e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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þ |
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2007
or
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o |
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 1-33615
Concho Resources Inc.
(Exact name of registrant as specified in its charter)
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|
Delaware
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|
76-0818600 |
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|
(State or other jurisdiction
of incorporation or organization)
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|
(I.R.S. Employer
Identification No.) |
|
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550 West Texas Avenue, Suite 1300
Midland, Texas
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79701 |
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|
(Address of principal executive offices)
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(Zip code) |
(432) 683-7443
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes o No þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Large accelerated filer o Accelerated filer o Non-accelerated filer þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
Number of
shares of the registrants common stock outstanding at
September 7, 2007: 75,750,520
shares.
PART I Financial Information
ITEM 1. Financial Statements
Concho Resources Inc. and subsidiaries
Consolidated balance sheets
Unaudited
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
(in thousands, except share and per share data) |
|
2007 |
|
2006 |
|
Assets |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
10,387 |
|
|
$ |
1,122 |
|
Accounts receivable: |
|
|
|
|
|
|
|
|
Oil and gas |
|
|
28,976 |
|
|
|
27,304 |
|
Joint operations and other |
|
|
10,880 |
|
|
|
22,638 |
|
Related parties |
|
|
|
|
|
|
1,449 |
|
Derivative instruments |
|
|
81 |
|
|
|
6,013 |
|
Deferred income taxes |
|
|
82 |
|
|
|
82 |
|
Inventory |
|
|
1,314 |
|
|
|
1,309 |
|
Prepaid insurance and other |
|
|
4,857 |
|
|
|
3,848 |
|
|
|
|
Total current assets |
|
|
56,577 |
|
|
|
63,765 |
|
|
|
|
Property and equipment, at cost: |
|
|
|
|
|
|
|
|
Oil and gas properties, successful efforts method: |
|
|
|
|
|
|
|
|
Proved properties |
|
|
1,219,270 |
|
|
|
1,159,756 |
|
Unproved properties |
|
|
235,365 |
|
|
|
239,462 |
|
Accumulated depletion and depreciation |
|
|
(123,855 |
) |
|
|
(84,098 |
) |
|
|
|
Total oil and gas properties, net |
|
|
1,330,780 |
|
|
|
1,315,120 |
|
Other property and equipment, net |
|
|
6,136 |
|
|
|
5,535 |
|
|
|
|
Total property and equipment, net |
|
|
1,336,916 |
|
|
|
1,320,655 |
|
|
|
|
Deferred loan costs, net |
|
|
5,100 |
|
|
|
4,417 |
|
Other assets |
|
|
335 |
|
|
|
1,235 |
|
|
|
|
Total assets |
|
$ |
1,398,928 |
|
|
$ |
1,390,072 |
|
|
|
|
Liabilities and stockholders equity |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable: |
|
|
|
|
|
|
|
|
Trade |
|
$ |
3,355 |
|
|
$ |
16,157 |
|
Related parties |
|
|
1,493 |
|
|
|
3,593 |
|
Other current liabilities: |
|
|
|
|
|
|
|
|
Revenue payable |
|
|
9,497 |
|
|
|
9,901 |
|
Accrued drilling costs |
|
|
9,251 |
|
|
|
17,051 |
|
Accrued interest |
|
|
8,833 |
|
|
|
8,004 |
|
Other accrued liabilities |
|
|
5,673 |
|
|
|
6,220 |
|
Derivative instruments |
|
|
5,692 |
|
|
|
6,224 |
|
Dividends payable |
|
|
|
|
|
|
87 |
|
Chase Group unaccredited investors asset purchase obligation |
|
|
|
|
|
|
906 |
|
Current portion of long-term debt |
|
|
2,500 |
|
|
|
400 |
|
Current asset retirement obligations |
|
|
1,545 |
|
|
|
1,958 |
|
|
|
|
Total current liabilities |
|
|
47,839 |
|
|
|
70,501 |
|
|
|
|
Long-term debt |
|
|
501,540 |
|
|
|
495,100 |
|
Noncurrent derivative instruments |
|
|
2,709 |
|
|
|
|
|
Deferred income taxes |
|
|
245,863 |
|
|
|
241,752 |
|
Asset retirement obligations and other long-term liabilities |
|
|
7,072 |
|
|
|
7,563 |
|
Commitments and contingencies (Note K)
|
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Series A
preferred stock, $0.01 par value; 30,000,000 shares authorized; and zero shares issued and
outstanding at June 30, 2007 and December 31, 2006 |
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value; 10,000,000 shares authorized; and zero shares issued and
outstanding at June 30 ,2007 and December 31, 2006 |
|
|
|
|
|
|
|
|
Common stock, $0.001 par value; 300,000,000 authorized; 59,167,060 and 59,092,830
shares issued and outstanding at June 30, 2007 and December 31, 2006, respectively. |
|
|
59 |
|
|
|
59 |
|
Additional paid-in capital |
|
|
577,993 |
|
|
|
575,389 |
|
Notes receivable from officers and employees |
|
|
(2,616 |
) |
|
|
(12,858 |
) |
Retained earnings |
|
|
22,655 |
|
|
|
12,152 |
|
Accumulated other comprehensive income (loss) |
|
|
(4,186 |
) |
|
|
414 |
|
|
|
|
Total stockholders equity |
|
|
593,905 |
|
|
|
575,156 |
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
1,398,928 |
|
|
$ |
1,390,072 |
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
1
Concho Resources Inc. and subsidiaries
Consolidated statements of operations
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
(in thousands, except per share amounts) |
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
Operating revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
43,096 |
|
|
$ |
34,094 |
|
|
$ |
82,467 |
|
|
$ |
50,498 |
|
Natural gas sales |
|
|
23,007 |
|
|
|
17,624 |
|
|
|
43,982 |
|
|
|
26,872 |
|
|
|
|
Total operating revenues |
|
|
66,103 |
|
|
|
51,718 |
|
|
|
126,449 |
|
|
|
77,370 |
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production |
|
|
6,950 |
|
|
|
5,058 |
|
|
|
14,209 |
|
|
|
8,987 |
|
Oil and gas production taxes |
|
|
5,256 |
|
|
|
4,229 |
|
|
|
9,943 |
|
|
|
6,210 |
|
Exploration and abandonments |
|
|
5,864 |
|
|
|
495 |
|
|
|
6,305 |
|
|
|
1,401 |
|
Depreciation and depletion |
|
|
17,609 |
|
|
|
15,257 |
|
|
|
37,033 |
|
|
|
22,496 |
|
Accretion of discount on asset retirement obligations |
|
|
115 |
|
|
|
88 |
|
|
|
228 |
|
|
|
109 |
|
Impairments of proved oil and gas properties |
|
|
2,085 |
|
|
|
2,978 |
|
|
|
3,198 |
|
|
|
3,083 |
|
Contract drilling fees stacked rigs |
|
|
915 |
|
|
|
|
|
|
|
4,269 |
|
|
|
|
|
General and administrative (Including non-cash stock-based
compensation of $1,128 and $329 for the three months ended
June 30, 2007 and 2006, respectively, and $1,953 and $6,951
for the six months ended June 30, 2007 and 2006, respectively |
|
|
7,629 |
|
|
|
3,153 |
|
|
|
11,921 |
|
|
|
12,212 |
|
Ineffective portion of cash flow hedges |
|
|
(99 |
) |
|
|
340 |
|
|
|
1,156 |
|
|
|
1,126 |
|
|
|
|
Total operating costs and expenses |
|
|
46,324 |
|
|
|
31,598 |
|
|
|
88,262 |
|
|
|
55,624 |
|
|
|
|
Income from operations |
|
|
19,779 |
|
|
|
20,120 |
|
|
|
38,187 |
|
|
|
21,746 |
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(10,074 |
) |
|
|
(8,204 |
) |
|
|
(20,749 |
) |
|
|
(11,814 |
) |
Other, net |
|
|
208 |
|
|
|
271 |
|
|
|
473 |
|
|
|
574 |
|
|
|
|
Total other expense |
|
|
(9,866 |
) |
|
|
(7,933 |
) |
|
|
(20,276 |
) |
|
|
(11,240 |
) |
|
|
|
Income before income taxes |
|
|
9,913 |
|
|
|
12,187 |
|
|
|
17,911 |
|
|
|
10,506 |
|
Income tax expense |
|
|
(3,988 |
) |
|
|
(4,566 |
) |
|
|
(7,363 |
) |
|
|
(4,313 |
) |
|
|
|
Net income |
|
|
5,925 |
|
|
|
7,621 |
|
|
|
10,548 |
|
|
|
6,193 |
|
Preferred stock dividends |
|
|
(11 |
) |
|
|
(32 |
) |
|
|
(45 |
) |
|
|
(1,178 |
) |
Effect of induced conversion of preferred stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,601 |
|
|
|
|
Net income applicable to common shareholders |
|
$ |
5,914 |
|
|
$ |
7,589 |
|
|
$ |
10,503 |
|
|
$ |
16,616 |
|
|
|
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share |
|
$ |
0.10 |
|
|
$ |
0.14 |
|
|
$ |
0.19 |
|
|
$ |
0.42 |
|
|
|
|
Shares used in basic earnings per share |
|
|
57,747 |
|
|
|
54,877 |
|
|
|
56,369 |
|
|
|
39,512 |
|
|
|
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share |
|
$ |
0.10 |
|
|
$ |
0.13 |
|
|
$ |
0.18 |
|
|
$ |
0.39 |
|
|
|
|
Shares used in diluted earnings per share |
|
|
59,625 |
|
|
|
58,344 |
|
|
|
59,260 |
|
|
|
42,509 |
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
2
Concho Resources Inc. and subsidiaries
Consolidated statements of stockholders equity
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivable |
|
|
Retained |
|
|
Accumulated |
|
|
|
|
|
|
Series A |
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
from |
|
|
Earnings |
|
|
Other |
|
|
Total |
|
|
|
Preferred Stock |
|
|
Common Stock |
|
|
Paid-in |
|
|
Officers and |
|
|
(Accumulated |
|
|
Comprehensive |
|
|
Stockholders |
|
(in thousands) |
|
Shares |
|
|
Amount |
|
|
Shares |
|
|
Amount |
|
|
Capital |
|
|
Employees |
|
|
Deficit) |
|
|
Income (Loss) |
|
|
Equity |
|
|
BALANCE AT DECEMBER 31, 2005 |
|
|
12,959 |
|
|
$ |
130 |
|
|
|
8,142 |
|
|
$ |
8 |
|
|
$ |
135,876 |
|
|
$ |
(9,012 |
) |
|
$ |
(6,272 |
) |
|
$ |
(11,060 |
) |
|
$ |
109,670 |
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,668 |
|
|
|
|
|
|
|
19,668 |
|
Deferred hedge gains,
net of tax of $4,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,736 |
|
|
|
7,736 |
|
Net settlement losses included in earnings, net of
taxes of $2,030 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,738 |
|
|
|
3,738 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31,142 |
|
Issuance of subscribed units |
|
|
4,518 |
|
|
|
45 |
|
|
|
2,259 |
|
|
|
2 |
|
|
|
45,329 |
|
|
|
(3,158 |
) |
|
|
|
|
|
|
|
|
|
|
42,218 |
|
Issuance of common stock |
|
|
|
|
|
|
|
|
|
|
578 |
|
|
|
1 |
|
|
|
577 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
578 |
|
Conversion of preferred stock |
|
|
(17,477 |
) |
|
|
(175 |
) |
|
|
13,106 |
|
|
|
13 |
|
|
|
162 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock for
acquisition |
|
|
|
|
|
|
|
|
|
|
34,795 |
|
|
|
35 |
|
|
|
384,301 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
384,336 |
|
Restricted stock issued as stock-based compensation |
|
|
|
|
|
|
|
|
|
|
214 |
|
|
|
|
|
|
|
1,044 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,044 |
|
Cancellation of restricted
stock |
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation for stock options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,125 |
|
Stock-based compensation on issuance of units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
975 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
975 |
|
Accrued interestofficer & employee notes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(688 |
) |
|
|
|
|
|
|
|
|
|
|
(688 |
) |
6% Series A Preferred stock
dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,244 |
) |
|
|
|
|
|
|
(1,244 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2006 |
|
|
|
|
|
$ |
|
|
|
|
59,093 |
|
|
$ |
59 |
|
|
$ |
575,389 |
|
|
$ |
(12,858 |
) |
|
$ |
12,152 |
|
|
$ |
414 |
|
|
$ |
575,156 |
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,548 |
|
|
|
|
|
|
|
10,548 |
|
Deferred hedge losses,
net of tax of ( $3,594) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,028 |
) |
|
|
(5,028 |
) |
Net settlement losses included in earnings, net of
taxes of $306 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
428 |
|
|
|
428 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive
income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,948 |
|
Restricted stock issued as stock-based compensation |
|
|
|
|
|
|
|
|
|
|
20 |
|
|
|
|
|
|
|
781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
781 |
|
Stock-based compensation for stock options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,173 |
|
Issuance of common stock for acquisition obligation |
|
|
|
|
|
|
|
|
|
|
54 |
|
|
|
|
|
|
|
650 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
650 |
|
Proceeds from notes receivable officers & employees |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,482 |
|
|
|
|
|
|
|
|
|
|
|
10,482 |
|
Accrued interestofficer & employee notes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(240 |
) |
|
|
|
|
|
|
|
|
|
|
(240 |
) |
6% Series A Preferred stock
dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45 |
) |
|
|
|
|
|
|
(45 |
) |
|
|
|
BALANCE AT JUNE 30, 2007 |
|
|
|
|
|
$ |
|
|
|
|
59,167 |
|
|
$ |
59 |
|
|
$ |
577,993 |
|
|
$ |
(2,616 |
) |
|
$ |
22,655 |
|
|
$ |
(4,186 |
) |
|
$ |
593,905 |
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
3
Concho Resources Inc. and subsidiaries
Consolidated statements of cash flows
Unaudited
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
|
June 30, |
|
(in thousands) |
|
2007 |
|
|
2006 |
|
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
10,548 |
|
|
$ |
6,193 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation and depletion |
|
|
37,033 |
|
|
|
22,496 |
|
Impairments of proved oil and gas properties |
|
|
3,198 |
|
|
|
3,083 |
|
Accretion of discount on asset retirement obligations |
|
|
228 |
|
|
|
109 |
|
Exploration expense, including dry holes |
|
|
5,665 |
|
|
|
363 |
|
Non-cash compensation expense |
|
|
1,954 |
|
|
|
6,951 |
|
Gas imbalances |
|
|
54 |
|
|
|
(2 |
) |
Ineffective portion of cash flow hedges |
|
|
1,156 |
|
|
|
1,126 |
|
Deferred rent liability |
|
|
41 |
|
|
|
112 |
|
Deferred income taxes |
|
|
7,399 |
|
|
|
3,785 |
|
Interest accrued on officer and employee notes |
|
|
(240 |
) |
|
|
(331 |
) |
Amortization of deferred loan costs |
|
|
1,889 |
|
|
|
828 |
|
Amortization of discount on long-term debt |
|
|
40 |
|
|
|
|
|
Changes in operating assets and liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
10,640 |
|
|
|
(8,470 |
) |
Prepaid insurance and other |
|
|
(1,015 |
) |
|
|
(2,288 |
) |
Other assets |
|
|
|
|
|
|
12 |
|
Accounts payable |
|
|
(14,902 |
) |
|
|
6,230 |
|
Revenue payable |
|
|
(404 |
) |
|
|
(6,087 |
) |
Accrued liabilities |
|
|
(519 |
) |
|
|
(1,214 |
) |
Accrued interest |
|
|
829 |
|
|
|
493 |
|
|
|
|
Net cash provided by operating activities |
|
|
63,594 |
|
|
|
33,389 |
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Capital expenditures on oil and gas properties |
|
|
(69,889 |
) |
|
|
(82,460 |
) |
Acquisition of oil and gas properties and other assets |
|
|
(256 |
) |
|
|
(414,920 |
) |
Additions to other property and equipment |
|
|
(1,114 |
) |
|
|
(492 |
) |
Proceeds from the sale of oil and gas properties |
|
|
652 |
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(70,607 |
) |
|
|
(497,872 |
) |
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt |
|
|
266,100 |
|
|
|
485,505 |
|
Payments of long-term debt |
|
|
(257,600 |
) |
|
|
(88,500 |
) |
Proceeds from issuance of subscribed units and common stock |
|
|
|
|
|
|
61,178 |
|
Payments of preferred stock dividends |
|
|
(132 |
) |
|
|
(2,511 |
) |
Proceeds from repayment of officer and employee notes |
|
|
10,482 |
|
|
|
|
|
Payments for loan origination costs |
|
|
(2,572 |
) |
|
|
(5,000 |
) |
Negative cash balances |
|
|
|
|
|
|
4,629 |
|
|
|
|
Net cash provided by financing activities |
|
|
16,278 |
|
|
|
455,301 |
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
9,265 |
|
|
|
(9,182 |
) |
BEGINNING CASH AND CASH EQUIVALENTS |
|
|
1,122 |
|
|
|
9,182 |
|
|
|
|
ENDING CASH AND CASH EQUIVALENTS |
|
$ |
10,387 |
|
|
$ |
|
|
|
|
|
SUPPLEMENTAL CASH FLOWS: |
|
|
|
|
|
|
|
|
Cash paid for interest and fees, net of $1,336 and $1,001 capitalized |
|
$ |
18,891 |
|
|
$ |
11,294 |
|
|
|
|
Cash paid for income taxes |
|
$ |
1,800 |
|
|
$ |
100 |
|
|
|
|
NON-CASH INVESTING AND FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Issuance of common stock in acquisition of oil and gas properties and other
assets |
|
$ |
650 |
|
|
$ |
384,336 |
|
Deferred tax effect of acquired oil and gas properties |
|
$ |
|
|
|
$ |
227,735 |
|
Issuance of notes receivable issued in connection with capital options |
|
$ |
|
|
|
$ |
3,158 |
|
Discount on long-term debt |
|
$ |
(1,000 |
) |
|
$ |
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
4
Concho Resources Inc. and subsidiaries
Condensed notes to consolidated financial statements
Unaudited
Note A. Organization and nature of operations
Concho Resources Inc. (Resources) is a Delaware corporation formed by Concho Equity Holdings
Corp. (CEHC) on February 22, 2006, for purposes of effecting the combination of CEHC, Chase Oil
Corporation, Caza Energy LLC (Caza) and certain other parties thereto (collectively with Chase
Oil Corporation and Caza, the Chase Group). Pursuant to the Combination Agreement dated February
24, 2006, Resources acquired working interests in oil and natural gas properties from the Chase
Group and issued shares of its common stock to certain stockholders of CEHC in exchange for their
capital stock of CEHC. CEHC is a Delaware corporation formed on April 21, 2004 by certain
individuals and private equity investors. CEHC commenced substantial oil and gas operations in
December 2004 upon its acquisition of certain oil and gas properties located in Southeast New
Mexico and West Texas. The combination transaction described above (the Combination) was
accounted for as an acquisition by CEHC of the Chase Group properties and a simultaneous
reorganization of Resources such that CEHC is now a wholly owned subsidiary of Resources. Prior to
the Combination, Resources had no assets, operations or net equity. Upon the closing of the
Combination, the executive officers of CEHC became the executive officers of Resources. Resources
and its wholly owned subsidiaries are hereafter collectively referred to as the Company.
CEHCs shareholders received 23,767,691 shares of common stock of Resources in exchange for
their preferred and common shares of CEHC, excluding eighteen holders owning an aggregate of
254,621 shares of CEHC 6% Series A Preferred Stock and 127,313 shares of CEHC common stock, as
discussed in Note G Stockholders equity and stock issued subject to limited recourse notes. In
addition, the Chase Group transferred their ownership in certain oil and gas properties in
Southeast New Mexico to Resources in exchange for cash in the aggregate amount of approximately
$409 million and 34,794,638 shares of Resources common stock. As of June 30, 2007 and December 31,
2006, this ownership of the Chase Group represented approximately 59 percent of the total
outstanding common stock ownership of the Company.
