
Financing activities
Financing activities during the three months ended December 31, 2005 resulted in a net decrease of cash totalling $1.5 million primarily due to payments made on our capital leases and the repurchase of Series B mandatorily redeemable preferred shares. See “Sources of Liquidity” for further discussion of our Series B mandatorily redeemable preferred shares.
Financing activities during the nine months ended December 31, 2005 resulted in a cash inflow of $13.5 million. A portion of the proceeds from the issuance of the US$60.5 million of 9% senior secured notes and $7.5 million of Series B preferred shares was used to repay the amount outstanding under our senior secured credit facility and to pay the fees and expenses related to the refinancing. Payments of $1.5 million were also made on our capital lease obligations.
Financing activities during the three and nine months ended December 31, 2004 related primarily to borrowings under our revolving credit facility, term credit facility scheduled repayments, and repayment of capital lease obligations.
Liquidity Requirements
Our primary uses of cash are to purchase property, plant and equipment, fulfill debt repayment and interest payment obligations, and finance working capital requirements.
We have outstanding US$200 million of 8 3/4% senior notes due 2011.
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 swap and interest rate swaps which went into effect concurrent with the issuance. Interest of $12.8 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 8 3/4% 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 July 26, 2005, we registered substantially identical notes with the United States Securities and Exchange Commission and exchanged them for the notes issued in the private placement.
The foreign currency risk relating to both the principal and interest payments on the 9% senior secured notes has not been hedged. Interest of US$2.7 million is payable semi-annually in June and December of each year until the notes mature on June 1, 2010. There are no principal repayments required on the 9% senior secured notes until maturity.
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 conserve cash, we have financed our recent requirements for large pieces of heavy construction equipment through operating leases. In addition, we continue to lease a portion of our motor vehicle fleet and assumed several heavy equipment operating leases from Norama Ltd., the company we acquired on November 26, 2003.
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NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
Our cash requirements during the nine months ended December 31, 2005 increased due to continued growth and acquisition of new projects. Our cash requirements for the remainder of the 2006 fiscal year 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 upcoming new projects.
Sources of Liquidity
Our principal sources of cash are funds from operations and borrowings under our revolving credit facility. The revolving credit facility provides for borrowings of up to $40.0 million, subject to borrowing base limitations, under which revolving loans may be made and letters of credit, up to a limit of $30.0 million, may be issued. As of December 31, 2005, we had no outstanding borrowings under the revolving credit facility and had issued $23.0 million in letters of credit to support bonding requirements and performance guarantees associated with customer contracts. The borrowing base less first lien exposure on our swap agreements and outstanding letters of credit at December 31, 2005 was $4.9 million. In addition, we had cash on hand of $31.8 million. The facility bears interest at the Canadian prime rate plus 2% or Canadian bankers’ acceptance rate plus 3%. The indebtedness under the revolving credit facility is secured by substantially all of our assets and those of our subsidiaries, including accounts receivable, inventory and property, plant and equipment, and a pledge of our capital stock and that of our subsidiaries.
On April 27, 2005, Moody’s lowered its rating of our 8 3/4% senior notes to Caa1 from B3 and lowered our long-term corporate rating to B3 from B2. In addition, Moody’s assigned a rating of B3 to the new 9% senior secured notes. On May 19, 2005, Standard & Poor’s lowered its rating of our 8 3/4% senior notes to CCC+ from B- and our long-term corporate credit rating to B- from B, while assigning a rating of B to our new senior secured notes. The lower credit ratings have no effect on the interest rates associated with our 8 3/4% senior notes or 9% senior secured notes.
The Series B mandatorily redeemable preferred shares were initially issued for cash proceeds of $7.5 million on May 19, 2005 to the Sponsors referred to under “Related Party Transactions” below. We subsequently offered and sold $0.9 million of Series B preferred shares to other existing shareholders of our ultimate parent company, NACG Holdings Inc. On November 1, 2005, the proceeds from this subsequent sale were used to repurchase a like amount of Series B preferred shares from the Sponsors. During the three months ended December 31, 2005, 163 Series B preferred shares were issued for cash consideration of $16.
