e6vk
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 2008
Commission File Number 001-33161
NORTH AMERICAN ENERGY PARTNERS INC.
Zone 3 Acheson Industrial Area
2-53016 Highway 60
Acheson, Alberta
Canada T7X 5A7
(Address of principal executive offices)
Indicate by check mark whether the registrant files or will file annual reports under cover
Form 20-F or 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.
If Yes is marked, indicate below the file number assigned to the registrant in connection
with Rule 12g3-2(b): 82- ___
Included herein:
1. |
|
Interim consolidated financial statements of North American Energy
Partners Inc. for the three and nine months ended December 31, 2007. |
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2. |
|
Managements 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.
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NORTH AMERICAN ENERGY PARTNERS INC.
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By: |
/s/ David Blackley
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Name: |
David Blackley |
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Title: |
Vice President, Finance |
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Date: February 14, 2008
NORTH AMERICAN ENERGY PARTNERS INC.
Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Expressed in thousands of Canadian dollars)
(Unaudited)
NORTH AMERICAN ENERGY PARTNERS INC.
Interim Consolidated Balance Sheets
(in thousands of Canadian dollars)
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December 31, 2007 |
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March 31, 2007 |
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(unaudited) |
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Assets |
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Current assets: |
|
|
|
|
|
|
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Cash and cash equivalents |
|
$ |
21,243 |
|
|
$ |
7,895 |
|
Accounts receivable |
|
|
115,512 |
|
|
|
93,220 |
|
Unbilled revenue |
|
|
73,447 |
|
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|
82,833 |
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Inventory |
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|
114 |
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|
156 |
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Asset held for sale |
|
|
|
|
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|
8,268 |
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Prepaid expenses and deposits |
|
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6,975 |
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|
11,932 |
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Other assets |
|
|
3,376 |
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|
|
10,164 |
|
Future income taxes |
|
|
3,165 |
|
|
|
14,593 |
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|
|
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|
223,832 |
|
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|
229,061 |
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|
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Future income taxes (note 3(a)) |
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|
30,059 |
|
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|
14,364 |
|
Plant and equipment (note 5 and 6) |
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|
284,762 |
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|
255,963 |
|
Goodwill (note 5) |
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|
200,056 |
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|
199,392 |
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Intangible
assets, net of accumulated amortization, of $19,181 (March 31,
2007 $17,608) (notes 3(a), 5 and 7(a)) |
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|
2,447 |
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|
600 |
|
Deferred
financing costs, net of accumulated amortization, of $nil (March
31, 2007 $7,595) (note 3(a)) |
|
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|
|
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|
11,356 |
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|
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$ |
741,156 |
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$ |
710,736 |
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Liabilities and Shareholders Equity |
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Current liabilities: |
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Revolving credit facility (note 7(a)) |
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$ |
20,000 |
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$ |
20,500 |
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Accounts payable |
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102,994 |
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94,548 |
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Accrued liabilities |
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16,097 |
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23,393 |
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Billings in excess of costs incurred and estimated earnings on
uncompleted contracts |
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3,619 |
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2,999 |
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Current portion of capital lease obligations |
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3,915 |
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3,195 |
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Current portion of derivative financial instruments (note 11(b)) |
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4,640 |
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2,669 |
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Future income taxes |
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|
10,065 |
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|
4,154 |
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|
|
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|
161,330 |
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151,458 |
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Deferred lease inducements (note 8) |
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967 |
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Capital lease obligations |
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7,840 |
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6,514 |
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Senior notes (notes 3(a) and 7(b)) |
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190,546 |
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230,580 |
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Derivative financial instruments (notes 3(a) and 11(b)) |
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96,676 |
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58,194 |
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Future income taxes (note 3(a)) |
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|
21,551 |
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19,712 |
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|
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478,910 |
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466,458 |
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Shareholders equity: |
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Common shares (authorized
unlimited number of voting and
non-voting common shares; issued
and outstanding 35,951,684
voting common shares (March 31,
2007 35,192,260 voting common
shares and 412,400 non-voting
common shares)) (note 9(a)) |
|
|
298,481 |
|
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|
296,198 |
|
Contributed surplus (note 9(b)) |
|
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3,945 |
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|
3,606 |
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Deficit |
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(40,180 |
) |
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(55,526 |
) |
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262,246 |
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244,278 |
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Guarantee (note 17) |
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$ |
741,156 |
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$ |
710,736 |
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See accompanying notes to unaudited interim consolidated financial statements.
2
NORTH AMERICAN ENERGY PARTNERS INC.
Interim Consolidated Statements of Operations, Comprehensive Income and Deficit
(in thousands of Canadian dollars, except per share amounts)
(unaudited)
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Three months ended |
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Nine months ended |
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December 31 |
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December 31 |
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2007 |
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2006 |
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2007 |
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2006 |
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Revenue |
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$ |
274,894 |
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$ |
155,858 |
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$ |
666,096 |
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$ |
424,024 |
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Project costs |
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|
167,323 |
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92,023 |
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397,262 |
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232,115 |
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Equipment costs |
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44,231 |
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29,244 |
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131,582 |
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78,777 |
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Equipment operating lease expense |
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4,825 |
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|
2,088 |
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12,329 |
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|
|
15,657 |
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Depreciation |
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|
7,885 |
|
|
|
6,531 |
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|
|
24,179 |
|
|
|
18,665 |
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Gross profit |
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|
50,630 |
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|
25,972 |
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|
100,744 |
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|
78,810 |
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General and administrative costs |
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|
17,009 |
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|
11,647 |
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48,996 |
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30,894 |
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Loss on disposal of plant and equipment |
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5 |
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|
381 |
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|
850 |
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|
839 |
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Loss on disposal of asset held for sale |
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|
316 |
|
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|
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Amortization of intangible assets |
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|
443 |
|
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|
127 |
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|
766 |
|
|
|
492 |
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Operating income before the undernoted |
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|
33,173 |
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|
13,817 |
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|
49,816 |
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|
46,585 |
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Interest expense (note 10) |
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|
7,399 |
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|
9,292 |
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|
20,333 |
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|
29,786 |
|
Foreign exchange (gain) loss |
|
|
(1,784 |
) |
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|
10,897 |
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|
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(33,136 |
) |
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|
(2,497 |
) |
Realized and unrealized (gain) loss on derivative
financial instruments (note 11(a)) |
|
|
(5,419 |
) |
|
|
(13,315 |
) |
|
|
39,766 |
|
|
|
(1,533 |
) |
Gain on repurchase of NACG Preferred Corp. Series A
preferred shares |
|
|
|
|
|
|
(9,400 |
) |
|
|
|
|
|
|
(9,400 |
) |
Loss on extinguishment of debt |
|
|
|
|
|
|
10,875 |
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|
|
|
|
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|
10,928 |
|
Other income |
|
|
(115 |
) |
|
|
(233 |
) |
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|
(351 |
) |
|
|
(824 |
) |
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Income before income taxes |
|
|
33,092 |
|
|
|
5,701 |
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|
|
23,204 |
|
|
|
20,125 |
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Income taxes (note 12(c)): |
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|
|
|
|
|
|
|
|
|
|
|
|
|
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Current income taxes |
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8 |
|
|
|
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|
29 |
|
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|
(2,844 |
) |
Future income taxes |
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|
7,707 |
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|
|
(938 |
) |
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|
6,053 |
|
|
|
3,193 |
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|
Net income and comprehensive income for the period |
|
|
25,377 |
|
|
|
6,639 |
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|
|
17,122 |
|
|
|
19,776 |
|
Deficit, beginning of period as previously reported |
|
|
(65,557 |
) |
|
|
(63,409 |
) |
|
|
(55,526 |
) |
|
|
(76,546 |
) |
Change in accounting policy related to financial
instruments (note 3(a)) |
|
|
|
|
|
|
|
|
|
|
(1,776 |
) |
|
|
|
|
Premium on repurchase of common shares
|
|
|
|
|
|
|
(59 |
) |
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|
|
|
|
|
(59 |
) |
|
Deficit, end of period |
|
$ |
(40,180 |
) |
|
$ |
(56,829 |
) |
|
$ |
(40,180 |
) |
|
$ |
(56,829 |
) |
|
Net income per share basic (note 9(c)) |
|
$ |
0.71 |
|
|
$ |
0.27 |
|
|
$ |
0.48 |
|
|
$ |
0.96 |
|
|
Net income per share diluted (note 9(c)) |
|
$ |
0.69 |
|
|
$ |
0.26 |
|
|
$ |
0.46 |
|
|
$ |
0.90 |
|
|
See accompanying notes to unaudited interim consolidated financial statements.
3
NORTH AMERICAN ENERGY PARTNERS INC.
Consolidated
Statements of Cash Flows
(in thousands of Canadian dollars)
(Unaudited)
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|
|
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Three months ended |
|
|
Nine months ended |
|
|
|
December 31 |
|
|
December 31 |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
Cash provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Net income for the period |
|
$ |
25,377 |
|
|
$ |
6,639 |
|
|
$ |
17,122 |
|
|
$ |
19,776 |
|
Items not affecting cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation |
|
|
7,885 |
|
|
|
6,531 |
|
|
|
24,179 |
|
|
|
18,665 |
|
Write-down of other assets to replacement cost |
|
|
|
|
|
|
|
|
|
|
1,848 |
|
|
|
|
|
Amortization of intangible assets |
|
|
443 |
|
|
|
127 |
|
|
|
766 |
|
|
|
492 |
|
Amortization of deferred lease inducements |
|
|
(26 |
) |
|
|
|
|
|
|
(78 |
) |
|
|
|
|
Amortization of deferred financing costs |
|
|
|
|
|
|
853 |
|
|
|
|
|
|
|
2,688 |
|
Loss on disposal of plant and equipment |
|
|
5 |
|
|
|
381 |
|
|
|
850 |
|
|
|
839 |
|
Loss on disposal of asset held for sale |
|
|
|
|
|
|
|
|
|
|
316 |
|
|
|
|
|
Unrealized foreign exchange (gain) loss on senior notes |
|
|
(1,612 |
) |
|
|
10,956 |
|
|
|
(32,626 |
) |
|
|
(2,537 |
) |
Amortization of bond issue costs (notes 3(a) and 10) |
|
|
162 |
|
|
|
|
|
|
|
669 |
|
|
|
|
|
Unrealized (gain) loss on derivative financial instruments |
|
|
(6,086 |
) |
|
|
(13,856 |
) |
|
|
37,764 |
|
|
|
(3,418 |
) |
Stock-based compensation expense (note 14) |
|
|
276 |
|
|
|
621 |
|
|
|
1,023 |
|
|
|
1,742 |
|
Gain on repurchase of NACG Preferred Corp. Series A
preferred shares |
|
|
|
|
|
|
(9,400 |
) |
|
|
|
|
|
|
(8,000 |
) |
Accretion and change in redemption value of mandatorily
redeemable preferred shares |
|
|
|
|
|
|
1,204 |
|
|
|
|
|
|
|
3,114 |
|
Loss on extinguishment of debt |
|
|
|
|
|
|
10,680 |
|
|
|
|
|
|
|
10,680 |
|
Future income taxes |
|
|
7,707 |
|
|
|
(938 |
) |
|
|
6,053 |
|
|
|
3,193 |
|
Net changes in non-cash working capital (note 12(b)) |
|
|
(1,294 |
) |
|
|
(37,819 |
) |
|
|
3,531 |
|
|
|
(52,496 |
) |
|
|
|
|
32,837 |
|
|
|
(24,021 |
) |
|
|
61,417 |
|
|
|
(5,262 |
) |
|
Investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition, net of cash acquired (note 5) |
|
|
|
|
|
|
|
|
|
|
(1,581 |
) |
|
|
(1,496 |
) |
Purchase of plant and equipment |
|
|
(8,021 |
) |
|
|
(78,398 |
) |
|
|
(51,566 |
) |
|
|
(97,707 |
) |
Additions to asset held for sale |
|
|
|
|
|
|
|
|
|
|
(2,248 |
) |
|
|
|
|
Proceeds on disposal of plant and equipment |
|
|
120 |
|
|
|
2,882 |
|
|
|
4,036 |
|
|
|
3,454 |
|
Proceeds on disposal of asset held for sale |
|
|
|
|
|
|
|
|
|
|
10,200 |
|
|
|
|
|
Net changes in non-cash working capital (note 12(b)) |
|
|
(18,976 |
) |
|
|
6,600 |
|
|
|
(4,727 |
) |
|
|
6,600 |
|
|
|
|
|
(26,877 |
) |
|
|
(68,916 |
) |
|
|
(45,886 |
) |
|
|
(89,149 |
) |
|
Financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in revolving credit facility |
|
|
20,000 |
|
|
|
15,000 |
|
|
|
(500 |
) |
|
|
15,000 |
|
Repayment of capital lease obligations |
|
|
(900 |
) |
|
|
(3,652 |
) |
|
|
(2,508 |
) |
|
|
(5,273 |
) |
Retirement of 9% senior secured notes |
|
|
|
|
|
|
(74,748 |
) |
|
|
|
|
|
|
(74,748 |
) |
Repurchase of NAEPI Series A preferred shares |
|
|
|
|
|
|
(1,000 |
) |
|
|
|
|
|
|
(1,000 |
) |
Repurchase of NACG Preferred Corp. Series A preferred shares |
|
|
|
|
|
|
(27,000 |
) |
|
|
|
|
|
|
(27,000 |
) |
Financing costs (note 7(a)) |
|
|
(7 |
) |
|
|
(267 |
) |
|
|
(774 |
) |
|
|
(1,347 |
) |
Share issue costs |
|
|
|
|
|
|
(16,197 |
) |
|
|
|
|
|
|
(18,138 |
) |
Repurchase of common shares for cancellation |
|
|
|
|
|
|
(84 |
) |
|
|
|
|
|
|
(84 |
) |
Issue of common shares (note 9(a)) |
|
|
859 |
|
|
|
171,165 |
|
|
|
1,599 |
|
|
|
171,304 |
|
|
|
|
|
19,952 |
|
|
|
63,217 |
|
|
|
(2,183 |
) |
|
|
58,714 |
|
|
Increase (decrease) in cash and cash equivalents |
|
|
25,912 |
|
|
|
(29,720 |
) |
|
|
13,348 |
|
|
|
(35,697 |
) |
Cash and cash equivalents (cheques issued in excess of cash
deposits), beginning of period |
|
|
(4,669 |
) |
|
|
36,827 |
|
|
|
7,895 |
|
|
|
42,804 |
|
|
Cash and cash equivalents, end of period |
|
$ |
21,243 |
|
|
$ |
7,107 |
|
|
$ |
21,243 |
|
|
$ |
7,107 |
|
|
Supplemental cash flow information (note 12(a))
See accompanying notes to unaudited interim consolidated financial statements.
4
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(Unaudited)
1. |
|
Nature of operations |
|
|
|
On November 26, 2003, North American Energy Partners Inc. (the Company) purchased
all the issued and outstanding shares of North American Construction Group Inc.
(NACGI), including subsidiaries of NACGI, from Norama Ltd. which had been operating
continuously in Western Canada since 1953. The Company had no operations prior to
November 26, 2003. |
|
|
|
The Company undertakes several types of projects including contract heavy construction
and mining, pipeline and piling installations in Canada. |
|
2. |
|
Basis of presentation |
|
|
|
These unaudited interim consolidated financial statements (the financial statements)
are prepared in accordance with Canadian generally accepted accounting principles
(GAAP) for interim financial statements and do not include all of the disclosures
normally contained in the Companys annual consolidated financial statements. Since
the determination of many assets, liabilities, revenues and expenses is dependent on
future events, the preparation of these financial statements requires the use of
estimates and assumptions. In the opinion of management, these financial statements
have been prepared within reasonable limits of materiality. Except as disclosed in
note 3, these financial statements follow the same significant accounting policies as
described and used in the most recent annual consolidated financial statements of the
Company for the year ended March 31, 2007 and should be read in conjunction with those
consolidated financial statements. |
|
|
|
These financial statements include the accounts of the Company, its wholly-owned
subsidiary, NACGI, the Companys joint venture, Noramac Ventures Inc. and the
following wholly-owned subsidiaries of NACGI: |
|
|
|
|
|
|
|
|
|
North American Caisson Ltd.
|
|
|
|
North American Pipeline Inc. |
|
|
North American Construction
Ltd.
|
|
|
|
North American Road Inc. |
|
|
North American Engineering Ltd.
|
|
|
|
North American Services Inc. |
|
|
North American Enterprises Ltd.
|
|
|
|
North American Site Development
Ltd. |
|
|
North American Industries Inc.
|
|
|
|
North American Site Services Inc. |
|
|
North American Mining Inc.
|
|
|
|
North American Pile Driving Inc. |
|
|
North American Maintenance Ltd. |
|
|
|
|
3. |
|
Accounting policy changes |
|
a) |
|
Financial instruments recognition and measurement |
|
|
|
|
Effective April 1, 2007, the Company adopted the Canadian Institute of Chartered
Accountants (CICA) Handbook Section 3855, Financial Instruments Recognition
and Measurement, and Handbook Section 3865, Hedges. These standards have been
applied retroactively without restatement as discussed below and, accordingly,
comparative amounts for prior periods have not been restated. |
5
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
|
|
|
On April 1, 2007, the Company made the following transitional adjustments to the
consolidated balance sheet to adopt the new standards: |
|
|
|
|
|
|
|
Increase (decrease) |
|
|
Deferred financing costs |
|
$ |
(11,356 |
) |
Intangible assets |
|
|
1,622 |
|
Long-term future income tax asset |
|
|
2,588 |
|
Senior notes |
|
|
(12,634 |
) |
Derivative financial instruments |
|
|
7,246 |
|
Long-term future income tax liability |
|
|
18 |
|
Opening deficit |
|
|
1,776 |
|
|
|
|
|
CICA Handbook Sections 3855 and 3865 provide guidance on when a financial
asset, financial liability or non-financial derivative is to be recognized on the
balance sheet of the Company and on what basis these assets, liabilities and
derivatives should be valued. Under the standards: |
|
|
|
Financial assets are classified as loans and receivables,
held-to-maturity, held-for-trading or available-for-sale. Loans and
receivables include all loans and receivables and are accounted for at
amortized cost. Held-to-maturity classification is restricted to fixed
maturity instruments that the Company intends and is able to hold to maturity
and is accounted for at amortized cost. Held-for-trading instruments are
recorded at fair value with realized and unrealized gains and losses reported
in net income. The remaining financial assets are classified as
available-for-sale. These are recorded at fair value with unrealized gains
and losses reported in other comprehensive income until the investment is
derecognized at which time the amounts would be recorded in net income. On
adoption of the standard, the Company has classified its cash and cash
equivalents, unbilled revenue and accounts receivable as loans and
receivables. The Company did not hold any financial assets that were
held-for-trading, available-for-sale or held-to-maturity; |
|
|
|
|
Financial liabilities are classified as either held-for-trading or other
financial liabilities. Held-for-trading instruments are recorded at fair
value with realized and unrealized gains and losses reported in net income.