The Companys principal business is the acquisition, development, exploitation and exploration
of oil and gas properties in the Permian Basin region of Southeast New Mexico and West Texas.
Reverse stock split. On July 3, 2007, the Companys board of directors approved a one-for-two
reverse stock split of the Companys outstanding common stock which has been approved by the
Companys shareholders and became effective on August 3, 2007 at the completion of the Companys
initial public offering. All common shares and per share amounts in the accompanying consolidated
financial statements and notes to the consolidated financial statements have been retroactively
adjusted for all periods presented to give effect to the reverse stock split.
Note B. Summary of significant accounting policies
Principles of consolidation. Prior to the Combination, the consolidated financial statements
of Resources represent the accounts of CEHC and its wholly owned subsidiaries. After the
Combination, the consolidated financial statements of Resources include the accounts of Resources
and its wholly owned subsidiaries, including CEHC. All material intercompany balances and
transactions have been eliminated.
Interim financial statements. The accompanying consolidated financial statements of the
Company have not been audited by the Companys independent registered public accounting firm,
except that the consolidated balance sheet at December 31, 2006 is derived from audited financial
statements. In the opinion of management, the accompanying financial statements reflect all
adjustments necessary to present fairly the Companys financial position at June 30, 2007, its
income for the three and six months ended June 30, 2007 and 2006 and its cash flows for the six
months ended June 30, 2007 and 2006. All such adjustments are of a normal recurring nature. In
preparing the accompanying financial statements, management has made certain estimates and
assumptions that affect reported amounts in the financial statements and disclosures of
contingencies. Actual results may differ from those estimates. Certain amounts presented in prior
period financial statements have been reclassified for consistency with current period
presentation. The results for interim periods are not necessarily indicative of annual results.
Certain disclosures have been condensed or omitted from these financial statements.
Accordingly, these financial statements should be read with the audited consolidated financial
statements and notes thereto included in the Companys Registration Statement on Form S-1, as
amended (Registration No 333-142315).
5
Oil and gas sales and imbalances. Oil and gas revenues are recorded at the time of delivery of
such products to pipelines for the account of the purchaser or at the time of physical transfer of
such products to the purchaser. The Company follows the sales method of accounting for oil and gas
sales, recognizing revenues based on the Companys share of actual proceeds from the oil and gas
sold to purchasers. Oil and gas imbalances are generated on properties for which two or more owners
have the right to take production in-kind and, in doing so, take more or less than their
respective entitled percentage. Imbalances are tracked by well, but the Company does not record any
receivable to or payable from the other owners unless the imbalance has reached a level whereby it
exceeds the remaining reserves in the respective well. If reserves are insufficient to offset the
imbalance and the Company is in an overtake position, a liability is recorded for the amount of
shortfall in reserves valued at a contract price or the market price in effect at the time the
imbalance is generated. If the Company is in an undertake position, a receivable is recorded for an
amount that is reasonably expected to be received, not to exceed the current market value of such
imbalance.
At June 30, 2007, the Company had a gas imbalance liability, included in Asset Retirement
Obligations and Other Long-Term Liabilities in the accompanying consolidated balance sheet of
approximately $629,000 related to the Companys overtake position of 97,499 Mcf on certain wells
and a gas imbalance receivable, included in Other Assets in the accompanying consolidated
balance sheet of approximately $335,000 related to the Companys undertake position of 74,466Mcf on
certain wells.
General and administrative expense. The Company receives fees for the operation of jointly owned
oil and gas properties and records such reimbursements as reductions of General and administrative
expense. Such fees totaled approximately $221,000 and $205,000 for the three months ended June 30,
2007 and 2006, respectively, and totaled approximately $630,000 and $421,000 for the six months
ended June 30, 2007 and 2006, respectively.
Note C. Exploratory well costs
Costs of drilling exploratory wells are capitalized, pending managements determination of
whether the wells have found proved reserves. If proved reserves are found, the costs remain
capitalized. If proved reserves are not found, the capitalized costs of drilling the well are
charged to expense. Management makes this determination as soon as possible after completion of
drilling considering the guidance provided in Financial Accounting Standards Board (FASB)
Statement of Financial Accounting Standards (SFAS) No. 19, Financial Accounting and Reporting by
Oil and Gas Producing Companies and FASB Staff Position (FSP) No. 19-1 Accounting for Suspended
Well Costs.
The following table provides an aging as of June 30, 2007 and December 31, 2006 of capitalized
exploratory well costs based on the date the drilling was completed:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
(in thousands) |
|
2007 |
|
2006 |
|
Wells in progress |
|
$ |
487 |
|
|
$ |
916 |
|
Capitalized exploratory well costs that have been capitalized for a period of one year or less |
|
|
15,948 |
|
|
|
14,042 |
|
Capitalized exploratory well costs that have been capitalized for a period greater than one year |
|
|
6,071 |
|
|
|
4,915 |
|
|
|
|
Total exploratory well costs |
|
$ |
22,506 |
|
|
$ |
19,873 |
|
|
|
|
As of June 30, 2007, the Company had one exploratory well in the Western Delaware Basin
of Texas on which the drilling was completed for more than one year with a total cost of
approximately $6.1 million. This well has been completed in two of the four prospective formations
that are being tested in the project area and has found both zones capable of producing gas in the
vertical well bores; however, quantities found thus far are not commercial. The current evaluation
being conducted on this well is to determine the viability of another one of the four prospective
formations which is deeper than the formations to which the well has currently been completed.
This formation is a shale formation which is present and productive in another of the Companys
exploratory wells located in the Western Delaware Basin. If determined to be a viable target
formation, assessing it would require re-entry into the existing wellbore.
A second well has been drilled in the project area. It was completed and flowing gas to sales
during its initial evaluation stage during the six months ended June 30, 2007. This well will be
included in the evaluation of the viability of the additional prospective formation in the deeper
horizon mentioned above. Accumulated capitalized exploratory costs on this well of approximately
$5.2 million are included above in Capitalized exploratory well costs that have been capitalized
for a period of one year or less.
6
The Company anticipates finalizing its evaluation of this deeper, prospective formation in
these two wells by the end of the third quarter of 2007. Depending on the results and the
evaluation of such activity, the costs capitalized for the completed wells may be charged to
expense during the third quarter of 2007.
During the six months ended June 30, 2007, a third well in the Western Delaware Basin was
drilled to a shallower, previously untested, prospective formation. During June 2007, the Company
determined that the well had not found sufficient reserves to justify its completion or its
inclusion in the evaluation of the viability of any additional prospective formations in the
project area. The well was temporarily abandoned, and the Company recognized exploratory dry hole
expense of approximately $2.8 million. Such expense is included in Exploration and abandonments in
the accompanying consolidated statement of operations for the three months ended June 30, 2007.
The changes in capitalized exploratory well costs were as follows:
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
June 30, |
(in thousands) |
|
2007 |
|
2006 |
|
Beginning capitalized exploratory well costs |
|
$ |
19,873 |
|
|
$ |
3,955 |
|
Additions to exploratory well costs pending the determination of proved reserves |
|
|
37,832 |
|
|
|
17,679 |
|
Reclassifications due to determination of proved reserves |
|
|
(35,199 |
) |
|
|
(7,756 |
) |
Exploratory well costs charged to expense |
|
|
|
|
|
|
|
|
|
|
|
Ending capitalized exploratory well costs |
|
$ |
22,506 |
|
|
$ |
13,878 |
|
|
|
|
The Company charged $5,665,000 and $363,000 of exploratory well costs to expense during
the six months ended June 30, 2007 and 2006, respectively. These exploratory well costs were
capitalized and subsequently expensed in the same annual period; therefore, they are not included
in the table above in accordance with FSP No. 19-1.
Note D. Business combination
On February 27, 2006, the Company closed a Combination Agreement with the Chase Group whereby
ownership in certain oil and gas properties and non-producing leasehold acreage in Southeast New
Mexico (the Chase Group Properties) were merged with the properties previously owned by CEHC. The
results of the Chase Group Properties have been included in the consolidated financial statements
since that date.
The Chase Group received cash in the aggregate amount of $409 million and 34,794,638 shares of
Resources common stock valued at $384 million for an aggregate purchase price of $796 million
including transaction costs. The value of the Resources common stock shares issued was determined
based on an agreed upon fair market value of the assets purchased evaluated using reserve
engineering estimates. This entire transaction was accounted for using the purchase method of
accounting. At the time of the Combination, due to a difference in book and tax basis of the
acquired properties, the Company recognized a deferred tax liability of approximately $227.7
million.
The following table summarizes the final allocated net purchase price of the Combination,
including capitalized transaction costs:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Proved oil and gas properties |
|
$ |
830,540 |
|
Unproved oil and gas properties |
|
|
200,000 |
|
|
|
|
|
|
|
|
|
|
Total assets acquired |
|
|
1,030,540 |
|
|
|
|
|
Asset retirement obligations |
|
|
(6,158 |
) |
Chase investors asset purchase obligation |
|
|
(906 |
) |
Deferred tax liability |
|
|
(227,735 |
) |
|
|
|
|
Total liabilities assumed |
|
|
(234,799 |
) |
|
|
|
|
Net purchase price |
|
$ |
795,741 |
|
|
|
|
|
7
As discussed in Note K Commitments and contingencies, the Company was obligated under the
Combination Agreement to offer to purchase additional working interests in the Chase Group
Properties from nine individuals within the Chase Group for total
consideration of approximately $906,000. In April 2007, the Company satisfied this obligation
by paying $256,000 in cash and issuing 54,230 shares of common stock. This aggregate purchase price
is reflected in Proved properties and the related obligation is reflected in Chase Group
unaccredited investors asset purchase obligation in the accompanying consolidated balance sheet as
of December 31, 2006.
The following table represents pro forma consolidated statements of operations as though the
Combination had been completed as of January 1, 2006:
|
|
|
|
|
|
|
Pro forma |
|
|
Six months |
|
|
ended |
|
|
June 30, |
(in thousands, except per share data) (unaudited) |
|
2006 |
|
Operating revenues |
|
$ |
98,826 |
|
Net income applicable to common shareholders |
|
$ |
10,421 |
|
Earnings per common share: |
|
|
|
|
Basic |
|
$ |
0.20 |
|
Diluted |
|
$ |
0.19 |
|
|
On February 27, 2006, the Company signed a contract operator agreement with Mack Energy
Corporation (MEC), an affiliate of the Chase Group, whereby the Company engaged MEC as contract
operator to provide certain services with respect to the Chase Group Properties. This agreement was
replaced with a Transition Services Agreement on April 23, 2007, which terminated upon completion
of the Companys initial public offering on August 7, 2007. See further discussion in Note N
Related parties.
Note E. New accounting pronouncements
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurement. This statement
defines fair value, establishes a framework for measuring fair value and expands disclosures about
fair value measurements. This statement is effective for financial statements issued for fiscal
years beginning after November 15, 2007. The Company will adopt SFAS No. 157 effective January 1,
2008. The Company is currently evaluating the impact of SFAS No. 157.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets
and Financial Liabilities, Including an Amendment of FASB Statement No. 115, which will become
effective in 2008. SFAS No. 159 permits entities to measure eligible financial assets, financial
liabilities and firm commitments at fair value, on an instrument-by-instrument basis, that are
otherwise not permitted to be accounted for at fair value under other generally accepted accounting
principles. The fair value measurement election is irrevocable and subsequent changes in fair value
must be recorded in earnings. The Company will adopt this statement January 1, 2008, and the
Company is currently evaluating if it will elect the fair value option for any of its eligible
financial instruments and other items.
In June 2007, the FASB ratified a consensus opinion reached by the Emerging Issues Task Force
(EITF) on EITF Issue 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based
Payment Awards. EITF Issue 06-11 requires an employer to recognize tax benefits realized from
dividend or dividend equivalents paid to employees for certain share-based payment awards as an
increase to additional paid-in capital and include such amounts in the pool of excess tax benefits
available to absorb future tax deficiencies on share-based payment awards. If an entitys estimate
of forfeitures increases (or actual forfeitures exceed the entitys estimates), or if an award is
no longer expected to vest, entities should reclassify the dividends or dividend equivalents paid
on that award from retained earnings to compensation cost. However, the tax benefits from dividends
that are reclassified from additional paid-in capital to the income statement are limited to the
entitys pool of excess tax benefits available to absorb tax deficiencies on the date of
reclassification. The consensus in EITF Issue 06-11 is effective for fiscal years, and interim
periods within those fiscal years, beginning after December 15, 2007. Retrospective application of
EITF Issue 06-11 is not permitted. Early adoption is permitted; however, the Company does not
intend to adopt EITF Issue 06-11 prior to the required effective date of January 1, 2008. The
Company does not expect the adoption of EITF Issue 06-11 to have a significant effect on its
financial statements since the Company historically has accounted for the income tax benefits of
dividends paid for share-based payment awards in the manner described in the consensus.
8
Note F. Asset retirement obligations
The Companys asset retirement obligations represent the estimated present value of the
estimated cash flows the Company will incur to plug, abandon and remediate its producing properties
at the end of their production lives, in accordance with applicable state laws. The Company does
not provide for a market risk premium associated with asset retirement obligations because a
reliable estimate cannot be determined. The Company has no assets that are legally restricted for
purposes of settling asset retirement obligations.
The following table summarizes the Companys asset retirement obligation transactions recorded
in accordance with the provisions of SFAS No. 143 during the six months ended June 30, 2007 and
2006:
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
June 30, |
(in thousands) |
|
2007 |
|
2006 |
|
Asset retirement obligations, beginning of period |
|
$ |
8,700 |
|
|
$ |
1,120 |
|
Liability incurred upon acquiring and drilling wells |
|
|
131 |
|
|
|
6,294 |
|
Accretion expense |
|
|
228 |
|
|
|
109 |
|
Liabilities settled upon plugging and abandoning wells |
|
|
|
|
|
|
|
|
Revisions to estimated cash flows |
|
|
(1,393 |
) |
|
|
(199 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, end of period |
|
$ |
7,666 |
|
|
$ |
7,324 |
|
|
|
|
Note G. Stockholders equity and stock issued subject to limited recourse notes
Equity commitments. Pursuant to a stock purchase agreement (the Stock Purchase Agreement)
entered into on August 13, 2004, the Company obtained private equity commitments totaling $202.5
million, comprised of equity commitments from fourteen private investors (the Private Investors)
of approximately $188.9 million and equity commitments from the five original officers (the
Officers) of the Company in the aggregate amount of $13.6 million. The original commitments were
subject to call by a vote of the board of directors over a four year period beginning August 13,
2004 (the Take-Down Period), with the first date on which capital was called being August 13,
2004. Subsequent calls were made on November 11, 2004, June 22, 2005, December 7, 2005 and February
10, 2006. The percentage of total commitments called per capital call date was approximately 15.0
percent, 23.3 percent, 10.0 percent, 15.0 percent and 22.0 percent, respectively. In conjunction
with the exchange of CEHC common stock for Resources common stock as of the date of the
Combination, the remaining 14.7 percent of these private equity commitments was terminated.
In addition to this arrangement between the Private Investors and the Officers, certain
employees and executive officers of the Company entered into separate subscription agreements with
the Company. The officers and employees equity purchases were paid in a combination of cash and
the issuance of notes payable to the Company with recourse only to any equity security of the
Company held by the respective officer or employee (the Purchase Notes). Based on guidance
contained in SFAS No. 123R, the agreements to sell stock to the Officers and certain employees
subject to Purchase Notes are accounted for as the issuance of options (Bundled Capital Options
for the Officers and Capital Options for the certain employees) on the dates that the various
subscription agreements were signed and the purchase commitments were made.
Capital
calls. The Companys fifth capital call on
February 10, 2006, principally funded February 23, 2006, called for 4,155,800 Preferred Units from the Private Investors for $41,558,000
in cash.
For
the Companys fifth capital call, also principally funded February 23, 2006, the Officers and
certain employees purchased 577,721 shares of CEHC common stock and 351,670 Preferred Units for
consideration consisting of $1,200,000 in cash and Purchase Notes in the aggregate principal amount
of $3,044,000.
From inception of the Company through February 23, 2006, the Private Investors purchased
16,113,170 Preferred Units for $161.1 million in cash. The Officers had purchased 2,240,083 CEHC
common shares and 938,303 Preferred Units for $3.6 million in cash and Purchase Notes totaling $8.0
million. Certain employees purchased 425,221 Preferred Units for $1.0 million in cash and Purchase
Notes totaling $3.8 million.
Series A preferred stock. The Series A preferred stock of the Company consisted of 30 million
authorized shares of 6% Series A Preferred Stock with a stated value of $9.00 per share and par
value of $0.01 per share. Such shares bore a 6 percent dividend, payable annually in arrears with
accrual of such dividend commencing on the date of issue. The Company could have
9
elected to pay the
dividend in whole or in part in cash or in additional Units. Upon liquidation, the 6% Series A
Preferred Stock would have been ranked senior to all other classes of shares.
Preferred stock dividends were generally paid on the anniversary of date of issue. Preferred
stock dividends of approximately $98,000 and $14,000 were paid during the three months ended June
30, 2007 and 2006, respectively. Preferred stock dividends of approximately $132,000 and $2,511,000
were paid during the six months ended June 30, 2007 and 2006, respectively. As discussed in Note
A Organization and nature of operations and below, the majority of the CEHC preferred stock was
converted into Resources common stock on the Combination date. Final dividend payments on converted
CEHC 6% Series A Preferred Stock were made in March 2006.
Dividend payments continued to be made to the eighteen employee shareholders that did not
convert their shares of CEHC preferred stock to Resources common stock through April 16, 2007. On
April 16, 2007, these CEHC preferred shares were exchanged for 190,972 shares of the Companys
common stock. These shares are reported as if converted on the Combination date. Final dividend
payments on this final portion of converted CEHC 6% Series A Preferred Stock were made on April 16,
2007.
Preferred stock. The board of directors is authorized to issue up to 10,000,000 shares of
preferred stock with a par value of $0.001 per share (Preferred Stock). The board of directors
will determine for each series of issuance:
|
|
the number of shares in any series; |
|
|
|
voting powers, if any; |
|
|
|
redemption provisions, if any; |
|
|
|
dividend rate and other dividend attributes; and |
|
|
|
convertible features or attached rights, if any. |
As of June 30, 2007, no shares of Preferred Stock had been issued.
Purchase Notes. On April 23, 2007, the executive officers repaid their Purchase Notes in full,
including principal of $9,426,000 and accrued interest of $1,037,000. The agreements to sell stock
to the executive officers of the Company subject to Purchase Notes were accounted for as the
issuance of options. As such, the repayment of the executive officer Purchase Notes represents the
full exercise of the options on the Bundled Capital Options (as defined below) the Officers held as
well as the Capital Options (as defined below) of one certain employee who is currently an
executive officer.
At June 30, 2007, the Company had Purchase Notes receivable from certain employees of
approximately $2,616,000 comprised of an aggregate principal amounts of $2,361,000 and accrued
interest of $255,000.
Valuation of stock issuances treated as Capital Options.
