e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2008
or
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o |
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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 |
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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 þ No o
Indicate by check
mark whether the
registrant is a
large accelerated filer, an accelerated filer, a non-accelerated
filer, or a
smaller reporting company.
See the definitions of large accelerated
filer, accelerated
filer
and smaller reporting company in
Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer
o
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Accelerated filer
o |
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Non-accelerated filer
þ
(Do not check if a smaller reporting company) |
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Smaller reporting company
o |
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 August 12, 2008:
84,432,912 shares.
PART I FINANCIAL INFORMATION
Item 1. CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
ii
Concho Resources Inc. and subsidiaries
Consolidated balance sheets
Unaudited
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|
June 30, |
|
December 31, |
(in thousands, except share and per share data) |
|
2008 |
|
2007 |
|
Assets |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
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|
Cash and cash equivalents |
|
$ |
31,716 |
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$ |
30,424 |
|
Accounts receivable: |
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|
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|
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Oil and gas, net of allowance for doubtful accounts |
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|
55,270 |
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|
36,735 |
|
Joint operations and other |
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10,903 |
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|
21,183 |
|
Assets held for sale |
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|
256 |
|
Derivative instruments |
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|
|
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|
1,866 |
|
Deferred income taxes |
|
|
44,750 |
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|
13,502 |
|
Prepaid insurance and other |
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|
3,224 |
|
|
|
4,017 |
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|
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|
Total current assets |
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145,863 |
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|
107,983 |
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Property and equipment, at cost: |
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Oil and gas properties, successful efforts method |
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|
1,675,163 |
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|
1,555,018 |
|
Accumulated depletion and depreciation |
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|
(209,688 |
) |
|
|
(167,109 |
) |
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|
Total oil and gas properties, net |
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|
1,465,475 |
|
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|
1,387,909 |
|
Other property and equipment, net |
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|
10,046 |
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|
7,085 |
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Total property and equipment, net |
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|
1,475,521 |
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|
1,394,994 |
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|
|
|
Deferred loan costs, net |
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|
3,800 |
|
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|
3,426 |
|
Inventory |
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|
8,702 |
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|
1,459 |
|
Other assets |
|
|
347 |
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|
|
367 |
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|
Total assets |
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$ |
1,634,233 |
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$ |
1,508,229 |
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Liabilities and stockholders equity |
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Current liabilities: |
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Accounts payable: |
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Trade |
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$ |
5,509 |
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$ |
14,222 |
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Related parties |
|
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623 |
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|
2,119 |
|
Other current liabilities: |
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|
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Bank overdrafts |
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8,896 |
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|
5,651 |
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Revenue payable |
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22,212 |
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|
14,494 |
|
Accrued drilling costs |
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34,955 |
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|
39,276 |
|
Accrued interest |
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|
496 |
|
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|
1,590 |
|
Other accrued liabilities |
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|
18,291 |
|
|
|
11,935 |
|
Derivative instruments |
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|
114,504 |
|
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|
36,414 |
|
Income taxes payable |
|
|
|
|
|
|
29 |
|
Current portion of long-term debt |
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2,500 |
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|
2,000 |
|
Current asset retirement obligations |
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765 |
|
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|
912 |
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|
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Total current liabilities |
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208,751 |
|
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|
128,642 |
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Long-term debt |
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|
298,453 |
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|
325,404 |
|
Noncurrent derivative instruments |
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|
44,824 |
|
|
|
10,517 |
|
Deferred income taxes |
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|
288,098 |
|
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|
259,070 |
|
Asset retirement obligations and other long-term liabilities |
|
|
10,148 |
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|
9,198 |
|
Commitments and contingencies (Note K) |
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Stockholders equity: |
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Preferred stock, $0.001 par value; 10,000,000 shares authorized; and zero shares issued and
outstanding at June 30, 2008 and December 31, 2007 |
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Common stock, $0.001 par value; 300,000,000 authorized; 76,140,269 and 75,832,310
shares issued at June 30, 2008 and December 31, 2007, respectively |
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76 |
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|
76 |
|
Additional paid-in capital |
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|
759,928 |
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752,380 |
|
Notes receivable from employees |
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(330 |
) |
Retained earnings |
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45,412 |
|
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|
37,467 |
|
Accumulated other comprehensive income (loss) |
|
|
(21,332 |
) |
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|
(14,195 |
) |
Treasury stock, at cost; 3,142 and zero shares of common stock at June 30, 2008 and
December 31, 2007, respectively |
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|
(125 |
) |
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|
|
|
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Total stockholders equity |
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|
783,959 |
|
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|
775,398 |
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|
Total liabilities and stockholders equity |
|
$ |
1,634,233 |
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|
$ |
1,508,229 |
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|
The accompanying notes are an integral part of these consolidated financial statements.