Other financial liabilities are accounted for at amortized cost with gains
and losses reported in net income in the period that the liability is
derecognized. The Company has classified its revolving credit facility,
accounts payable, accrued liabilities, capital lease obligations and senior
notes as other financial liabilities; and |
|
|
|
|
Derivative financial instruments, including non-financial derivatives, are
classified as held-for-trading and measured at fair value unless designated
as hedging instruments or exempted from derivative treatment as a normal
purchase and sale. Certain derivatives embedded in other contracts are also
measured at fair value. |
|
|
|
In determining the fair value of financial instruments, the Company used a variety
of methods and assumptions that are based on market conditions and risks existing
on each reporting date. Counterparty confirmations and standard market conventions
and techniques, such as discounted cash flow analysis and option pricing models,
are used to determine the fair value of the Companys financial instruments,
including derivatives. All methods of fair value measurement result in a general
approximation of value and such value may never actually be realized. |
6
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
|
|
The Company elected April 1, 2003 as the transition date for identifying contracts
with embedded derivatives. The adoption of these standards resulted in the
following adjustments as of April 1, 2007 in accordance with the transition
provisions: |
|
|
|
Transaction costs that are directly attributable to the acquisition or
issue of financial assets or liabilities are accounted for as a part of the
respective asset or liabilitys carrying value at inception. Deferred
financing costs related to the issue of the senior notes that were previously
presented as a separate asset on the consolidated balance sheet are now
included in the carrying value of the senior notes and are being amortized
using the effective interest method over the remaining term of the debt.
Prior to April 1, 2007, these deferred financing costs were amortized on a
straight line basis over the term of the debt. As a result of the change in
method of accounting, financing costs were re-measured on April 1, 2007 using
the effective interest method. This re-measurement resulted in a $9,734
decrease in deferred financing costs, a decrease of $9,815 in senior notes, a
decrease of $63 in opening deficit and an increase of $18 in the future
income tax liability. |
|
|
|
|
Transaction costs incurred in connection with the Companys revolving
credit facility of $1,622 were reclassified from deferred financing costs to
intangible assets on April 1, 2007 and these costs continue to be amortized
on a straight-line basis over the term of the facility. |
|
|
|
|
The Company determined that the issuers early prepayment option included
in the senior notes should be bifurcated from the host contract, along with a
contingent embedded derivative in the senior notes that provide for
accelerated redemption by the holders in certain instances. These embedded
derivatives were measured at fair value at the inception of the senior notes
and the residual amount of the proceeds was allocated to the debt. Changes
in fair value of the embedded derivatives are recognized in net income and
the carrying amount of the senior notes is accreted to par value over the
term of the notes using the effective interest method and is recognized as
interest expense. At transition on April 1, 2007, the Company recorded the
fair value of $8,519 related to these embedded derivatives and a
corresponding decrease in opening deficit of $7,305, net of future income
taxes of $1,214. The impact of the bifurcation of these embedded derivatives
at issuance of the senior notes resulted in an increase of senior notes of
$5,700 and an increase in opening deficit of $3,963, net of income taxes of
$1,737 after applying the effective interest method to the premium resulting
from the bifurcation of these embedded derivatives on April 1, 2007. |
|
|
|
|
The Company determined that a price escalation feature in a revenue
construction contract is an embedded derivative that is not closely related
to the host contract. The embedded derivative has been measured at fair
value and included in derivative financial instruments on the consolidated
balance sheet, with changes in the fair value recognized in net income. The
Company recorded the fair value of $7,246 related to this embedded derivative
on April 1, 2007, with a corresponding increase in opening deficit of $5,181,
net of future income taxes of $2,065. |
7
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
b) |
|
Financial instruments disclosure and presentation |
|
|
|
|
Revised CICA Handbook Section 3861, Financial Instruments Disclosure and
Presentation replaces CICA Handbook Section 3860, Financial Instruments
Disclosure and Presentation, and establishes standards for presentation of
financial instruments and non-financial derivatives, and identifies information
that should be disclosed. There was no material effect on the Companys financial
statements upon adoption of CICA Handbook Section 3861 on April 1, 2007. |
|
|
c) |
|
Comprehensive income and equity |
|
|
|
|
CICA Handbook Section 1530, Comprehensive Income establishes standards for the
reporting and display of comprehensive income. The new section defines other
comprehensive income to include revenues, expenses, and gains and losses that, in
accordance with primary sources of GAAP, are recognized in comprehensive income
but excluded from net income. The standard does not address issues of recognition
or measurement for comprehensive income and its components. The adoption of CICA
Handbook Section 1530 on April 1, 2007 did not have a material impact on the
Companys financial statement presentation in the current period. |
|
|
|
|
CICA Handbook Section 3251, Equity establishes standards for the presentation of
equity and changes in equity during the reporting period. The requirements in
this section are in addition to those of Section 1530 and recommend that an
enterprise should present separately the following components of equity: retained
earnings, accumulated other comprehensive income, the total for retained earnings
and accumulated other comprehensive income, contributed surplus, share capital and
reserves. The adoption of CICA Handbook Section 3251 on April 1, 2007 did not
have an impact on the Companys financial statement presentation in the current
period. The Company currently has no accumulated other comprehensive income
components. |
|
|
d) |
|
Accounting changes |
|
|
|
|
In July 2006, the CICA revised Handbook Section 1506, Accounting Changes, which
requires that: (1) voluntary changes in accounting policy are made only if they
result in the financial statements providing reliable and more relevant
information; (2) changes in accounting policy are generally applied
retrospectively; and (3) prior period errors are corrected retrospectively. This
guidance was adopted by the Company on April 1, 2007 and did not have a material
impact on the consolidated financial statements. |
|
|
e) |
|
Accounting policy choice for transaction costs |
|
|
|
|
In June 2007, the CICA issued Emerging Issues Committee Abstract No. 166,
Accounting Policy Choice for Transaction Costs (EIC-166). CICA Handbook
Section 3855 requires that when an entity acquires a financial asset or incurs a
financial liability classified other than as held-for-trading, it adopts an
accounting policy for transaction costs of either: (a) recognizing all transaction
costs in net income; or (b) adding transaction costs that are directly
attributable to the acquisition or issue of a financial asset or financial
liability to the carrying amount of the financial instrument. EIC-166 clarifies
that the same accounting policy choice should be made for all similar instruments
classified as other than held-for-trading, but that a different accounting policy
choice may be made for financial instruments that are not |
8
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
|
|
similar. This guidance was adopted by the Company on April 1, 2007 and did not
have a material impact on the consolidated financial statements. |
|
f) |
|
Goodwill |
|
|
|
|
In October 2007, the Company changed the date of its annual impairment test for
goodwill from December 31 to October 1 of each year. This change in accounting
policy was applied on a retrospective basis and had no impact on the consolidated
financial statements. |
4. |
|
Recent accounting pronouncements not yet adopted |
|
a) |
|
Financial instruments |
|
|
|
|
In March 2007, the CICA issued Handbook Section 3862, Financial Instruments
Disclosures, which replaces CICA Handbook Section 3861 and provides expanded
disclosure requirements that provide additional detail by financial asset and
liability categories. This standard harmonizes disclosures with International
Financial Reporting Standards. The standard applies to interim and annual
financial statements relating to fiscal years beginning on or after October 1,
2007, specifically April 1, 2008 for the Company. The Company is currently
evaluating the impact of this standard. |
|
|
|
|
In March 2007, the CICA issued Handbook Section 3863, Financial Instruments
Presentation , which replaces CICA Handbook Section 3861, to enhance financial
statement users understanding of the significance of financial instruments to an
entitys financial position, performance and cash flows. This section establishes
standards for presentation of financial instruments and non-financial derivatives.
It deals with the classification of financial instruments, from the perspective
of the issuer, between liabilities and equity, the classification of related
interest, dividends, gains and losses, and the circumstances in which financial
assets and financial liabilities are offset. This standard harmonizes disclosures
with International Financial Reporting Standards and applies to interim and annual
financial statements relating to fiscal years beginning on or after October 1,
2007, specifically April 1, 2008 for the Company. The Company is currently
evaluating the impact of this standard. |
|
|
b) |
|
Capital disclosures |
|
|
|
|
In December 2006, the CICA issued Handbook Section 1535, Capital Disclosures.
This standard requires that an entity disclose information that enables users of
financial statements to evaluate an entitys objectives, policies and processes
for managing capital, including disclosures of any externally imposed capital
requirements and the consequences of non-compliance. The new standard applies to
interim and annual financial statements relating to fiscal years beginning on or
after October 1, 2007, specifically April 1, 2008 for the Company. The Company is
currently evaluating the impact of this standard. |
9
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
c) |
|
Inventories |
|
|
|
|
In June 2007, the CICA issued Handbook Section 3031, Inventories to harmonize
accounting for inventories under Canadian GAAP with International Financial
Reporting Standards. This standard requires the measurement of inventories at the
lower of cost and net realizable value and includes guidance on the determination
of cost, including allocation of overheads and other costs to inventory. The
standard also requires the consistent use of either first-in, first out (FIFO) or
weighted average cost formula to measure the cost of other inventories and
requires the reversal of previous write-downs to net realizable value when there
is a subsequent increase in the value of inventories. The new standard applies to
interim and annual financial statements relating to fiscal years beginning on or
after January 1, 2008, specifically April 1, 2008 for the Company. The Company is
currently evaluating the impact of this standard. |
|
|
d) |
|
Going concern |
|
|
|
|
In April 2007, the CICA approved amendments to Handbook Section 1400,
General Standards of Financial Statement Presentation. These amendments
require management to assess an entitys ability to continue as a going concern.
When management is aware of material uncertainties related to events or
conditions that may cast doubt on an entitys ability to continue as a going
concern, those uncertainties must be disclosed. In assessing the appropriateness
of the going concern assumption, the standard requires management to consider all
available information about the future, which is at least, but not limited to,
twelve months from the balance sheet date. The new requirements of the standard
are applicable for interim and annual financial statements relating to fiscal
years beginning on or after January 1, 2008, specifically April 1, 2008 for the
Company. The Company is currently evaluating the impact of this
standard. |
|
|
e) |
|
Goodwill and Intangible Assets |
|
|
|
|
In February 2008, the CICA issued Handbook Section 3064, (CICA 3064) Goodwill
and Intangible Assets. CICA 3064, which replaces Section 3062, Goodwill and
Intangible Assets, and Section 3450, Research and Development Costs, establishes
standards for the recognition, measurement and disclosure of goodwill and
intangible assets. The provisions relating to the definition and initial
recognition of intangible assets, including internally generated intangible
assets, are equivalent to the corresponding provisions of International Financial
Reporting Standard IAS 38, Intangible Assets. This new standard is effective for
the Companys interim and annual consolidated financial statements commencing
April 1, 2009. The Company is currently evaluating the impact of this standard. |
5. |
|
Acquisition |
|
|
|
On May 1, 2007, the Company acquired all of the assets of Active Auger Services 2001
Ltd., a piling company specializing in the design and installation of screw piles in
north central Saskatchewan, for total cash consideration and acquisition costs of
$1,581. The transaction has been accounted for by the purchase method with the
results of operations included in the financial statements from the date of
acquisition. The details of the acquisition are as follows: |
|
|
|
|
|
|
|
|
Net assets acquired at assigned values: |
|
|
|
|
Plant and equipment |
|
$ |
700 |
|
Intangible assets |
|
|
217 |
|
Goodwill |
|
|
664 |
|
|
|
|
$ |
1,581 |
|
|
|
|
The allocation of the purchase price to the fair value of the assets acquired and
liabilities assumed is preliminary and is subject to adjustment. The goodwill related
to this transaction is deductible for tax purposes. |
10
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
December 31, 2007 |
|
Cost |
|
|
depreciation |
|
|
Net book value |
|
|
Heavy equipment |
|
$ |
284,094 |
|
|
$ |
57,465 |
|
|
$ |
226,629 |
|
Major component parts in use |
|
|
9,960 |
|
|
|
3,307 |
|
|
|
6,653 |
|
Other equipment |
|
|
19,167 |
|
|
|
6,919 |
|
|
|
12,248 |
|
Licensed motor vehicles |
|
|
27,851 |
|
|
|
14,566 |
|
|
|
13,285 |
|
Office and computer equipment |
|
|
7,046 |
|
|
|
3,163 |
|
|
|
3,883 |
|
Buildings |
|
|
17,048 |
|
|
|
1,412 |
|
|
|
15,636 |
|
Leasehold improvements |
|
|
6,169 |
|
|
|
983 |
|
|
|
5,186 |
|
Assets under construction |
|
|
1,242 |
|
|
|
|
|
|
|
1,242 |
|
|
|
|
$ |
372,577 |
|
|
$ |
87,815 |
|
|
$ |
284,762 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
March 31, 2007 |
|
Cost |
|
|
depreciation |
|
|
Net book value |
|
|
Heavy equipment |
|
$ |
254,107 |
|
|
$ |
46,609 |
|
|
$ |
207,498 |
|
Major component parts in use |
|
|
7,884 |
|
|
|
2,489 |
|
|
|
5,395 |
|
Other equipment |
|
|
16,001 |
|
|
|
5,651 |
|
|
|
10,350 |
|
Licensed motor vehicles |
|
|
23,345 |
|
|
|
12,121 |
|
|
|
11,224 |
|
Office and computer equipment |
|
|
4,841 |
|
|
|
2,249 |
|
|
|
2,592 |
|
Buildings |
|
|
16,443 |
|
|
|
716 |
|
|
|
15,727 |
|
Leasehold improvements |
|
|
2,992 |
|
|
|
664 |
|
|
|
2,328 |
|
Assets under construction |
|
|
849 |
|
|
|
|
|
|
|
849 |
|
|
|
|
$ |
326,462 |
|
|
$ |
70,499 |
|
|
$ |
255,963 |
|
|
|
|
The above amounts include $19,904 (March 31, 2007 $15,422) of assets under
capital lease and accumulated depreciation of $9,231 (March 31, 2007 $7,302)
related thereto. During the three and nine months ended December 31, 2007,
additions of plant and equipment included $4,255 and $4,553, respectively, for
capital leases (three and nine months ended December 31, 2006 $758 and $3,952
respectively). Depreciation of equipment under capital leases of $783 and $1,929
for the three and nine months ended December 31, 2007, respectively, is included
in deprecation expense (three and nine months ended December 31, 2006 $614 and
$1,956 respectively). |
11
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
a) |
|
Revolving credit facility |
|
|
|
|
On June 7, 2007, the Company modified its amended and restated credit agreement to
provide for borrowings of up to the lesser of a restricted covenant
resulting in a current ratio of 1.25 times and $125.0 million (previously $55.0 million) under
which revolving loans and letters of credit may be issued. Based upon the
Companys current credit rating, prime rate and swing line revolving loans under
the agreement will bear interest at the Canadian prime rate plus 0.25% per annum,
Canadian bankers acceptances have stamping fees equal to 1.75% per annum and
letters of credit are subject to a fee of 1.25% per annum. |
|
|
|
|
The credit facility is secured by a first priority lien on substantially all the
Companys existing and after-acquired property and contains certain restrictive
covenants including, but not limited to, incurring additional debt, transferring
or selling assets, making investments including acquisitions or to pay dividends
or redeem shares of capital stock. The Company is also required to meet certain
financial covenants under the new credit agreement. |
|
|
|
|
As of December 31, 2007, the Company had $20.0 million outstanding borrowings