The following table summarizes the Bundled Capital Options activity for the six months ended
June 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
Weighted |
|
|
|
|
Bundled Capital |
|
average |
|
Grant date |
|
|
Options |
|
exercise price |
|
fair value |
|
Six months ended June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of period |
|
|
938,303 |
|
|
$ |
9.52 |
|
|
|
|
|
Bundled Capital Options granted |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
Bundled Capital Options exercised |
|
|
(938,303 |
) |
|
$ |
9.52 |
|
|
|
|
|
Cancelled / forfeited |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested outstanding at end of period |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
The following table summarizes information about the Companys Vested Bundled Capital Options
outstanding and exercisable at June 30, 2007 and December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested Bundled Capital Options Outstanding and Exercisable |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
average |
|
Weighted |
|
|
|
|
Number |
|
remaining |
|
average |
|
|
|
|
outstanding, vested |
|
contractual |
|
exercise |
|
Intrinsic |
Date |
|
and exercisable |
|
life |
|
price |
|
value |
|
June 30, 2007 |
|
|
|
|
|
|
N / A |
|
|
|
N / A |
|
|
|
N / A |
|
December 31, 2006 |
|
|
938,303 |
|
|
3.45 years |
|
$ |
9.52 |
|
|
$ |
45,655,000 |
|
The following table summarizes the Capital Options activity for the six months ended June 30,
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
Weighted |
|
|
|
|
Capital |
|
average |
|
Grant date |
|
|
Options |
|
exercise price |
|
fair value |
|
Six months ended June 30, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of period |
|
|
425,221 |
|
|
$ |
9.81 |
|
|
|
|
|
$10 Capital Options granted |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
$15 Capital Options granted |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
$10 Capital Options exercised |
|
|
(172,733 |
) |
|
$ |
9.34 |
|
|
|
|
|
Cancelled / forfeited |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period |
|
|
252,488 |
|
|
$ |
10.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested outstanding at end of period |
|
|
252,488 |
|
|
$ |
10.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes information about the Companys vested Capital Options
outstanding and exercisable at June 30, 2007 and December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested Capital Options Outstanding and Exercisable |
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
Number |
|
|
average |
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
outstanding, |
|
|
remaining |
|
|
average |
|
|
|
|
|
|
Exercise |
|
|
vested and |
|
|
contractual |
|
|
exercise |
|
|
Intrinsic |
|
Date |
|
prices |
|
|
exercisable |
|
|
life |
|
|
price |
|
|
value |
|
|
June 30, 2007 |
|
$ |
10.00 |
|
|
|
136,480 |
|
|
3.04 years |
|
$ |
8.34 |
|
|
$ |
677,000 |
|
|
|
$ |
15.00 |
|
|
|
116,008 |
|
|
3.34 years |
|
$ |
12.26 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
252,488 |
|
|
|
|
|
|
$ |
10.14 |
|
|
$ |
677,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
$ |
10.00 |
|
|
|
309,213 |
|
|
3.61 years |
|
$ |
8.90 |
|
|
$ |
3,268,000 |
|
|
|
$ |
15.00 |
|
|
|
116,008 |
|
|
3.83 years |
|
$ |
12.26 |
|
|
$ |
633,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
425,221 |
|
|
|
|
|
|
$ |
9.81 |
|
|
$ |
3,901,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
The following table summarizes the stock-based compensation for all Capital Options and is
included in General and administrative expense in the accompanying consolidated statement of
operations for the three and six months ended June 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
|
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
Stock-based compensation expense from Capital Options: |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
975,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bundled Capital Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
508,000 |
|
Options vesting during period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
242,000 |
|
Weighted average grant date fair value per option |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Options
Stock-based compensation expense |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
467,000 |
|
Options vesting during period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
119,799 |
|
Weighted average grant date fair value per option |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
3.90 |
|
Conversion of CEHC 6% Series A Preferred Stock and CEHC common stock. On February 27, 2006,
concurrent with the closing of the Combination described in Note A Organization and nature of
operations and Note D Business combination, the majority of the shares of CEHC preferred stock
and shares of CEHC common stock outstanding were converted to shares of Resources common stock, as
described below.
Eighteen employee shareholders owning an aggregate of 254,621 shares of CEHC preferred stock
and 127,313 shares of CEHC common stock did not convert their shares to Resources common stock at
the date of the Combination. On April 16, 2007, these remaining shares of CEHC were exchanged for
318,285 shares of the Companys common stock. These shares are reported as if converted on the
Combination date. In addition, CEHC made a final dividend payment to these eighteen employee
shareholders on their CEHC preferred stock in the aggregate amount of approximately $99,000 on
April 16, 2007.
Also in conjunction with the Combination described in Note AOrganization and nature of
operations and Note D Business combination and the conversion of CEHC preferred stock into
Resources common stock at the ratio of 0.75:1, the CEHC Bundled Capital Options were converted into
Resources Bundled Capital Options and CEHC Capital Options were converted into Resources Capital
Options. The Resources Capital Options are considered to be exercisable for 1.25 shares of
Resources common stock.
Common stock held in escrow. On February 27, 2006 the Company entered into an agreement with
certain stockholders of the Company in which certain of the Companys shareholders placed 430,755
shares of Resources common stock in an escrow account (the Escrow Agreement). The Escrow
Agreement provided that if, on or before February 27, 2007 (the Initial Period), the Company
consummated one of two specified transactions, the shares held in escrow would be released to the
Company for reissuance to Messrs. Leach, Beal, Copeland, Kamradt and Wright. Neither of those
specified transactions occurred in the Initial Period. However, the Escrow Agreement specified that
if neither of the two specified transactions occurred during the Initial Period, a sale of the
Company in a business combination on or before August 26, 2007 where the per share valuation of the
Companys common stock in such sale was equal to or greater than $28.00 per share would result in
the release of the shares held in escrow to the Company for reissuance to Messrs. Leach, Beal,
Copeland, Kamradt and Wright. These shares have been treated as issued and outstanding in the
consolidated financial statements at June 30, 2007 and December 31, 2006. This condition did not
occur by August 26, 2007. As a result, the escrow agent has been instructed to distribute the
escrowed shares to the registered owners thereof that originally deposited the shares.
Note H. Stock incentive plan
The Companys 2006 Stock Incentive Plan (together with applicable option agreements and
restricted stock agreements, the Plan) provides for granting stock options and restricted stock
awards to employees and individuals associated with the Company.
Restricted stock awards. Under the Plan, the Company has issued 232,216 restricted shares, of
which restrictions have lapsed with respect to 60,000 shares. On April 23, 2007, the Company
issued a total of 20,000 shares of restricted common stock comprised of 2,500 shares to each of the
eight outside directors subject to certain restrictions as set forth in the Plan. These
restrictions lapsed
12
with respect to 100 percent of the restricted shares on April 23, 2007, the date of grant. The
grant date fair value of the stock was estimated to be approximately $340,000 which the Company
recognized as stock-based compensation expense in April 2007.
All restricted shares are treated as issued and outstanding in the accompanying consolidated
balance sheets. If an employee terminates employment prior the lapse date, the awarded shares are
forfeited and cancelled and are no longer considered issued and outstanding. A summary of the
Companys restricted stock awards during the six months ended June 30, 2007 is presented below:
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
Grant date |
|
|
common shares |
|
fair value |
|
Restricted stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006 |
|
|
212,216 |
|
|
|
|
|
Shares granted |
|
|
20,000 |
|
|
$ |
340,000 |
|
Shares cancelled / forteited |
|
|
|
|
|
|
|
|
Lapse of restrictions |
|
|
(60,000 |
) |
|
$ |
956,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2007 |
|
|
172,216 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
Company recorded stock-based compensation for restricted stock of $560,000 and $88,000,
which is recognized in General and administrative expense in the accompanying consolidated
statement of operations, for the three months ended June 30, 2007 and 2006, respectively, and
$781,000 and $88,000 for the six months ended June 30, 2007 and 2006, respectively. Future
stock-based compensation expense related to restricted stock outstanding at June 30, 2007 for the
remaining six months of 2007 and the years ending December 31, 2008 and 2009 is expected to be
approximately $441,000, $882,000, and $454,000, respectively. The income tax benefit recognized in
the accompanying statement of operations for restricted stock was
approximately $235,000 and
$37,000 for the three months ended June 30, 2007 and 2006,
respectively, and $327,000 and $37,000
for the six months ended June 30, 2007 and 2006, respectively.
Stock option awards. A summary of the Companys stock option activity under the Plan for the
six months ended June 30, 2007 is presented below:
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
June 30, 2007 |
|
|
|
|
|
|
Weighted |
|
|
Number of |
|
Average |
|
|
options (a) |
|
Price |
|
Stock options: |
|
|
|
|
|
|
|
|
Outstanding at beginning of period |
|
|
2,797,997 |
|
|
$ |
8.93 |
|
Options granted |
|
|
|
|
|
$ |
|
|
Options forfeited |
|
|
(1,275 |
) |
|
$ |
8.00 |
|
Options exercised |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period |
|
|
2,796,722 |
|
|
$ |
8.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period |
|
|
2,063,499 |
|
|
$ |
8.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
One option can be exercised for one share of Resources common stock. |
13
The following table summarizes information about the Companys vested stock options
exercisable at June 30, 2007 and December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested Options Exercisable |
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
average |
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Number |
|
|
remaining |
|
|
average |
|
|
|
|
|
|
Exercise |
|
|
vested and |
|
|
contractual |
|
|
exercise |
|
|
Intrinsic |
|
Date |
|
prices |
|
|
exercisable |
|
|
life |
|
|
price |
|
|
value |
|
|
June 30, 2007 |
|
$ |
8.00 |
|
|
|
1,753,819 |
|
|
7.98 years |
|
$ |
8.00 |
|
|
$ |
8,243,000 |
|
|
|
$ |
12.00 |
|
|
|
309,680 |
|
|
8.58 years |
|
$ |
12.00 |
|
|
$ |
217,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,063,499 |
|
|
|
|
|
|
$ |
8.60 |
|
|
$ |
8,460,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
$ |
8.00 |
|
|
|
1,755,094 |
|
|
8.47 years |
|
$ |
8.00 |
|
|
$ |
15,099,000 |
|
|
|
$ |
12.00 |
|
|
|
197,180 |
|
|
8.86 years |
|
$ |
12.00 |
|
|
$ |
769,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,952,274 |
|
|
|
|
|
|
$ |
8.40 |
|
|
$ |
15,868,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes information about stock-based compensation for options which is
recognized in General and administrative expense in the accompanying consolidated statement of
operations for the three and six months ended June 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
Grant date fair value: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time Vesting options (a) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,931,000 |
|
Performance Vesting options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Officers (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
500,000 |
|
Certain employee (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31,000 |
|
Non-officers (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
142,000 |
|
Current officer stock options (d) |
|
|
|
|
|
|
3,555,000 |
|
|
|
|
|
|
|
3,555,000 |
|
|
|
|
Total |
|
$ |
|
|
|
$ |
3,555,000 |
|
|
$ |
|
|
|
$ |
6,159,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense from stock options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time Vesting options (a) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
5,085,000 |
|
Performance Vesting options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Officers (b) |
|
|
141,000 |
|
|
|
141,000 |
|
|
|
279,000 |
|
|
|
194,000 |
|
Certain employee (b) |
|
|
10,000 |
|
|
|
10,000 |
|
|
|
20,000 |
|
|
|
14,000 |
|
Non-officers (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
505,000 |
|
Current officer stock options (d) |
|
|
418,000 |
|
|
|
91,000 |
|
|
|
874,000 |
|
|
|
91,000 |
|
|
|
|
Total |
|
$ |
569,000 |
|
|
$ |
242,000 |
|
|
$ |
1,173,000 |
|
|
$ |
5,889,000 |
|
|
|
|
|
|
|
(a) |
|
Vested immediately as of the date of the Combination, from change of control. |
|
(b) |
|
Vesting revised to a three year cliff vesting schedule by approval from CEHCs Board of Directors. |
|
(c) |
|
Vested as of the date of the Combination by approval from CEHCs Board of Directors. |
|
(d) |
|
June 12, 2006 option grant, by approval of the Companys Board of Directors. |
14
Future stock-based compensation expense related to incentive stock options outstanding at
June 30, 2007 for the remaining six months ended December 31, 2007 and the years ending December
31, 2008, 2009 and 2010 is expected to be approximately $789,000, $1,322,000, $443,000, and $99,000
respectively.
Income tax benefit recognized in the income statement for these stock-based compensation
arrangements was $239,000 and $94,000 for the three months ended
June 30, 2007 and 2006, respectively, and $492,000 and $2,297,000 for the six months ended June 30, 2007 and 2006,
respectively. No amounts have been treated as deductions to the Companys current taxable income
for the three or six months ended June 30, 2007 and 2006, since no options have been exercised.
Note I. Derivative financial instruments
Cash flow hedges. The Company, from time to time, uses derivative financial instruments as
cash flow hedges of its commodity price risks. Commodity hedges are used to (a) reduce the effect
of the volatility of price changes on the natural gas and crude oil the Company produces and sells
and (b) support the Companys annual capital budgeting and expenditure plans.
Through December 31, 2006, the Company had entered into certain natural gas and crude oil zero
cost price collars and crude oil price swaps to hedge a portion of its estimated natural gas and
crude oil production for calendar years 2006, 2007 and 2008.
On February 8, 2007, the Company entered into one natural gas price swap to hedge an
additional portion of its estimated natural gas production for the period of March through December
2007. The contract is for 2,100 MMBtu per day at a fixed index price of $7.40 per MMBtu. The index
price is based on the Inside FERC El Paso Permian Basin spot price at the first of each month.
The Company has designated all of these derivative instruments as cash flow hedges.
The fair market value of these cash flow hedges at June 30, 2007 was a liability of
approximately $8.3 million.
The following table sets forth the Companys outstanding natural gas and crude oil zero cost
collars and swaps at June 30, 2007:
|
|
|
|
|
|
|
|
|
|
Hedged Period |
|
|
2007 |
|
|
2008 |
|
|
Natural gas price collars: |
|
|
|
|
|
|
|
|
Volume (MMBtu/day) |
|
|
16,000 |
|
|
|
13,500 |
|
Index price per MMBtu (a) |
|
$ |
5.98-$9.75 |
(c) |
|
$ |
6.50-$9.35 |
|
|
Natural gas price swap: |
|
|
|
|
|
|
|
|
Volume (MMBtu/day) |
|
|
2,100 |
|
|
|
|
|
Index price per MMBtu (a) |
|
$ |
7.40 |
|
|
|
|
|
|
Crude oil price collars: |
|
|
|
|
|
|
|
|
Volume (Bbl/day) |
|
|
650 |
|
|
|
|
|
NYMEX price per Bbl (b) |
|
$ |
37.95-$41.75 |
|
|
|
|
|
|
Crude oil price swaps: |
|
|
|
|
|
|
|
|
Volume (Bbl/day) |
|
|
2,300 |
|
|
|
2,600 |
|
NYMEX price per Bbl (b) |
|
$ |
67.85 |
|
|
$ |
67.50 |
|
|
|
|
(a) |
|
The index prices for the natural gas price collars are based on the Inside FERC-El
Paso Permian Basis first-of-the-month spot price. |
|
(b) |
|
The index prices for the oil price collars and price swaps are based on the NYMEX-West Texas
Intermediate monthly average spot price. |
|
(c) |
|
Amounts disclosed represent weighted average prices. |
15
The Companys reported oil and gas revenue and average oil and gas prices includes the
effects of oil quality and Btu content, gathering and transportation costs, gas processing and
shrinkage, and the net effect of the commodity hedges. The following table summarizes the
reclassifications of gains and losses into earnings as a result of periodic contractual cash
settlements related to the commodity financial instruments that were previously reported in
Accumulated other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
June 30, |
(in thousands) |
|
2007 |
|
2006 |
|
Cash settlements: |
|
|
|
|
|
|
|
|
Gains (losses) reclassified into earnings
previously reported in Accumulated other
comprehensive income (loss)
|
|
$ |
(734 |
) |
|
$ |
(4,420 |
) |
All of the Companys derivatives are expected to settle within the next two years. Based on
futures prices as of December 31, 2006, the Company expects a pre-tax loss of $211,000 to be
reclassified into earnings during the year ended December 31, 2007. Based on futures prices as of
June 30, 2007, the Company expects a pre-tax loss of $4,976,000 to be reclassified into earnings
during the twelve months ended June 30, 2008.
Note J. Long-term debt
The Companys long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
(in thousands) |
|
2007 |
|
2006 |
|
Bank debt: |
|
|
|
|
|
|
|
|
1st Lien Credit Facility |
|
$ |
305,000 |
|
|
$ |
455,700 |
|
2nd Lien Credit Facility |
|
|
|
|
|
|
39,400 |
|
New 2nd Lien Credit Facility |
|
|
197,500 |
|
|
|
|
|
Unamortized original issue discount on New 2nd Lien Credit Facility |
|
|
(960 |
) |
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
501,540 |
|
|
$ |
495,100 |
|
Current portion of New 2nd Lien Credit Facility |
|
|
2,500 |
|
|
|
400 |
|
|
|
|
Total debt |
|
$ |
504,040 |
|
|
$ |
495,500 |
|
|
|
|
On February 24, 2006, in conjunction with the Combination, the Company replaced its prior
revolving credit facility and its prior term loan facility with a new revolving credit facility, as
described below. A portion of the initial advance from the new revolving credit facility was used
to repay all funds borrowed under the prior revolving and term credit facilities. Remaining
unamortized fees paid in connection with the issuance of the prior revolving and term credit
facilities were fully expensed into Interest expense in the accompanying consolidated statement of
operations for the six months ended June 30, 2006 when the prior revolving and term credit
facilities were replaced.
1st Lien Credit Facility. As of February 24, 2006, the Company entered into a credit agreement
with a syndicate of banks (the 1st Lien Banks) which provides for a revolving credit facility
(the 1st Lien Credit Facility) with commitments from the 1st Lien Banks aggregating $475 million,
subject to a borrowing base. The borrowing base is calculated based on the Companys oil and gas
reserves. The maturity date of the 1st Lien Credit Facility is February 24, 2010. The Company may
also request the issuance of letters of credit up to $20 million. The borrowing commitment is
reduced by any outstanding letters of credit. The initial advance on the 1st Lien Credit Facility
made on February 27, 2006 was $421 million. The proceeds from this initial advance were used as
follows:
|
|
|
|
|
Cash payment to the Chase Group in the Combination |
|
$ |
400,000,000 |
|
Repay balance on prior revolving credit facility |
|
|
15,900,000 |
|
Bank fees and legal costs |
|
|
5,100,000 |
|
|
|
|
|
|
|
$ |
421,000,000 |
|
|
|
|
|
16
The initial borrowing base was $475 million. The borrowing base components are redetermined
semiannually as of January 1 and June 30 of each year. In addition to the regular redetermination
dates listed above, the 1st Lien Credit Facility required a special redetermination as of April 30,
2006. This special redetermination was conducted during the quarter ended June 30, 2006 by the 1st
Lien Banks and both the borrowing base and the conforming borrowing base were affirmed at their
then current amounts. In addition to the scheduled redeterminations, the Company and the 1st Lien
Banks are each provided the option to request an additional redetermination once between the
scheduled redeterminations.
Advances on the 1st Lien Credit Facility bear interest, at the Companys option, based on (a)
the prime rate of JPMorgan Chase Bank (JPM Prime Rate) (8.25 percent at June 30, 2007) or (b) a
Eurodollar rate (substantially equal to the London Interbank Offered Rate). The interest rates of
Eurodollar rate advances and JPM Prime Rate advances vary, with interest margins ranging from 100 -
225 basis points and 0 125 basis points, respectively, per annum depending on the available
borrowing base utilized. The Company pays commitment fees on the unused portion of the borrowing
base ranging from 25 50 basis points per annum depending on the available borrowing base
utilized. The amount outstanding under this facility at December 31, 2006 was $455.7 million, of
which $432 million was at the Eurodollar rate and $23.7 million was at the JPM Prime Rate. The
amount outstanding under this facility at June 30, 2007 was $305 million, all of which was at the
Eurodollar rate.
The 1st Lien Credit Facility also includes a same-day advance facility under which the Company
may borrow funds on a daily basis from the 1st Lien Banks administrative agent. Advances made on
this same-day basis cannot exceed $25 million and the maturity dates cannot exceed fourteen days.
The interest rate on this facility is the JPM Prime Rate plus the applicable interest margin. There
were no amounts outstanding on this facility at June 30, 2007.
The Companys obligations under the 1st Lien Credit Facility are secured by substantially all
of the Companys oil and gas properties. In addition, all but one of the Companys subsidiaries are
guarantors, and all subsidiary general partners, limited partners and membership interests owned by
the Company and its subsidiaries have been pledged as collateral in the credit agreement. The
credit agreement contains various restrictive covenants and compliance requirements which include
(a) maintenance of certain financial ratios (i) maintenance of a quarterly ratio of total debt to
consolidated earnings before interest expense, income taxes, depletion, depreciation, and
amortization, exploration expense and other noncash income and expenses no greater than 3.5 to 1.0,
amended to 4.0 to 1.0 as of March 27, 2007 and (ii) maintenance of a ratio of current assets to
current liabilities, excluding noncash assets and liabilities related to financial derivatives and
asset retirement obligations, to be no less than 1.0 to 1.0, (b) limits on the incurrence of
additional indebtedness and certain types of liens and (c) restrictions as to merger and sale or
transfer of assets. The Company was in compliance with all covenants of the Credit Facility at June
30, 2007.