The payment of dividends and the redemption of the shares are restricted by the indenture agreements governing our 8 3/4% senior notes and 9% senior secured notes, as well as the agreement governing our revolving credit facility. The redemption amount is the greatest of:
i. | $15.0 million less the amount, if any, of dividends previously paid in cash; |
ii. | an amount that, when combined with the amount, if any, of dividends previously paid in cash, provides a 40% internal rate of return, compounded annually from the date of issue, which at December 31, 2005 is calculated to be $9.2 million; and |
iii. | 25% of the fair market value of our capital shares without taking into account the Series B preferred shares, which management estimates to be $43.6 million at December 31, 2005. |
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NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
The total redemption amount is limited to $100 million. For additional information on the Series B preferred shares, refer to note 7(a) in our interim consolidated financial statements for the three and nine months ended December 31, 2005.
Contractual Obligations
Our principal contractual obligations relate to our long-term debt (senior notes and senior secured notes), Series A and B mandatorily redeemable preferred shares, and capital and operating leases. The following table summarizes our future contractual obligations, excluding interest payments unless otherwise noted, as of December 31, 2005.
Payments Due by Period | ||||||||||||||||||
(in millions of Canadian dollars) | Total | 2006 | 2007 | 2008 | 2009 | 2010 and after | ||||||||||||
Long-term debt | $ | 303.7 | $ | — | $ | — | $ | — | $ | — | $ | 303.7 | ||||||
Mandatorily redeemable preferred shares | 44.6 | — | — | — | — | 44.6 | ||||||||||||
Capital leases (including interest) | 9.0 | 2.6 | 2.8 | 2.1 | 1.2 | 0.3 | ||||||||||||
Operating leases | 52.4 | 19.0 | 16.8 | 7.5 | 6.0 | 3.1 | ||||||||||||
Total contractual obligations | $ | 409.7 | $ | 21.6 | $ | 19.6 | $ | 9.6 | $ | 7.2 | $ | 351.7 | ||||||
Stock-Based Compensation
Certain of our directors, officers, employees, and service providers have been granted options to purchase common shares of NACG Holdings Inc., our ultimate parent company, under a stock-based compensation plan. The plan and outstanding balances are disclosed in note 13 to our interim consolidated financial statements for the three and nine months ended December 31, 2005.
Related Party Transactions
The Sterling Group, L.P. (“Sterling”), Genstar Capital, L.P., Perry Strategic Capital Inc., and Stephens Group, Inc., (the “Sponsors”), entered into an agreement with NACG Holdings Inc. and certain of its subsidiaries, including us, to provide consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. As compensation for these services an advisory fee of $100,000 for the three months ended December 31, 2005 (three months ended December 31, 2004 – $100,000) is payable to the Sponsors, as a group. For the nine months ended December 31, 2005, an advisory fee of $300,000 (nine months ended December 31, 2004 – $300,000) is payable to the Sponsors pursuant to this agreement.
Pursuant to several office lease agreements, for the three months ended December 31, 2005 we paid $178,000 (three months ended December 31, 2004 – $237,000) to a company owned, indirectly and in part, by one of our directors. For the nine months ended December 31, 2005 we paid $772,000 (nine months ended December 31, 2004 – $645,000).
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. Future events and their
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NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
effects cannot be determined with absolute certainty. Therefore, the determination of estimates requires the exercise of management’s judgment. Actual results could differ from those estimates, and any such differences may be material to our financial statements.
Revenue recognition
Our contracts with customers fall under the following contract types: time-and-materials, unit-price, cost-plus and lump sum. The contracts are generally less than one year in duration although we do have several long-term contracts.