under the revolving credit facility and had issued $20.0 million in letters of
credit to support performance guarantees associated with customer contracts. The
Companys unused borrowing availability under the facility was
$33.8 million at
December 31, 2007. |
|
|
|
|
During the three and nine months ended December 31, 2007, financing fees of $7 and
$774, respectively, were incurred in connection with the modifications to the
amended and restated credit agreement and were recorded as intangible assets. |
|
|
b) |
|
Senior notes |
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
March 31, 2007 |
|
|
Principal outstanding ($US) |
|
$ |
200,000 |
|
|
$ |
200,000 |
|
Unrealized foreign exchange |
|
|
(2,410 |
) |
|
|
30,580 |
|
Unamortized financing
costs and discounts
(premiums), net |
|
|
(3,082 |
) |
|
|
|
|
Fair value of embedded
prepayment and early
redemption options |
|
|
(3,962 |
) |
|
|
|
|
|
|
|
$ |
190,546 |
|
|
$ |
230,580 |
|
|
|
|
|
Effective April 1, 2007, the Company adopted CICA Handbook Section 3855 as
described in note 3(a). The standards have been applied retroactively without
restatement and, accordingly, comparative amounts for prior periods have not been
restated. The senior notes have an effective interest rate of 9.4%. |
8. |
|
Deferred lease inducements |
|
|
|
Lease inducements applicable to lease contracts are deferred and amortized as a
reduction of general and administrative costs on a straight-line basis over the lease
term, which includes the initial lease term and renewal periods only where renewal is
determined to be reasonably assured. During the nine months ended December 31, 2007, the Company received inducements from a lessor in the form of
leasehold improvements to an office facility of $1,045. |
12
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
a) |
|
Common shares |
|
|
|
|
Authorized: |
|
|
|
Unlimited number of common voting shares |
|
|
|
|
Unlimited number of common non-voting shares |
|
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
|
|
Shares |
|
Amount |
|
Common voting shares |
|
|
|
|
|
|
|
|
|
Outstanding at March 31, 2007 |
|
|
35,192,260 |
|
|
$ |
294,136 |
|
Issued on exercise of options |
|
|
347,024 |
|
|
|
1,599 |
|
Transferred from contributed surplus on exercise of options |
|
|
|
|
|
|
684 |
|
Conversion of common non-voting shares |
|
|
412,400 |
|
|
|
2,062 |
|
|
Outstanding at December 31, 2007 |
|
|
35,951,684 |
|
|
$ |
298,481 |
|
|
|
|
|
|
|
|
|
|
|
Common non-voting shares |
|
|
|
|
|
|
|
|
|
Outstanding at March 31, 2007 |
|
|
412,400 |
|
|
$ |
2,062 |
|
Conversion to common voting shares |
|
|
(412,400 |
) |
|
|
(2,062 |
) |
|
Outstanding at December 31, 2007 |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
Total common shares |
|
|
35,951,684 |
|
|
$ |
298,481 |
|
|
|
|
|
On July 27, 2007, the Companys non-voting common shares were exchanged for
voting common shares. Each holder of the non-voting common shares received one
voting common share for each non-voting share held on the exchange date. |
|
|
b) |
|
Contributed surplus |
|
|
|
|
|
|
Balance, March 31, 2007 |
|
$ |
3,606 |
|
Stock-based compensation (note 14) |
|
|
1,023 |
|
Transferred to common shares on exercise of options |
|
|
(684 |
) |
|
Balance, December 31, 2007 |
|
$ |
3,945 |
|
|
13
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended December 31 |
|
|
Nine months ended December 31 |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
Basic net income per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to
common shareholders |
|
$ |
25,377 |
|
|
$ |
6,639 |
|
|
$ |
17,122 |
|
|
$ |
19,776 |
|
Weighted average number of
common shares |
|
|
35,809,141 |
|
|
|
24,728,170 |
|
|
|
35,744,406 |
|
|
|
20,669,517 |
|
|
Basic net income per share |
|
$ |
0.71 |
|
|
$ |
0.27 |
|
|
$ |
0.48 |
|
|
$ |
0.96 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to
common shareholders |
|
$ |
25,377 |
|
|
$ |
6,639 |
|
|
$ |
17,122 |
|
|
$ |
19,776 |
|
|
Net income, assuming dilution |
|
|
25,377 |
|
|
|
6,639 |
|
|
|
17,122 |
|
|
|
19,776 |
|
|
Weighted average number of
common shares |
|
|
35,809,141 |
|
|
|
24,728,170 |
|
|
|
35,744,406 |
|
|
|
20,669,517 |
|
Dilutive effect of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options |
|
|
919,297 |
|
|
|
818,425 |
|
|
|
1,110,011 |
|
|
|
1,381,368 |
|
|
Weighted average number of
diluted common shares |
|
|
36,728,438 |
|
|
|
25,546,595 |
|
|
|
36,854,417 |
|
|
|
22,050,885 |
|
|
Diluted net income per share |
|
$ |
0.69 |
|
|
$ |
0.26 |
|
|
$ |
0.46 |
|
|
$ |
0.90 |
|
|
|
|
For the three and nine months ended December 31, 2007, stock options of 276,384
and 217,409, respectively, were excluded from the calculation of diluted net
income per share as the options average exercise price was greater than the
average market price of the common shares for the year. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
December 31 |
|
|
December 31 |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
Interest on senior notes |
|
$ |
5,834 |
|
|
$ |
6,802 |
|
|
$ |
17,503 |
|
|
$ |
21,582 |
|
Interest on capital lease obligations |
|
|
165 |
|
|
|
164 |
|
|
|
497 |
|
|
|
480 |
|
Interest on NACG Preferred Corp. Series A
preferred shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,400 |
|
Accretion and change in redemption value of
NAEPI Series B preferred shares |
|
|
|
|
|
|
612 |
|
|
|
|
|
|
|
2,489 |
|
Accretion of NAEPI Series A preferred shares |
|
|
|
|
|
|
592 |
|
|
|
|
|
|
|
625 |
|
|
Interest on long-term debt |
|
|
5,999 |
|
|
|
8,170 |
|
|
|
18,000 |
|
|
|
26,576 |
|
Amortization of bond issue costs |
|
|
162 |
|
|
|
|
|
|
|
669 |
|
|
|
|
|
Amortization of deferred financing costs |
|
|
|
|
|
|
853 |
|
|
|
|
|
|
|
2,688 |
|
Interest on revolving credit facility and
other interest |
|
|
1,238 |
|
|
|
269 |
|
|
|
1,664 |
|
|
|
522 |
|
|
|
|
$ |
7,399 |
|
|
$ |
9,292 |
|
|
$ |
20,333 |
|
|
$ |
29,786 |
|
|
14
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
11. Derivative financial instruments
|
a) |
|
Realized and unrealized (gain) loss on derivative financial instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended December 31 |
|
|
Nine months ended December 31 |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
Realized and
unrealized (gain)
loss on
cross-currency and
interest rate swaps |
|
$ |
(3,925 |
) |
|
$ |
(13,315 |
) |
|
$ |
26,248 |
|
|
$ |
(1,533 |
) |
Unrealized (gain)
loss on embedded
price escalation
clauses in
long-term revenue
construction
contract |
|
|
(2,630 |
) |
|
|
|
|
|
|
8,961 |
|
|
|
|
|
Unrealized loss on
embedded prepayment
and early
redemption options
on senior notes |
|
|
1,136 |
|
|
|
|
|
|
|
4,557 |
|
|
|
|
|
|
|
|
$ |
(5,419 |
) |
|
$ |
(13,315 |
) |
|
$ |
39,766 |
|
|
$ |
(1,533 |
) |
|
|
b) |
|
Fair value of derivative financial instruments |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative |
|
|
|
|
|
|
financial |
|
|
|
|
December 31, 2007 |
|
instruments |
|
|
Senior notes |
|
|
Cross-currency and interest rate swaps |
|
$ |
85,109 |
|
|
$ |
|
|
Embedded price escalation clauses in long-term
revenue construction contract |
|
|
16,207 |
|
|
|
|
|
Embedded prepayment and early redemption options on
senior notes |
|
|
|
|
|
|
(3,962 |
) |
|
Total fair value of derivative financial instruments |
|
|
101,316 |
|
|
|
(3,962 |
) |
Less: current portion |
|
|
(4,640 |
) |
|
|
|
|
|
|
|
$ |
96,676 |
|
|
$ |
(3,962 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial |
|
|
|
|
April 1, 2007 |
|
instruments |
|
|
Senior notes |
|
|
Cross-currency and interest rate swaps |
|
$ |
60,863 |
|
|
$ |
|
|
Embedded price escalation clauses in long-term
revenue construction contract |
|
|
7,246 |
|
|
|
|
|
Embedded prepayment and early redemption options on
senior notes |
|
|
|
|
|
|
(8,519 |
) |
|
Total fair value of derivative financial instruments |
|
|
68,109 |
|
|
|
(8,519 |
) |
Less: current portion |
|
|
(2,669 |
) |
|
|
|
|
|
|
|
$ |
65,440 |
|
|
$ |
(8,519 |
) |
|
15
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
12. Other information
|
a) |
|
Supplemental cash flow information |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended December 31 |
|
|
Nine months ended December 31 |
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
Cash paid during the period for: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
$ |
13,787 |
|
|
$ |
16,476 |
|
|
$ |
27,551 |
|
|
$ |
33,182 |
|
Income taxes |
|
|
8 |
|
|
|
|
|
|
|
29 |
|
|
|
342 |
|
Cash received during the period for: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
|
97 |
|
|
|
195 |
|
|
|
282 |
|
|
|
1,092 |
|
Non-cash transactions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital leases |
|
|
4,255 |
|
|
|
758 |
|
|
|
4,553 |
|
|
|
3,952 |
|
Lease inducements |
|
|
|
|
|
|
|
|
|
|
1,045 |
|
|
|
|
|
|
|
b) |
|
Net change in non-cash working capital |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended December 31 |
|
|
Nine months ended December 31 |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
Operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
$ |
8,454 |
|
|
$ |
(25,312 |
) |
|
$ |
(22,374 |
) |
|
$ |
(30,347 |
) |
Allowance for doubtful accounts |
|
|
82 |
|
|
|
|
|
|
|
82 |
|
|
|
24 |
|
Unbilled revenue |
|
|
(758 |
) |
|
|
295 |
|
|
|
9,386 |
|
|
|
4,404 |
|
Inventory |
|
|
40 |
|
|
|
(143 |
) |
|
|
42 |
|
|
|
(99 |
) |
Prepaid expenses and deposits |
|
|
212 |
|
|
|
(2,930 |
) |
|
|
4,957 |
|
|
|
(18,587 |
) |
Other assets |
|
|
2,092 |
|
|
|
(1,859 |
) |
|
|
4,940 |
|
|
|
(11,290 |
) |
Accounts payable |
|
|
(8,086 |
) |
|
|
10,069 |
|
|
|
13,174 |
|
|
|
13,142 |
|
Accrued liabilities |
|
|
(4,970 |
) |
|
|
(18,300 |
) |
|
|
(7,296 |
) |
|
|
(13,411 |
) |
Billings in excess of costs
and estimated earnings |
|
|
1,640 |
|
|
|
361 |
|
|
|
620 |
|
|
|
3,668 |
|
|
|
|
$ |
(1,294 |
) |
|
$ |
(37,819 |
) |
|
$ |
3,531 |
|
|
$ |
(52,496 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
(18,976 |
) |
|
$ |
6,600 |
|
|
$ |
(4,727 |
) |
|
$ |
6,600 |
|
|
|
|
$ |
(18,976 |
) |
|
$ |
6,600 |
|
|
$ |
(4,727 |
) |
|
$ |
6,600 |
|
|
16
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
Income tax expense as a percentage of income before income taxes for the three and
nine months ended December 31, 2007 differs from the statutory rate of 31.47%
primarily due to the impact of enacted rate changes during the period and the
impact of new accounting standards for the recognition and measurement of
financial instruments as certain embedded derivatives are considered capital in
nature for income tax purposes. Income tax as a percentage of income before
income taxes for the nine months ended December 31, 2006 differed from the
statutory rate of 32.12% primarily due to the elimination of the valuation
allowance of $5,858 that was recorded during that period offset by permanent
differences relating to certain financing transactions which are not deductible
for tax purposes and accruals for certain tax exposure items.
13. Segmented information
The Company operates in the following reportable business segments, which follow
the organization, management and reporting structure within the Company.
|
|
|
Heavy Construction and Mining: |
|
|
|
|
The Heavy Construction and Mining segment provides mining and site preparation
services, including overburden removal and reclamation services, project
management and underground utility construction, to a variety of customers
throughout Canada. |
|
|
|
|
Piling: |
|
|
|
|
The Piling segment provides deep foundation construction and design build
services to a variety of industrial and commercial customers throughout Western
Canada. |
|
|
|
|
Pipeline: |
|
|
|
|
The Pipeline segment provides both small and large diameter pipeline
construction and installation services to energy and industrial clients
throughout Western Canada. |
Certain business units of the Company have been aggregated into the Heavy
Construction and Mining segment as they do meet quantitative thresholds for
separate disclosure and have similar economic characteristics. These business
units are considered to have similar economic characteristics based on
similarities in the nature of the services provided, the customer base and the
similarities in the production process and the resources used
to provide these services.
17
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
b) |
|
Results by business segment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy |
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Construction |
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
and Mining |
|
|
Piling |
|
|
Pipeline |
|
|
Total |
|
|
Revenues from external customers |
|
$ |
154,402 |
|
|
$ |
43,751 |
|
|
$ |
76,741 |
|
|
$ |
274,894 |
|
Depreciation of plant and equipment |
|
|
5,563 |
|
|
|
817 |
|
|
|
419 |
|
|
|
6,799 |
|
Segment profits |
|
|
28,097 |
|
|
|
11,386 |
|
|
|
12,934 |
|
|
|
52,417 |
|
Segment assets |
|
|
439,487 |
|
|
|
116,195 |
|
|
|
98,473 |
|
|
|
654,155 |
|
Expenditures for segment plant and
equipment |
|
|
5,462 |
|
|
|
1,890 |
|
|
|
44 |
|
|
|
7,396 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy |
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Construction |
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
and Mining |
|
|
Piling |
|
|
Pipeline |
|
|
Total |
|
|
Revenues from external customers |
|
$ |
111,416 |
|
|
$ |
29,164 |
|
|
$ |
15,278 |
|
|
$ |
155,858 |
|
Depreciation of plant and equipment |
|
|
3,875 |
|
|
|
1,023 |
|
|
|
275 |
|
|
|
5,173 |
|
Segment profits (loss) |
|
|
8,922 |
|
|
|
10,322 |
|
|
|
(1,776 |
) |
|
|
17,468 |
|
Segment assets |
|
|
449,594 |
|
|
|
94,410 |
|
|
|
52,405 |
|
|
|
596,409 |
|
Expenditures for segment plant and
equipment |
|
|
68,748 |
|
|
|
1,954 |
|
|
|
1,122 |
|
|
|
71,824 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy |
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
Construction |
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
and Mining |
|
|
Piling |
|
|
Pipeline |
|
|
Total |
|
|
Revenues from external customers |
|
$ |
431,140 |
|
|
$ |
121,698 |
|
|
$ |
113,258 |
|
|
$ |
666,096 |
|
Depreciation of plant and equipment |
|
|
16,676 |
|
|
|
2,534 |
|
|
|
721 |
|
|
|
19,931 |
|
Segment profits |
|
|
68,631 |
|
|
|
31,725 |
|
|
|
14,154 |
|
|
|
114,510 |
|
Segment assets |
|
|
439,487 |
|
|
|
116,195 |
|
|
|
98,473 |
|
|
|
654,155 |
|
Expenditures for segment plant and
equipment |
|
|
30,210 |
|
|
|
10,878 |
|
|
|
4,923 |
|
|
|
46,011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy |
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
Construction |
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
and Mining |
|
|
Piling |
|
|
Pipeline |
|
|
Total |
|
|
Revenues from external customers |
|
$ |
323,048 |
|
|
$ |
79,394 |
|
|
$ |
21,582 |
|
|
$ |
424,024 |
|
Depreciation of plant and equipment |
|
|
11,917 |
|
|
|
2,459 |
|
|
|
514 |
|
|
|
14,890 |
|
Segment profits (loss) |
|
|
47,550 |
|
|
|
25,573 |
|
|
|
(710 |
) |
|
|
72,413 |
|
Segment assets |
|
|
449,594 |
|
|
|
94,410 |
|
|
|
52,405 |
|
|
|
596,409 |
|
Expenditures for segment plant and
equipment |
|
|
79,168 |
|
|
|
6,264 |
|
|
|
1,904 |
|
|
|
87,336 |
|
|
18
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
i. |
|
Income before income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
December 31 |
|
|
December 31 |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
Total profit for reportable segments |
|
$ |
52,417 |
|
|
$ |
17,468 |
|
|
$ |
114,510 |
|
|
$ |
72,413 |
|
General and Administrative costs |
|
|
(17,009 |
) |
|
|
(11,647 |
) |
|
|
(48,996 |
) |
|
|
(30,894 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(7,399 |
) |
|
|
(9,292 |
) |
|
|
(20,333 |
) |
|
|
(29,786 |
) |
|
Realized and unrealized (loss) gain
on foreign exchange and derivative
financial instruments |
|
|
7,203 |
|
|
|
2,418 |
|
|
|
(6,630 |
) |
|
|
4,030 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other unallocated corporate costs |
|
|
(333 |
) |
|
|
(1,750 |
) |
|
|
(1,581 |
) |
|
|
(2,036 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over allocated (unallocated)
equipment costs |
|
|
(1,787 |
) |
|
|
8,504 |
|
|
|
(13,766 |
) |
|
|
6,398 |
|
|
Income before income taxes |
|
$ |
33,092 |
|
|
$ |
5,701 |
|
|
$ |
23,204 |
|
|
$ |
20,125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
March 31, 2007 |
|
|
Total assets for reportable segments |
|
$ |
654,155 |
|
|
$ |
621,636 |
|
Corporate assets |
|
|
87,001 |
|
|
|
89,100 |
|
|
Total assets |
|
$ |
741,156 |
|
|
$ |
710,736 |
|
|
The Companys goodwill was assigned to the Heavy Construction and Mining,
Piling and Pipeline segments in the amounts of $125,447, $41,856 and $32,753,
respectively.
Substantially all of the Companys assets are located in Western Canada and the
activities are carried out throughout the year.
19
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
iii. |
|
Depreciation of plant and equipment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
December 31 |
|
|
December 31 |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
Total depreciation for reportable segments |
|
$ |
6,799 |
|
|
$ |
5,173 |
|
|
$ |
19,931 |
|
|
$ |
14,890 |
|
Depreciation for corporate assets |
|
|
1,086 |
|
|
|
1,358 |
|
|
|
4,248 |
|
|
|
3,775 |
|
|
Total depreciation |
|
$ |
7,885 |
|
|
$ |
6,531 |
|
|
$ |
24,179 |
|
|
$ |
18,665 |
|
|
|
iv. |
|
Capital expenditures for plant and equipment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
December 31 |
|
|
December 31 |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
Total capital expenditures for
reportable segments |
|
$ |
7,396 |
|
|
$ |
71,824 |
|
|
$ |
46,011 |
|
|
$ |
87,336 |
|
Capital expenditures for corporate assets |
|
|
625 |
|
|
|
6,574 |
|
|
|
5,555 |
|
|
|
10,371 |
|
|
Total capital expenditures |
|
$ |
8,021 |
|
|
$ |
78,398 |
|
|
$ |
51,566 |
|
|
$ |
97,707 |
|
|
Prior year segmented capital expenditures have been adjusted to reflect the
reclassification of assets between reported segments and corporate assets.