On July 6, 2006, the Company entered into the First Amendment to the 1st Lien Credit Facility.
The Amendment allowed the Company to obtain additional financing in the form of a $40 million
second lien term loan.
2nd Lien Credit Facility. On July 6, 2006, the Company entered into an additional credit
agreement for a term loan facility in the amount of $40 million (the 2nd Lien Credit Facility).
The full amount of this facility was funded on the closing date to reduce the amount outstanding
under the 1st Lien Credit Facility by $32.1 million, with the remaining $7.9 million used for
general corporate purposes.
The 2nd Lien Credit Facility provides a $40 million term loan, which bears interest, at the
Companys option, based on (a) the prime rate of Bank of America, N.A. (BOA Prime Rate) (8.25
percent at June 30, 2007) or (b) a Eurodollar rate (substantially equal to the London Interbank
Offered Rate). The interest rates of Eurodollar Rate advances and BOA Prime Rate advances vary,
with interest margins of 400 basis points and 250 basis points, respectively. The Company may
select interest periods on Eurodollar Rate advances of one, two, three, six, nine and twelve
months, subject to availability. Interest is payable at the end of the selected interest period,
but no less frequently than quarterly.
The Company is required to repay $100,000 of the 2nd Lien Credit Facility on the last day of
each calendar quarter beginning September 30, 2006. The amount outstanding under this facility at
December 31, 2006 was $39.8 million. The portion of this facility which is due within the next
twelve months, $400,000, is reflected in Current portion of long-term debt in the accompanying
consolidated balance sheet as of December 31, 2006. On March 27, 2007, the amount outstanding under
2nd Lien Credit Facility was repaid in full.
Refinancing of debt facilities. As of March 27, 2007, the Company amended the 1st Lien Credit
Facility, repaid the 2nd Lien Credit Facility and entered into a new 2nd lien credit facility (the
New 2nd Lien Credit Facility).
The Company entered into the Second Amendment to the 1st Lien Credit Facility on March 27,
2007. The amendment allowed for the incurrence of additional indebtedness in the form of a $200
million second lien term loan. The amendment also redetermined the borrowing base at $375 million
and increased the maximum allowable quarterly ratio of total debt to consolidated
17
earnings before
interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and
other non-cash income and expenses from 3.5 to 1.0 to 4.0 to 1.0. The amount outstanding under
this facility at June 30, 2007 was $305 million, all of which was at the Eurodollar rate.
On March 27, 2007, the Company entered into the New 2nd Lien Credit Facility for a term loan
facility in the amount of $200 million. The full amount of the facility was funded on the closing
date. The New 2nd Lien Credit Facility was issued at a discount of 0.5 percent; thus, the Company
received proceeds of $199.0 million. The proceeds from the borrowing were used to repay the 2nd
Lien Credit Facility in full in the amount of $39.8 million without penalty, reduce the amount
outstanding under the 1st Lien
Credit Facility by $154.0 million, with the remaining $5.2 million used to pay loan fees,
accrued interest and for general corporate purposes.
The New 2nd Lien Credit Facility provides a $200 million term loan, which bears interest, at
the Companys option, based on (a) the BOA Prime Rate (8.25 percent at June 30, 2007) or (b) a
Eurodollar rate (substantially equal to the London Interbank Offered Rate). The interest rates of
Eurodollar rate advances and prime rate advances vary, with interest margins of 375 basis points
and 225 basis points, respectively, until the sooner to occur of an initial public offering by the
Company or the first anniversary of the closing date of the loan; thereafter, interest margins on
Eurodollar rate advances and prime rate advances will be 425 basis points and 275 basis points,
respectively. The Company may select interest periods on Eurodollar rate advances of one, two,
three, six, nine and twelve months, subject to availability. Interest is payable at the end of the
selected interest period, but no less frequently than quarterly.
The Company is required to repay $0.5 million of the New 2nd Lien Credit Facility on the last
day of each calendar quarter beginning June 30, 2007. There are five quarters, or $2,500,000,
classified as Current portion of long-term debt on the consolidated balance sheet as of June 30,
2007, because the end of the second quarter fell on a Saturday. The next business day convention
contained in the credit agreement allowed for the payment to be due on Monday, July 2nd. The
maturity date of the term loan facility is March 27, 2012. The Company has the right to prepay the
outstanding balance under the term loan facility at any time. The Company will not incur a
prepayment penalty on any principal amount prepaid during the first twelve months of the loan. A
two percent prepayment penalty will be incurred on any principal amount prepaid during the second
year following the closing and one percent penalty will be incurred during the third year. After
the third year, no prepayment penalty will be incurred.
Borrowings under the New 2nd Lien Credit Facility are secured by a second lien on the same
assets as are securing the 1st Lien Credit Facility. The second lien is subordinated to liens
securing the 1st Lien Credit Facility. The New 2nd Lien Credit Facility contains various
restrictive covenants including (a) maintenance of certain financial ratios including (i)
maintenance of a quarterly ratio of total debt to consolidated earnings before interest expense,
income taxes, depletion, depreciation, and amortization, exploration expense and other non-cash
income and expenses of less than 4.5 to 1.0, (ii) maintenance of a ratio of current assets to
current liabilities, excluding non-cash assets and liabilities related financial derivatives and
asset retirement obligations, to be greater than 1.0 to 1.0 and (iii) maintenance of a ratio, as of
January 1 and June 30 of each year, of the net present value of the Companys oil and gas
properties to total debt to be greater than 1.5 to 1.0. (b) limits on the incurrence of additional
indebtedness and certain types of liens and (c) restrictions as to merger and sale or transfer of
assets.
The amount outstanding under New 2nd Lien Credit Facility at June 30, 2007 was $199.1 million,
net of a discount of $0.9 million, all of which was at the Eurodollar rate. The Company was in
compliance with all covenants of the New 2nd Lien Credit Facility at June 30, 2007.
The Company paid an arrangement fee of $2.5 million at the date of closing. This fee will be
amortized to Interest expense over the five-year term of the facility beginning in April 2007.
The amendment of the 1st Lien Credit Facility on March 27, 2007, resulted in a $100 million,
or 21 percent, reduction of the borrowing base. As such, the pro rata portion of the
remaining debt issuance costs associated with the 1st Lien Credit Facility, totaling
approximately $766,000, was written off and included in Interest expense in the first
quarter of 2007. The remaining debt issuance costs of $433,000 associated with the 2nd Lien
Credit Facility repaid in full on March 27, 2007, were written off and included in Interest
expense in the first quarter of 2007.
18
Principal maturities of long-term debt outstanding at June 30, 2007 for the six months
ended December 31, 2007 and the years ended December 31, 2008, 2009, 2010 and 2011 and thereafter,
are as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2007 |
|
$ |
1,500 |
|
2008 |
|
|
2,000 |
|
2009 |
|
|
2,000 |
|
2010 |
|
|
307,000 |
|
2011 |
|
|
2,000 |
|
2012 and thereafter |
|
|
190,500 |
|
|
|
|
|
Total |
|
$ |
505,000 |
|
|
|
|
|
Note K. Commitments and contingencies
Daywork drilling contract commitments. The Company signed a daywork drilling contract with a
drilling contractor (Contractor B) on July 20, 2006, that provided the Company exclusive use of
one rig with an operating day rate of $15,500 for a term that commenced on August 1, 2006 and ended
on June 15, 2007. During February 2007, management decided to stack this rig due to budget
modifications. The Company incurred costs of approximately $915,000 and $1,296,000 during the three
and six months ended June 30, 2007, respectively. These costs were minimized as Contractor B
secured work for the rig and refunded the Company the difference between the current operating day
rate pursuant to the contract and the operating day rate received from the new customer.
The Company signed a new daywork drilling contract with Contractor B on June 26, 2007, that
provides the Company exclusive use of one rig for a term that commenced on July 3, 2007 and ends on
January 3, 2008. The Company may direct the rig to locations within the Permian Basin region as
needed. The Company is solely responsible and assumes liability for all consequences of operations
by both parties while on a daywork basis, with the exception that Contractor B is liable for its
employees, subcontractors and invitees. In addition, Contractor B is responsible for pollution or
contamination from their equipment. Contractor B will release the Company of any liability for
negligence of any party in connection with Contractor B. The operating day rate is $14,000. The
operating day rate can be revised to reflect changes in costs incurred by Contractor B for labor
and/or fuel. The contract allows an early termination by the Company with at least a thirty day
notice and a payment of the lump sum termination amount equal to the current operating day rate
less $6,000, multiplied by the days remaining through the end of the contract term. However, if
Contractor B secures work for the subject rig with a new customer prior to the end of the contract
term, Contractor B will rebate the Company the difference between the current operating day rate
pursuant to the contract and the operating day rate received from the new customer.
The Company signed daywork drilling contracts with Silver Oak Drilling, LLC (Silver Oak), an
affiliate of the Chase Group, on August 1, 2006, that provides the Company use of four drilling
rigs for a term that commenced on August 1, 2006 and ends on July 31, 2007. The Company may direct
the rig to locations located in New Mexico as needed. If the Company moves the rig out of certain
New Mexico counties specified in the contract, all effective daywork rates will be increased by an
additional $2,000 per day. The Company is solely responsible and assumes liability for all
consequences of operations by both parties while on a daywork basis, with the exception that Silver
Oak is liable for its employees, subcontractors and invitees. In addition, Silver Oak is
responsible for pollution or contamination from their equipment. Silver Oak will release the
Company of any liability for negligence of any party connected to Silver Oak. The operating day
rate is $14,500 for two of the contracts and $13,500 for the other two contracts. The operating day
rate can be revised to reflect changes in costs incurred by more than 5 percent by Silver Oak for
labor, insurance premiums, fuel, and/or an increase in the number of Silver Oaks personnel needed.
Under the contract, the Company must pay the full operating day rate for each day during the
contract term. Although there is no early termination provision in the contract, Silver Oak has a
duty to mitigate damages to the Company by reasonably attempting to secure replacement contracts
for the rigs if they are released by the Company or if any contract is terminated by Silver Oak
prior to the expiration of the term of the contract. The Company will then be entitled to a 75
percent credit for any revenues received by Silver Oak. Even if the Company releases the rigs, the
Company, with 20 days notice, may withdraw its release and reactivate the contract for the
remainder of the term to the extent the rig has not been committed to a third party in mitigation
of the Companys damages. During February 2007, management decided to stack these four rigs due to
budget modifications. The Company incurred no costs in the three months ended June 30, 2007 and
approximately $2,973,000 during the six months ended June 30, 2007, based on the drilling agreement
described above. As of April 1, 2007, the Company began to utilize all four rigs, in order to
proceed with its 2007 drilling budget.
The Company signed new daywork drilling contracts with Silver Oak on June 19, 2007, that
provides the Company use of four drilling rigs for a term that commences on August 1, 2007 and is
in effect until drilling operations are completed on specified wells or for a term of 1 year. If
any well commenced during the term of the contract is drilling at the expiration of the one year
19
primary term, drilling will continue under the terms of the contract until drilling operations for
that well have been completed. The Company may direct the rig to locations located in New Mexico
as needed. The Company is solely responsible and assumes liability for all consequences of operations by both parties while on a daywork basis, with the
exception that Silver Oak is liable for its employees, subcontractors and invitees. In addition,
Silver Oak is responsible for pollution or contamination from their equipment. Silver Oak will
release the Company of any liability for negligence of any party connected to Silver Oak. The
operating day rate is $14,500 for two of the contracts and $13,500 for the other two contracts. The
operating day rate can be revised to reflect changes in costs incurred by more than 5 percent by
Silver Oak for labor, insurance premiums, fuel, and/or an increase in the number of Silver Oaks
personnel needed. Under the contract, the Company must pay the full operating day rate for each day
during the contract term. Although there is no early termination provision in the contract, Silver
Oak has a duty to mitigate damages to the Company by reasonably attempting to secure replacement
contracts for the rigs if they are released by the Company or if any contract is terminated by
Silver Oak prior to the expiration of the term of the contract. The Company will then be entitled
to a 75 percent credit for any revenues received by Silver Oak. Even if the Company releases the
rigs, the Company, with 20 days notice, may withdraw its release and reactivate the contract for
the remainder of the term to the extent the rig has not been committed to a third party in
mitigation of the Companys damages.
Oil & gas lease extension payment. The Company is party to an agreement which, in part,
governs the exploration activities on the Companys acreage in the Western Delaware Basin shale
play in Culberson County, Texas. The agreement contains a three-well drilling commitment. In
addition to the drilling well requirement, the agreement required the Company to pay an additional
$2.1 million ($150 per net acre for 13,952 net acres) in order to maintain its leasehold position,
with such payment required within 90 days after the completion of the drilling of the third of the
Companys three-well drilling commitment.
As of January 1, 2007, the Company had drilled or was drilling all three of these wells. The
last of the three wells drilled reached total depth on January 19, 2007. On April 17, 2007, the
Company made the payment of $2.1 million described above.
Chase Group accredited and unaccredited investors asset purchase obligation. As discussed in
Note D Business combination, on February 27, 2006, as required by the Combination Agreement, the
Company agreed to purchase working interests in the Chase Group Properties from certain individuals
within the Chase Group. On May 18, 2006, the Company purchased interests in the Chase Group
Properties from ten individuals within the Chase Group who were accredited investors in exchange
for $8.9 million in cash and 111,323 shares of Resources common stock valued at $1.4 million for an
aggregate purchase price of $10.3 million. The value of the common shares issued was $12 per share,
as required by the Combination Agreement. The aggregate purchase price is reflected in Proved
properties in the accompanying consolidated balance sheet at December 31, 2006. This transaction is
included in the aggregate purchase price disclosed in Note D Business combination.
The Company was further obligated to offer to purchase additional interests in the Chase Group
Properties from nine individuals within the Chase Group. In April 2007, the Company satisfied this
obligation by paying $256,000 in cash and issuing 54,230 shares of common stock. The aggregate
purchase price is reflected in Proved properties and the related obligation is reflected in
Chase Group unaccredited investors asset purchase obligation in the accompanying consolidated
balance sheet at December 31, 2006. This transaction is included in the aggregate purchase price
disclosed in Note D Business combination.
Note L. Regulatory matters
From 1984 through 1997, the owners of the Grayburg-Jackson West Cooperative Unit (GJ Unit),
a group of formations and intervals unitized by state regulatory authorities, comprised of
approximately 2,400 acres in Eddy County, New Mexico and which comprises a portion of the Chase
Group Properties, drilled or deepened approximately 70 wells that produced from zones below a depth
approved as the unitized formation. The owners of the working interests in the GJ Unit possessed
the ownership rights entitling them to produce hydrocarbons from the subject producing intervals
below the unitized formation, but had not obtained the necessary regulatory approval (1) as to
certain wells, to drill or deepen below the base of the unitized formation or (2) to produce
hydrocarbons from intervals below the base of the unitized formation and to commingle such
production with production from the unitized formation. In connection with the failure to obtain
the required regulatory approval to produce on a commingled basis from these deeper intervals, the
operators filed incorrect perforation and completion reports with state regulatory authorities, and
filed monthly production reports that did not disclose that hydrocarbons had been produced from
intervals below the unitized formation and that hydrocarbons produced from these deeper intervals
were improperly commingled with production from the unitized formation (although the reports
apparently reflected the actual volumes produced by the wells). As a result, a unit royalty
interest owner in the unitized formation was overpaid and the State of New Mexico, which was the
owner of the royalty interest in the subject producing intervals below the unitized formation, was
underpaid for several years.
On November 15, 2005, MEC filed an application with the New Mexico Oil Conservation Division
(NMOCD) to expand the vertical limit of the unitized formation to include the deeper intervals
that had been accessed, produced and commingled without obtaining regulatory approval. A hearing on
the application was originally scheduled for December 15, 2005, but was continued at the request of
MEC. On February 27, 2006, the combination transaction occurred and, as a result, the Company
acquired the GJ Unit.
20
On April 13, 2006, the NMOCD held a hearing on MECs application to expand the vertical limit
of the unitized formation. Representatives of MEC, acting under the Contract Operator Agreement
with MEC, participated in the hearing and presented testimony during that hearing that intervals below the unitized formation had not been tested
or developed. Based on the application submitted by MEC and the evidence and testimony presented at
the hearing, on June 13, 2006, the NMOCD approved the application and entered its order expanding
the vertical limit of the unitized formation to include certain deeper intervals, including one of
those that had previously been produced and commingled without regulatory approval.
Over the course of developing our drilling program for the Chase Group Properties in July and
August 2006, the Company discovered the existence of these violations and this testimony. Following
further investigation by the Companys employees and discussions with a representative of Chase Oil
and MEC and the Companys counsel, the Company reported these developments to the Companys board
of directors. Because this matter related to ongoing regulatory violations by entities that were
under the control of certain members of the Companys board of directors, the Companys board of
directors determined on September 6, 2006, to form a special committee of the board of directors
that consisted of independent and disinterested non-management directors for the purpose of
investigating the matters identified by the Companys management relating to the GJ Unit. The
special committee engaged separate legal counsel to assist it with its investigation of this
matter. Also, in September 2006, representatives of MEC and the Company met with relevant
regulatory authorities from the State of New Mexico, and voluntarily self-reported the matters
related to the GJ Unit, and the Company filed amended reports to correct prior reporting
inaccuracies.
As a result of these actions, the Company, along with MEC, entered into a settlement agreement
with the New Mexico State Land Office on November 2, 2006 related to the underpayment of royalties
arising from these circumstances. Under the terms of the settlement agreement, MEC paid $615,444 to
the State of New Mexico for underpayment of royalties and interest thereon. The Company was not
required to make any payments under the settlement agreement. Further, on January 22, 2007, the
State of New Mexico advised the Company that there was no basis for a compliance and enforcement
proceeding against the Company and no evidence of a knowing and willful violation of applicable law
by the Company. On January 19, 2007, MEC entered into an Agreed Compliance Order and agreed to pay
a penalty of $250,000 for its violations of applicable rules, regulations and statutes. Finally,
the NMOCD approved the Companys correction of the prior records related to the GJ Unit and, in
February 2007, approved the Companys application to expand the vertical limit of the unitized
formation below the depth of the intervals that had previously been improperly produced and
commingled with production from the unitized formation and to bring all of the wells in the GJ Unit
into compliance with all applicable rules, regulations and statutes.
The special committee of the board of directors examined relevant documents provided by the
Company and its regulatory counsel in New Mexico, conducted interviews of members of management and
heard a presentation from a representative of Chase Oil and MEC. The special committee also
monitored the activities of the Company and the Companys legal counsel during the discussions and
proceedings with relevant New Mexico regulatory authorities. Based on its review of this matter,
the special committee recommended the adoption of certain policies and procedures governing the
operation of all legal proceedings involving the Company as well as a review of the due diligence
processes associated with future acquisitions of properties. The special committee also recommended
certain actions to address corporate governance matters at the Company. Finally, the special
committee reviewed the conduct of the Companys officers and directors to determine whether any
such conduct would indicate that an officer or director was unsuitable to continue in their
position, and the special committee did not determine that any officer or director was unsuitable
to continue in their position with the Company.
Note M. Income taxes
The Company accounts for income taxes in accordance with the provisions of SFAS No. 109
Accounting for Income Taxes. The Company and its subsidiaries file federal corporate income tax
returns on a consolidated basis. The tax returns and the amount of taxable income or loss are
subject to examination by United States federal and state taxing authorities. In determining the
interim period income tax provision, the Company utilizes an estimated annual effective tax rate.
The Company adopted the provisions of FASB Interpretation No. 48 Accounting for Uncertainty
in Income Taxes (FIN 48) an interpretation of FASB Statement No. 109 Accounting for Income
Taxes, on January 1, 2007. At the time of adoption and as of June 30, 2007, the Company did not
have any significant uncertain tax positions requiring recognition in the financial statements.