• | Time-and-materials — We provide equipment and labor on an hourly basis to fulfill customer requests. Hourly billing rates are calculated by us through careful consideration of all costs expected to be incurred to provide the requested services and incorporating a mark-up to generate the required profit margin. Revenue is recognized as the labor, equipment, materials, subcontract costs, and other services are supplied to the customer. |
• | Unit-price — For every unit of work performed, we are paid a specified amount (for example: cubic meters of earth moved; lineal meters of pipe installed; completed piles). The price per unit of work performed is calculated by estimating all of the costs expected to be incurred and adding a mark-up to generate the required profit margin. Revenue related to unit-price contracts is recognized as applicable quantities are completed. |
• | Cost-plus — Under this contract type, we charge and are reimbursed for all allowable or otherwise defined costs incurred to provide the requested services plus a pre-arranged fixed or variable fee that represents profit. Revenue recognition is based on actual incurred costs to date plus the applicable fee. |
• | Lump sum — The price for services performed is established at the outset of the contract and is not subject to any adjustment based on the costs incurred or our performance under the scope of the original contract. Changes in scope added by the customer are priced incrementally to the original bid or lump sum. Similar to unit-price contracts, the price charged to the customer for the services performed is calculated by estimating all of the costs expected to be incurred in performing services required by the contract and adding an appropriate amount to the contract price to generate the required profit margin. Revenue on lump sum contracts is recognized using the percentage-of-completion method, calculated using output measures like cubic meters, lineal meters, or completed piles to date. In the absence of reliable output measures, we recognize revenue based upon input measures such as costs incurred to date. |
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
11
NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
claim have been incurred, when it is probable that the claim will result in a bona fide addition to contract value and 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 almost solely dependent on the accuracy of our estimates of the cost to complete each 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 bid. Because we have many projects of varying levels of complexity and size in process at any given time, these changes in estimates can offset each other without materially impacting our profitability; however, 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; the availability and skill level of workers in the geographic location of the project; the availability and proximity of materials; the accuracy of the original bid and subsequent estimates; inclement weather and timing; and coordination issues inherent in all projects. Until we feel we can accurately estimate job profitability, no profit on the related project is recognized. 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.
Property, plant and equipment
The most significant estimate in accounting for property, plant and equipment is the expected useful life of the asset and the expected residual value. Most of our property, 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 Canadian Institute of Chartered Accountants Handbook Section 3063 “Impairment or Disposal of Long-Lived Assets” and the revised 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.
Repair and maintenance costs
The parts, shop labor, and overhead costs, which are included in equipment costs on our statement of operations, represent the total cost of operating our equipment and maintaining it in an acceptable condition. It is our policy to expense these costs as they are incurred.
Goodwill
As described under “Consolidated Financial Position – Impairment of Goodwill”, we perform our annual goodwill impairment test in the third quarter 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
12
NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
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. All such 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 mandatorily redeemable preferred shares
We are required to estimate the redemption value of the Series B mandatorily redeemable preferred shares at each reporting date as if the settlement occurred on that date. When calculating the redemption value, we are required to estimate the arm’s length fair value of our common shares. The process of determining fair value is subjective and requires management to exercise judgment in making assumptions about future results, including revenue and cash flow projections, and discount rates.
Accounting policy changes
Revenue recognition
Effective April 1, 2005, we amended our accounting policy regarding the recognition of revenue on claims. Once contract performance is underway, we often experience changes in conditions, client requirements, specifications, designs, materials and work schedule. Generally, a “change order” will be negotiated with our customer to modify the original contract to approve both the scope and price of the change. Occasionally, however, disagreements sometimes arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change becomes a point of dispute between our customer and us, we then consider it as a claim.
Costs related to change orders and claims are recognized when they are incurred. Change orders are included in total estimated contract revenue when it is probable that the change order will result in a bona fide addition to contract value and can be reliably estimated. Prior to April 1, 2005, revenue from claims was included in total estimated contract revenue when awarded or received. After April 1, 2005, 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 can be reliably estimated. Those two conditions are satisfied when (1) the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained providing a reasonable basis to support the claim, (2) additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our performance, (3) costs associated with the claim are identifiable and reasonable in view of work performed and (4) evidence supporting the claim is objective and verifiable. This can lead to a situation where costs are recognized in one period and revenue, when the above
13
NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
conditions warrant recognition of the claim, occurs in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries. For additional information, refer to note 3(a) in our interim consolidated financial statements for the three and nine months ended December 31, 2005.
Vendor rebates
In April 2005, we adopted the amended Canadian Accounting Standard EIC-144, “Accounting by a Customer (Including a Reseller) for Certain Consideration Received from a Vendor.” EIC-144 requires companies to recognize the benefit of non-discretionary rebates for achieving specified cumulative purchasing levels as a reduction of the cost of purchases over the relevant period, provided the rebate is probable and reasonably estimable. Otherwise, the rebates would be recognized as purchasing milestones are achieved. The implementation of this new standard did not have a material impact on our consolidated financial statements.
Recently Issued Accounting Standards
The following recent Canadian accounting pronouncements have not yet been adopted by the Company:
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 will be effective for interim and annual financial statements commencing in fiscal 2007. 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.