The following customers accounted for 10% or more of total revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
December 31 |
|
|
December 31 |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
Customer A |
|
|
27 |
% |
|
|
|
|
|
|
14 |
% |
|
|
|
|
Customer B |
|
|
24 |
% |
|
|
31 |
% |
|
|
31 |
% |
|
|
21 |
% |
Customer C |
|
|
14 |
% |
|
|
7 |
% |
|
|
13 |
% |
|
|
7 |
% |
Customer D |
|
|
12 |
% |
|
|
17 |
% |
|
|
13 |
% |
|
|
18 |
% |
Customer E |
|
|
11 |
% |
|
|
13 |
% |
|
|
12 |
% |
|
|
12 |
% |
|
This revenue by major customer was earned in the Heavy Construction and Mining,
Piling and Pipeline segments.
14. |
|
Stock-based compensation plans |
|
a) |
|
Employer stock option plan |
Under the 2004 Amended and Restated Share Option Plan, directors, officers,
employees and certain service providers to the Company are eligible to receive
stock options to acquire voting common shares in the Company. Each stock option
provides the right to acquire one common share in the Company and expires ten
years from the grant date or on termination of employment. Options may be
exercised at a price determined at the time the option is awarded, and vest as
follows: no options vest on the award date and twenty percent vest on each
subsequent anniversary date.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended December 31 |
|
|
|
|
|
|
|
2007 |
|
|
|
|
|
|
2006 |
|
|
|
|
|
|
|
|
Weighted average |
|
|
|
|
|
|
Weighted average |
|
|
|
|
|
|
|
exercise price |
|
|
|
|
|
|
exercise price |
|
|
|
Number of options |
|
|
($ per share) |
|
|
Number of options |
|
|
($ per share) |
|
|
Outstanding, beginning of period |
|
|
1,927,440 |
|
|
$ |
6.14 |
|
|
|
2,230,840 |
|
|
$ |
5.99 |
|
Granted |
|
|
315,100 |
|
|
|
13.50 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(199,624 |
) |
|
|
(5.00 |
) |
|
|
|
|
|
|
|
|
Forfeited |
|
|
(75,000 |
) |
|
|
(17.53 |
) |
|
|
(44,000 |
) |
|
|
(5.00 |
) |
|
Outstanding, end of period |
|
|
1,967,916 |
|
|
$ |
7.00 |
|
|
|
2,186,840 |
|
|
$ |
6.01 |
|
|
20
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended December 31 |
|
|
|
|
|
|
|
2007 |
|
|
|
|
|
|
2006 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
average |
|
|
|
|
|
|
average |
|
|
|
Number of |
|
|
exercise price |
|
|
Number of |
|
|
exercise price |
|
|
|
options |
|
|
($ per share) |
|
|
options |
|
|
($ per share) |
|
|
Outstanding, beginning of period |
|
|
2,146,840 |
|
|
$ |
6.03 |
|
|
|
2,066,360 |
|
|
$ |
5.00 |
|
Granted |
|
|
315,100 |
|
|
|
13.50 |
|
|
|
315,520 |
|
|
|
11.61 |
|
Exercised |
|
|
(347,024 |
) |
|
|
(5.00 |
) |
|
|
(27,760 |
) |
|
|
(5.00 |
) |
Forfeited |
|
|
(147,000 |
) |
|
|
(11.39 |
) |
|
|
(167,280 |
) |
|
|
(5.00 |
) |
|
Outstanding, end of period |
|
|
1,967,916 |
|
|
$ |
7.00 |
|
|
|
2,186,840 |
|
|
$ |
6.01 |
|
|
At December 31, 2007, the weighted average remaining contractual life of
outstanding options is 7.8 years (March 31, 2007 7.7 years). The Company
recorded $276 and $1,023 of compensation expense related to the stock options in
the three and nine months ended December 31, 2007, respectively (three and nine
months ended December 31, 2006 $621 and $1,742 respectively), with such amount
being credited to contributed surplus.
The fair value of each option granted by the Company was estimated on the grant
date using the Black Scholes option-pricing model with the following weighted
average assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
December 31 |
|
|
Nine months ended
December 31 |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
Number of options granted |
|
|
315,100 |
|
|
|
|
|
|
|
315,100 |
|
|
|
315,520 |
|
Weighted average fair value
per option granted ($) |
|
|
6.42 |
|
|
|
|
|
|
|
6.42 |
|
|
|
9.91 |
|
Weighted average assumptions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend yield |
|
nil% |
|
|
|
|
|
nil% |
|
nil% |
Expected volatility |
|
|
40.90 |
% |
|
|
|
|
|
|
40.90 |
% |
|
|
24.73 |
% |
Risk-free interest rate |
|
|
4.00 |
% |
|
|
|
|
|
|
4.00 |
% |
|
|
4.30 |
% |
Expected life (years) |
|
|
6.5 |
|
|
|
|
|
|
|
6.5 |
|
|
|
6.4 |
|
|
21
NORTH AMERICAN ENERGY PARTNERS INC.
Notes to the Interim Consolidated Financial Statements
For the three and nine months ended December 31, 2007
(Amounts in thousands of Canadian dollars unless otherwise specified)
(unaudited)
|
b) |
|
Directors deferred stock unit plan |
|
|
|
|
On November 27, 2007, the Company approved a Directors Deferred Stock Unit
(DDSU) Plan, which became effective January 1, 2008. Under the DDSU Plan,
non-employee or officer directors of the Company shall receive 50% of their annual
fixed remuneration (which is included in general and administrative expenses in
the consolidated statement of operations) in the form of DDSUs and may elect to
receive all or a part of their annual fixed remuneration in excess of 50% in the
form of DDSUs. The DDSUs vest immediately upon grant and are redeemable, in cash,
equal to the difference between the market
value of the Companys common stock at maturity (Maturity occurs when the director resigns
or retires) and the market value of the Companys common stock on the grant date. DDSUs must be redeemed within 60 days following
maturity. Directors, who are not US taxpayers, may elect to defer the maturity
date until a date no later than December 1st of the calendar year following the
year in which the maturity date falls. |
15. |
|
Related party transactions |
|
|
|
The Company may receive consulting and advisory services provided by companies
in which directors of the corporation may have an interest of the Corporation with respect to the organization of the
companies, employee benefit and compensation arrangements, and other matters, and no fee is charged for these consulting and advisory services. |
|
|
|
In order for the companies to provide such advice and consulting we provide reports,
financial data and other information. This permits them to consult with and advise our
management on matters relating to our operations, company affairs and finances. In
addition this permits them to visit and inspect any of our properties
and facilities. The transactions are in the normal course
of operations and are measured at the exchange amount of consideration established and agreed to by the related parties. |
|
16. |
|
Seasonality |
|
|
|
The Company generally experiences a decline in revenues during the first quarter of
each fiscal year due to seasonality, as weather conditions make operations in the
Companys operating regions difficult during this period. The level of activity in
the Heavy Construction and Mining and Pipeline segments declines when frost leaves the
ground and many secondary roads are temporarily rendered incapable of supporting the
weight of heavy equipment. The duration of this period is referred to as spring
breakup and has a direct impact on the Companys activity levels. Revenues during
the fourth quarter of each fiscal year are typically highest as ground conditions are
most favorable in the Companys operating regions. As a result, full-year results are
not likely to be a direct multiple of any particular quarter or combination of
quarters. |
|
17. |
|
Guarantee |
|
|
|
At December 31, 2007, in connection with a heavy equipment financing agreement, the
Company has guaranteed a $0.9 million debt owed to the equipment manufacturer by a
third party finance company. The Companys guarantee of this indebtedness will expire
when the equipment is commissioned, which is expected to be February 28, 2008. The
Company has determined that the fair value of this financial instrument at inception
and December 31, 2007 was minimal. |
|
18. |
|
Comparative figures |
|
|
|
Certain of the comparative figures have been reclassified to conform to the current
periods presentation. |
22
NORTH AMERICAN ENERGY PARTNERS
INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
The following discussion and analysis is as of February 14, 2008 and should be read in conjunction
with the attached unaudited interim consolidated financial statements for the three and nine months
ended December 31, 2007 and the audited consolidated financial statements included in our annual
report on Form 20-F for the fiscal year ended March 31, 2007, which have been prepared in
accordance with Canadian generally accepted accounting principles (GAAP). Additional information
relating to our business is available on SEDAR at www.sedar.com and EDGAR at www.sec.gov. Except
where otherwise specifically indicated, all dollar amounts are expressed in Canadian dollars.
February 14, 2008
Prior Year Comparisons
On November 28, 2006 we completed an initial public offering (IPO) of common shares in
Canada and the U.S. We became publicly traded on the Toronto Stock Exchange and New York Stock
Exchange under the symbol NOA. Prior to the consummation of the IPO, the predecessor company was
amalgamated with its parent companies and we undertook certain transactions that resulted in
changes to our capital structure. Upon completion of the IPO, we used the proceeds to undertake
additional transactions, which further changed our capital structure. As a result, comparisons of
current periods to prior periods are impacted by the amalgamation and capital restructuring
transactions. For a description of the amalgamation and IPO transactions see note 2 in our annual
report on Form 20-F for the fiscal year ended March 31, 2007.
Consolidated Financial Highlights
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended Dec 31, |
|
|
|
|
|
|
|
% of |
|
|
|
|
|
|
% of |
|
|
|
2007 |
|
|
Revenue |
|
|
2006 |
|
|
Revenue |
|
|
|
|
|
|
|
|
(dollars in thousands, except per
share information) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
274,894 |
|
|
|
100.0 |
% |
|
$ |
155,858 |
|
|
|
100.0 |
% |
Gross profit |
|
|
50,630 |
|
|
|
18.4 |
% |
|
|
25,972 |
|
|
|
16.7 |
% |
General & administrative costs |
|
|
17,009 |
|
|
|
6.2 |
% |
|
|
11,647 |
|
|
|
7.5 |
% |
Operating income |
|
|
33,173 |
|
|
|
12.1 |
% |
|
|
13,817 |
|
|
|
8.9 |
% |
Net income |
|
|
25,377 |
|
|
|
9.2 |
% |
|
|
6,639 |
|
|
|
4.3 |
% |
Per share information |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income basic |
|
$ |
0.71 |
|
|
|
|
|
|
$ |
0.27 |
|
|
|
|
|
Net income diluted |
|
|
0.69 |
|
|
|
|
|
|
|
0.26 |
|
|
|
|
|
Building on our solid performance in the second quarter we achieved even stronger financial
results in the third quarter (three months ended December 31, 2007). Growth in all three segments
of our business helped boost consolidated revenue to $274.9 million, up 76.4% from the previous
year. Consolidated gross profit increased at an even faster pace, rising 94.9% over the prior year
to $50.6 million. The improvement in gross profit reflects increased sales as well as an increase
in profit margin from 16.7% to 18.4%. The higher gross profit margin reflects the return to
profitability in our Pipeline segment, an advantageous mix of projects and solid execution across
our entire portfolio of projects. General and administrative (G&A) cost performance improved
during the period with G&A costs representing 6.2% of revenue compared to 7.5% a year ago. The
combination of higher revenue, improved margins and better G&A cost performance contributed to a
140.1% increase in third quarter operating income. Net income climbed to $25.4 million or $0.71
per share, basic, from $6.6 million or $0.27 per share, basic, last year. Non-cash, after-tax
unrealized gains on foreign exchange and derivative financial instruments positively impacted
reported net income by $5.7 million ($0.16 per share, basic) compared to a $2.1 million ($0.09 per
share, basic) favourable impact in the prior year.
Overview and Outlook
Demand for our services continued to grow in the third quarter with increased volumes of work
in the Alberta oil sands, increased activity on a major pipeline project and strong commercial
construction markets in Western Canada. Our business divisions responded effectively to these
opportunities, achieving record revenue and operating income on both a consolidated and segmented
basis. While we typically benefit from seasonally high activity levels during the third quarter,
our results for the period were virtually free of claims, unusual expenses and other factors that can skew results either positively or
negatively. Accordingly, we believe these third quarter results provide a clear picture of our
performance capabilities.
1
NORTH AMERICAN ENERGY PARTNERS
INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
Our Heavy Construction and Mining segment, which, in the third quarter, accounted for 56.2%
and 53.6% of consolidated revenues and segment profits, respectively, continued to benefit from
robust oil sands activity. We further expanded our equipment fleet with an additional 14 mining
trucks. We provided a record level of industrial construction and mining services to long-term
customers including Suncor Energy Inc. (Suncor), Albian Sands Energy (Albian), Syncrude Canada Ltd.
(Syncrude) and Canadian Natural Resources Ltd. (Canadian Natural). We also initiated services to
Petro-Canadas Fort Hills oil sands project and we are actively tendering additional work on that
site. The intense level of activity, combined with an excellent project mix and tight cost
control, supported higher revenues and significantly improved profitability from this segment
during the third quarter. On the cost side, our results began to show the benefit of a strategic
shift to mid-sized mining trucks. Tires for these trucks are currently in better supply and
available at lower costs than for larger-sized trucks, which in turn, has helped to stabilize our
maintenance costs.
Our Piling division, which, in the third quarter, accounted for 15.9% and 21.7% of
consolidated revenues and segment profits, respectively, achieved year-over-year revenue growth of
53.3%. Oil sands development and a high level of commercial and industrial construction activity
were key factors in the revenue gain, supported by our acquisition of Midwest Foundation
Technologies Inc. (Midwest Micropile) in September, 2006 and the opening of a new branch office
in Saskatoon in May, 2007. As anticipated, margins in our Piling segment have returned to a more
typical 26%, after peaking at 35% a year earlier on an unusually profitable project mix. We view
the current margin level as more sustainable.
Our Pipeline division, which, in the third quarter, accounted for 27.9% and 24.7% of
consolidated revenues and segment profits, respectively, achieved dramatically improved performance
compared to the third quarter of last year. Revenue expanded by over five times and segment
profits improved significantly to $12.9 million, compared to a $1.8 million loss last year, as we
undertook a large portion of work on the Trans Mountain Expansion (TMX) Anchor Loop project for
Kinder Morgan Canada (Kinder Morgan). We have now completed approximately 50% of this $185
million contract.
Overall, we are very pleased with our third quarter performance. We have attracted an
excellent mix of short and long-term projects and our execution and cost control for these projects
has been of a very high standard.
Looking forward, we expect our operating performance will remain strong through the balance of
the fiscal year. The fourth quarter is typically strong and we anticipate a high level of activity
in all three of our operating segments.*
Our Heavy Construction and Mining segment continues to respond effectively to opportunities in
the Alberta oil sands. Despite recent changes to Alberta royalty rates affecting natural gas,
conventional oil and oil sands producers, development of the oil sands continues to expand.
Suncor, a major customer of ours for 31 years, recently announced it will spend over $20 billion on
its Voyageur expansion. We have already initiated work at the Voyageur project under a five-year
multiple-use contract with Suncor and we anticipate this project will create additional demand for
our services. In addition, our activity levels with Syncrude and Albian are increasing, we have
six years remaining on a major overburden removal contract with Canadian Natural and as mentioned
above, we have recently initiated work at Petro-Canadas Fort Hills project. Beyond the oil sands,
our involvement in the De Beers Victor diamond mine in northern Ontario is beginning to wind down
as construction draws to a close. In keeping with our strategy of building diversification into
our project mix, we will seek to replace this business with other non-oil sands projects. In the
mean time, all equipment and people, surplus to our needs at Victor, have been redeployed on other
revenue generating work.*
Pipeline results are expected to remain significantly above last years levels as we continue
to execute on the TMX contract with Kinder Morgan. This contract relates to the first of
three pipeline expansion phases being undertaken by Kinder Morgan in Western Canada. Phase one,
the TMX Anchor Loop project, establishes our company in the large-inch pipeline construction market
and improves our competitive position within the rapidly expanding Western Canadian market for
large pipeline construction projects. We see numerous opportunities to continue growing our
Pipeline business as the oil and gas transmission industry responds to increasing oil sands
production and the resulting demand for additional pipeline capacity. *
In our Piling division, demand levels remain strong as a result of oil sands development and
strong construction activity in major Western Canadian centers. The recent announcement of a $120 billion capital spending plan by the
Province of Alberta could greatly accelerate demand for piling and construction services as the
majority of the funding will be targeted to infrastructure enhancement. *
Overall,
our outlook for all three of our business segments remains positive.
|
|
|
* |
|
This paragraph contains forward-looking information.