The tax years 2004 2006 remain subject to examination by major tax jurisdictions.
The Companys provision for income taxes differed from the U.S. statutory rate of 35%
primarily due to state income taxes and non-deductible expenses. The effective income tax rate for
the six months ended June 30, 2007 was 41.1%.
21
Note N. Related parties
Contract operator agreement. On February 27, 2006, the Company signed a contract operator
agreement with MEC, an affiliate of the Chase Group, whereby the Company engaged MEC as contract
operator to provide certain services with respect to the Chase Group Properties. The initial term
of the contract operator agreement was 5 years commencing on March 1, 2006 and ending on February
28, 2011. The Company and MEC entered into a Transition Services Agreement on April 23, 2007, which
terminated the contract operator agreement and under which MEC will provide certain field level
operating services on the Chase Group Properties.
The Company incurred charges from MEC of approximately $5.1 million and $10.2 million for the
three and six months ended June 30, 2007, respectively, for services rendered under the contract
operator agreement.
The Company incurred charges from MEC of approximately $1.3 million for both the three and six
months ended June 30, 2006 for services rendered under the contract operator agreement.
At June 30, 2007, the Company had outstanding invoices payable to MEC of approximately $0.2
million which are reflected in Accounts payablerelated parties in the accompanying consolidated
balance sheet.
At December 31, 2006, the Company had outstanding invoices payable to MEC of approximately
$1.8 million which are reflected in Accounts payablerelated parties in the accompanying
consolidated balance sheet.
Transition Services Agreement. The Company entered into a Transition Services Agreement with
MEC whereby it provides services to the properties in Southeast New Mexico that the Company
acquired from Chase Oil and its affiliates in the Combination. The Transition Services Agreement
replaced the prior Contract Operator Agreement with MEC that the Company entered into in connection
with the initial closing of the Combination. The Company agreed with MEC to terminate the Contract
Operator Agreement in connection with the execution of the Transition Services Agreement on April
23, 2007. Under the Transition Services Agreement, MEC provides field level services, including
pumping, well service oversight and supervision and certain equipment for workover and recompletion
services, at costs prevailing in the area of the subject properties, but not to exceed charges for
comparable services by and among MEC and its affiliates. MEC performed substantially similar
services on behalf of the Company under the Contract Operator Agreement prior to its termination.
The Transition Services Agreement terminates upon the earlier to occur of (i) February 28, 2011;
(ii) the date on which the Company completes the initial sale of its shares of common stock to the
public pursuant to a registration statement filed under the Securities Act of 1933, as amended; or
(iii) a change of control, as defined, or sooner as otherwise provided in the agreement or mutually
agreed upon by the parties. The Transition Services Agreement was terminated effective August 7,
2007 pursuant to the Companys completion of its initial public offering. See Note P Subsequent
events. Accordingly, upon termination, the Companys employees along with third party contractors
have assumed the operation of the subject properties.
Other related party transactions. The Company also has engaged in transactions with certain
other affiliates of the Chase Group, including Silver Oak, an oilfield services company, a supply
company, a drilling fluids supply company, a pipe and tubing supplier, a fixed base operator of
aircraft services and a software company.
The Company incurred charges from these related party vendors of approximately $10.7 million
and $22.1 million for the three and six months ended June 30, 2007, respectively, for services
rendered.
The Company incurred charges from these related party vendors of approximately $11.4 million
and $13.4 million for the three and six months ended June 30, 2006, respectively, for services
rendered.
At June 30, 2007, the Company had outstanding invoices payable to the other related party
vendors identified above of approximately $1.3 million which are reflected in Accounts
payablerelated parties in the accompanying consolidated balance sheets.
At December 31, 2006, the Company had outstanding invoices payable to the other related party
vendors mentioned above of approximately $1.8 million which are reflected in Accounts
payablerelated parties in the accompanying consolidated balance sheet.
Overriding royalty and royalty interests. Certain members of the Chase Group own overriding
royalty interests in certain of the Chase Group Properties. The amount paid attributable to such
interests was approximately $458,000 and $973,000 for the three and six months ended June 30, 2007,
respectively. The amount paid attributable to such interests was approximately $501,000 and
$973,000 for the three and six months ended June 30, 2006.
22
Royalties are paid on certain properties located in Andrews County, Texas to a partnership of which
one of the Companys directors is the General Partner, and who also owns a 3.5% partnership
interest. The Company paid approximately $36,000 and $59,000 for the three and six months ended
June 30, 2007, respectively, and approximately $1,000 for each of the three and six months ended
June 30, 2006. The Company also paid this entity a $24,000 lease bonus during the six months ended
June 30, 2007. The Company had no outstanding invoices payable to this entity as of June 30, 2007
or December 31, 2006.
In April 2005, the Company acquired certain working interests in 46,861 gross (26,908 net)
acres located in Culberson County, Texas from an entity partially owned by a person who became an
executive officer of the Company immediately following such acquisition. In connection with this
acquisition, such entity retained a 2% overriding royalty interest in the acquired properties,
which overriding royalty interest is now owned equally by such officer and a non-officer employee
of the Company. The amount attributable to such interest was approximately $2,000 during the three
and six months ended June 30, 2007. During the three and six months ended June 30, 2007 and 2006,
no payments were made related to this overriding royalty interest.
Prospect participation. Subsequent to the closing of the Combination, the Company acquired
working interests from Caza in certain lands in New Mexico in which Caza owns an interest.
The Company paid Caza approximately $1.8 million for the three and six months ended June 30,
2006 for these interests. Approximately all of the costs were capital prospect costs which are
reflected in Unproved properties in the accompanying consolidated balance sheet at December 31,
2006.
The Company paid Caza approximately $3,000 for the six months ended June 30, 2007 for delay
rentals which are reflected in Unproved properties in the accompanying consolidated balance sheet
at June 30, 2007. There were no amounts paid to Caza during the three months ended June 30, 2007
for these interests.
At June 30, 2007 and December 31, 2006, the Company had no outstanding invoices owed to Caza.
Note O. Net income per share
Basic income per share is computed by dividing net income applicable to common shareholders by
the weighted average number of common shares treated as outstanding for the period. As discussed in
Note G Stockholders equity and stock issued subject to limited recourse notes, agreements to
sell stock to the Officers and certain employees subject to Purchase Notes are accounted for as
options (Bundled Capital Options and Capital Options, respectively). As a result, Bundled
Capital Options and Capital Options are excluded from the weighted average number of common shares
treated as outstanding during each period until the Purchase Notes are paid in full, thus
exercising the options.
The computation of diluted income per share reflects the potential dilution that could occur
if securities or other contracts to issue common stock that are dilutive to income were exercised
or converted into common stock or resulted in the issuance of common stock that would then share in
the earnings of the Company. These amounts include unexercised Bundled Capital Options, Capital
Options, stock options (as issued under the Stock Option Plan of CEHC adopted in 2004 and the Plan
of CRI adopted in 2006, both as described in Note H Stock incentive plan ) and restricted stock.
Potentially dilutive effects are calculated using the treasury stock method.
The CEHC 6% Series A Preferred Stock were entitled to receive an amount equal to its stated
value ($9.00) plus any unpaid dividends upon occurrence of a liquidation event, as defined. In
connection with the Combination on February 24, 2006, a liquidation event occurred. Instead of
receiving the stated value, the holders of the CEHC 6% Series A Preferred Stock agreed to accept
0.75 shares of Resources common stock in exchange for each share of CEHC 6% Series A Preferred
Stock. This was considered to be an induced conversion, as defined in the FASB Emerging Issues Task
Force Topic D-42, The Effect on the Calculation of Earnings per Share for the Redemption or
Induced Conversion of Preferred Stock. The excess of the carrying amount of the CEHC 6% Series A
Preferred Stock over the fair value of the Resources common stock issued is required to be added to
2006 net income to arrive at 2006 net income applicable to common shareholders for the six months
ended June 30, 2006.
23
The following table is a reconciliation of the basic weighted average common shares
outstanding to diluted weighted average common shares outstanding for the three and six months
ended June 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ending |
|
Six months ending |
|
|
June 30, |
|
June 30, |
(in thousands) |
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
57,747 |
|
|
|
54,877 |
|
|
|
56,369 |
|
|
|
39,512 |
|
Dilutive Bundled Capital Options |
|
|
660 |
|
|
|
2,583 |
|
|
|
1,695 |
|
|
|
2,332 |
|
Dilutive Capital Options |
|
|
160 |
|
|
|
187 |
|
|
|
204 |
|
|
|
150 |
|
Dilutive common stock options |
|
|
996 |
|
|
|
696 |
|
|
|
921 |
|
|
|
515 |
|
Dilutive restrictive stock |
|
|
62 |
|
|
|
1 |
|
|
|
71 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
59,625 |
|
|
|
58,344 |
|
|
|
59,260 |
|
|
|
42,509 |
|
|
|
|
For the three and six months ended June 30, 2007 and 2006, the effects of all securities
(including Bundled Capital Options, Capital Options and stock options) were included in the
computation of diluted earnings per share because the Company had net income applicable to common
shareholders and, therefore, there were no antidilutive effects.
For the six months ended June 30, 2006, the effect of 450,000 common stock options were
excluded from the computation of diluted earnings per share because the effect would have been
antidilutive.
Note P. Subsequent events
Initial public offering. On August 7, 2007 the Company completed an initial public offering
(the IPO) of its common stock. The Company sold 13,332,851 shares and certain shareholders,
including our executive officers and members of the Chase Group, sold 7,554,256 shares of Resources
common stock, in each case, at $11.50 per share. After deducting underwriting discounts of
approximately $9.6 million and offering expenses of approximately $4.4 million, the Company
received net proceeds of approximately $139.3 million. In conjunction with the IPO, the
underwriters were granted an option to purchase 3,133,066 additional shares of Resources common
stock. The underwriters fully exercised this option and purchased the additional shares on August
9, 2007. After deducting underwriting discounts of approximately $2.1 million, the Company
received net proceeds of approximately $33.9 million. The aggregate net proceeds of approximately
$173.2 million received by the Company at closing on August 7, 2007 and August 9, 2007 were
utilized as follows:
|
|
|
|
|
Partial prepayment of 1st Lien Credit Facility August 20, 2007 |
|
$ |
86,575,000 |
|
Partial repayment of New 2nd Lien Credit Facility August 9, 2007 |
|
$ |
86,575,000 |
|
Repayment of portion of New 2nd Lien Credit Facility. As mentioned above, IPO
proceeds in the amount of $86.6 million were used to repay a portion of the New 2nd Lien
Credit Facility on August 9, 2007. Subsequent to such repayment the outstanding balance, net of
remaining original issue discount, as of August 9, 2007, was $112.9 million. As set forth by this
facilitys credit agreement and as described in Note J Long-term debt, effective on the
consummation of the IPO, the interest margins on Eurodollar rate advances and prime rate advances
increased to 425 basis points and 275 basis points, respectively.
A pro rata portion of the deferred loan costs associated with the New 2nd Lien
Credit Facility were written off to interest expense in August 2007 in the amount of approximately
$1.0 million. Additionally, a pro rata portion of the unamortized original issue discount related
to the New 2nd Lien Credit Facility was written off to interest expense in August 2007
in the amount of approximately $0.4 million.
Stock option awards. In August 2007, the Companys board of directors approved the issuance
of 215,000 stock options under the Plan. These options have an exercise price of $12.85, a
contractual term of 10 years from the date of grant, and vest using a four year graded vesting
schedule. For more details of the Plan, see Note H Stock incentive plan.
Issuance of restricted stock. In August 2007, the Companys board of directors appointed a
new director who was granted 5,000 shares of restricted common stock by
the Compensation Committee of the Companys board of directors in accordance with the Companys
director compensation plan, subject to certain restrictions as set forth in the Plan and a
restricted stock agreement between the Company and such director. These restrictions lapse with
respect to 100 percent of the restricted shares twelve months from the date of grant. The grant
date fair value of the stock was estimated by the Company to be approximately $64,000, which the
Company will recognize as stock-based compensation expense over twelve months beginning August
2007.
In
September 2007, the Compensation Committee of the Companys board of directors approved
the grant of 112,543 shares of restricted common stock to the non-officer employees of the Company,
subject to certain restrictions as set forth in the Plan and respective restricted stock agreements
between the Company and each such employee. These restrictions lapse with respect to 100 percent
of the restricted shares three years from the date of grant. The grant date fair value of the
stock was estimated by the Company to be approximately $1,620,000 which the Company will recognize
as stock-based compensation expense over the next three years
beginning September 2007. For more
details of the Plan, see Note H Stock incentive plan.
24
Note Q. Supplementary information
Costs incurred for oil and gas producing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
(in thousands) |
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
8,000 |
|
|
$ |
15,826 |
|
|
$ |
8,000 |
|
|
$ |
823,950 |
|
Unproved |
|
|
(4,886 |
) |
|
|
5,564 |
|
|
|
(4,096 |
) |
|
|
215,365 |
|
Exploration |
|
|
30,027 |
|
|
|
8,615 |
|
|
|
41,734 |
|
|
|
14,646 |
|
Development |
|
|
2,072 |
|
|
|
41,812 |
|
|
|
17,373 |
|
|
|
50,587 |
|
Capitalized asset retirement obligations |
|
|
(922 |
) |
|
|
212 |
|
|
|
(1,289 |
) |
|
|
6,403 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred for oil and gas properties |
|
$ |
34,291 |
|
|
$ |
72,029 |
|
|
$ |
61,722 |
|
|
$ |
1,110,951 |
|
|
|
|
25
Item 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist you in understanding our business and
results of operations together with our present financial condition. This section should be read in
conjunction with managements discussion and analysis contained in our Prospectus dated August 2,
2007 and filed with the Securities and Exchange Commission (SEC) pursuant to Rule 424 (b) on
August 3, 2007, as well as with the consolidated financial statements and notes thereto included in
this quarterly report on Form 10-Q.
Statements in our discussion may be forward-looking statements. These forward-looking
statements involve risks and uncertainties. We caution that a number of factors could cause future
production, revenue and expenses to differ materially from our expectations.
Overview
We are an independent oil and natural gas company engaged in the acquisition,
development, exploitation and exploration of oil and natural gas properties. Our conventional
operations are primarily focused in the Permian Basin of Southeast New Mexico and West Texas. These
conventional operations are complemented by our activities in unconventional emerging resource
plays. We intend to grow our reserves and production through development drilling, exploitation and
exploration activities on our multi-year project inventory and through acquisitions that meet our
strategic and financial objectives.
Our operations are primarily concentrated in the Permian Basin, the largest onshore oil and
gas basin in the United States. As of December 31, 2006, 99% of our total estimated net proved
reserves were located in the Permian Basin and consisted of approximately 57% crude oil and 43%
natural gas. This basin is characterized by an extensive production history, mature infrastructure,
long reserve life, multiple producing horizons, enhanced recovery potential and a large number of
operators. The primary producing formation in the Permian Basin under our core properties in
Southeast New Mexico is the Yeso formation, including the Paddock interval, which is located at
depths ranging from 3,800 feet to 5,800 feet, and the Blinebry interval, the top of which is
located approximately 400 feet below the base of the Paddock interval. We have assembled a
multi-year inventory of development drilling and exploitation projects, including further projects
targeting the Yeso formation, that we believe will allow us to grow proved reserves and production.
We have also acquired significant acreage positions in unconventional emerging resource plays,
where we intend to apply horizontal drilling, advanced fracture stimulation and enhanced recovery
technologies.
Factors that significantly affect our results
Our revenue, cash flow from operations and future growth depend substantially on factors
beyond our control, such as economic, political and regulatory developments and competition from
other sources of energy. Oil and natural gas prices have historically been volatile and may
fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could
materially and adversely affect our financial position, our results of operations, the quantities
of oil and gas that we can economically produce and our ability to access capital.
We generally hedge a portion of our expected future oil and natural gas production to reduce
our exposure to fluctuations in commodity price. See Liquidity and capital resourcesHedging for
a discussion of our hedging and hedge positions.
Like all businesses engaged in the exploration and production of oil and natural gas, we face
the challenge of natural production declines. As initial reservoir pressures are depleted, oil and
natural gas production from a given well decreases. Thus, an oil and natural gas exploration and
production company depletes part of its asset base with each unit of oil or natural gas it
produces. We attempt to overcome this natural decline by drilling to find additional reserves and
acquiring more reserves than we produce and by implementing secondary recovery techniques. Our
future growth will depend on our ability to enhance production levels from our existing reserves
and to continue to add reserves in excess of production. We will maintain our focus on costs
necessary to produce our reserves as well as the costs necessary to add reserves through drilling
and acquisitions. Our ability to make capital expenditures to increase production from our existing
reserves and to add reserves through drilling is dependent on our capital resources and can be
limited by many factors, including our ability to access capital in a cost-effective manner and to
timely obtain drilling permits and regulatory approvals.
Items impacting comparability of our financial results
Our historical results of operations for the periods presented may not be comparable,
either from period to period or going forward, for the reasons described below.
26
Combination transaction
We were formed in February 2006 as a result of the combination transaction between Concho
Equity Holdings Corp. and Chase Oil Corporation, Caza Energy LLC (Caza) and certain other parties
thereto (collectively with Chase Oil Corporation and Caza, the Chase Group).
Concho Equity Holdings Corp. is our predecessor for accounting purposes. As a result, our
historical financial statements prior to February 27, 2006, are the financial statements of Concho
Equity Holdings Corp. Concho Equity Holdings Corp. was formed on April 21, 2004, and did not own
any material assets and did not conduct substantial operations other than organizational activities
until it acquired oil and gas properties from Lowe Partners, LP on December 7, 2004 (the Lowe
Acquisition). For a discussion of the results of operations of Concho Resources Inc. (Resources)
(as the accounting successor to Concho Equity Holdings Corp.), please read Results of operations
of Concho Resources Inc.
As of December 31, 2006, approximately 76% of our PV-10 was attributable to the properties
contributed to us by the Chase Group in the combination transaction.
Additional indebtedness and other expenses
During 2006 and 2007, we incurred additional indebtedness and other expenses as a result of
our rapid growth, particularly as a result of the combination transaction. Our historical financial
information prior to February 28, 2006 does not give effect to the results of operation of the
properties contributed by the Chase Group in the combination transaction, as well as, the following
items:
|
|
|
we closed the combination transaction on February 27, 2006 and properties were
contributed to us by the Chase Group that represent approximately 76% of our PV-10 as of
December 31, 2006; |
|
|
|
|
we incurred approximately $405 million of new indebtedness upon the initial closing of
the combination transaction; |
|
|
|
|
we entered into a $200.0 million second lien term loan facility on March 27, 2007, from
which we received proceeds of $199.0 million to repay the $39.8 million outstanding under
our prior term loan facility, to reduce the outstanding balance under our revolving credit
facility by $154.0 million and the remaining $5.2 million to pay loan fees, accrued
interest and for general corporate purposes; and |
|
|
|
|
we have incurred additional general and administrative costs as a result of the
expansion of our technical and administrative staffs and as a result of increased amounts
of professional fees. |
Curtailment of drilling
We determined in January 2007 to reduce our drilling activities for the first three months of
2007. This determination was due to a decline in oil and natural gas prices in January 2007
compared to such prices in the fourth quarter of 2006, the costs of goods and services necessary to
complete our drilling activities and the resulting effect of these circumstances on our expected
cash flow for the three months ended March 31, 2007. In addition, we determined to reduce our
drilling activities and curtail capital expenditures until we were able to complete our second lien
term loan facility in March 2007 in order to preserve liquidity. Also due to the reduced drilling
activities described above, we recorded an expense in the six months ended June 30, 2007 of
approximately $4.3 million for contract drilling fees related to stacked rigs subject to daywork
drilling contracts with two drilling contractors. Approximately $3.0 million of this amount was
paid to Silver Oak Drilling, LLC, which is an affiliate of the Chase Group. We resumed the majority
of our planned drilling activities in April 2007 and all planned drilling activities in June 2007,
and we believe we will spend our revised 2007 exploration and development budget of approximately
$183.0 million during 2007. See Recent events for a discussion of the revised 2007 budget.