Non-monetary transactions
In June 2005, the CICA replaced Handbook Section 3830, “Non-monetary Transactions”, with the new Handbook Section 3831, “Non-monetary Transactions”. The requirements of the new standard apply to non-monetary transactions initiated in periods beginning on or after January 1, 2006, though earlier adoption is permitted as of periods beginning on or after July 1, 2005. The standard requires all non-monetary transactions to be measured at fair market value unless:
• | the transaction lacks commercial substance; |
• | the transaction is an exchange of production or property held for sale in the ordinary course of business for production or property to be sold in the same line of business to facilitate sales to customers other than the parties to the exchange; |
• | neither the fair value of the assets or services received nor the fair value of the assets or services given up is reliably measurable; or |
• | the transaction is a non-monetary, non-reciprocal transfer to owners that represents a spin-off or other form of restructuring or liquidation. |
14
NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
We do not expect the adoption of this standard to have a material impact on our results of operations or financial position.
Risk Factors
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 provide our services primarily to a small number of major integrated and independent oil and gas and other natural resources companies operating in western Canada. Revenue from our five largest customers represented approximately 70% and 73% of our total revenue for the three and nine months ended December 31, 2005, respectively, and those customers are expected to continue to provide a significant percentage of our revenues in the future. Each period any one of our customers may constitute a significant portion of our revenue. For example, for the three and nine months ended December 31, 2005, revenue generated from work for CNRL constituted approximately 40% and 38%, respectively, of our total revenue due to several large projects with CNRL, including the 10-year overburden removal contract and a large site grading contract. If we lose or experience a significant reduction of business from a major customer, we may not be able to replace the work generated by these projects with work from other customers. Moreover, a significant number of our contracts terminate upon completion of the project without having a definite termination date, and the contracts typically allow the customer to reduce or eliminate the work which we are to perform. Our customers also may choose not to extend the existing contracts or enter into new contracts. The loss of or significant reduction in business with one or more of these customers could have a material adverse effect on our business.
Lump sum and unit-price contracts with our customers expose us to losses when our estimates of project costs are too low or when we fail to perform within our cost estimates.
Our recent operating results have been adversely affected by losses we have incurred on lump sum and unit-price contracts. The terms of these contracts require us to guarantee the price of the services we provide and assume the risk that our costs to perform the services and provide the materials will be greater than anticipated. Our profitability under such contracts is dependent upon our ability to accurately predict the costs associated with our services. We cannot assure the accuracy of our cost estimating, which can result in unsuccessful bids for contracts or losses on contracts actually received.
In addition, the costs we actually incur may be affected by a variety of factors, some of which may be beyond our control. Factors that contribute to differences in the costs we actually incur as compared to our estimates and which therefore affect profitability include, without limitation, site conditions which differ from those assumed in the original bid, the availability and skill level of workers in the geographic location of the project, inclement weather, equipment productivity and timing differences that result from actual project starting time as compared to projected starting time and 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, some projects result in lower margins than anticipated or incur losses, which adversely impact our results of operations, financial condition and cash flow.
15
NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
Approximately 61% of our revenue for both the three and nine months ended December 31, 2005 was derived from lump sum and unit-price contracts. Going forward, the percentage of our revenue derived from lump sum and unit-price contracts is expected to increase as several of our long-term contracts, including the 10-year overburden removal contract for CNRL, are unit-price and/or lump sum contracts. Given the magnitude of the projected revenues from these contracts as compared to the revenues expected to be earned from other contracts, if we underestimated the costs to perform these contracts, or if we were to incur unrecoverable cost overruns on these projects, it is likely that we would be unable to service our debt obligations.
Until we establish and maintain effective internal controls and procedures for 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 had to restate our financial statements for the first and second quarters of fiscal 2005, primarily due to certain inaccurate expense accruals. During the preparation of our financial statements for the third quarter of fiscal 2005, we discovered a number of invoices recorded in the third quarter which were related to costs actually incurred in the first and second quarters of fiscal 2005. A review of our accounting and control procedures identified a number of deficiencies in our financial reporting processes and internal controls that contributed to several misstated amounts. We are currently addressing these deficiencies. Our auditors have advised us that unless we have appropriate procedures and controls in place with respect to accounting for our contracts and with respect to our purchases and accounts payable, we will not be able to report our results on a timely basis and may cause future filing delays.
We have also had to subsequently restate our financial statements for each period after November 26, 2003 to eliminate the impact of hedge accounting. This was accomplished by recognizing the foreign exchange gain or loss relating to the senior notes each period and recording the derivative financial instruments at fair value and the realized and unrealized gains and losses in the derivative instruments for each period through the Consolidated Statement of Operations, along with the associated future income tax effects.