Concho Resources Inc. and subsidiaries
Consolidated statements of operations
Unaudited
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Three months ended |
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Six months ended |
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June 30, |
|
June 30, |
(in thousands, except per share amounts) |
|
2008 |
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2007 |
|
2008 |
|
2007 |
|
Operating revenues: |
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|
|
|
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Oil sales |
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$ |
95,408 |
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|
$ |
43,096 |
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$ |
171,226 |
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$ |
82,467 |
|
Natural gas sales |
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41,975 |
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|
23,007 |
|
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|
72,868 |
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|
43,982 |
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|
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|
Total operating revenues |
|
|
137,383 |
|
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|
66,103 |
|
|
|
244,094 |
|
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|
126,449 |
|
Operating costs and expenses: |
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|
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Oil and gas production |
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|
9,949 |
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|
|
6,950 |
|
|
|
17,766 |
|
|
|
14,209 |
|
Oil and gas production taxes |
|
|
12,030 |
|
|
|
5,256 |
|
|
|
21,108 |
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|
|
9,943 |
|
Exploration and abandonments |
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|
723 |
|
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|
5,864 |
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|
3,464 |
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|
|
6,305 |
|
Depreciation and depletion |
|
|
22,010 |
|
|
|
17,609 |
|
|
|
43,294 |
|
|
|
37,033 |
|
Accretion of discount on asset retirement obligations |
|
|
148 |
|
|
|
115 |
|
|
|
301 |
|
|
|
228 |
|
Impairments of proved oil and gas properties |
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|
53 |
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|
|
2,085 |
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|
69 |
|
|
|
3,198 |
|
Contract drilling fees stacked rigs |
|
|
|
|
|
|
915 |
|
|
|
|
|
|
|
4,269 |
|
General and administrative (including non-cash stock-based
compensation of $1,730 and $1,128 for the three months ended
June 30, 2008 and 2007, respectively, and $3,029 and $1,954
for the six
months ended June 30, 2008 and 2007, respectively) |
|
|
8,586 |
|
|
|
7,629 |
|
|
|
16,266 |
|
|
|
11,921 |
|
Bad debt expense |
|
|
1,799 |
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|
|
|
|
|
|
1,799 |
|
|
|
|
|
Ineffective portion of cash flow hedges |
|
|
(356 |
) |
|
|
(99 |
) |
|
|
(920 |
) |
|
|
1,156 |
|
Loss on derivatives not designated as hedges |
|
|
102,456 |
|
|
|
|
|
|
|
119,634 |
|
|
|
|
|
|
|
|
Total operating costs and expenses |
|
|
157,398 |
|
|
|
46,324 |
|
|
|
222,781 |
|
|
|
88,262 |
|
|
|
|
Income (loss) from operations |
|
|
(20,015 |
) |
|
|
19,779 |
|
|
|
21,313 |
|
|
|
38,187 |
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(3,885 |
) |
|
|
(10,074 |
) |
|
|
(9,500 |
) |
|
|
(20,749 |
) |
Other, net |
|
|
311 |
|
|
|
208 |
|
|
|
1,331 |
|
|
|
473 |
|
|
|
|
Total other expense |
|
|
(3,574 |
) |
|
|
(9,866 |
) |
|
|
(8,169 |
) |
|
|
(20,276 |
) |
|
|
|
Income (loss) before income taxes |
|
|
(23,589 |
) |
|
|
9,913 |
|
|
|
13,144 |
|
|
|
17,911 |
|
Income tax benefit (expense) |
|
|
9,169 |
|
|