Please refer to Forward-Looking Information, Risks and Uncertainties for a
discussion of the risks and uncertainties related to such information. |
2
NORTH
AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
Consolidated Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended Dec 31, |
|
|
Nine Months Ended Dec 31, |
|
|
|
|
|
|
|
% of |
|
|
|
|
|
|
% of |
|
|
|
|
|
|
% of |
|
|
|
|
|
|
% of |
|
|
|
2007 |
|
|
Revenue |
|
|
2006 |
|
|
Revenue |
|
|
2007 |
|
|
Revenue |
|
|
2006 |
|
|
Revenue |
|
|
|
|
|
|
|
|
|
|
(dollars in thousands, except per
share information) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
274,894 |
|
|
|
100.0 |
% |
|
$ |
155,858 |
|
|
|
100.0 |
% |
|
$ |
666,096 |
|
|
|
100.0 |
% |
|
$ |
424,024 |
|
|
|
100.0 |
% |
Equipment costs |
|
|
44,231 |
|
|
|
16.1 |
% |
|
|
29,244 |
|
|
|
18.8 |
% |
|
|
131,582 |
|
|
|
19.8 |
% |
|
|
78,777 |
|
|
|
18.6 |
% |
Depreciation |
|
|
7,885 |
|
|
|
2.9 |
% |
|
|
6,531 |
|
|
|
4.2 |
% |
|
|
24,179 |
|
|
|
3.6 |
% |
|
|
18,665 |
|
|
|
4.4 |
% |
Gross profit |
|
|
50,630 |
|
|
|
18.4 |
% |
|
|
25,972 |
|
|
|
16.7 |
% |
|
|
100,744 |
|
|
|
15.1 |
% |
|
|
78,810 |
|
|
|
18.6 |
% |
General & administrative costs |
|
|
17,009 |
|
|
|
6.2 |
% |
|
|
11,647 |
|
|
|
7.5 |
% |
|
|
48,996 |
|
|
|
7.4 |
% |
|
|
30,894 |
|
|
|
7.3 |
% |
Operating income |
|
|
33,173 |
|
|
|
12.1 |
% |
|
|
13,817 |
|
|
|
8.9 |
% |
|
|
49,816 |
|
|
|
7.5 |
% |
|
|
46,585 |
|
|
|
11.0 |
% |
Net income |
|
|
25,377 |
|
|
|
9.2 |
% |
|
|
6,639 |
|
|
|
4.3 |
% |
|
|
17,122 |
|
|
|
2.6 |
% |
|
|
19,776 |
|
|
|
4.7 |
% |
Per share information |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income basic |
|
$ |
0.71 |
|
|
|
|
|
|
$ |
0.27 |
|
|
|
|
|
|
$ |
0.48 |
|
|
|
|
|
|
$ |
0.96 |
|
|
|
|
|
Net income diluted |
|
|
0.69 |
|
|
|
|
|
|
|
0.26 |
|
|
|
|
|
|
|
0.46 |
|
|
|
|
|
|
|
0.90 |
|
|
|
|
|
EBITDA(1) |
|
$ |
48,819 |
|
|
|
17.8 |
% |
|
$ |
21,651 |
|
|
|
13.9 |
% |
|
$ |
68,482 |
|
|
|
10.3 |
% |
|
$ |
69,068 |
|
|
|
16.3 |
% |
Consolidated EBITDA(1) |
|
|
42,069 |
|
|
|
15.3 |
% |
|
|
24,636 |
|
|
|
15.8 |
% |
|
|
79,659 |
|
|
|
12.0 |
% |
|
|
71,921 |
|
|
|
17.0 |
% |
|
|
|
(1) |
|
EBITDA is calculated as net income (loss) before interest expense, income taxes,
depreciation and amortization. Consolidated EBITDA is defined as EBITDA, excluding the
effects of foreign exchange gain or loss, realized and unrealized gain or loss on
derivative financial instruments, non-cash stock-based compensation expense, gain or loss
on disposal of plant and equipment and certain other non-cash items included in the
calculation of net income (loss) (see Sources of
liquidity for a detailed definition of Consolidated EBITDA in
our credit facility). We believe that EBITDA is a meaningful measure of the
performance of our business because it excludes items, such as depreciation and
amortization, interest and taxes that are not directly related to the operating performance
of our business. Management reviews EBITDA to determine whether plant and equipment are
being allocated efficiently. In addition, our revolving credit facility requires us to
maintain a minimum interest coverage ratio and a maximum senior leverage ratio, which are
calculated using Consolidated EBITDA. Non-compliance with these financial covenants could
result in our being required to immediately repay all amounts outstanding under our
revolving credit facility. EBITDA and Consolidated EBITDA are not measures of performance
under Canadian GAAP or U.S. GAAP and our computations of EBITDA and Consolidated EBITDA may
vary from others in our industry. EBITDA and Consolidated EBITDA should not be considered
as alternatives to operating income or net income as measures of operating performance or
cash flows as measures of liquidity. EBITDA and Consolidated EBITDA have important
limitations as analytical tools and should not be considered in isolation or as substitutes
for analysis of our results as reported under Canadian GAAP or U.S. GAAP. For example,
EBITDA and Consolidated EBITDA: |
|
|
|
do not reflect our cash expenditures or requirements for capital expenditures or
capital commitments; |
|
|
|
|
do not reflect changes in or cash requirements for, our working capital needs; |
|
|
|
|
do not reflect the interest expense or the cash requirements necessary to service
interest or principal payments on our debt; |
|
|
|
|
exclude tax payments that represent a reduction in cash available to us; and |
|
|
|
|
do not reflect any cash requirements for assets being depreciated and amortized that
may have to be replaced in the future. |
In addition, Consolidated EBITDA excludes unrealized foreign exchange gains and losses and
unrealized and realized gains and losses on derivative financial instruments, which, in the
case of unrealized losses, may ultimately result in a liability that will need to be paid and
in the case of realized losses, represents an actual use of cash during the period.
3
NORTH
AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
A reconciliation of net income (loss) to EBITDA and Consolidated EBITDA is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended Dec 31, |
|
|
Nine Months Ended Dec 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
25,377 |
|
|
$ |
6,639 |
|
|
$ |
17,122 |
|
|
$ |
19,776 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
7,399 |
|
|
|
9,292 |
|
|
|
20,333 |
|
|
|
29,786 |
|
Income taxes |
|
|
7,715 |
|
|
|
(938 |
) |
|
|
6,082 |
|
|
|
349 |
|
Depreciation |
|
|
7,885 |
|
|
|
6,531 |
|
|
|
24,179 |
|
|
|
18,665 |
|
Amortization of intangible assets |
|
|
443 |
|
|
|
127 |
|
|
|
766 |
|
|
|
492 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA |
|
$ |
48,819 |
|
|
$ |
21,651 |
|
|
$ |
68,482 |
|
|
$ |
69,068 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized foreign exchange (gain) loss on
senior notes |
|
|
(1,612 |
) |
|
|
10,956 |
|
|
|
(32,626 |
) |
|
|
(2,537 |
) |
Realized and unrealized (gain) loss on
derivative financial instruments |
|
|
(5,419 |
) |
|
|
(13,315 |
) |
|
|
39,766 |
|
|
|
(1,533 |
) |
Loss on disposal of plant and equipment and
assets held for sale |
|
|
5 |
|
|
|
381 |
|
|
|
1,166 |
|
|
|
839 |
|
Stock-based compensation |
|
|
276 |
|
|
|
621 |
|
|
|
1,023 |
|
|
|
1,742 |
|
Write-off of deferred financing costs |
|
|
|
|
|
|
4,342 |
|
|
|
|
|
|
|
4,342 |
|
Write-down of other assets to replacement cost |
|
|
|
|
|
|
|
|
|
|
1,848 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated EBITDA |
|
$ |
42,069 |
|
|
$ |
24,636 |
|
|
$ |
79,659 |
|
|
$ |
71,921 |
|
Third quarter revenue increased to $274.9 million, a 76.4% increase over the same period last
year. While revenue improvements were achieved in all three operating segments, most of the $119.0
million increase was driven by the execution of a major contract in our Pipeline division and by
increased Heavy Construction and Mining activity levels in the oil sands. During the nine months
ended December 31, 2007, revenue increased to $666.1 million, up 57.1% compared to the same period
last year. 82.5% of this $242.1 million revenue increase was driven by growth in our Pipeline and
Heavy Construction and Mining segments.
Third quarter gross profit increased to $50.6 million, up 94.9% from last year. As a
percentage of revenue, gross profit increased to 18.4% from 16.7% primarily driven by strong third
quarter Pipeline segment margins in the current year compared to a third quarter Pipeline segment
loss in the prior year. Margins in our Heavy Construction and Mining segment also returned to
stronger levels during the quarter, after being negatively impacted by demobilization costs and a
lower margin contract in the previous year.
Contributing to stronger current year third quarter gross profit were lower equipment costs
and depreciation, both decreasing as a percentage of revenue. The relative reduction in equipment
costs reflects higher volumes in the Pipeline segment and a higher utilization of labour and
subcontractors in the Heavy Construction and Mining segment, while proportionately lower
depreciation reflects the use of more rental equipment in the current year. Overall, third quarter
gross margins were higher in the current year due to improved performance on a higher-margin
portfolio of contracts. This year-over-year improvement is even more significant in light of the
fact that prior year gross profit was positively impacted by a $6.5 million (4.2% of revenue)
reversal of accrued overhours related to the buyout of certain rented and leased equipment with
proceeds from the IPO.
Nine month gross profit margin decreased to 15.1% of revenue from 18.6% last year. The
year-over-year change primarily reflects the negative impact of Pipeline losses relating to a
fixed-price contract in the first half as well as higher equipment costs during the nine months.
The higher equipment costs primarily reflect the addition of 149 new units of heavy equipment and
148 new support vehicles to our fleet during the first nine months of this year. Equipment costs
as a percent of revenue, while lower in the third quarter, increased in the first half, reflecting
higher costs for larger-sized truck tires due to a worldwide imbalance in supply and demand. We
believe this situation will continue through calendar year 2010. In addition, prior year gross
profit margin was positively impacted by the settlement of a $6.1 million claim and an additional
$6.5 million reversal of accrued overhours related to the buyout of certain rented and leased equipment with proceeds from the IPO.*
|
|
|
* |
|
This paragraph contains forward-looking information.
Please refer to Forward-Looking Information, Risks and Uncertainties for a
discussion of the risks and uncertainties related to such information. |
4
NORTH AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
Third quarter operating income increased to $33.2 million, well over double the prior year
operating income of $13.8 million. This improvement reflects the higher gross profit margin as
well as a reduction in general and administrative (G&A) costs as a percentage of revenue. At 6.2%
of revenue, third quarter G&A expenses were down significantly from 7.5% of revenue in the prior
year. In absolute dollars, third quarter G&A increased $5.4 million or 46.0% over the prior year
due to increased salary costs related to a 44% increase in our salaried workforce. We have
welcomed 81 new salaried employees and 600 new hourly employees since December 31, 2006, bringing
our total number of employees to 2,065 at December 31, 2007.
Operating income for the nine months increased 6.9% to $49.8 million reflecting higher
revenue, partially offset by the lower gross profit margin discussed above. G&A as a percentage of
revenue was also slightly higher at 7.4% compared to 7.3% last year. In absolute dollars, nine
month G&A increased $18.1 million or 58.6% year-over-year as a result of higher compensation costs
related to discretionary bonuses for past services, which were paid in the first quarter and the
higher salary costs related to the increase in our salaried workforce mentioned above. In
addition, the company incurred $1.9 million of costs relating to the secondary offering in the
second quarter.
Third quarter net income improved to $25.4 million compared to $6.6 million in the same period
in the prior year. Unrealized gains and losses on foreign exchange and unrealized gains and losses
on derivative financial instruments resulted in a net non-cash,
after-tax positive impact of $5.7
million or $0.16 per share, basic, in the current year versus $2.1 million or $0.09 per share,
basic, in the prior year.
For the nine months, net income was $17.1 million compared to net income of $19.8 million last
year. Unrealized gains and losses on foreign exchange and derivative financial instruments
resulted in a net non-cash, after-tax negative impact of $4.6 million or $0.13 per share, basic, in
the current year versus a positive impact of $4.7 million or
$0.19 per share, basic, in the prior
year. The impact of these items on earnings in the current year reflects the adoption of the new
Canadian accounting standards with respect to Financial Instruments in the first quarter. The new
standards require us to account for changes in the fair value of embedded derivative financial
instruments in various contracts and to modify the method of amortizing deferred financing costs.
These changes were not in effect in the prior year and have resulted in an incremental non-cash,
after-tax charge to net income of $10.3 million or $0.29 per share, basic, in the nine months ended
December 31, 2007.
Segment Operations
Segmented profit includes revenue earned from the performance of our projects, including
amounts arising from approved change orders and claims that have met the appropriate accounting
criteria for recognition, less all direct projects expenses, including direct labour, short-term
equipment rentals and materials, payments to subcontractors, indirect job costs and internal
charges for use of capital equipment.
5
NORTH AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended Dec 31, |
|
|
Nine Months Ended Dec 31, |
|
|
|
2007 |
|
|
% of Total |
|
|
2006 |
|
|
% of Total |
|
|
2007 |
|
|
% of Total |
|
|
2006 |
|
|
% of Total |
|
|
|
|
| |
|
| |
|
| |
|
|
(dollars in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue by operating segment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy Construction and Mining |
|
$ |
154,402 |
|
|
|
56.2 |
% |
|
$ |
111,416 |
|
|
|
71.5 |
% |
|
$ |
431,140 |
|
|
|
64.7 |
% |
|
$ |
323,048 |
|
|
|
76.2 |
% |
Piling |
|
|
43,751 |
|
|
|
15.9 |
% |
|
|
29,164 |
|
|
|
18.7 |
% |
|
|
121,698 |
|
|
|
18.3 |
% |
|
|
79,394 |
|
|
|
18.7 |
% |
Pipeline |
|
|
76,741 |
|
|
|
27.9 |
% |
|
|
15,278 |
|
|
|
9.8 |
% |
|
|
113,258 |
|
|
|
17.0 |
% |
|
|
21,582 |
|
|
|
5.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
274,894 |
|
|
|
100.0 |
% |
|
$ |
155,858 |
|
|
|
100.0 |
% |
|
$ |
666,096 |
|
|
|
100.0 |
% |
|
$ |
424,024 |
|
|
|
100.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy Construction and Mining |
|
$ |
28,097 |
|
|
|
53.6 |
% |
|
$ |
8,923 |
|
|
|
51.1 |
% |
|
$ |
68,631 |
|
|
|
59.9 |
% |
|
$ |
47,550 |
|
|
|
65.7 |
% |
Piling |
|
|
11,386 |
|
|
|
21.7 |
% |
|
|
10,322 |
|
|
|
59.1 |
% |
|
|
31,725 |
|
|
|
27.7 |
% |
|
|
25,573 |
|
|
|
35.3 |
% |
Pipeline |
|
|
12,934 |
|
|
|
24.7 |
% |
|
|
(1,776 |
) |
|
|
-10.2 |
% |
|
|
14,154 |
|
|
|
12.4 |
% |
|
|
(710 |
) |
|
|
-1.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
52,417 |
|
|
|
100.0 |
% |
|
$ |
17,469 |
|
|
|
100.0 |
% |
|
$ |
114,510 |
|
|
|
100.0 |
% |
|
$ |
72,413 |
|
|
|
100.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy Construction and Mining
Heavy Construction and Mining revenue climbed to $154.4 million during the third quarter,
38.6% higher than in the same period last year. During the nine months, Heavy Construction and
Mining increased revenue to $431.1 million, up 33.5% over the prior year period. The revenue
improvement in both the third quarter and nine month periods reflects increased demand from our
major oil sands customers. In the most recent period, we continued the site preparation and
underground installation at Suncors Millennium Naphtha Unit project and initiated similar work at
Suncors Voyageur project. We also completed construction of the aerodrome project for Albian and
increased our supply of mining support services to this customer. Mining and construction services
performed to support Syncrudes operations also increased substantially from prior year levels and
included work on a new one-year overburden removal contract. Finally, production under our 10-year
mining contract with Canadian Natural continued to ramp up according to plan.
Third quarter Heavy Construction and Mining profit more than tripled to $28.1 million from
$8.9 million in the prior year as a result of increased volumes and higher segment margin. A more
profitable mix of contracts and solid execution helped to increase this segments profit margin to
18.2% in the third quarter, a significant improvement over 8.0% in the prior year. For the nine
months ended December 31, 2007, segment profit grew to $68.6 million, up 44.3% from the prior year.
During this same period, gross profit margin increased to 15.9% from 14.7% reflecting the positive
impact of this years robust third quarter results, partially offset by the benefit of a $6.1
million claim settlement in the prior year.
Piling
Piling revenue in the third quarter increased to $43.8 million, 50.0% higher than in the same
period last year. The improvement reflects strong business activity in Calgary and increased
activity levels in Saskatchewan following our recent expansion in that province. We also continued
to perform work for Shell Canada Ltd.s (Shell) Scotford upgrader expansion in the Edmonton region.
For the nine months, Piling segment revenue was $121.7 million, a 53.3% increase over the same
period in the prior year, again reflecting the strong market demand.
Piling segment profit rose to $11.4 million on higher volumes in the third quarter, 10.3%
above the same period last year. The third quarter profit increase brought the nine month segment
profit to $31.7 million, a 24.1% improvement year-over-year. As anticipated, profit margin on the
Piling revenue declined to 26.0% in the third quarter and 26.1% in the nine months of the current
year from 35.4% in the third quarter and 32.2% in the nine months of last year. This decrease
reflects the return to a more balanced project portfolio, which includes both higher-margin
fixed-price contracts and lower-margin cost-reimbursable contracts.
Pipeline
Pipeline revenue achieved dramatic growth in the third quarter, climbing to $76.7 million from
$15.3 million in the same period last year, as we completed a significant portion of work on Kinder
Morgans TMX Anchor Loop project. The increase in third quarter revenue boosted nine month segment
revenue to $113.3 million, over five times the
$21.6 million of revenue earned in the nine months of the prior year.
6
NORTH AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
The Pipeline segment also made a strong return to profitability in the third quarter,
reporting segment profit of $12.9 million and a profit margin of 16.9% compared to a loss of $1.8
million last year. These gains reflect strong performance on the TMX Anchor Loop project, which
got underway in the second quarter of this year. Results from the previous year were negatively
impacted by losses of $1.4 million incurred on fixed-price contracts. Over the nine months, the
Pipeline segment reported profit of $14.2 million and a margin of 12.5%, compared to a loss of $0.7
million in the nine months last year. The year-over-year improvement reflects the positive impact
of the TMX project, partially offset by losses related to a fixed-price contract in the first half
of this year. The prior year was also negatively impacted by losses incurred on fixed-price
contracts.