The financial statements for the first quarter of fiscal 2006 were also required to be restated to correct the accounting for various aspects of the refinancing transactions which occurred on May 19, 2005, including: recording additional liabilities and interest expense for the increase in the redemption value of the Series B mandatorily redeemable preferred shares issued; discounting the liability associated with the Series A mandatorily redeemable preferred shares issued; and deferring and amortizing most of the transaction costs associated with the new debt issued rather than expensing them in the current period.
We may be unable to implement the changes required to provide accurate and timely operating and financial reports. Failure to do so would cause us to breach the reporting requirements under our revolving credit facility and the indentures governing our 8 3/4% senior notes due 2011 and 9% senior secured notes due 2010, as well as have a material adverse effect on our business, financial condition and results of operations. Until we establish and maintain effective internal controls and procedures for financial reporting, we may not have appropriate procedures in place to eliminate financial statement inaccuracies and avoid delays in financial reporting in the future.
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NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
Our substantial debt could adversely affect our financial health, make us more vulnerable to adverse economic conditions and prevent us from fulfilling our debt obligations.
We have a substantial amount of debt outstanding and significant debt service requirements. As of December 31, 2005, we had outstanding $514.2 million of consolidated debt, $78.8 million of which, including capital leases, was secured debt. Our substantial indebtedness could have important consequences, such as:
• | limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements, potential growth or other purposes; |
• | limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make payments on our debt; |
• | limiting our ability to obtain bonding which is required by some of our customers; |
• | placing us at a competitive disadvantage compared to competitors with less debt; |
• | increasing our vulnerability to, and reducing our flexibility in planning for, changes in economic, industry and competitive conditions; and |
• | increasing our vulnerability to increases in interest rates because borrowings under our revolving credit facility are subject to variable interest rates. |
Any of the above listed factors could make us more vulnerable to defaults and place us at a competitive disadvantage, therefore making an investment in our common shares less attractive when compared to other investments. 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 do on commercially reasonable terms or at all.
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 restricted subsidiaries to:
• | incur or guarantee additional debt, issue disqualified capital stock or enter into sale and leaseback transactions; |
• | pay dividends or distributions on our capital stock or repurchase our capital stock, redeem subordinated debt or make other restricted payments; |
• | incur dividend or other payment restrictions affecting certain of our subsidiaries; |
• | issue stock of subsidiaries; |
• | make certain investments or acquisitions; |
• | create liens on our assets to secure debt; |
• | enter into transactions with affiliates; |
• | consolidate, merge or transfer all or substantially all of our assets; and |
• | transfer or sell assets, including capital stock of our subsidiaries. |
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NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
Our revolving credit facility also requires us, and our future credit facilities may require us, to maintain specified financial ratios and satisfy specified financial tests. 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 declare all amounts outstanding under such credit facilities, including accrued interest or other obligations, to be immediately due and payable. Additionally, 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, our business operations would be interrupted and you may lose all or part of your investment.
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 net cash flow provided by operating activities and to make scheduled payments on our indebtedness will depend on our future financial performance. Our future performance will be affected 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, or other events beyond our control 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, and 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 repay our 9% senior secured notes and to borrow under our revolving credit facility.
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.
Our ability to borrow under our revolving credit facility is limited, in part, by the mark-to-market liabilities under our swap agreements. If the Canadian dollar increases in value against the U.S. dollar, the mark-to-market liabilities under the swap agreements will increase, which may adversely affect our liquidity or even cause a default under the new revolving credit facility if the mark-to-market liabilities were to increase to the extent that the amount of outstanding borrowings and letters of credit would exceed the reduced availability under the revolving credit facility.
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NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
This situation has occurred on more than one occasion recently, reducing to zero the amount of available borrowings under the facility. We and the lenders under our revolving credit facility have agreed upon a resolution that reduces, but does not eliminate, the consequences of these currency fluctuations.
If our access to the surety market were to be restricted in the future, or if our demand for surety bonds were to increase significantly, our business could be impaired.
Like all businesses providing similar services, we are at times required to post bid or performance bonds issued by a financial institution known as a surety. 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 bond market, our bonding capacity becomes insufficient to satisfy our future bonding requirements, our business could be impaired.
We are dependent upon continued outsourcing by our customers of mining and site preparation services.
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 74% and 76% of our revenues, respectively, in the three and nine months ended December 31, 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.