|
(3,988 |
) |
|
|
(5,199 |
) |
|
|
(7,363 |
) |
|
|
|
Net income (loss) |
|
|
(14,420 |
) |
|
|
5,925 |
|
|
|
7,945 |
|
|
|
10,548 |
|
Preferred stock dividends |
|
|
|
|
|
|
(11 |
) |
|
|
|
|
|
|
(45 |
) |
|
|
|
Net income (loss) applicable to common shareholders |
|
$ |
(14,420 |
) |
|
$ |
5,914 |
|
|
$ |
7,945 |
|
|
$ |
10,503 |
|
|
|
|
Basic earnings (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share |
|
$ |
(0.19 |
) |
|
$ |
0.10 |
|
|
$ |
0.11 |
|
|
$ |
0.19 |
|
|
|
|
Weighted average shares used in basic earnings (loss) per share |
|
|
75,665 |
|
|
|
57,747 |
|
|
|
75,569 |
|
|
|
56,369 |
|
|
|
|
Diluted earnings (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share |
|
$ |
(0.19 |
) |
|
$ |
0.10 |
|
|
$ |
0.10 |
|
|
$ |
0.18 |
|
|
|
|
Weighted average shares used in diluted earnings (loss) per share |
|
|
75,665 |
|
|
|
59,625 |
|
|
|
77,034 |
|
|
|
59,260 |
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Concho Resources Inc. and subsidiaries
Consolidated statements of stockholders equity
Unaudited
|
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|
|
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|
|
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|
|
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|
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|
|
|
|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes |
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
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|
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Additional |
|
|
receivable from |
|
|
|
|
|
|
other |
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
Common stock |
|
|
paid-in |
|
|
officers and |
|
|
Retained |
|
|
comprehensive |
|
|
Treasury stock |
|
|
stockholders |
|
(in thousands) |
|
Shares |
|
|
Amount |
|
|
capital |
|
|
employees |
|
|
earnings |
|
|
income (loss) |
|
|
Shares |
|
|
Amount |
|
|
equity |
|
|
BALANCE AT DECEMBER 31, 2007 |
|
|
75,832 |
|
|
$ |
76 |
|
|
$ |
752,380 |
|
|
$ |
(330 |
) |
|
$ |
37,467 |
|
|
$ |
(14,195 |
) |
|
|
|
|
|
$ |
|
|
|
$ |
775,398 |
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,945 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,945 |
|
Deferred hedge losses, net of tax benefit of $12,705 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19,805 |
) |
|
|
|
|
|
|
|
|
|
|
(19,805 |
) |
Net settlement losses included in earnings, net of tax benefit of $8,127 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,668 |
|
|
|
|
|
|
|
|
|
|
|
12,668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
808 |
|
Stock options exercised |
|
|
263 |
|
|
|
|
|
|
|
2,373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,373 |
|
Restricted stock issued as stock-based compensation |
|
|
81 |
|
|
|
|
|
|
|
862 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
862 |
|
Cancellation of restricted stock |
|
|
(36 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation for stock options |
|
|
|
|
|
|
|
|
|
|
2,167 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,167 |
|
Tax benefits related to stock-based compensation |
|
|
|
|
|
|
|
|
|
|
2,146 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,146 |
|
Proceeds from notes receivable officers and employees |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
333 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
333 |
|
Accrued interest employee notes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3 |
) |
Purchase of treasury stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
(125 |
) |
|
|
(125 |
) |
|
|
|
BALANCE AT JUNE 30, 2008 |
|
|
76,140 |
|
|
$ |
76 |
|
|
$ |
759,928 |
|
|
$ |
|
|
|
$ |
45,412 |
|
|
$ |
(21,332 |
) |
|
|
3 |
|
|
$ |
(125 |
) |
|
$ |
783,959 |
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Concho Resources Inc. and subsidiaries
Consolidated statements of cash flows
Unaudited
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
June 30, |