Recent events
On June 27, 2007, we were notified that a natural gas processing plant through which we
process and sell a portion of the production from our Shelf Properties in New Mexico was shut-down
for repairs as a result of a storm. Approximately 40 MMcfe per day of our production was shut-in as
a result of this plant shut-down. The plant became fully operational on July 3, 2007, and we
resumed production from all of our properties that had been affected. On July 16, 2007 this plant
was shut-down again for repairs. Approximately 40 MMcfe per day of our production was shut-in as a
result of this plant shut-down. The plant became fully operational on July 20, 2007, and we
resumed production from all of our properties that had been affected.
On August 7, 2007 we completed an initial public offering (the IPO) of our common stock. We
sold 13,332,851 shares and certain shareholders, including our executive officers and members of
the Chase Group, sold 7,554,256 shares of Resources common
27
stock, in each case, at $11.50 per
share. After deducting underwriting discounts of approximately $9.6 million and offering expenses
of approximately $4.4 million, we received net proceeds of approximately $139.3 million. In
conjunction with the IPO, the underwriters were granted an option to purchase 3,133,066 additional
shares of Resources common stock from us. The underwriters fully exercised this option and
purchased the additional shares on August 9, 2007. After deducting underwriting discounts of
approximately $2.1 million, we received net proceeds of approximately $33.9 million. The aggregate
net proceeds of approximately $173.2 million received by us at closing on August 7, 2007 and August
9, 2007 were utilized to repay a portion of the 2nd Lien Credit facility in the amount
of $86.6 million on August 9, 2007,and to prepay a portion of the 1st Lien Credit
Facility in the amount of $86.6 million on August 20, 2007. A pro rata portion of the deferred
loan costs associated with the 2nd Lien Credit facility were written off to interest
expense in August 2007 in the amount of approximately $1.0 million. Additionally, a pro rata
portion of the unamortized original issue discount related to the 2nd Lien Credit
facility was written off to interest expense in August 2007 in the amount of approximately $0.4
million.
On August 16, 2007, our board of directors approved an increase in its 2007 exploration and
development budget in the amount of $29 million from $154 million to $183 million. Our 2007
capital budget is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
Original |
|
Revised |
(in millions) |
|
Budget |
|
Budget |
|
Drilling and recompletion opportunities in our core operating area |
|
$ |
119.4 |
|
|
$ |
135.2 |
|
Projects in our emerging plays |
|
|
15.7 |
|
|
|
28.9 |
|
Projects operated by third parties |
|
|
14.2 |
|
|
|
14.2 |
|
Acquisition of leasehold acreage and other property interests |
|
|
4.7 |
|
|
|
4.7 |
|
|
|
|
|
|
$ |
154.0 |
|
|
$ |
183.0 |
|
|
|
|
We anticipate that this incremental $29 million in its 2007 exploration and development budget
will be funded by utilizing availability under our revolving credit facility.
28
Results of operations of Concho Resources Inc.
The following table presents selected financial and operating information of Concho
Resources Inc. (as successor to Concho Equity Holdings Corp.) for the three and six months ended
June 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
|
|
2007 |
|
2006 |
|
2007 |
|
2006 |
(in thousands, except price data) |
|
(unaudited) |
|
(unaudited) |
|
Oil sales |
|
$ |
43,096 |
|
|
$ |
34,094 |
|
|
$ |
82,467 |
|
|
$ |
50,498 |
|
Natural gas sales |
|
|
23,007 |
|
|
|
17,624 |
|
|
|
43,982 |
|
|
|
26,872 |
|
|
|
|
Total operating revenues |
|
|
66,103 |
|
|
|
51,718 |
|
|
|
126,449 |
|
|
|
77,370 |
|
Operating costs and expenses |
|
|
46,324 |
|
|
|
31,598 |
|
|
|
88,262 |
|
|
|
55,624 |
|
Interest, net and other revenue |
|
|
9,866 |
|
|
|
7,933 |
|
|
|
20,276 |
|
|
|
11,240 |
|
|
|
|
Income before income taxes |
|
|
9,913 |
|
|
|
12,187 |
|
|
|
17,911 |
|
|
|
10,506 |
|
Income tax expense |
|
|
(3,988 |
) |
|
|
(4,566 |
) |
|
|
(7,363 |
) |
|
|
(4,313 |
) |
|
|
|
Net income |
|
$ |
5,925 |
|
|
$ |
7,621 |
|
|
$ |
10,548 |
|
|
$ |
6,193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
|
730 |
|
|
|
580 |
|
|
|
1,438 |
|
|
|
893 |
|
Natural gas (MMcf) |
|
|
2,953 |
|
|
|
2,502 |
|
|
|
5,905 |
|
|
|
3,916 |
|
Natural gas equivalent (MMcfe) |
|
|
7,330 |
|
|
|
5,985 |
|
|
|
14,536 |
|
|
|
9,273 |
|
Average prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without hedges ($/Bbl) |
|
$ |
60.15 |
|
|
$ |
64.04 |
|
|
$ |
57.16 |
|
|
$ |
61.48 |
|
Oil, with hedges ($/Bbl) |
|
$ |
59.07 |
|
|
$ |
58.73 |
|
|
$ |
57.33 |
|
|
$ |
56.56 |
|
Natural gas, without hedges ($/Mcf) |
|
$ |
7.77 |
|
|
$ |
6.93 |
|
|
$ |
7.42 |
|
|
$ |
6.87 |
|
Natural gas, with hedges ($/Mcf) |
|
$ |
7.79 |
|
|
$ |
7.04 |
|
|
$ |
7.45 |
|
|
$ |
6.86 |
|
Natural gas equivalent, without hedges ($/Mcfe) |
|
$ |
9.12 |
|
|
$ |
9.11 |
|
|
$ |
8.67 |
|
|
$ |
8.82 |
|
Natural gas equivalent, with hedges ($/Mcfe) |
|
$ |
9.02 |
|
|
$ |
8.64 |
|
|
$ |
8.70 |
|
|
$ |
8.34 |
|
|
|
|
|
|
|
Bbl Barrel |
|
MBbl Thousand Barrels |
|
Mcf Thousand cubic feet |
|
MMcf Million cubic feet |
|
Mcfe Thousand cubic feet of natural gas equivalent (computed on an energy equivalent
basis of one Bbl equals six Mcf) |
|
MMcfe Million cubic feet of natural gas equivalent (computed on an energy equivalent
basis of one Bbl equals six Mcf) |
29
Three months ended June 30, 2007, compared to three months ended June 30, 2006
Oil and gas revenues. Revenue from oil and gas operations for the three months ended
June 30, 2007 were $66,103,000, a $14,385,000 (28%) increase from $51,718,000 for the three months
ended June 30, 2006. This increase was primarily due to successful drilling efforts during 2006 and
2007. Total production for the three months ended June 30, 2007 was 7,330 MMcfe, a 1,345 MMcfe
(22%) increase from 5,985 MMcfe for the three months ended June 30, 2006. Total production during
the three months ended June 30, 2007 was reduced by approximately 160 MMcfe as a result of the
temporary shut-down of a natural gas processing plant through which we process and sell a portion
of our production. See Items impacting comparability of our financial results Recent events.
In addition, average realized oil prices (after giving effect to hedging activities) were $59.07
per Bbl during the three months ended June 30, 2007, an increase of 1% from $58.73 per Bbl during
the three months ended June 30, 2006; average realized natural gas prices (after giving effect to
hedging activities) were $7.79 per Mcf during the three months ended June 30, 2007, an increase of
11% from $7.04 per Mcf during the three months ended June 30, 2006; and average realized natural
gas equivalent prices (after giving effect to hedging activities) were $9.02 per Mcfe during the
three months ended June 30, 2007, an increase of 4% from $8.64 per Mcfe during the three months
ended June 30, 2006.
Hedging activities. The oil and gas prices that we report are based on the market price
received for the commodities adjusted to give effect to the results of our cash flow hedging
activities. We utilize commodity derivative instruments (swaps and zero cost collar option
contracts) in order to (1) reduce the effect of the volatility of price changes on the commodities
we produce and sell, (2) support our annual capital budgeting and expenditure plans and (3) lock-in
commodity prices to protect economics related to certain capital projects. During the three months
ended June 30, 2007, our commodity price hedges decreased oil revenues by $783,000 ($1.07 per Bbl)
and increased gas revenues by $49,000 ($0.02 per Mcf). During the three months ended June 30, 2006,
our commodity price hedges decreased oil revenues by $3,079,000 ($5.30 per Bbl) and increased gas
revenues by $282,000 ($0.11 per Mcf).
The effect of the commodity price hedges in decreasing oil revenues during the three months
ended June 30, 2007 less than their effect of decreasing of oil revenues during the three months
ended June 30, 2006 was the result of (1) a larger amount of hedged volumes in 2006 of 337,000 Bbls
as compared to 2007 of 268,000 Bbls and (2) a higher market price of NYMEX crude oil in 2006 of
$70.65 per Bbl as compared to the 2007 price of $65.08 per Bbl. The effect of commodity price
hedges in increasing gas revenues during the three months ended June 30, 2007 less than their
effect of increasing gas revenues during the three months ended June 30, 2006 was the result of (1)
a larger amount of hedged volumes in 2006 of 1,684,000 MMBtus as compared to 2007 of 1,647,000
MMBtus and (2) a lower reference market price of natural gas in 2006 of $5.55 per MMBtu as compared
to the 2007 price of $6.59 per MMBtu.
Production expenses. Production expenses (including production taxes) were $12,206,000 ($1.67
per Mcfe) for the three months ended June 30, 2007, a $2,919,000 (31%) increase from $9,287,000
($1.55 per Mcfe) for the three months ended June 30, 2006. The increase in production
expenses is due to costs associated with new wells that were successfully completed in 2006 and
2007 as a result of our drilling activities. Lease operating expenses and workover costs comprised
approximately 57% and 54% of production expenses for the three months ended June 30, 2007 and 2006,
respectively. These costs per unit of production were $0.95 per Mcfe during the three months ended
June 30, 2007, an increase of 12% from $0.85 per Mcfe during the three months ended June 30, 2006.
This is primarily due to an increase in the cost of contract labor, storage tank maintenance,
electrical work, and well service and repair. Lease operating expenses include ad valorem taxes
that are affected by commodity price changes and ad valorem tax rates. Ad valorem taxes were
approximately 5% of lease operating expenses for both the three months ended June 30, 2007 and
2006.
The secondary component of production expenses is production taxes and is directly related to
commodity price changes. These costs comprised approximately 43% and 46% of production expenses
during the three months ended June 30, 2007 and 2006, respectively. Production taxes per unit of
production were $0.72 per Mcfe during the three months ended June 30, 2007, an increase of 1% from
$0.71 per Mcfe during the three months ended June 30, 2006. This increase was primarily due to an
increase in average natural gas equivalent prices received by the Company.
30
Exploration and abandonments expense. The following table provides a breakdown of our
exploration and abandonments expense for the three-month period ended June 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
June 30, |
|
|
2007 |
|
2006 |
(in thousands) |
|
(unaudited) |
|
(unaudited) |
|
Geological and geophysical |
|
$ |
225 |
|
|
$ |
163 |
|
Exploratory dry holes |
|
|
5,635 |
|
|
|
329 |
|
Leasehold abandonments and other |
|
|
4 |
|
|
|
3 |
|
|
|
|
Total exploration and abandonments |
|
$ |
5,864 |
|
|
$ |
495 |
|
|
|
|
Our geological and geophysical expense, which primarily consists of general and
administrative costs for our geology department as well as seismic data, geophysical data and core
analysis, during the three months ended June 30, 2007 was $225,000, an increase of $62,000 from
$163,000 for the three months ended June 30, 2006. This 38% increase is attributable to a core
analysis purchased in the second quarter of 2007.
Our exploratory dry holes expense during the three months ended June 30, 2007 is primarily
attributable to three operated exploratory wells that were unsuccessful. The costs associated with
one of these wells drilled in the Western Delaware Basin in Culberson County, Texas approximated
$2.8 million. Another of these wells, which was drilled in the Southeastern New Mexico Basin in Lea
County, New Mexico, had costs of approximately $2.0 million. An additional $0.8 million was charged
to exploratory dry hole costs relative to a target zone in the third of these wells in the
Southeastern New Mexico Basin in Eddy County, New Mexico which was determined to be dry. This well
is currently being completed in a shallower zone which was found to be productive.
Our exploratory dry holes expense during the three months ended June 30, 2006 was attributable
to one unsuccessful operated exploratory well located in Gaines County, Texas.
We had minimal leasehold abandonments during the three months ended June 30, 2007 and 2006.
Depreciation and depletion expense. Depreciation and depletion expense was $17,609,000 ($2.40
per Mcfe) for the three months ended June 30, 2007, an increase of $2,352,000 from $15,257,000
($2.55 per Mcfe) for the three months ended June 30, 2006. The decrease in depreciation and
depletion expense per Mcfe was primarily due to an increase in proved oil and natural gas reserves
as a result of our successful development and exploratory drilling program.
Impairment of oil and gas properties. In accordance with SFAS No. 144 Accounting for the
Impairment or Disposal of Long-Lived Assets, we review our long-lived assets to be held and used,
including proved oil and gas properties accounted for under the successful efforts method of
accounting. As a result of this review of the recoverability of the carrying value of our assets
during the three months ended June 30, 2007, we recognized a non-cash charge against earnings of
$2,085,000, primarily related to a well drilled on acreage in Schleicher County, Texas. For the
three months ended June 30, 2006, we recognized a non-cash charge against earnings of $2,978,000,
51% of which related to a property acquired in our Lowe Acquisition in December 2004 located in
Pecos County, Texas and 33% related to a well drilled in Lea County, New Mexico.
Contract drilling fees stacked rigs. As discussed above under Items impacting
comparability of our financial results Curtailment of drilling, we determined in January 2007 to
reduce our drilling activities for the first three months of 2007. We resumed the majority of our
planned drilling activities in April 2007 and all planned drilling activities in June 2007. As a
result, for the drilling rigs that remained stacked, we recorded an expense during the three months
ended June 30, 2007 of approximately $915,000 for contract drilling fees related to stacked rigs
subject to daywork drilling contracts with two drilling contractors. These costs were minimized as
one contractor secured work for a rig for 26 days during the quarter and charged us the difference
between the current operating day rate pursuant to the contract and the lower operating day rate
received from the new customer.
General and administrative expenses. General and administrative expenses were $7,629,000
($1.04 per Mcfe) for the three months ended June 30, 2007, an increase of $4,476,000 (142%) from
$3,153,000 ($0.53 per Mcfe) for the three months ended June 30, 2006. Excluding non-cash
stock-based compensation of $1,128,000 during the three months ended June 30, 2007 and $329,000
during the three months ended June 30, 2006, general and administrative expenses would have been
$6,501,000 ($0.89 per Mcfe) for the three months ended June 30, 2007, an increase of $3,677,000
(130%) from $2,824,000 ($0.47 per Mcfe) for the three months ended June 30, 2006. The increase in
general and administrative expense during the three months ended June 30, 2007 was
31
due (i) to the
increase in the size and complexity of our operations following the combination transaction and
related increase in professional fees, and (ii) annual bonuses in the aggregate amount of
$2,529,000 paid to the officers and employees in April 2007 as approved by the Compensation
Committee of the board of directors.
We earn revenue as operator of certain oil and gas properties in which we own interests. As
such, we earned revenue of $221,000 and $188,000 during the three months ended June 30, 2007 and
2006, respectively. This revenue is reflected as a reduction of general and administrative expenses
in the accompanying consolidated statements of operations.
Interest expense. Interest expense was $10,074,000 for the three months ended June 30, 2007,
an increase of $1,870,000 from $8,204,000 for the three months ended June 30, 2006. The weighted
average interest rate for the three months ended June 30, 2007 and 2006 was 7.8% and 7.3%,
respectively. The weighted average debt balance during the three months ended June 30, 2007 and
2006 was approximately $506,147,000 and $454,435,000, respectively. The increase in interest
expense was due to the increase in overall debt outstanding and an increase in interest rates. The
increase in weighted average debt balance during the three months ended June 30, 2007 was primarily
due to our borrowing under our revolving credit facility to fund our drilling activities.
Income tax provisions. We recorded an income tax expense of $3,988,000 and $4,566,000 for the
three months ended June 30, 2007 and 2006, respectively. The income tax expense was due to the
income reported during the three months ended June 30, 2007 and 2006. The effective income tax rate
for the three months ended June 30, 2007 and 2006 was 40.2% and 37.5%, respectively.
We had a net deferred tax liability of $245,781,000 and $241,670,000 at June 30, 2007 and
December 31, 2006, respectively. The net liability balance is primarily due to differences in basis
and depletion of oil and gas properties for tax purposes as compared to book purposes related to
the acquisition of the Chase Group Properties in February 2006. The net change is due to 2007
intangible drilling costs which are allowed by the Internal Revenue Service as deductions and are
capitalized under generally accepted accounting principles in the United States of America,
partially offset by an increase in deferred hedge losses.
Six months ended June 30, 2007, compared to six months ended June 30, 2006
Oil and gas revenues. Revenue from oil and gas operations was $126,449,000 for the six
months ended June 30, 2007, an increase of $49,079,000 (63%) from $77,370,000 for the six months
ended June 30, 2006. This increase was primarily because of increased production as a result of the
acquisition of the Chase Group Properties and secondarily due to successful drilling efforts during
2006 and 2007. Total production was 14,536 MMcfe for the six months ended June 30, 2007, an
increase of 5,263 MMcfe (57%) from 9,273 MMcfe for the six months ended June 30, 2006. Total
production during the six months ended June 30, 2007 was reduced by approximately 160 MMcfe as a
result of the temporary shut-down of a natural gas processing plant through which we process and
sell a portion of our production. See Items impacting comparability of our financial results
Recent events. The increases in revenue and production attributable to the acquired Chase Group
Properties between 2006 and 2007 were $26,600,000 and 3,259 MMcfe, respectively. In addition,
average realized oil prices (after giving effect to hedging activities) were $57.33 per Bbl during
the six months ended June 30, 2007, an increase of 1% from $56.56 per Bbl during the six months
ended June 30, 2006; average realized natural gas prices (after giving effect to hedging
activities) were $7.45 per Mcf during the six months ended June 30, 2007, an increase of 9% from
$6.86 per Mcf during the six months ended June 30, 2006; and average realized natural gas
equivalent prices (after giving effect to hedging activities) were $8.70 per Mcfe during the six
months ended June 30, 2007, an increase of 4% from $8.34 per Mcfe during the six months ended June
30, 2006.
Hedging activities. The oil and gas prices that we report are based on the market price
received for the commodities adjusted to give effect to the results of our cash flow hedging
activities. We utilize commodity derivative instruments (swaps and zero cost collar option
contracts) in order to (1) reduce the effect of the volatility of price changes on the commodities
we produce and sell, (2) support our annual capital budgeting and expenditure plans and (3) lock-in
commodity prices to protect economics related to certain capital projects. During the six months
ended June 30, 2007, our commodity price hedges increased oil revenues by $244,000 ($0.17 per Bbl)
and increased gas revenues by $187,000 ($0.03 per Mcf). During the six months ended June 30, 2006,
our commodity price hedges decreased oil revenues by $4,394,000 ($4.92 per Bbl) and decreased gas
revenues by $26,000 ($0.01 per Mcf).
The effect of the commodity price hedges in increasing oil revenues during the six months
ended June 30, 2007 as compared to reducing oil revenues during the six months ended June 30, 2006
was the result of (1) increased hedged volumes from 400,000 Bbls in 2006 to 534,000 Bbls in 2007,
(2) a decrease in the market price of NYMEX crude oil from an average of $67.02 per Bbl in 2006 to
$61.70 per Bbl in 2007 and (3) a higher weighted average fixed price on the active derivative
contracts of $62.10 in 2007 as compared to $58.52 in 2006. The effect of the commodity price
hedges in increasing gas revenues during the six months ended June 30, 2007 as compared to reducing
gas revenues during the six months ended June 30, 2006 was the result of (1) increased hedged
volumes from 2,044,000 MMBtus in 2006 to 3,152,000 MMBtus in 2007, (2) a slight increase in the
reference market price of natural gas from an average of $6.35 per MMBtu in 2006 to $6.46 per MMBtu
in 2007 and (3) a higher weighted average floor price on the active zero cost collar option
contracts of $5.98 in 2007 as compared to $5.53 in 2006.