Non-operating expenses (income)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended Dec 31, |
|
|
Nine Months Ended Dec 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
(dollars in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest on senior debt |
|
$ |
5,834 |
|
|
$ |
6,802 |
|
|
$ |
17,503 |
|
|
$ |
21,582 |
|
Interest on revolving credit facility and
other interest |
|
|
1,238 |
|
|
|
269 |
|
|
|
1,664 |
|
|
|
522 |
|
Interest on capital lease obligations |
|
|
165 |
|
|
|
164 |
|
|
|
497 |
|
|
|
480 |
|
Accretion manditorily redeemable preferred
shares |
|
|
|
|
|
|
1,204 |
|
|
|
|
|
|
|
4,514 |
|
Amortization of deferred bond issue costs |
|
|
162 |
|
|
|
|
|
|
|
669 |
|
|
|
|
|
Amortization of deferred financing costs |
|
|
|
|
|
|
853 |
|
|
|
|
|
|
|
2,688 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Interest expense |
|
$ |
7,399 |
|
|
$ |
9,292 |
|
|
$ |
20,333 |
|
|
$ |
29,786 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign exchange (gain) loss on senior notes |
|
$ |
(1,784 |
) |
|
$ |
10,897 |
|
|
$ |
(33,136 |
) |
|
$ |
(2,497 |
) |
Realized and unrealized (gain) loss on
derivative financial instruments |
|
|
(5,419 |
) |
|
|
(13,315 |
) |
|
|
39,766 |
|
|
|
(1,533 |
) |
Gain on repurchase of NACG Preferred Corp.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Series A preferred shares |
|
|
|
|
|
|
(9,400 |
) |
|
|
|
|
|
|
(9,400 |
) |
Loss on extinguishment of debt |
|
|
|
|
|
|
10,875 |
|
|
|
|
|
|
|
10,928 |
|
Other income |
|
|
(115 |
) |
|
|
(233 |
) |
|
|
(351 |
) |
|
|
(824 |
) |
Income tax (recovery) expense |
|
|
7,715 |
|
|
|
(938 |
) |
|
|
6,082 |
|
|
|
349 |
|
Total interest expense decreased by $1.9 million in the third quarter and by $9.5 million in
the nine months, compared to the same periods last year, primarily due to the retirement of the
senior secured 9% notes with proceeds from our IPO and the exchange of the Series B preferred
shares for common shares as part of the amalgamation that occurred prior to the IPO.
The foreign exchange gains and losses recognized in the current and prior-year periods
primarily relate to changes in the strength of the Canadian versus the U.S. dollar on conversion of
the US$200 million of 83/4% senior notes. The Canadian dollar has strengthened from $0.8674 CAN/US
on April 1, 2007 to $1.0120 CAN/US on December 31, 2007.
The realized and unrealized gains on derivative financial instruments in the prior year
reflect changes in the fair value of the cross-currency and interest rate swaps that we employ to
provide an economic hedge for our 83/4% senior notes. Changes in the fair value of the swaps
generally have an offsetting effect to changes in the value of our 83/4% senior notes, both caused by
variations in the Canadian/US foreign exchange rate. However, the valuation of the derivative
financial instruments can also be impacted by changes in interest rates and the remaining present
value of scheduled interest payments on the 83/4% senior notes. Interest payments occur in the first
and third quarters. See Liquidity and Capital Resources Liquidity Requirements for further
information regarding these derivative financial instruments.
Due to the adoption of a new Canadian accounting standard regarding financial instruments, the
current year realized and unrealized gains and losses on derivative financial instruments also
includes changes in the fair value of derivatives embedded in our 83/4% senior notes and in a
long-term construction contract. In the current year, the change in the fair value of the swaps
was a gain of $3.9 million during the third quarter and a $26.2 million loss in the nine months.
The balance of the realized and unrealized gains and losses on derivative financial instruments
resulted from gain and losses on derivatives embedded in our 83/4% senior notes and in a long-term
construction contract.
7
NORTH
AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
Effective April 1, 2007, we adopted the new Canadian CICA Handbook Section 3855 Financial
Instruments Recognition and Measurement which resulted in the recognition of derivatives
embedded in our 83/4% senior
notes and in a long-term construction contract as follows:
|
|
|
Our 83/4% senior notes include certain embedded derivatives, notably optional
redemption and change of control redemption rights. These embedded derivatives met the
criteria for separation from the debt contract and separate measurement at fair value.
Upon adoption of Section 3855, we recorded a reduction in the carrying amount of our
83/4% senior notes of $8.5 million together with related impacts on retained earnings and
future income taxes on April 1, 2007. The change in the fair value of these embedded
derivatives resulted in a pre-tax charge to earnings of $1.1 million in the third
quarter and $4.6 million in the nine months. |
|
|
|
|
A long-term construction contract contains a price escalation feature that
represents an embedded foreign currency and price index derivative that meets the
criteria for separation from the host contract and separate measurement at fair value.
Upon adoption of Section 3855, we recorded a liability of $7.2 million together with
related impacts on retained earnings and future income taxes on April 1, 2007. The
change in the fair value of the liability resulted in a pre-tax benefit to earnings of
$2.6 million in the third quarter and a pre-tax charge to earnings of $9.0 million in
the nine months. |
With respect to the early redemption provision in the 83/4% senior notes, the process to
determine the fair value of the implied derivative was to compare the rate on the notes to the best
financial alternative. The fair value determined as at April 1, 2007 resulted in a positive
adjustment to opening retained earnings. The change in fair value in future periods is recognized
as a charge to earnings. Changes in fair value result from changes in long-term bond interest rates
during that period. The valuation process presumes a 100% probability of our implementing the
inferred transaction and does not permit a reduction in the probability if there are other factors
that would impact the decision.
With respect to the customer contract, there is a provision that requires an adjustment to
billings to our customer to reflect actual exchange rate and price index changes versus the
contract amount. The embedded derivative instrument takes into account the impact on revenues but
does not consider the impact on costs as a result of fluctuations in these measures.
The new accounting guidelines for embedded derivatives will cause our reported earnings to
fluctuate as currency exchange and interest rates change. The accounting for these derivatives
will have no impact on operations, Consolidated EBITDA or how we will evaluate performance.
We recorded income tax expense of $7.7 million in the third quarter and $6.1 million in the
nine months, as compared to an income tax recovery of $0.9 million and an expense of $0.3 million
for the corresponding periods last year. Income tax expense as a percentage of income before tax
for the nine months differs from the statutory rate of 31.47% primarily due to the impact of the
enacted rate changes during the year and the new accounting standards for the recognition,
measurement and disclosure of financial instruments as certain embedded derivatives are considered
capital in nature for income tax purposes. Income tax expense as a percentage of income before tax
for the nine months last year differs from the statutory rate of 32.12% primarily due to the
elimination of the valuation allowance of $5.9 million that was recorded during that period offset
by permanent differences relating to certain financing transactions which were not deductible for
tax purposes and accruals for certain tax exposure items.
Comparative Quarterly Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(dollars in millions, except per |
|
Fiscal 2008 |
|
|
Fiscal 2007 |
|
|
Fiscal 2006 |
share amounts) |
|
Q3 |
|
Q2 |
|
Q1 |
|
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
|
Q4 |
Revenue |
|
$ |
274.9 |
|
|
$ |
223.6 |
|
|
$ |
167.6 |
|
|
|
$ |
205.3 |
|
|
$ |
155.9 |
|
|
$ |
130.1 |
|
|
$ |
138.1 |
|
|
|
$ |
142.3 |
|
Gross profit |
|
|
50.6 |
|
|
|
35.2 |
|
|
|
14.9 |
|
|
|
|
13.6 |
|
|
|
26.0 |
|
|
|
20.2 |
|
|
|
32.6 |
|
|
|
|
31.7 |
|
Operating income (loss) |
|
|
33.2 |
|
|
|
17.1 |
|
|
|
(0.4 |
) |
|
|
|
4.5 |
|
|
|
13.8 |
|
|
|
9.7 |
|
|
|
23.1 |
|
|
|
|
22.4 |
|
Net income (loss) |
|
|
25.4 |
|
|
|
2.1 |
|
|
|
(10.3 |
) |
|
|
|
1.4 |
|
|
|
6.6 |
|
|
|
(4.8 |
) |
|
|
17.9 |
|
|
|
|
13.7 |
|
EPS Basic (1) |
|
$ |
0.71 |
|
|
$ |
0.06 |
|
|
$ |
(0.29 |
) |
|
|
$ |
0.04 |
|
|
$ |
0.27 |
|
|
$ |
(0.26 |
) |
|
$ |
0.96 |
|
|
|
$ |
0.73 |
|
EPS Diluted (1) |
|
|
0.69 |
|
|
|
0.06 |
|
|
|
(0.29 |
) |
|
|
|
0.04 |
|
|
|
0.26 |
|
|
|
(0.26 |
) |
|
|
0.71 |
|
|
|
|
0.73 |
|
|
|
|
(1) |
|
Net income (loss) per share for each quarter has been computed based on the
weighted average number of shares issued and outstanding during the respective quarter;
therefore, quarterly amounts may not add to the annual total. Per share calculations
are based on full dollar and share amounts. |
8
NORTH
AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
A number of factors contribute to variations in our quarterly results between periods,
including weather, capital spending by our customers on large oil sands projects, our ability to
manage our project-related business so as to avoid or minimize periods of relative inactivity and
the strength of the Western Canadian economy.
By way of example, we generally experience a decline in revenues during the first quarter of
each fiscal year (the spring breakup) due to seasonal weather conditions that make many roads
unsuitable for the operation of heavy equipment. Conversely, we tend to experience our highest
revenues in the latter half of our fiscal year as climatic conditions become favourable to our
operating requirements. As a result, full-year results are not likely to be a direct multiple of
any particular quarter or combination of quarters.
In addition to revenue variability, gross margins can be negatively impacted in less active
periods because we are likely to incur higher maintenance and repair costs due to our equipment
being available for service. We incurred higher equipment costs in the first quarter of fiscal
2008 due to the increased equipment repairs and tire costs. Profitability also varies from period
to period due to claims and change orders. Claims and change orders are a normal aspect of the
contracting business but can cause variability in profit margin due to the unmatched recognition of
costs and revenues. For further explanation see Claims and Unapproved Change Orders. During the
first quarter of fiscal 2007, a $6.1 million dollar claim was recognized causing gross margins to
increase above normal levels. The additional costs relating to the claim were incurred in fiscal
2005. During the fourth quarter of fiscal 2007 and the first half of fiscal 2008 we recognized
additional costs related to fixed-price contracts in the Pipeline segment and as a result, we are
currently working with our clients through the claims process.
During the higher activity periods we have experienced improvements in operating income due to
operating leverage. General and administrative costs are generally fixed and we see these costs
decrease as a percent of revenue. Net income and EPS are also subject to operating leverage as
provided by fixed interest expense, however we have experienced earnings variability in all periods
due to the recognition of realized and unrealized non-cash gains and losses on derivative financial
instruments and foreign exchange primarily driven by changes in the Canadian and US dollar exchange
rates discussed previously.
Consolidated Financial Position
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
December 31, 2007 |
|
|
March 31, 2007 |
|
|
% Change |
|
Current assets |
|
$ |
223,832 |
|
|
$ |
229,061 |
|
|
|
-2.3 |
% |
Current liabilities |
|
|
161,330 |
|
|
|
151,458 |
|
|
|
6.5 |
% |
Net working capital |
|
|
62,502 |
|
|
|
77,603 |
|
|
|
-19.5 |
% |
Plant and equipment |
|
|
284,762 |
|
|
|
255,963 |
|
|
|
11.3 |
% |
Total assets |
|
|
741,156 |
|
|
|
710,736 |
|
|
|
4.3 |
% |
Capital Lease obligations (including current portion) |
|
|
11,754 |
|
|
|
9,709 |
|
|
|
21.1 |
% |
Total long-term financial liabilities (1) |
|
|
295,062 |
|
|
|
295,288 |
|
|
|
-0.1 |
% |
|
|
|
(1) |
|
Total long-term financial liabilities exclude the current portions of capital lease
obligations, current portions of derivative financial instruments and both current and
non-current future income taxes balances. |
At December 31, 2007, we had net working capital (current assets less current liabilities) of
$62.5 million compared to $77.6 million at March 31, 2007. The $15.1 million decrease in net
working capital resulted largely from decreases in both unbilled revenue and the current portion of
the future income tax asset. The additional detective controls implemented in the third quarter
have improved the accounting for payments to suppliers. This has resulted in accounts payable
returning to normalized levels. Management also undertook a complete review of the procurement to
pay process and is developing preventative control procedures that will start to be implemented in
the fourth quarter. The current detective controls, that include tasks such as reconciliations of
key vendor statements, will remain in place until the new processes are implemented.
Plant and equipment, net of depreciation, increased by $28.8 million in the nine months ended
December 31, 2007 primarily due to the purchase of additional haul trucks and piling rigs in the
second quarter, partially offset by depreciation and the disposal of surplus equipment in the first
quarter.
Capital lease obligations, including the current portion, increased by $2.0 million in the
nine months ended December 31, 2007 due to the acquisition of additional support vehicles.
9
NORTH
AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
Liquidity and Capital Resources
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended Dec 31, |
|
|
Nine Months Ended Dec 31, |
|
(in thousands) |
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Cash provided by (used in) operating activities |
|
$ |
32,837 |
|
|
$ |
(24,021 |
) |
|
$ |
61,417 |
|
|
$ |
(5,262 |
) |
Cash (used in) investing activities |
|
|
(26,877 |
) |
|
|
(68,916 |
) |
|
|
(45,886 |
) |
|
|
(89,149 |
) |
Cash provided by (used in) financing activities |
|
|
19,952 |
|
|
|
63,217 |
|
|
|
(2,183 |
) |
|
|
58,714 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
$ |
25,912 |
|
|
$ |
(29,720 |
) |
|
$ |
13,348 |
|
|
$ |
(35,697 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
Cash provided by operating activities was $32.8 million in the third quarter and $61.4 million
in the nine months versus cash used in operating activities of $24.0 million and $5.3 million,
respectively, in the comparable periods last year. The cash generated in the third quarter period
reflects a combination of higher net income and a lower net increase in non-cash working capital of
$1.3 million, compared to $37.8 million in the same period last year. The cash generated in the
nine months reflects a net decrease in non-cash working capital of $3.5 million compared to a net
increase in non-cash working capital of $52.5 million in the same respective periods last year.
Investing activities
Sustaining capital expenditures are those that are required to keep our existing fleet of
equipment at its optimal useful life through capital maintenance or replacement. Growth capital
expenditures relate to incremental additions to our fleet of equipment.
Total capital expenditures in the third quarter were $8.0 million, including $3.9 million in
sustaining and $4.1 million in growth, compared to total capital expenditures of $78.4 million last
year, including $0.9 million in sustaining and $77.5 million in growth. This brings total capital
expenditures for the nine months to $51.6 million, including $19.8 million in sustaining and $31.7
million in growth, compared to $97.7 million last year, including $5.9 million in sustaining and
$91.8 million in growth. The significantly higher capital expenditure in the prior year is due to
the buy out of $44.6 million of certain leased equipment using part of the IPO proceeds. In
addition, approximately $30 million of equipment was acquired through operating leases in the third
quarter of the current year. Offsetting capital expenditures in the nine months of the current
year were proceeds of $14.2 million from the disposal of plant and equipment and assets held for
sale, the majority of which was disposed of in the first quarter.
Financing activities
Financing activities in the third quarter resulted in a cash inflow of $20.0 million,
primarily reflecting borrowings under our revolving credit facility.
Liquidity Requirements
Our primary uses of cash are for plant and equipment purchases, to fulfill debt repayment and
interest payment obligations, to fund operating lease obligations and to finance working capital
requirements.
Our long-term debt includes US$200 million of 83/4% senior notes due in 2011. The foreign
currency risk relating to both the principal and interest portions of these senior notes has been
managed with a cross-currency swap and interest rate swaps, which went into effect concurrent with
the issuance of the notes on November 26, 2003. The swap agreement is an economic hedge but has
not been designated as a hedge for accounting purposes. Interest totaling $13.0 million on the 83/4%
senior notes and the swap is payable semi-annually in June and December of each year until the
notes mature on December 1, 2011. The US$200 million principal amount was hedged at
C$1.315=US$1.000, resulting in a principal repayment of $263 million due on December 1, 2011.
There are no principal repayments required on the 83/4% senior notes until maturity.
10
NORTH
AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
One of our major contracts allows the customer to require that we provide up to $50 million in
letters of credit. As at December 31, 2007, we had $20 million in letters of credit outstanding in
connection with this contract. Any change in the amount of the letters of credit required by this
customer must be requested by November 1st for an issue date of January 1st,
each year for the remaining life of the contract.
We maintain a significant equipment and vehicle fleet comprised of units with remaining useful
lives covering a variety of time spans. It is important to adequately maintain our large
revenue-producing fleet in order to avoid equipment downtime which can impact our revenue stream
and inhibit our ability to satisfactorily perform on our projects. Once units reach the end of
their useful lives, they are replaced as it becomes cost prohibitive to continue to maintain them.
As a result, we are continually acquiring new equipment to replace retired units and to support our
growth as we take on new projects. In order to maintain a balance of owned and leased equipment,
we have financed a portion of our heavy construction fleet through operating leases. In addition,
we continue to lease our motor vehicle fleet through our capital lease facilities.
We require between $30 million and $40 million of sustaining capital expenditures and our
total capital requirements will typically range from $150 million to $175 million depending on our
growth capital requirements. We typically finance approximately 30% to 50% of our total capital
requirements through our operating lease facilities, 5% to 10% through capital lease facilities and
the remainder out of cash flow from operations. We believe our operating and capital lease
facilities and cash flow from operations will be sufficient to meet these requirements.*
Sources of Liquidity
Our principal sources of cash are funds from operations and borrowings under our revolving
credit facility. Our revolving credit facility provides for borrowings up to the lesser of a restricted covenant
resulting in a current ratio of 1.25 times and $125 million under revolving loans and letters of credit. As of December 31, 2007, we had approximately $33 million
of available borrowings under the revolving credit facility after
taking into account the impact of the restricted covenant, the $20
million drawn on the facility and the $20 million of outstanding and undrawn letters of credit to
support performance guarantees associated with a single customer contract as discussed above. The
indebtedness under the revolving credit facility is secured by a first priority lien on
substantially all of our existing and after-acquired property.