(in thousands) |
|
2008 |
|
2007 |
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
7,945 |
|
|
$ |
10,548 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation and depletion |
|
|
43,294 |
|
|
|
37,033 |
|
Impairments of proved oil and gas properties |
|
|
69 |
|
|
|
3,198 |
|
Accretion of discount on asset retirement obligations |
|
|
301 |
|
|
|
228 |
|
Exploration expense, including dry holes |
|
|
1,147 |
|
|
|
5,665 |
|
Non-cash compensation expense |
|
|
3,029 |
|
|
|
1,954 |
|
Bad debt expense |
|
|
1,799 |
|
|
|
|
|
Gas imbalances |
|
|
(137 |
) |
|
|
54 |
|
Deferred rent liability |
|
|
22 |
|
|
|
41 |
|
Deferred income taxes |
|
|
4,504 |
|
|
|
7,399 |
|
Interest accrued on employee notes |
|
|
(3 |
) |
|
|
(240 |
) |
Amortization of deferred loan costs |
|
|
627 |
|
|
|
1,889 |
|
Amortization of discount on long-term debt |
|
|
49 |
|
|
|
40 |
|
Gain on sale of property and equipment |
|
|
(777 |
) |
|
|
|
|
Ineffective portion of cash flow hedges |
|
|
(920 |
) |
|
|
1,156 |
|
Loss on derivatives not designated as hedges |
|
|
119,634 |
|
|
|
|
|
Dedesignated cash flow hedges reclassified from AOCI |
|
|
222 |
|
|
|
|
|
Changes in operating assets and liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(12,003 |
) |
|
|
10,640 |
|
Prepaid insurance and other |
|
|
793 |
|
|
|
3,985 |
|
Inventory |
|
|
(7,243 |
) |
|
|
(5,000 |
) |
Excess tax benefit from stock-based compensation |
|
|
(2,146 |
) |
|
|
|
|
Accounts payable |
|
|
(10,209 |
) |
|
|
(14,902 |
) |
Revenue payable |
|
|
7,718 |
|
|
|
(404 |
) |
Accrued liabilities |
|
|
6,356 |
|
|
|
(519 |
) |
Accrued interest |
|
|
(1,094 |
) |
|
|
829 |
|
Income taxes payable |
|
|
(29 |
) |
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
162,948 |
|
|
|
63,594 |
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Capital expenditures on oil and gas properties |
|
|
(122,757 |
) |
|
|
(69,889 |
) |
Acquisition of oil and gas properties and other assets |
|
|
|
|
|
|
(256 |
) |
Additions to other property and equipment |
|
|
(4,017 |
) |
|
|
(1,114 |
) |
Proceeds from the sale of oil and gas properties |
|
|
1,034 |
|
|
|
652 |
|
Settlements paid on derivatives not designated as hedges |
|
|
(16,387 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(142,127 |
) |
|
|
(70,607 |
) |
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt |
|
|
13,000 |
|
|
|
266,100 |
|
Payments of long-term debt |
|
|
(39,500 |
) |
|
|
(257,600 |
) |
Exercise of incentive plan stock options |
|
|
2,373 |
|
|
|
|
|
Excess tax benefit from stock-based compensation |
|
|
2,146 |
|
|
|
|
|
Payments of preferred stock dividends |
|
|
|
|
|
|
(132 |
) |
Proceeds from repayment of officer and employee notes |
|
|
333 |
|
|
|
10,482 |
|
Payments for loan origination costs |
|
|
(1,001 |
) |
|
|
(2,572 |
) |
Purchase of treasury stock |
|
|
(125 |
) |
|
|
|
|
Bank overdrafts |
|
|
3,245 |
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
(19,529 |
) |
|
|
16,278 |
|
|
|
|
Net increase in cash and cash equivalents |
|
|
1,292 |
|
|
|
9,265 |
|
BEGINNING CASH AND CASH EQUIVALENTS |
|
|
30,424 |
|
|
|
1,122 |
|
|
|
|
ENDING CASH AND CASH EQUIVALENTS |
|
$ |
31,716 |
|
|
$ |
10,387 |
|
|
|
|
SUPPLEMENTAL CASH FLOWS: |
|
|
|
|
|
|
|
|
Cash paid for interest and fees, net of $840 and $1,336 capitalized interest |
|
$ |
9,918 |
|
|
$ |
18,891 |
|
|
|
|
Cash paid for income taxes |
|
$ |
650 |
|
|
$ |
1,800 |
|
|
|
|
NON-CASH INVESTING AND FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Issuance of common stock in acquisition of oil and gas properties and other assets |
|
$ |
|
|
|
$ |
650 |
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
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 in Southeast New
Mexico from the Chase Group (Chase Group Properties) 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 members of the Companys management team 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