32
Production expenses. Production expenses (including production taxes) were $24,152,000 ($1.66
per Mcfe) for the six months ended June 30, 2007, an increase of $8,955,000 (59%) from $15,197,000
million ($1.64 per Mcfe) for the six months ended June 30, 2006. The increase in production
expenses is from to two sources: (1) production expenses associated with the Chase Group Properties
acquired in February 2006 of approximately $2,907,000 and (2) production expenses associated with
new wells that were
successfully completed in 2006 and 2007 as a result of our drilling activities. Lease
operating expenses and workover costs comprised approximately 59% of production expenses for both
the six months ended June 30, 2007 and 2006. These costs per unit of production were $0.98 per Mcfe
during the six months ended June 30, 2007, an increase of 1% from $0.97 per Mcfe during the six
months ended June 30, 2006. Lease operating expenses include ad valorem taxes that are affected by
commodity price changes and ad valorem tax rates. Ad valorem taxes were approximately 7% and 5% of
lease operating expenses for the six months ended June 30, 2007 and 2006, respectively.
The secondary component of production expenses is production taxes and is directly related to
commodity price changes. These costs comprised approximately 41% of production expenses during both
the six months ended June 30, 2007 and 2006. Production taxes per unit of production were $0.68 per
Mcfe during the six months ended June 30, 2007, an increase of 2% from $0.67 per Mcfe during the
six months ended June 30, 2006. This increase was primarily due to an increase in average natural
gas equivalent prices received by the Company.
Exploration and abandonments expense. The following table provides a breakdown of our
exploration and abandonments expense for the six-month period ended June 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
June 30, |
|
|
2007 |
|
2006 |
(in thousands) |
|
(unaudited) |
|
(unaudited) |
|
Geological and geophysical |
|
$ |
624 |
|
|
$ |
1,035 |
|
Exploratory dry holes |
|
|
5,665 |
|
|
|
363 |
|
Leasehold abandonments and other |
|
|
16 |
|
|
|
3 |
|
|
|
|
Total exploration and abandonments |
|
$ |
6,305 |
|
|
$ |
1,401 |
|
|
|
|
Our geological and geophysical expense, which primarily consists of general and
administrative costs for our geology department as well as seismic data, geophysical data and core
analysis, during the six months ended June 30, 2007 was $624,000, a decrease of $411,000 from
$1,035,000 for the six months ended June 30, 2006. This 40% decrease is attributable to a data
license and a core analysis purchased in the first quarter of 2006.
Our exploratory dry holes expense during the six months ended June 30, 2007 is primarily
attributable to three operated exploratory wells that were unsuccessful. The costs associated with
one of these wells drilled in the Western Delaware Basin in Culberson County, Texas approximated
$2.8 million. Another of these wells, which was drilled in the Southeastern New Mexico Basin in Lea
County, New Mexico, had costs of approximately $2.0 million. An additional $0.8 million was charged
to exploratory dry hole costs relative to a target zone in the third of these wells in the
Southeastern New Mexico Basin in Eddy County, New Mexico which was determined to be dry. This well
is currently being completed in a shallower zone which was found to be productive.
Our exploratory dry holes expense during the six months ended June 30, 2006 was primarily
attributable to one unsuccessful operated exploratory well located in Gaines County, Texas.
We had minimal leasehold abandonments during the six months ended June 30, 2007 and 2006.
Depreciation and depletion expense. Depreciation and depletion expense was $37,033,000 ($2.55
per Mcfe) for the six months ended June 30, 2007, an increase of $14,537,000 from $22,496,000
($2.43 per Mcfe) for the six months ended June 30, 2006. The increase in depreciation and depletion
expense and the increase in depreciation and depletion expense per Mcfe was primarily due to the
acquisition of the Chase Group Properties and related acquisition costs associated with the
combination transaction.
Impairment of oil and gas properties. In accordance with SFAS No. 144, we review our long-lived assets to be held and used,
including proved oil and gas properties accounted for under the successful efforts method of
accounting. As a result of this review of the recoverability of the carrying value of our assets
during the six months ended June 30,
33
2007, we recognized a non-cash charge against earnings of
$3,198,000, 63% of which related to a well drilled on acreage in Schleicher County, Texas, and 12%
of which related to a well drilled on acreage in Mountrail County, North Dakota. Of the total
amount, $164,000 was related to the Chase Group Properties. For the six months ended June 30, 2006,
we recognized a non-cash charge against earnings of $3,083,000, 50% of which related to a property
acquired in our Lowe Acquisition in December 2004 located in
Pecos County, Texas and 32% related to
a well drilled on acreage in Lea County, New Mexico.
Contract drilling fees stacked rigs. As discussed above under Items impacting
comparability of our financial results Curtailment of drilling, we determined in January 2007 to
reduce our drilling activities for the first three months of 2007. As a result, we recorded an
expense during the six months ended June 30, 2007 of approximately $4,269,000 for contract drilling
fees related to stacked rigs subject to daywork drilling contracts with two drilling contractors.
We resumed the majority of our planned drilling activities in April 2007 and all planned drilling
activities in June 2007. These costs were minimized during the first six months of 2007 as one
contractor secured work for a rig for 71 days during the six months and charged us the difference
between the current operating day rate pursuant to the contract and the lower operating day rate
received from the new customer.
General and administrative expenses. General and administrative expenses were $11,921,000
($0.82 per Mcfe) for the six months ended June 30, 2007, a decrease of $291,000 (2%) from
$12,212,000 ($1.32 per Mcfe) for the six months ended June 30, 2006. Excluding non-cash stock-based
compensation of $1,953,000 during the six months ended June 30, 2007 and $6,951,000 during the six
months ended June 30, 2006, general and administrative expenses would have been $9,968,000 ($0.69
per Mcfe) for the six months ended June 30, 2007, an increase of $4,707,000 (89%) from $5,261,000
($0.57 per Mcfe) for the six months ended June 30, 2006. The increase in general and administrative
expense during the six months ended June 30, 2007 was primarily due to the increase in the size and
complexity of our operations following the combination transaction and related increase in
professional fees. In addition, annual bonuses in the aggregate amount of $2,529,000 were paid to
the officers and employees in April 2007 as compared to $907,000 aggregate bonuses paid to
employees in February 2006, all of which were approved by the
Compensation Committee of the board
of directors.
We earn revenue as operator of certain oil and gas properties in which we own interests. As
such, we earned revenue of $630,000 and $421,000 during the six months ended June 30, 2007 and
2006, respectively. This revenue is reflected as a reduction of general and administrative expenses
in the consolidated statements of operations.
Interest expense. Interest expense was $20,749,000 for the six months ended June 30, 2007, an
increase of $8,935,000 from $11,814,000 for the six months ended June 30, 2006. The weighted
average interest rate for the six months ended June 30, 2007 and 2006 was 7.8% and 7.3%,
respectively. The weighted average debt balance during the six months ended June 30, 2007 and 2006
was approximately $501,314,000 and $326,325,000, respectively. The increase in interest expense was
due to the increase in overall debt outstanding and an increase in interest rates. The increase in
weighted average debt balance during the six months ended June 30, 2007 was primarily due to our
borrowing under our revolving credit facility to fund the cash portion of the combination
transaction on February 27, 2006, and to fund our drilling activities.
Income tax provisions. We recorded income tax expense of $7,363,000 and $4,313,000 for the
six months ended June 30, 2007 and 2006, respectively. The income tax expense was due to the income
reported during the six months ended June 30, 2007 and 2006. The effective income tax rate for both
the six months ended June 30, 2007 and 2006 was 41.1%.
We had a net deferred tax liability of $245,781,000 and $241,670,000 at June 30, 2007 and December
31, 2006, respectively. The net liability balance is primarily due to differences in basis and
depletion of oil and gas properties for tax purposes as compared to book purposes related to the
acquisition of the Chase Group Properties in February 2006. The net change is due to 2007
intangible drilling costs which are allowed by the Internal Revenue Service as deductions and are
capitalized under generally accepted accounting principles in the United States of America,
partially offset by an increase in deferred hedge losses.
Liquidity and capital resources
Our primary sources of liquidity for the six months ended June 30, 2007 have been cash
flows generated from operating activities and financing provided by our bank credit facilities. As
discussed in Items impacting comparability of our financial results Recent events, in August
2007 we received aggregate net proceeds of $173.2 million from the sale of common stock and
utilized such proceeds to repay a portion of our outstanding indebtedness. We believe that funds
from operating cash flows and our bank credit facilities should be sufficient to meet both our
short-term working capital requirements and our revised 2007 exploration and development budget.
Cash flow from operating activities
Our net cash provided by operating activities was $63.6 million and $33.4 million for the six
months ended June 30, 2007 and 2006, respectively. The increase in operating cash flows during the
six months ended June 30, 2007 was principally due the
34
increase in oil and gas sales, net of
production costs for the six months ended June 30, 2007 as compared to the six months ended June
30, 2006, as a result of our successful development and exploratory drilling program and to the
Chase Group Properties that we acquired in the combination transaction in February 2006.
Cash flow used in investing activities
During
the six months ended June 30, 2007 and 2006, we invested
$70.1 million and $497.4
million, respectively, for additions to, and acquisitions of, oil and gas properties, inclusive of
dry hole costs. Cash flows used in investing activities were substantially higher during the six
months ended June 30, 2006, primarily due to the $409 million cash portion of the consideration we
paid to the Chase Group in the combination transaction. We determined to reduce our drilling
activities and curtail capital expenditures during the three months ended March 31, 2007 until we
were able to complete our second lien term loan facility in March 2007 in order to preserve
liquidity. See Items impacting comparability of our financial resultsCurtailment of drilling
above.
Cash flow from financing activities
Net cash provided by financing activities was $16.3 million and $455.3 million for the six
months ended June 30, 2007 and 2006, respectively. Cash provided by financing activities in the six
months ended June 30, 2006 was primarily due to borrowings under our revolving credit facility to
fund the approximate $409 million cash portion of the consideration paid to the Chase Group
pursuant to the combination transaction and proceeds from private issuances of equity in our
company.
Bank credit facilities
We have two separate bank credit facilities. The first bank credit facility is our Credit
Agreement, dated as of February 24, 2006, with JPMorgan Securities Inc. as the administrative agent
for a group of lenders that provides a revolving line of credit having a maximum facility amount of
$750 million, which we refer to as the revolving credit facility. The total amount that we can
borrow and have outstanding at any one time is limited to the lesser of the maximum facility amount
of $750 million or the borrowing base established by the lenders. As of June 30, 2007, the
borrowing base under our revolving credit facility was $375 million. As of June 30, 2007, the
principal amount outstanding under our revolving credit facility was $305.0 million. In February
2006, we incurred borrowings of approximately $421.0 million under our revolving credit facility in
connection with the combination transaction to pay the cash purchase price of $400.0 million to the
Chase Group, $15.9 million to repay the balance on the prior revolving credit facility of Concho
Equity Holdings Corp. and approximately $5.1 million for bank fees and legal costs associated with
our revolving credit facility. We also incurred borrowings of approximately $8.9 million in May
2006 in connection with the purchase of additional working interests in the Chase Group Properties
pursuant to the combination transaction from persons associated with the Chase Group. The remaining
borrowings under our revolving credit facility during 2006 and the six months ended June 30, 2007
were used for working capital and to fund a portion of our exploration and development drilling
program.
The second bank credit facility is our Second Lien Credit Agreement, dated as of March 27,
2007, with Bank of America, N.A., as the administrative agent for the other lenders thereunder,
that provides a five year term loan in the amount of $200.0 million, which we refer to as the
second lien term loan facility. Upon execution of the second lien term loan facility, we funded
the full amount under that facility and received proceeds of $199.0 million to repay the $39.8
million outstanding under our prior term loan facility, to reduce the outstanding balance under our
revolving credit facility by $154.0 million and the remaining $5.2 million to pay loan fees,
accrued interest and for general corporate purposes. As mentioned in Items impacting comparability
of our financial results Recent Events, we repaid $86.6 million of this facility on August 9,
2007 with proceeds from our initial public offering of common stock.
Revolving credit facility. The revolving credit facility allows us to borrow, repay and
reborrow amounts available under the revolving credit facility. The amount of the borrowing base is
based primarily upon the estimated value of our oil and natural gas reserves. The borrowing base
under our revolving credit facility is re-determined at least semi-annually. The revolving credit
facility matures on February 24, 2010, and borrowings under our revolving credit facility bear
interest, payable quarterly, at our option, at (1) a rate (as defined and further described in our
revolving credit facility) per annum equal to a Eurodollar Rate (which is substantially the same as
the London Interbank Offered Rate) for one, two, three or six months as offered by the lead bank
under our revolving credit facility, plus an applicable margin ranging from 100 to 225 basis
points, or (2) such banks Prime Rate, plus an applicable margin ranging from 0 to 125 basis
points, dependent in each case upon the percentage of our available borrowing base then utilized.
Our revolving credit facility bore interest at 6.86% per annum as of June 30, 2007. We pay
quarterly commitment fees under our revolving credit facility on the unused portion of the
available borrowing base ranging from 25 to 50 basis points, dependent upon the percentage of our
available borrowing base then utilized.
Borrowings under our revolving credit facility are secured by a first lien on substantially
all of our assets and properties. Our revolving credit facility also contains restrictive covenants
that may limit our ability to, among other things, pay cash dividends, incur
35
additional
indebtedness, sell assets, make loans to others, make investments, enter into mergers involving our
company, incur liens and engage in certain other transactions without the prior consent of the
lenders. The revolving credit facility also requires us to maintain certain ratios as defined and
further described in our revolving credit facility, including a current ratio of not less than 1.0
to 1.0 and a maximum leverage ratio (generally defined as the ratio of total funded debt to a
defined measure of cash flow) of no greater than 4.0 to 1.0. In addition, at the inception of the
revolving credit facility, we had a one-time requirement to enter into hedging agreements with
respect to not less than 75% of our forecasted production through December 31, 2008, that was
attributable to our
proved developed producing reserves estimated as of December 31, 2005. As of June 30, 2007, we
were in compliance with all such covenants.
Second lien term loan facility. The second lien term loan facility provides a $200 million
term loan, which bears interest, at our option, at (1) a rate per annum equal to the London
Interbank Offered Rate, plus an applicable margin of 375 basis points or (2) the prime rate, plus
an applicable margin of 225 basis points. Upon the completion of the equity offering on August 7,
2007, the interest rate under any of the second lien term loan facility outstanding increased, at
our option, to (1) a rate per annum equal to the London Interbank Offered Rate, plus an applicable
margin of 425 basis points or (2) the prime rate, plus an applicable margin of 275 basis points. We
have the option to select different interest periods, subject to availability, and interest is
payable at the end of the interest period we select, though such interest payments must be made at
least on a quarterly basis. We are required to repay $500,000 of the second lien term loan facility
on the last day of each calendar quarter, commencing June 30, 2007, until the remaining balance of
the loan matures on March 27, 2012. Our second lien term loan facility bore interest at 9.10% per
annum as of June 30, 2007. We have the right to prepay the outstanding balance under the second
lien term loan facility at any time, provided, however, that we will incur a 2% prepayment penalty
on any principal amount prepaid from March 27, 2008 until March 26, 2009 and a 1% prepayment
penalty on any principal amount prepaid from March 27, 2009 until March 26, 2010. The prepayment
made on August 9, 2007 was not subject to a prepayment penalty. As a result of the partial
repayment of this facility on August 9, 2007, a pro rata portion of the deferred loan costs
associated with our second lien term loan facility were written off to interest expense in August
2007 in the amount of approximately $1.0 million. Additionally, a pro rata portion of the
unamortized original issue discount related to our second lien term loan facility was written off
to interest expense in August 2007 in the amount of approximately $0.4 million.
Borrowings under the second lien term loan facility are secured by a second lien on the same
assets as are securing our revolving credit facility, which liens are subordinated to liens
securing our revolving credit agreement. The second lien term loan facility also contains various
restrictive financial covenants and compliance requirements that are similar to those contained in
the revolving credit agreement, including the maintenance of certain financial ratios.
Future capital expenditures and commitments
We evaluate opportunities to purchase or sell oil and natural gas properties in the
marketplace and could participate as a buyer or seller of properties at various times. We seek to
acquire oil and gas properties that provide opportunities for the addition of reserves and
production through a combination of exploitation, development, high-potential exploration and
control of operations and that will allow us to apply our operating expertise or that otherwise
have geologic characteristics that are similar to our existing properties.
Expenditures for exploration and development of oil and natural gas properties are the primary
use of our capital resources. We anticipate investing approximately $183 million for exploration
and development expenditures during the year ending December 31, 2007 (including capital
expenditures incurred through June 30, 2007) as follows:
|
|
|
|
|
(in millions) |
|
Amount |
|
|
Drilling and recompletion opportunities in our core operating area |
|
$ |
135.2 |
|
Projects in our emerging plays |
|
|
28.9 |
|
Projects operated by third parties |
|
|
14.2 |
|
Acquisition of leasehold acreage and other property interests |
|
|
4.7 |
|
|
|
|
|
|
|
$ |
183.0 |
|
|
|
|
|
Although we cannot provide any assurance, assuming successful implementation of our
strategy, including the future development of our proved reserves and realization of our cash flows
as anticipated, we believe that our remaining cash balance and cash flows from operations and
availability under our revolving credit facility will be sufficient to satisfy our 2007 exploration
and development budget. The actual amount and timing of our expenditures may differ materially from
our estimates as a result of, among other things, actual drilling results, the timing of
expenditures by third parties on projects that we do not operate, the availability of drilling rigs
and other services and equipment, and regulatory, technological and competitive developments.
36
Hedging
We account for derivative instruments in accordance with SFAS No. 133 Accounting for
Derivative Instruments and Hedging Activities, as amended. The specific accounting treatment for
changes in the market value of the derivative instruments used in hedging activities is determined
based on the designation of the derivative instruments as a cash flow or fair value hedge and
effectiveness of the derivative instruments. We generally attempt to qualify such derivative
instruments as cash flow hedges for accounting purposes.
We have utilized fixed-price contracts and zero-cost collars to reduce exposure to unfavorable
changes in oil and natural gas prices that are subject to significant and often volatile
fluctuation. Under the fixed price physical delivery contracts, we receive the fixed price stated
in the contract. Under the zero-cost collars, if the market price of crude oil or natural gas, as
applicable, is less than the ceiling strike price and greater than the floor strike price, we
receive the market price. If the market price of crude oil or natural gas, as applicable, exceeds
the ceiling strike price or falls below the floor strike price, we receive the applicable collar
strike price.