Our revolving credit facility contains covenants that restrict our activities, including but
not limited to, incurring additional debt, transferring or selling assets and making investments
including acquisitions. Under the revolving credit facility, Consolidated Capital Expenditures
during any applicable period cannot exceed 120% of the amount in the capital expenditure plan for
such period which is approved from time to time by the Board of Directors of the borrower. In
addition, we are required to and did satisfy certain financial covenants, including a minimum
interest coverage ratio and a maximum senior leverage ratio, both of which are calculated using
Consolidated EBITDA, as well as a minimum current ratio.
Consolidated EBITDA is defined in the credit facility as the sum, without duplication, of (1)
consolidated net income, (2) consolidated interest expense, (3) provision for taxes based on
income, (4) total depreciation expense, (5) total amortization expense, (6) costs and expenses
incurred by us in entering into the credit facility, (7) accrual of stock-based compensation
expense to the extent not paid in cash or if satisfied by the issue of new equity, (8) the non-cash
currency translation losses or mark-to-market losses on any hedge agreement or any embedded
derivative and (9) other non-cash items (other than any such non-cash item to the extent it
represents an accrual of or reserve for cash expenditure in any future period), but only, in the
case of clauses (2)-(9), to the extent deducted in the calculation of consolidated net income, less
other non-cash currency translation gains or mark-to-market gains on any hedge agreement or any
embedded derivative to the extent added in the calculation of consolidated net income items added
in the calculation of consolidated net income (other than any such non-cash item to the extent it
will result in the receipt of cash payments in any future period), all of the foregoing as
determined on a consolidated basis for us in conformity with Canadian GAAP.
Interest coverage is determined based on a ratio of Consolidated EBITDA to consolidated
interest expense on debt, and the senior leverage is determined as a ratio of senior debt to
Consolidated EBITDA. Measured as of the last day of each fiscal quarter on a trailing four-quarter
basis, Consolidated EBITDA may not be less than 2.5 times consolidated cash interest expense. Also,
measured as of the last day of each fiscal quarter on a trailing four quarter basis, senior
leverage may not exceed two times Consolidated EBITDA. These permitted ratios change over time
during the term of the revolving credit facility. We believe Consolidated EBITDA as defined in the
credit facility is an important measure of our liquidity.
Backlog
Backlog is a measure of the amount of secured work we have outstanding and as such is an
indicator of future revenue potential. Backlog is not a GAAP measure. As a result, the definition
and determination of a backlog will vary among different organizations ascribing a value to
backlog. Although backlog reflects business that we consider to be firm, cancellations or
reductions may occur and may reduce backlog and future income.
|
|
|
* |
|
This paragraph contains forward-looking information.
Please refer to Forward-Looking Information, Risks and Uncertainties for a
discussion of the risks and uncertainties related to such information. |
11
NORTH
AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
We define backlog as that work that has a high certainty of being performed as evidenced by
the existence of a signed contract or work order specifying job scope, value and timing. We have
also set a policy that our definition of backlog will be limited to contracts or work orders with
values exceeding $500,000 and work that will be performed in the next five years, even if the
related contracts extend beyond five years.
We work with our customers using cost-plus, time-and-materials, unit-price and lump-sum
contracts and the mix of contract types varies year-by-year. For the nine months, our revenue
consisted of 50.9% time-and-materials, 40.4% unit-price and 8.7% lump-sum. Our definition of
backlog results in the exclusion of cost-plus and time-and-material contracts performed under
master service agreements where scope is not clearly defined. While contracts exist for a range of
services to be provided, the work scope and value are not clearly defined under those contracts.
For the 12 month period ended December 31, 2007, the total amount of revenue earned under the
master services agreements that did not qualify for inclusion in our calculation of backlog was
$169 million.
Our estimated backlog as at December 31, 2007 and 2006 was (in millions):
|
|
|
|
|
|
|
|
|
By Segment |
|
December 31, 2007 |
|
|
|
|
2007 |
|
|
2006 |
|
Heavy Construction & Mining |
|
$ |
760.0 |
|
|
$ |
677.3 |
|
Piling |
|
|
19.6 |
|
|
|
13.1 |
|
Pipeline |
|
|
88.9 |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
868.5 |
|
|
$ |
690.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By Contract Type |
|
December 31, 2007 |
|
|
|
|
2007 |
|
|
2006 |
|
Unit-Price |
|
$ |
681.8 |
|
|
$ |
619.3 |
|
Lump-Sum |
|
|
7.3 |
|
|
|
39.8 |
|
Time-and-Material, Cost-Plus |
|
|
179.4 |
|
|
|
31.3 |
|
|
|
|
|
|
|
|
Total |
|
$ |
868.5 |
|
|
$ |
690.4 |
|
|
|
|
|
|
|
|
A contract with a single customer represented approximately $579.9 of the December 31, 2007
backlog. It is expected that approximately $337.1 million of the total backlog will be performed
and realized in the 12 months ending December 31, 2008. *
Claims and Unapproved Change Orders
Due to the complexity of the projects we undertake, changes often occur after work has
commenced. These changes include but are not limited to:
|
|
|
Client requirements, specifications and design; |
|
|
|
|
Materials and work schedules; and |
|
|
|
|
Changes in ground and weather conditions. |
Contract change management processes require that we prepare and submit change orders to the
client requesting approval of scope and/or price adjustments to the contract. Accounting
guidelines require that management consider changes in cost estimates that have occurred up to the
release of the financial statements and reflect the impact of these changes in the financial
statements. Conversely, potential revenue associated with increases in cost estimates is not
included in financial statements until an agreement is reached with the client or specific criteria
for the recognition of revenue from unapproved change orders and claims are met. This can and
often does, lead to costs being recognized in one period and revenue being recognized in subsequent
periods.
Occasionally, disagreements arise regarding changes, their nature, measurement, timing and
other characteristics that impact costs and revenue under the contract. If a change becomes a
point of dispute between our customer and us, we then consider it to be a claim. Historical claim
recoveries should not be considered indicative of future claim recoveries.
As a result of certain projects experiencing the changed conditions discussed above, at
December 31, 2007 we had recognized approximately $16.7 million in additional contract costs from
project inception to date, with no associated increase in contract value. We are working with our
customers to come to resolution on additional amounts, if any, to be paid to us in respect to these
additional costs.
Contractual Obligations and Other Commitments
|
|
|
* |
|
This paragraph contains forward-looking information.
Please refer to Forward-Looking Information, Risks and Uncertainties for a
discussion of the risks and uncertainties related to such information. |
12
NORTH AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
Our principal contractual obligations relate to our long-term debt and capital and operating
leases. The following table summarizes our future contractual obligations, excluding interest
payments, unless otherwise noted, as of December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by fiscal year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 and |
|
|
Total |
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
after |
(in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior notes (1) |
|
$ |
263.0 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
263.0 |
|
Capital leases (including interest) |
|
|
12.2 |
|
|
|
4.3 |
|
|
|
3.5 |
|
|
|
2.6 |
|
|
|
1.7 |
|
|
|
0.1 |
|
Operating leases |
|
|
76.5 |
|
|
|
18.5 |
|
|
|
24.0 |
|
|
|
18.7 |
|
|
|
9.3 |
|
|
|
6.0 |
|
Supplier contract (2) |
|
|
37.3 |
|
|
|
5.3 |
|
|
|
5.3 |
|
|
|
7.5 |
|
|
|
9.6 |
|
|
|
9.6 |
|
|
|
|
Total contractual obligations |
|
$ |
389.0 |
|
|
$ |
28.1 |
|
|
$ |
32.8 |
|
|
$ |
28.8 |
|
|
$ |
20.6 |
|
|
$ |
278.7 |
|
|
|
|
|
|
|
(1) |
|
As at December 31, 2007, the exchange rate was C$1.012=US$1.000,
resulting in a value of C$202.4 million upon conversion of the principle
balance of the US$200 million 83/4% senior notes. We have entered into
cross-currency and interest rate swaps, which represent an economic hedge
of the 83/4% senior notes. At maturity, we will be required to pay $263
million in order to retire these senior notes and the swaps. This amount
reflects the fixed exchange rate of C$1.315=US$1.00 established as of
November 26, 2003, the inception of the swap contracts. At December 31,
2007, the carrying value of the derivative financial instruments was $85.1
million, inclusive of the interest components. |
|
(2) |
|
This contract can be terminated by either party with 30 days notice. |
Off-Balance Sheet Arrangements
At December 31, 2007, in connection with a heavy equipment financing agreement, the Company
has guaranteed a $0.9 million debt owed to the equipment manufacturer by a third party finance
company. The Companys guarantee of this indebtedness will expire when the equipment is
commissioned, which is expected to be February 28, 2008. The Company has determined that the fair
value of this financial instrument at inception and December 31, 2007 was minimal. *
Outstanding Share Data
We are authorized to issue an unlimited number of voting common shares and an unlimited number
of non-voting common shares. As at February 7, 2008, 35,957,236 voting common shares and 1,962,364
options to acquire voting common shares were outstanding compared to
35,951,684 voting common shares and 1,967,916 options outstanding as at December 31, 2007.
Stock-Based Compensation
Some of our directors, officers, employees and service providers have been granted options to
purchase common shares under the Amended and Restated 2004 Share Option Plan. There were 315,100
options issued in the first nine month period ending December 31, 2007.
Related party transactions
The
Company may receive consulting and advisory services provided by companies
in which directors of the Corporation may have an interest of the Corporation with respect to the organization of the
companies, employee benefit and compensation arrangements, and other matters, and no
fee is charged for these consulting and advisory services.
In
order for the companies to provide such advice and consulting we provide
reports, financial data and other information. This permits them to consult with and
advise our management on matters relating to our operations, company affairs and
finances. In addition this permits them to visit and inspect any of our properties
and facilities. The transactions are in the normal course of operations and are
measured at the exchange amount of consideration established and agreed to by the
related parties.
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. |
|
|
|
|
|
* This paragraph contains forward-looking information.
Please refer to Forward-Looking Information, Risks and Uncertainties for a
discussion of the risks and uncertainties related to such information. |
13
NORTH AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
|
|
|
Step 2 We compare the implied fair value of each reporting units goodwill to its
carrying amount. If the carrying amount of a reporting units goodwill exceeds its fair
value, an impairment loss will be recognized in an amount equal to that excess. |
We completed Step 1 of this test during the quarter ended December 31, 2007 and were not
required to record an impairment loss on goodwill. We have conducted our annual assessment of
goodwill in October of last year and will continue to do so each year going forward.
Critical Accounting Estimates
Certain accounting policies require management to make significant estimates and assumptions
about future events that affect the amounts reported in our financial statements and the
accompanying notes. Therefore, the determination of estimates requires the exercise of
managements judgment. Actual results could differ from those estimates and any differences may be
material to our financial statements.
Revenue recognition
Our contracts with customers fall under the following contract types: cost-plus,
time-and-materials, unit-price and lump-sum. While contracts are generally less than one year in
duration, we do have several long-term contracts. The mix of contract types varies year-by-year.
For the nine months, our revenue consisted of 50.9% time-and-materials, 40.4% unit-price and 8.7%
lump-sum.
Profit for each type of contract is included in revenue when its realization is reasonably
assured. Estimated contract losses are recognized in full when determined. Claims and unapproved
change orders are included in total estimated contract revenue only to the extent that contract
costs related to the claim or unapproved change order have been incurred, when it is probable that
the claim or unapproved change order will result in a bona fide addition to contract value and the
amount of revenue can be reliably estimated.
The accuracy of our revenue and profit recognition in a given period is dependent, in part, on
the accuracy of our estimates of the cost to complete each unit-price and lump-sum project. Our
cost estimates use a detailed bottom up approach, using inputs such as labour and equipment
hours, detailed drawings and material lists. These estimates are updated monthly. We believe our
experience allows us to produce materially reliable estimates. However, our projects can be highly
complex and in almost every case, the profit margin estimates for a project will either increase or
decrease to some extent from the amount that was originally estimated at the time of the related
bid. Because we have many projects of varying levels of complexity and size in process at any
given time, these changes in estimates can offset each other without materially impacting our
profitability. However, sizable changes in cost estimates, particularly in larger, more complex
projects, can have a significant effect on profitability.
Factors that can contribute to changes in estimates of contract cost and profitability
include, without limitation:
|
|
|
site conditions that differ from those assumed in the original bid, to the extent that
contract remedies are unavailable; |
|
|
|
|
identification and evaluation of scope modifications during the execution of the project; |
|
|
|
|
the availability and cost of skilled workers in the geographic location of the project; |
|
|
|
|
the availability and proximity of materials; |
|
|
|
|
unfavorable weather conditions hindering productivity; |
|
|
|
|
equipment productivity and timing differences resulting from project construction not
starting on time; and |
|
|
|
|
general coordination of work inherent in all large projects we undertake. |
The foregoing factors, as well as the stage of completion of contracts in process and the mix
of contracts at different margins, may cause fluctuations in gross profit between periods and these
fluctuations may be significant. These changes in cost estimates and revenue recognition impact
all three operating segments, Heavy Construction & Mining, Piling and Pipeline.
Effective April 1, 2005, the Company changed its accounting policy regarding the recognition
of revenue on claims. This change in accounting policy has been applied retroactively. 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
14
NORTH AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
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.
Plant and equipment
The most significant estimates in accounting for plant and equipment are the expected useful
life of the asset and the expected residual value. Most of our property, plant and equipment have
long lives which can exceed 20 years with proper repair work and preventative maintenance. Useful
life is measured in operating hours, excluding idle hours and a depreciation rate is calculated for
each type of unit. Depreciation expense is determined monthly based on daily actual operating
hours.
Another key estimate is the expected cash flows from the use of an asset and the expected
disposal proceeds in applying Canadian Institute of Chartered Accountants Handbook Section 3063
Impairment of Long-Lived Assets and Section 3475 Disposal of Long-Lived Assets and Discontinued
Operations. These standards require the recognition of an impairment loss for a long-lived asset
when changes in circumstances cause its carrying value to exceed the total undiscounted cash flows
expected from its use. An impairment loss, if any, is determined as the excess of the carrying
value of the asset over its fair value.
Goodwill
Impairment is tested at the reporting unit level by comparing the reporting units carrying
amount to its fair value. The process of determining fair value is subjective and requires us to
exercise judgment in making assumptions about future results, including revenue and cash flow
projections at the reporting unit level and discount rates. The Company previously tested goodwill
annually on December 31. For the current fiscal year the Company completed the goodwill impairment
testing on October 1. This change in timing was made to reduce conflict between the impairment
testing and the companys financial reporting close process for the fiscal period ending December
31. It is the Companys intention to continue to complete subsequent goodwill impairment testing
on October 1 going forward. This change in accounting policy was applied on a retrospective basis and
has no impact on the consolidated financial statements.
Financial instruments
Our derivative financial instruments related to cross-currency and interest rate swaps are not
designated as hedges for accounting purposes and are recorded on the balance sheet at fair value,
which is determined based on values quoted by the counterparties to the agreements. The primary
factors affecting fair value are the changes in the interest rate term structures in the US and
Canada, the life of the swaps and the CAD/USD foreign exchange spot rate.
Effective April 1, 2007, we adopted the new standards issued by the CICA on financial
instruments, hedges and comprehensive income. Section 1530, Comprehensive income, Section 3855,
Financial instruments-recognition and measurement, Section 3861, Financial
instruments-disclosure and presentation and Section 3865, Hedges, were effective for our first
quarter of fiscal 2007. We were not required to restate prior results.
15
NORTH AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
On April 1, 2007, we made the following transitional adjustments to our consolidated balance
sheet to adopt the new standards (in thousands of dollars):
|
|
|
|
|
|
|
Increase |
|
|
|
(decrease) |
|
|
|
|
|
Deferred financing costs |
|
$ |
(11,356 |
) |
Intangible assets |
|
|
1,622 |
|
Long-term future income tax asset |
|
|
2,588 |
|
Senior notes |
|
|
(12,634 |
) |
Derivative financial instruments |
|
|
7,246 |
|
Long-term income tax liability |
|
|
18 |
|
Opening deficit |
|
|
1,776 |
|
The details of the transitional adjustments are noted below.
The impact of the new standards on our income before income taxes for the three and nine
months ended December 31, 2007 is as follows (in thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months Ended |
|
|
|
Ended Dec 31, 2007 |
|
|
Dec 31, 2007 |
|
Decrease in interest expense due to change in method of amortizing deferred
financing costs and discounts (premiums), net |
|
$ |
(360 |
) |
|
$ |
(897 |
) |
Increase in unrealized foreign exchange gain on senior notes |
|
|
28 |
|
|
|
334 |
|
Increase (decrease) in unrealized loss on derivative financial instruments |
|
|
(1,494 |
) |
|
|
13,518 |
|
|
|
|
|
|
|
|
Decrease (increase) in income before income taxes |
|
$ |
(1,826 |
) |
|
$ |
12,955 |
|
|
|
|
|
|
|
|
The new standards require all financial assets and liabilities to be carried at fair value in
our consolidated balance sheet, except for loans and receivables, held-to-maturity investments and other financial liabilities, which are
carried at their amortized cost. We do not currently have any financial assets designated as
available-for-sale. On adoption of the standard, we have classified our cash and cash equivalents,
certain accounts receivable and unbilled revenue as loans and receivables and revolving credit
facility, accounts payable, certain accrued liabilities, capital lease obligations and senior notes
as other financial liabilities.
All derivatives, including embedded derivates that must be separately accounted for, are
measured at fair value in our consolidated balance sheet. The types of hedging relationships that
qualify for hedge accounting have not changed under the new standards. We currently do not
designate any of these derivatives as hedging instruments for accounting purposes.