Changes in oil and gas prices 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.
The profitability and growth of our customers may be impacted by the prices of oil and gas. Prices for oil are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil, market uncertainty and a variety of additional factors beyond our control. Such factors include weather conditions, the condition of the Canadian and U.S. economies, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the Middle East, increasing foreign demand for oil and gas, war or the threat of war in oil producing regions, the foreign supply of oil and the availability of fuel from alternate sources. In addition, our customers make their major expansion investment decisions based on their long-term outlook for the prices of oil and gas and their profitability based on those prices. If they believe that their profitability will be adversely affected by expected future changes in the prices of those commodities or by expected future fluctuations in currency exchange rates, they may delay or curtail their current expansion plans. Such a delay or curtailment could have a material adverse impact on our financial condition 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 result in lower margins than estimated.
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NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
Insufficient pipeline and refining capacity for heavy crude products 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.
While current pipeline capacity is sufficient to transport existing oil sands production to market, future production growth will require increased pipeline capacity. If such increases do not materialize, our customers may be unable to efficiently deliver increased production to market. Additionally, we expect that increases in oil sands production will require added heavy crude oil refinery capacity. Similarly, if such increased capacity or alternative markets do not materialize, future growth in demand for our customers’ products could be reduced.
Because most of our customers are located or operate in western Canada, a downturn in the energy industry in western Canada could result in a decrease in the demand for our services.
Most of our customers are located or operate in western Canada. In the three and nine months ended December 31, 2005, we generated approximately 77% and 73%, respectively, of our operating revenues from the Alberta oil sands. A downturn in the energy industry in western Canada 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.
Shortages of skilled labor, work stoppages or other labor disruptions at our operations or those of our principal customers or service providers could have an adverse effect on our profitability and financial condition.
Our ability to provide high-quality services on a timely basis requires an adequate number of skilled workers such as engineers, trades people and equipment operators. We cannot assure you that we will be able to maintain an adequate skilled labor force or that our labor expenses will not increase. A shortage of skilled labor would require us to curtail our planned internal growth or may require us to use less skilled labor which could adversely affect our ability to perform work.
Substantially all of our hourly employees are subject to collective bargaining agreements to which we are a party or are otherwise subject because of a bargaining relationship with the particular trade union that is a party to the collective bargaining agreement. Any work stoppage resulting from a strike or lockout could have a material adverse effect on our financial condition and results of operations.
In the province of Alberta, collective bargaining in the construction industry is conducted by registered groups consisting of an employers’ organization, on behalf of the employers, and a defined group of trade unions, on behalf of the unions. An employers’ organization which has been registered by the Labour Relations Board bargains with the trade unions named in the certificate on behalf of all employers who work in that part of the construction industry described in the certificate with whom the unions have a bargaining relationship. Any collective agreement entered into by the employers’ organization is binding on all such employers. We do not have control over the terms of such agreements but are bound by them pursuant to the provisions of the Labour Relations Code and the registrations.
In addition, our customers employ workers under other collective bargaining agreements. Any work stoppage or labor disruption experienced by our key customers could significantly reduce the amount of services that we provide.
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NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
Our ability to grow our operations in the future is, in part, dependent on our ability to secure tires for our equipment.
Currently, global demand for tires of the size and specifications we require is exceeding the available supply. While we have been able to secure the necessary tires to date to keep our equipment running, there is no guarantee that we will be able to do so in the future.
Because approximately 80% of the major projects that we pursue are awarded to us based on bid proposals, competitors with lower overhead cost structures may underbid us, negatively affecting our business operations and impeding our growth.
Approximately 80% of the major projects that we pursue are awarded to us based on bid proposals. We may compete in the future for these projects against companies that may have substantially greater financial and other resources than we do. Some smaller competitors may have lower overhead cost structures and may be able to provide their services at lower rates than we can. Further, public sector work is often performed by governmental agencies. Our growth may be impacted to the extent that we are unable to successfully bid against these companies.
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, causing an adverse effect on our financial condition.
A significant amount of our revenues are generated by providing non-recurring services.
Approximately 50% of our revenue for the three and nine months ended December 31, 2005, 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. Such penalties, if incurred, could have a significant impact on our profitability under these contracts.
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NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
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 Alberta oil sands and natural gas production. The operations of these companies, including the 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 induce 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 in and around sensitive environmental areas.