The tables below provide the volumes and related data associated with our oil and natural gas
hedging as of June 30, 2007:
Oil and natural gas price collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
El Paso |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MMBtus |
|
|
natural gas |
|
|
Fair |
|
|
|
Barrels |
|
|
NYMEX oil prices |
|
|
of natural |
|
|
prices |
|
|
market |
|
Period of time |
|
of oil |
|
|
Floor |
|
|
Cap |
|
|
gas |
|
|
Floor |
|
|
Cap |
|
|
value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
July 1, 2007 thru December 31, 2007 |
|
|
119,600 |
|
|
$ |
37.95 |
|
|
$ |
41.75 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(3,467 |
) |
July 1, 2007 thru December 31, 2007 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
644,000 |
|
|
$ |
5.00 |
|
|
$ |
6.02 |
|
|
$ |
(458 |
) |
July 1, 2007 thru December 31, 2007 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
2,300,000 |
|
|
$ |
6.25 |
|
|
$ |
10.80 |
|
|
$ |
1,482 |
|
January 1, 2008 thru December 31, 2008 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
4,941,000 |
|
|
$ |
6.50 |
|
|
$ |
9.35 |
|
|
$ |
(413 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net fair market value liability |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(2,856 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas price swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
El Paso |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MMBtus |
|
|
Permian Basin |
|
|
Fair |
|
|
|
Barrels |
|
|
NYMEX oil |
|
|
of natural |
|
|
natural gas |
|
|
market |
|
Period of time |
|
of oil |
|
|
swap prices |
|
|
gas |
|
|
swap price |
|
|
value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
July 1, 2007 thru December 31, 2007 |
|
|
|
|
|
|
|
|
|
|
386,400 |
|
|
$ |
7.40 |
|
|
$ |
356 |
|
July 1, 2007 thru December 31, 2007 |
|
|
423,200 |
|
|
$ |
67.85 |
|
|
|
|
|
|
|
|
|
|
$ |
(1,417 |
) |
January 1, 2008 thru December 31, 2008 |
|
|
951,600 |
|
|
$ |
67.50 |
|
|
|
|
|
|
|
|
|
|
$ |
(4,403 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net fair market value liability |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(5,464 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
Contractual obligations and commitments
We had the following contractual obligations and commitments as of June 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by period |
|
|
|
|
|
|
Less than |
|
1 - 3 |
|
3 - 5 |
|
More than |
(in thousands) |
|
Total |
|
1 year |
|
years |
|
years |
|
5 years |
|
Long-term debt(1) |
|
$ |
505,000 |
|
|
$ |
2,500 |
|
|
$ |
309,000 |
|
|
$ |
193,500 |
|
|
$ |
|
|
Operating lease obligation(2) |
|
|
2,745 |
|
|
|
433 |
|
|
|
867 |
|
|
|
867 |
|
|
|
578 |
|
Daywork drilling contracts(3) |
|
|
24,822 |
|
|
|
23,086 |
|
|
|
1,736 |
|
|
|
|
|
|
|
|
|
Employment agreements with executive officers(4) |
|
|
3,253 |
|
|
|
1,700 |
|
|
|
1,553 |
|
|
|
|
|
|
|
|
|
Asset retirement obligations(5) |
|
|
7,666 |
|
|
|
1,545 |
|
|
|
142 |
|
|
|
209 |
|
|
|
5,770 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations |
|
$ |
543,486 |
|
|
$ |
29,264 |
|
|
$ |
313,298 |
|
|
$ |
194,576 |
|
|
$ |
6,348 |
|
|
|
|
|
|
|
(1) |
|
See Note J Long-term debt to our consolidated
financial statements. |
|
(2) |
|
Operating lease obligation is for office space. |
|
(3) |
|
Consists of daywork drilling contracts related to five drilling rigs contracted for a
portion of 2007 and a portion of 2008. See Note K Commitments and contingencies to our
consolidated financial statements. |
|
(4) |
|
Represents amounts of cash compensation we are obligated to pay to our executive officers
under employment agreements assuming such employees continue to serve the entire term of
their employment agreement and their cash compensation is not adjusted in the discretion of
the board of directors. |
|
(5) |
|
Amounts represent costs related to expected oil and gas property abandonments related to
proved reserves by period, net of any future accretion. |
Off-balance sheet arrangements
Currently we do not have any off-balance sheet arrangements.
Critical accounting policies and practices
Our historical consolidated financial statements and notes to our historical consolidated
financial statements contain information that is pertinent to our managements discussion and
analysis of financial condition and results of operations. Preparation of financial statements in
conformity with accounting principles generally accepted in the United States requires that our
management make estimates, judgments and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities.
However, the accounting principles used by us generally do not change our reported cash flows or
liquidity. Interpretation of the existing rules must be done and judgments made on how the
specifics of a given rule apply to us.
In managements opinion, the more significant reporting areas impacted by managements
judgments and estimates are revenue recognition, the choice of accounting method for oil and
natural gas activities, oil and natural gas reserve estimation, asset retirement obligations and
impairment of assets. Managements judgments and estimates in these areas are based on information
available from both internal and external sources, including engineers, geologists and historical
experience in similar matters. Actual results could differ from the estimates, as additional
information becomes known.
There have been no material changes in our critical accounting policies and procedures during
the six months ended June 30, 2007. See our disclosure of critical accounting policies in the
consolidated financial statements on Form S-1 for the year ended
38
December 31, 2006 contained in our
Prospectus dated August 2, 2007 and filed with the SEC pursuant to Rule 424 (b) on August 3, 2007.
Recent accounting pronouncements
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurement. This statement
defines fair value, establishes a framework for measuring fair value and expands disclosures about
fair value measurements. This statement is effective for financial statements issued for fiscal
years beginning after November 15, 2007. We will adopt SFAS No. 157 effective January 1, 2008. We
are currently evaluating the impact of SFAS No. 157.
In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and
Financial Liabilities, Including an Amendment of FASB Statement No. 115, (FAS 159) which will
become effective in 2008. FAS 159 permits entities to
measure eligible financial assets, financial liabilities and firm commitments at fair value,
on an instrument-by-instrument basis, that are otherwise not permitted to be accounted for at fair
value under other generally accepted accounting principles. The fair value measurement election is
irrevocable and subsequent changes in fair value must be recorded in earnings. We will adopt this
statement January 1, 2008, and we are currently evaluating if we will elect the fair value option
for any of our eligible financial instruments and other items.
In June 2007, the FASB ratified a consensus opinion reached by the Emerging Issues Task
Force (EITF) on EITF Issue 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based
Payment Awards. EITF Issue 06-11 requires an employer to recognize tax benefits realized from
dividend or dividend equivalents paid to employees for certain share-based payment awards as an
increase to additional paid-in capital and include such amounts in the pool of excess tax benefits
available to absorb future tax deficiencies on share-based payment awards. If an entitys estimate
of forfeitures increases (or actual forfeitures exceed the entitys estimates), or if an award is
no longer expected to vest, entities should reclassify the dividends or dividend equivalents paid
on that award from retained earnings to compensation cost. However, the tax benefits from dividends
that are reclassified from additional paid-in capital to the income statement are limited to the
entitys pool of excess tax benefits available to absorb tax deficiencies on the date of
reclassification. The consensus in EITF Issue 06-11 is effective for fiscal years, and interim
periods within those fiscal years, beginning after December 15, 2007. Retrospective application of
EITF Issue 06-11 is not permitted. Early adoption is permitted;
however, we do not
intend to adopt EITF Issue 06-11 prior to the required effective date
of January 1, 2008. We do not expect the adoption of EITF Issue
06-11 to have a significant effect on our
financial statements since we historically have accounted for the income tax benefits of
dividends paid for share-based payment awards in the manner described in the consensus.
Inflation
Historically, general inflationary trends have not had a material effect on our operating
results. However, we have recently experienced inflationary pressure on technical staff
compensation and the cost of oilfield services and equipment due to the increase in drilling
activity and competitive pressures resulting from higher oil and natural gas prices in recent
years.
Cautionary statement regarding forward-looking statements
This report may contain forward-looking statements within the meaning of Section 27 A of
the Securities Act of 1933 and Section 21 E of the Securities Exchange Act of 1934 that are subject
to a number of risks and uncertainties, many of which are beyond our control. All statements, other
than statements of historical fact included in this quarterly report, regarding our strategy,
future operations, financial position, estimated revenues and losses, projected costs, prospects,
plans and objectives of management are forward-looking statements. When used in this quarterly
report, the words could, believe, anticipate, intend, estimate, expect, may,
continue, predict, potential, project and similar expressions are intended to identify
forward-looking statements, although not all forward-looking statements contain such identifying
words. In particular, the factors discussed below and detailed in our Prospectus dated August 2,
2007 and filed with the SEC pursuant to Rule 424 (b) on August 3, 2007, could affect our actual
results and cause our actual results to differ materially from expectations, estimates, or
assumptions expressed in, forecasted in, or implied in such forward-looking statements.
Forward-looking statements may include statements about our:
|
§ |
|
business strategy; |
|
|
§ |
|
estimated quantities of oil and natural gas reserves; |
|
|
§ |
|
technology; |
|
|
§ |
|
financial strategy; |
|
|
§ |
|
oil and natural gas realized prices; |
|
|
§ |
|
timing and amount of future production of oil and natural gas; |
|
|
§ |
|
the amount, nature and timing of capital expenditures; |
|
|
§ |
|
drilling of wells; |
|
|
§ |
|
competition and government regulations; |
|
|
§ |
|
marketing of oil and natural gas; |
|
|
§ |
|
exploitation or property acquisitions; |
|
|
§ |
|
costs of exploiting and developing our properties and conducting other operations; |
|
|
§ |
|
general economic and business conditions; |
|
|
§ |
|
cash flow and anticipated liquidity; |
|
|
§ |
|
uncertainty regarding our future operating results; and |
|
|
§ |
|
plans, objectives, expectations and intentions contained in this quarterly report that are not historical. |
39
You should not place undue reliance on these forward-looking statements. All forward-looking
statements speak only as of the date of this quarterly report. We do not undertake any obligation
to release publicly any revisions to the forward-looking statements to reflect events or
circumstances after the date of this quarterly report or to reflect the occurrence of unanticipated
events except as required by law.
Although we believe that our plans, objectives, expectations and intentions reflected in or
suggested by the forward-looking statements we make in this quarterly report are reasonable, we can
give no assurance that they will be achieved. These cautionary statements qualify all
forward-looking statements attributable to us or persons acting on our behalf.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following market risk disclosures should be read in conjunction with the quantitative
and qualitative disclosures about market risk contained in our Prospectus dated August 2, 2007 and
filed with the SEC pursuant to Rule 424 (b) on August 3, 2007, as well as with the consolidated
financial statements and notes thereto included in this quarterly report on Form 10-Q.
Hypothetical changes in interest rates and prices chosen for the following estimated
sensitivity analysis are considered to be reasonably possible near-term changes generally based on
consideration of past fluctuations for each risk category. However, since it is not possible to
accurately predict future changes in interest rates and commodity prices, these hypothetical
changes may not necessarily be an indicator of probable future fluctuations.
We are exposed to a variety of market risks including credit risk, commodity price risk and
interest rate risk. We address these risks through a program of risk management which includes the
use of derivative instruments.
Credit risk. We monitor our risk of loss due to non-performance by counterparties of their
contractual obligations. Our principal exposure to credit risk is through the sale of our oil and
natural gas production, which we market to energy marketing companies and refineries. We monitor
our exposure to these counterparties primarily by reviewing credit ratings, financial statements
and payment history. We extend credit terms based on our evaluation of each counterpartys
creditworthiness. Although we have not generally required our counterparties to provide collateral
to support their obligation to us, we may, if circumstances dictate, require collateral in the
future. In this manner, we reduce credit risk.
Commodity price risk. We are exposed to market risk as the prices of crude oil and natural gas
are subject to fluctuations resulting from changes in supply and demand. To partially reduce price
risk caused by these market fluctuations, we have hedged approximately 75% of our forecasted oil
and natural gas production through December 31, 2008, attributable to our proved developed
producing reserves as of December 31, 2005, through the utilization of derivatives, including
zero-cost collars and fixed price contracts. See Liquidity and capital resourcesHedging. Because
all of our futures contracts and swap agreements have been designated as hedge derivatives, changes
in their fair value generally are reported as a component of accumulated other comprehensive income
until the related sale of production occurs. At that time, the realized hedge derivative gain or
loss is transferred to product revenues in the consolidated income statement.
Interest rate risk. Our exposure to changes in interest rates relates primarily to long-term
debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a
certain percentage of total capitalization and by monitoring the effects of market changes in
interest rates. We may utilize interest rate derivatives to alter interest rate exposure in an
attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives
are used solely to modify interest rate exposure and not to modify the overall leverage of the debt
portfolio. We are exposed to changes in interest rates as a result of our bank credit facilities,
and the terms of our revolving credit facility require us to pay higher interest rate margins as we
utilize a larger percentage of our available borrowing base. We had total indebtedness of $305.0
million outstanding under our revolving credit facility at June 30, 2007. The impact of a 1%
increase in interest rates on this amount of debt would result in increased interest expense of
approximately $3.1 million and a corresponding decrease in net income before income tax. On March
27, 2007, we entered into a $200.0 million second lien term loan facility, from which we received
$199.0 million in proceeds, with $39.8 million of such amount used to retire our prior second lien
term loan facility, $154.0 million of such amount used to reduce the amount outstanding under our
revolving credit facility and the remaining $5.2 million of such amount used to pay loan fees,
accrued interest and for general corporate purposes. The impact of a 1% increase in interest rates
on this amount of debt under our second lien term loan facility would result in increased interest
expense of approximately $2.0 million and a corresponding decrease in net income before income tax.
Item 4. CONTROLS AND PROCEDURES
Our management, with the participation of our Chief Executive Officer and Chief Financial
Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule
13a-15 under the Securities Exchange Act of 1934 as of the end of the period covered by this
quarterly report. Based on that evaluation, our Chief Executive Officer and Chief Financial
Officer concluded that, as of June 30, 2007, our disclosure controls and procedures were effective,
in all material respects, to ensure that information we are required to disclose in reports that we
file or submit under the Exchange Act is recorded, processed, summarized
40
and reported within the
time periods specified in SEC rules and forms, and that such information is accumulated and
communicated to our management, including our Chief Executive Officer and Chief Financial Officer,
as appropriate, to allow timely decisions regarding required disclosure.
We have begun taking steps to comprehensively document and analyze our system of internal
controls. We plan to continue this initiative as well as prepare for our first management report
on internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act
of 2002, prior to its applicability to us. In that regard, we have made and expect to continue to
make changes in our internal controls over financial reporting. Although these changes may
continue to improve our internal controls, there were no changes in our internal controls over
financial reporting that occurred during the period covered by this Quarterly Report on Form 10-Q
that have materially affected, or are reasonably likely to materially affect, our internal control
over financial reporting.
PART II. OTHER INFORMATION
Item 1.
Legal proceedings
Not applicable.
Item 1A.
Risk factors
For a discussion of our potential risks and uncertainties, see the information under the
heading Risk factors in our prospectus dated August 2, 2007, filed with the SEC in accordance
with Rule 424(b) of the Securities Act on August 3, 2007, which is accessible on the SECs website
at www.sec.gov. There have been no material changes to the risk factors disclosed in the
prospectus.
Item 2.
Unregistered sales of equity securities and use of proceeds
On August 7, 2007, we completed our initial public offering of our common stock pursuant
to our registration statement on Form S-1 (File 333-142315) declared effective by the SEC on August
1, 2007. The underwriters for the offering were J.P. Morgan Securities Inc., Banc of America
Securities LLC, Lehman Brothers Inc., BNP Paribas Securities Corp., Merrill Lynch, Pierce, Fenner &
Smith Incorporated, UBS Securities LLC and Wachovia Capital Markets, LLC. Pursuant to the
registration statement, we registered the offer and sale of 24,020,173 shares of our $.001 par
value common stock, which included 7,554,256 shares sold by certain selling stockholders and
3,133,066 shares subject to an option granted to the underwriters by the company to cover
over-allotments. The underwriters exercised their over-allotment option on August 6, 2007. The sale
of the shares in our initial public offering closed on August 7, 2007 and the sale of the shares
covered by the over-allotment option closed on August 9, 2007. Our initial public offering
terminated upon completion of the closing.
The gross proceeds of our initial public offering, including the gross proceeds from
over-allotment option, based on the public offering price of $11.50 per share, were approximately
$276.2 million, which resulted in net proceeds to the Company of $173.2 million after deducting
underwriter discounts and commissions of approximately $17.3 million and other estimated expenses
related to the offering of approximately $4.4 million and the net proceeds to the selling
stockholders of approximately $81.3 million. We did not receive any proceeds from the sale of the
shares by the selling stockholders. We also paid for legal fees incurred by the selling
stockholders. Other than for such fees, no fees or expenses have been paid, directly or indirectly,
to any officer, director or 10% stockholder or other affiliate. The net proceeds from our initial
public offering were used to (i) retire outstanding borrowings under our second lien term loan
facility on August 9, 2007 totaling $86.6 million and (ii) retire outstanding borrowings under our
revolving credit facility on August 20, 2007 totaling $86.6 million.
Items 3. through 5.
Not applicable.
Item 6. Exhibits
|
|
|
Exhibit |
|
|
Number |
|
Exhibit |
3.1
|
|
Restated Certificate of Incorporation of Concho Resources Inc. (filed as Exhibit 3.1 to the
Companys Current Report on Form 8-K filed on August 8, 2007, and incorporated herein by
reference) |
41
|
|
|
Exhibit |
|
|
Number |
|
Exhibit |
3.2
|
|
Amended and Restated Bylaws of Concho Resources Inc. (filed as Exhibit 3.2 to the Companys
Current Report on Form 8-K filed on August 8, 2007, and incorporated herein by reference) |
|
|
|
4.1
|
|
Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Companys Registration Statement
on Form S-1/A filed July 5, 2007, (File No. 333-142315), and incorporated herein by reference) |
|
|
|
10.1
|
|
Transition Services Agreement dated April 23, 2007 between COG Operating LLC and Mack Energy
Corporation (filed as Exhibit 10.3 to the Companys Registration Statement on Form S-1 filed
April 24, 2007, (File No. 333-142315), and incorporated herein by reference) |
|
|
|
10.2
|
|
Indemnification Agreement dated August 21, 2007, by and between Concho Resources Inc. and Jack F.
Harper (filed as Exhibit 10.1 to the Companys Current Report on Form 8-K filed on August 24,
2007, and incorporated herein by reference) |
|
|
|
10.3
|
|
Indemnification Agreement dated August 21, 2007, by and between Concho Resources Inc. and Ray M.
Poage (filed as Exhibit 10.2 to the Companys Current Report on Form 8-K filed on August 24,
2007, and incorporated herein by reference) |
|
|
|
10.4
|
|
First Amendment to Employment Agreement, dated August 21, 2007, by and between Concho Resources
Inc. and Timothy A. Leach (filed as Exhibit 10.3 to the Companys Current Report on Form 8-K
filed on August 24, 2007, and incorporated herein by reference) |
|
|
|
10.5
|
|
First Amendment to Employment Agreement, dated August 21, 2007, by and between Concho Resources
Inc. and Steven L. Beal (filed as Exhibit 10.4 to the Companys Current Report on Form 8-K filed
on August 24, 2007, and incorporated herein by reference) |
|
|
|
10.6
|
|
First Amendment to Employment Agreement, dated August 21, 2007, by and between Concho Resources
Inc. and David W. Copeland (filed as Exhibit 10.5 to the Companys Current Report on Form 8-K
filed on August 24, 2007, and incorporated herein by reference) |
|
|
|
10.7
|
|
First Amendment to Employment Agreement, dated August 21, 2007, by and between Concho Resources
Inc. and Curt F. Kamradt (filed as Exhibit 10.6 to the Companys Current Report on Form 8-K filed
on August 24, 2007, and incorporated herein by reference) |
|
|
|
10.8
|
|
First Amendment to Employment Agreement, dated August 21, 2007, by and between Concho Resources
Inc. and E. Joseph Wright (filed as Exhibit 10.7 to the Companys Current Report on Form 8-K
filed on August 24, 2007, and incorporated herein by reference) |
|
|
|
10.9
|
|
First Amendment to Employment Agreement, dated August 31, 2007, by and between Concho Resources
Inc. and David M. Thomas III |
|
|
|
31.1
|
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
|
|
|
31.2
|
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
|
|
|
32.1
|
|
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
|
32.2
|
|
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
42
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.
|
|
|
|
|
|
|
CONCHO RESOURCES INC. |
Date: September 7, 2007
|
|
By
|
|
/S/ Timothy A. Leach |
|
|
|
|
|
|
|
|
|
Timothy A. Leach |
|
|
|
|
Chairman and Chief Executive Officer |
|
|
|
|
|
|
|
By
|
|
/S/ Curt F. Kamradt |
|
|
|
|
|
|
|
|
|
Curt F. Kamradt |
|
|
|
|
Vice President, Chief Financial Officer and Treasurer |
|
|
|
|
(Principal Financial Officer) |
43