Derivatives may be embedded in financial instruments (the host instrument). Under the new
standards, embedded derivatives are treated as separate derivatives when their economic
characteristics and risks are not closely related to those of the host instrument, the terms of the
embedded derivative are similar to those of a stand-alone derivative and the combined contract is
not held-for-trading or designated at fair value. These embedded derivatives are measured at fair
value with subsequent changes recognized in income. We have elected April 1, 2003 as our
transition date for identifying contracts with embedded derivatives. Currently we have prepayment
options that are embedded in our senior notes and foreign exchange rate and price index
escalation/de-escalation clauses in a long-term construction contract which meet the criteria for
bifurcation. The impact of the prepayment options and escalation/de-escalation clauses on our
consolidated financial statements is described under the transitional adjustments below and in note
3(a) in our interim consolidated financial statements for the nine months ended December 31, 2007.
In determining the fair value of our financial instruments, we used a variety of valuation
methods and assumptions that are based on market conditions and risks existing on each reporting
date. Standard market conventions and techniques, such as discounted cash flow analysis and option
pricing models, are used to determine the fair value of our financial instruments, including
derivatives. All methods of fair value measurement result in a general approximation of value and
such value may never actually be realized.
16
NORTH AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
The transitional impact of adopting the new financial instruments standards as at April 1,
2007 on our consolidated financial statements is as follows:
We determined that the issuers early prepayment option included in the senior notes
should be bifurcated from the host contract, along with a contingent embedded derivative in
the senior notes that provides for accelerated redemption by the holders in certain
instances. These embedded derivatives were measured at fair value at the inception of the
senior notes and the residual amount of the proceeds was allocated to the debt. Changes in
fair value of the embedded derivatives are recognized in net income and the carrying amount
of the senior notes is accreted to the par value over the term of the notes using the
effective interest method and is recognized as interest expense. At transition on April 1,
2007, we recorded the fair value of $8.5 million related to these embedded derivatives and a
corresponding decrease in opening deficit of $7.3 million, net of future income taxes of $1.2
million. The impact of the bifurcation of these embedded derivatives at issuance of the
senior notes resulted in an increase in senior notes of $5.7 million and an increase in
opening deficit of $4.0 million, net of income taxes of $1.7 million after applying the
effective interest method to the premium resulting from the bifurcation of these embedded
derivatives on April 1, 2007.
We also have foreign exchange rate and price index escalation/de-escalation clauses in a
long-term construction contract that qualify as an embedded derivative. These amounts must
be separated for reporting in accordance with the new standards. As at April 1, 2007, we
separated the fair value of the embedded derivative liability of $7.2 million from the
long-term construction contract, resulting in a corresponding increase to opening deficit of
$5.2 million, net of future income taxes of $2.0 million.
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Effective interest method: |
We incurred underwriting commissions and expenses relating to our senior notes offering.
Previously, these costs were classified as deferred assets under deferred financing costs
and amortized on a straight-line basis over the term of the debt. The new standard requires
us to reclassify the costs as a reduction in the cost of debt and to use the effective
interest rate method to amortize the deferred amounts to interest expense. As at April 1,
2007, we reclassified $9.7 million of unamortized costs from deferred financing costs to
long-term debt and recorded an adjustment to the unamortized cost balance as if the effective
interest rate method had been used since inception. Transaction costs incurred in connection
with the Companys revolving credit facility of $1,622 were reclassified from deferred
financing costs to intangible assets on April 1, 2007 and these costs continue to be
amortized on a straight-line basis over the term of the facility.
Revised CICA Handbook Section 3861, Financial Instruments Disclosure and Presentation
replaces CICA Handbook Section 3860, Financial Instruments Disclosure and Presentation and
establishes standards for presentation of financial instruments and non-financial derivatives and
identifies information that should be disclosed. There was no material effect on our financial
statements upon adoption of CICA Handbook Section 3861 effective April 1, 2007.
CICA Handbook Section 1530, Comprehensive Income establishes standards for the reporting and
display of comprehensive income. The new section defines other comprehensive income to include
revenues, expenses and gains and losses that, in accordance with primary sources of GAAP, are
recognized in comprehensive income but excluded from net income. The standard does not address
issues of recognition or measurement for comprehensive income and its components. The adoption of
CICA Handbook Section 1530 effective April 1, 2007 did not have a material impact on our financial
statement presentation in the current period.
Forward Looking Information and Risks and Uncertainties
Forward-Looking Information
This document contains forward-looking information that is based on expectations and estimates
as of the date of this document. Our forward-looking information is information that is subject to
known and unknown risks and other factors that may cause future actions, conditions or events to
differ materially from the anticipated actions, conditions or events expressed or implied by such
forward-looking information. Forward-looking information is information that does not relate
strictly to historical or current facts, and can be identified by the use of the future tense or
other forward-looking words such as believe, expect,
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NORTH AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
anticipate, intend,
plan, estimate, should, may, objective, projection, forecast, continue,
strategy, position or the negative of those terms or other variations of them or comparable
terminology.
Examples of such forward looking information in this document include but are not limited to
the following, each of which is subject to significant risks and uncertainties and is based on a
number of assumptions which may prove to be incorrect:
(A) information related to our operating performance and our level of activity in our
operating segments, including (1) the demand for services from Suncor under a five-year
multiple-use contract, and (2) the demand for piling and construction services related to the
capital spending plan announced by the Province of Alberta; this is subject to the risk and
uncertainty that anticipated major projects in the oil sands may not materialize due to changes in
the long-term view of oil prices, there may be insufficient pipeline upgrading and refining
capacity, there may be insufficient governmental infrastructure to support the growth in the oil
sands region and there may be cost overruns by our customers on their projects, which may cause our customers to
terminate future projects and is based on the assumption that long-term views of the economic
viability of oil sands projects will not significantly change;
(B) the anticipated higher costs for larger-sized truck tires; this is subject to the risk and
uncertainty that there may be a significant change in the global demand and/or supply of truck tires of
the size and specification that we require and is based on the assumption that the current
supply/demand imbalance for truck tires of the size and specification that we require continues for
several years;
(C) our anticipated sustaining capital expenditures and the expected manner of financing such
expenditures; this is subject to the risk and uncertainty that we may not be able to generate
sufficient cash flow to meet our debt service and capital requirements and we may not be able to
secure financing under operating and capital lease facilities and is based on the assumption that
operating cash flow will not be impacted from changes in economic conditions, increased
competition, reduced work or other events that would increase the need for additional sources of
liquidity;
(D) the
expected amount of our backlog to be performed and realized in the 12 months ending
December 31, 2008 (such estimate assists us in planning our activity level and may not be
suitable for other purposes); this is subject to the risk and uncertainty of a significant change
to the long-term views of the economic viability of oil sands projects, loss of a major customer,
unanticipated shut-downs of our customers operating facilities resulting in cessation or
cancellation of the projects, a shortage of qualified personnel and our inability to obtain
equipment and is based on the assumption that the Company will be
able to obtain the qualified
personnel and obtain the equipment required to execute the work in accordance with the contract and
there are no unplanned shutdowns or cancellations of current contracts and
(E) the expected commissioning date of February 28, 2008 for a piece of heavy equipment and
the corresponding expiry of a guarantee of a third partys obligations in the amount of $0.9
million; this is subject to the risk and uncertainty that the
equipment may not be assembled and in
working order due to harsh weather conditions and/or labour availability .
While we anticipate that subsequent events and developments may cause our views to change, we
do not have an intention to update this forward looking information, except as required by
applicable securities laws. This forward-looking information represents our views as of the date of
this document and such information should not be relied upon as representing our views as of any
date subsequent to the date of this document. We have attempted to identify important factors that
could cause actual results, performance or achievements to vary from those current expectations or
estimates expressed or implied by the forward-looking information. However, there may be other
factors that cause results, performance or achievements not to be as expected or estimated and that
could cause actual results, performance or achievements to differ materially from current
expectations. There can be no assurance that forward-looking information will prove to be
accurate, as actual results and future events could differ materially from those expected or
estimated in such statements. Accordingly, readers should not place undue reliance on
forward-looking information. These factors are not intended to represent a complete list of the
factors that could affect us. See Risks and Uncertainties below and risk factors highlighted in
materials filed with the securities regulatory authorities filed in the United States and Canada
from time to time, including but not limited to our most recent annual information form filed on
Form 20-F.
Risks and Uncertainties
For the nine month period ended December 31, 2007, there has been no significant change in our
risk factors from those described in our Prospectus dated July 31, 2007 and Managements Discussion
and Analysis for the year ended March 31, 2007 other than those noted below. In addition, there
have been no changes in our internal control over financial reporting that have materially affected
or are reasonably likely to affect, our internal control over financial reporting.
As discussed in the Prospectus dated July 31, 2007 and our Managements Discussion and
Analysis for the year ended March 31, 2007, we have identified a number of significant weaknesses
(as defined under Canadian auditing standards) in our financial reporting process and internal
controls. Certain detective controls were implemented in the procurement process during the third
quarter to mitigate the weaknesses identified previously. These processes included reconciliations
of vendor statements and investigation of subsequent payments to ensure that liabilities were
recorded in the correct period. Management also undertook a complete review of the procurement
processes and is developing new procedures and preventative controls. These controls will start to
be implemented
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NORTH AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
over the next two quarters. Current detective controls will remain in place until the new
processes are implemented and stabilized. Management continues to address the IT and general
control weaknesses. Specific actions to address weaknesses include changes to the security
structure which is expected to be implemented by the middle of the fourth quarter.
In addition, during the quarter ended June 30, 2007, we were required to implement new
Canadian accounting standards regarding financial instruments. In order to record the related
transactions, very complex and non-routine accounting and valuation procedures were undertaken. On
review, we determined that we did not apply certain of these procedures correctly. This,
therefore, represents a weakness in internal control as it had the potential to result in a
material misstatement of the financial statements. This weakness will be addressed in the future
by engaging third-party experts; however, there can be no assurance that we will be able to
generate accurate financial reports in a timely manner. Failure to do so would cause us to breach
the reporting requirements of Canadian and U.S. securities regulations in the future as well as the
covenants applicable to our indebtedness. This could, in turn, have a material adverse effect on
our business and financial condition. Until we establish and maintain effective internal controls
and procedures for financial reporting, we may not have appropriate measures in place to eliminate
financial statement inaccuracies and avoid delays in financial reporting.
Recently Adopted Canadian Accounting Pronouncements
Financial instruments
In January 2005, the CICA issued Handbook Section 3855, Financial Instruments Recognition
and Measurement, Handbook Section 3861, Financial Instruments Disclosure and Presentation
(CICA 3861), Handbook Section 1530, Comprehensive Income and Handbook Section 3865, Hedges.
The new standards are effective for interim and annual financial statements for fiscal years
beginning on or after October 1, 2006, specifically April 1, 2007 for us. The impact of the
adoption of the new standard for the Company is discussed above under the heading Financial
Instruments.
Equity
On April 1, 2007, we adopted CICA Handbook Section 3251, Equity, which establishes standards
for the presentation of equity and changes in equity during the reporting period. The requirements
in this section are in addition to those of CICA Handbook Section 1530 and recommend that an
enterprise should present separately the following components of equity: retained earnings,
accumulated other comprehensive income and the total for retained earnings and accumulated other
comprehensive income, contributed surplus, share capital and reserves. The standard did not have a
material impact of our consolidated financial statements in
the current period.
Accounting changes
In July 2006, the CICA revised Handbook Section 1506, Accounting Changes, which requires
that: (1) voluntary changes in accounting policy are made only if they result in the financial
statements providing reliable and more relevant information; (2) changes in accounting policy are
generally applied retrospectively; and (3) prior period errors are corrected retrospectively. This
revised standard is effective for fiscal years beginning on or after January 1, 2007, specifically
April 1, 2007 for us and did not have a material impact on our consolidated financial statements.
Accounting policy choice for transaction costs
In June 2007, the CICA issued Emerging Issues Committee Abstract No. 166, Accounting Policy
Choice For Transaction Costs (EIC-166). CICA Handbook Section 3855 requires that when an entity
acquires a financial asset or incurs a financial liability classified other than as
held-for-trading, it adopts an accounting policy for transaction costs of either: (a) recognizing
all transaction costs in net income; or (b) adding transaction costs that are directly attributable
to the acquisition or issue of a financial asset or financial liability to the carrying amount of
the financial instrument. EIC-166 clarifies that the same accounting policy choice should be made
for all similar instruments classified as other than held-for-trading but that a different
accounting policy choice may be made for financial instruments that are not similar. We adopted
this guidance on April 1, 2007, which did not have a material impact on our consolidated financial
statements.
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NORTH AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
Recent Canadian accounting pronouncements not yet adopted
Financial Instruments
In March 2007, the CICA issued Handbook Section 3862, Financial Instruments Disclosures,
which replaces CICA 3861 and provides expanded disclosure requirements that provide additional
detail by financial assets and liability categories. This standard harmonizes disclosures with
International Financial Reporting Standards. The standard applies to interim and annual financial
statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1,
2008 for us. We are currently evaluating the impact of this standard.
In March 2007, the CICA issued Handbook Section 3863, Financial Instruments Presentation,
which replaces CICA 3861 to enhance financial statement users understanding of the significance of
financial instruments to an entitys financial position, performance and cash flows. This Section
establishes standards for presentation of financial instruments and non-financial derivatives. It
deals with the classification of financial instruments, from the perspective of the issuer, between
liabilities and equity, the classification of related interest, dividends, gains and losses and the
circumstances in which financial assets and financial liabilities are offset. This standard
harmonizes disclosures with International Financial Reporting Standards and applies to interim and
annual financial statements relating to fiscal years beginning on or after October 1, 2007,
specifically April 1, 2008 for us. We are currently evaluating the impact of this standard.
Capital disclosures
In December 2006, the CICA issued Handbook Section 1535, Capital Disclosures. This standard
requires that an entity disclose information that enables users of its financial statements to
evaluate an entitys objectives, policies and processes for managing capital, including disclosures
of any externally imposed capital requirements and the consequences of non-compliance. The new
standard applies to interim and annual financial statements relating to fiscal years beginning on
or after October 1, 2007, specifically April 1, 2008 for us. We are currently evaluating the
impact of this standard.
Inventories
In June 2007, the CICA issued Handbook Section 3031, Inventories to harmonize accounting for
inventories under Canadian GAAP with International Financial Reporting Standards. This standard
requires the measurement of inventories at the lower of cost and net realizable value and includes
guidance on the determination of cost, including allocation of overheads and other costs to
inventory. The standard also requires the consistent use of either first-in, first-out (FIFO) or
weighted average cost formula to measure the cost of other inventories and requires the reversal of
previous write-downs to net realizable value when there is a subsequent increase in the value of
inventories. The new standard applies to interim and annual financial statements relating to
fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 for us. We are
currently evaluating the impact of this standard.
Going concern
In April 2007, the CICA approved amendments to Handbook Section 1400, General Standards Of
Financial Statement Presentation. These amendments require management to assess an entitys
ability to continue as a going concern. When management is aware of material uncertainties related
to events or conditions that may cast doubt on an entitys ability to continue as a going concern,
those uncertainties must be disclosed. In assessing the appropriateness of the going concern
assumption, the standard requires management to consider all available information about the
future, which is at least but not limited to, twelve months from the balance sheet date. The new
requirements of the standard are applicable for interim and annual financial statements relating to
fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 for us. We are
currently evaluating the impact of this standard.
Goodwill and intangible assets
In February 2008, the CICA issued Handbook Section 3064, (CICA 3064) Goodwill and Intangible
Assets. CICA 3064, which replaces Section 3062, Goodwill and Intangible Assets, and Section 3450,
Research and Development Costs, establishes standards for the recognition, measurement and
disclosure of goodwill and intangible assets. The provisions relating to the definition and initial
recognition of intangible assets, including internally generated intangible assets, are equivalent
to the corresponding provisions of International Financial Reporting Standard IAS 38, Intangible
Assets. This new standard is effective for our interim and annual consolidated financial statements commencing April 1, 2009. We are currently evaluating the impact
of this standard.
20
NORTH AMERICAN ENERGY PARTNERS INC.
Managements Discussion and Analysis
For the three and nine months ended December 31, 2007
U.S. Generally Accepted Accounting Principles
Our consolidated financial statements have been prepared in accordance with Canadian GAAP,
which differs in certain material respects from U.S. GAAP. The nature and effect of these
differences are set out in note 27 to our consolidated financial statements for the year ended
March 31, 2007.
Quantitative and Qualitative Disclosures Regarding Market Risk
Foreign currency risk
We are subject to currency exchange risk as our 83/4% senior notes are denominated in U.S.
dollars and all of our revenues and most of our expenses are denominated in Canadian dollars. To
manage the foreign currency risk and potential cash flow impact on our $200 million in U.S.
dollar-denominated notes, we have entered into currency swap and interest rate swap agreements.
These financial instruments consist of three components: a U.S. dollar interest rate swap; a U.S.
dollar-Canadian dollar cross-currency basis swap; and a Canadian dollar interest rate swap. The
cross currency and interest rate swap agreements can be cancelled at the counterpartys option at
any time after December 1, 2007 if the counterparty pays a cancellation premium. The premium is
equal to 4.375% of the US$200 million if exercised between December 1, 2007 and December 1, 2008; 2.1875% if
exercised between December 1, 2008 and December 1, 2009; and repurchased at par if cancelled after
December 1, 2009.
Interest rate risk
We are exposed to interest rate risk on the revolving credit facility, capital lease
obligations and certain operating leases with a variable payment that is tied to prime rates. We
do not use derivative financial instruments to reduce our exposure to these risks. The estimated
financial impact as a result of fluctuations in interest rates is not significant.
Inflation
Inflation can have a material impact on our operations due to increasing parts, equipment
replacement and labour costs; however, many of our contracts contain provisions for annual price
increases. Inflation can have a material impact on our operations if the rate of inflation and
cost increases remains above levels that we are able to pass to our customers.
Additional Information
Additional information relating to us, including our 2007 Annual Information Form on Form
20-F, as amended, can be found on the Canadian Securities Administrators System for Electronic
Document Analysis and Retrieval (SEDAR) database at www.sedar.com and the website of the Securities
and Exchange Commission at www.sec.gov.
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