Our operations are subject to numerous environmental protection laws and regulations that are complex and stringent. Contracts with our customers require us to operate in compliance with these laws and regulations. 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 provide for joint and several strict liability for remediation of releases of hazardous substances, rendering a person liable for environmental damage, without regard to negligence or fault on the part of such person. In addition to potential liabilities that may be incurred in satisfying these requirements, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances. These laws and regulations may expose us to liability arising out of the conduct of operations or conditions caused by others, or for our acts which were in compliance with all applicable laws at the time these acts were performed.
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 upon which fuel may have been spilled, or hydrocarbons or other wastes which may have been disposed of or released. 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, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of hazardous substances into the environment. Under such laws, we could be required to remove or remediate previously disposed wastes and clean up contaminated property.
Failure by our customers to obtain required permits and licenses may affect the demand for our services.
The development of the Alberta oil sands may require 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, and in the event that they do not, demand for our services could be adversely affected.
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NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
We are dependent on our ability to lease equipment.
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 projects expose us to potential professional liability, product liability, warranty or other claims.
We install deep foundations in congested areas and provide construction management services for significant projects. Notwithstanding the fact that we will generally 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. If we do not successfully integrate acquisitions, we may not realize anticipated operating advantages and cost savings. The integration of companies that have previously operated separately involves a number of risks, including:
• | demands on management related to the increase in our size after an acquisition; |
• | the diversion of our management’s attention from the management of daily operations; |
• | difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems; |
• | difficulties in the assimilation and retention of employees; and |
• | potential adverse effects on operating results. |
We may not be able to maintain the levels of operating efficiency that acquired companies will have achieved or might achieve separately. Successful integration of each of their 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 which would harm our financial condition and results of operations.
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NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
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.
Risk Management
Foreign currency risk
We are subject to currency exchange risk as the 8 3/4% senior notes and 9% senior secured notes are denominated in U.S. dollars and all of our revenues and most of our expenses are denominated in Canadian dollars. As noted above, 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 transaction 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 percent of the US$200 million if exercised between December 1, 2007 and December 1, 2008; 2.1875 percent if exercised between December 1, 2008 and December 1, 2009; and 0.000 percent if cancelled after December 1, 2009. We have not hedged the foreign currency risk on the 9% senior secured notes. Each $0.01 increase or decrease in the U.S. dollar-Canadian dollar exchange rate would change the interest cost on these notes by $0.05 million per year.
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 percent or Canadian bankers’ acceptance rate plus 3 percent. Assuming the revolving credit facility is fully drawn at $40 million, excluding the $23 million of outstanding letters of credit at December 31, 2005, each 1.0 percent increase or decrease in the applicable interest rate would change the interest cost by $0.17 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.
We also lease equipment with a variable lease payment tied to prime rates. At December 31, 2005, for each 1.0 percent annual fluctuation in this rate, annual lease expense will change by $0.24 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.
Outlook
We have developed a strong business foundation through our relationships with the key organizations in the Fort McMurray oil sands area of Alberta (Syncrude, CNRL, Suncor, Albian Sands, etc.) coupled with the long-term mining work at CNRL and Grande Cache Coal. 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.
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NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the three and nine months ended December 31, 2005
Activity in the Fort McMurray area remains very high and a number of high profile projects have been announced, most recently including the acceleration of CNRL’s expansion plans, Shell’s Jackpine Mine and the Petro-Canada/UTS Fort Hills project. Accordingly, activity levels are expected to remain strong.
Over the last nine months, we have completed a refinancing of our debt, the management team has been restructured, and a number of initiatives that have strengthened the financial and operating controls have been implemented. The company recently launched a major business improvement initiative 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 an outsource provider of services in the Fort McMurray oil sands area while concurrently reducing risk by bidding into opportunities in other Canadian provinces. The announcement of the five year reclamation work at the Syncrude base mine and the site grading work at the DeBeers Victor diamond project in Northern Ontario support the burgeoning success of this strategy. At the same time, our Piling segment remains a strong business and with the level of construction in the western provinces alone, it is considered likely that the work load will remain high in the foreseeable future. Similarly, the Pipeline segment had reduced activity last year and a low level of activity compared to expectations in the first nine months of the current year. However, the high number of announced projects in this business area augers well for considerable work in the winter months over the next few years.
U.S. Generally Accepted Accounting Principles
The 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 14 of the interim consolidated financial statements for the three and nine months ended December 31, 2005.
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