collectively referred to herein 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 the Chase Group Properties to Resources in exchange for cash
in the aggregate amount of approximately $409 million and 34,794,638 shares of Resources common
stock. In connection with the Companys initial public offering and secondary public offering (both
described below), the Chase Group sold a total of 18,638,014 shares of common stock thereby
reducing its ownership interest. As of June 30, 2008 and December 31, 2007, the Chase Group owned
approximately 12 percent and 21 percent, respectively, of the total outstanding common stock 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.
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 of its common stock in the IPO
and certain shareholders, including its 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 $4.5
million, the Company received net proceeds of approximately $139.2 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 $2.2 million, the Company
received net proceeds of approximately $33.8 million. The aggregate net proceeds of approximately
$173.0 million received by the Company at closing on August 7, 2007 and August 9, 2007 were
utilized in equal amounts to repay a portion of its term loan facility on August 9, 2007, and to
prepay a portion of its revolving credit facility on August 20, 2007. See further discussion in
Note J Long-term debt.
Secondary public offering. On December 19, 2007, the Company completed a secondary public
offering of 11,845,000 shares of its common stock, which were sold by certain of its stockholders,
including members of the Chase group. The Chase Group sold 10,194,732 shares in the aggregate and
certain other stockholders of the Company sold 1,650,268 shares in the aggregate, including one of
the Companys executive officers who sold 45,000 shares. Chase Oil Corporation granted the
underwriters an option to purchase up to 1,776,615 additional shares to cover over-allotments,
which was fully exercised on December 19, 2007. The Company did not receive any proceeds from the
sale of its common stock in this secondary offering.
Note B. Summary of significant accounting policies
Principles of consolidation. 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, 2007 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, 2008, its income for
the three and six months ended June 30,
2008 and 2007 and its cash flows for the six
months ended June 30, 2008 and 2007. 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 Annual Report on Form 10-K for the year
ended December 31, 2007.
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, 2008, 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 $464,000 related to the Companys overtake position of 83,714 Mcf on certain wells
and a gas imbalance receivable, included in Other assets in the accompanying consolidated balance
sheet of approximately $347,000 related to the Companys undertake position of 77,171 Mcf on
certain wells.
Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of
treasury shares held is reduced by the average purchase price per share of the aggregate treasury
shares held. During the three and six months ended June 30, 2008, the Company did not retire any
treasury stock.
General and administrative expense. The Company receives fees for its operation of jointly
owned oil and gas properties and records such reimbursements as reductions of General and
administrative expense. Such fees totaled approximately $265,000 and $221,000 for the three months
ended June 30, 2008 and 2007, respectively, and $504,000 and $630,000 for the six months ended June
30, 2008 and 2007, 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, 2008 and December 31, 2007, of
capitalized exploratory well costs based on the date drilling was completed:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
(in thousands) |
|
2008 |
|
2007 |
|
|
Wells in progress |
|
$ |
1,038 |
|
|
$ |
4,199 |
|
Capitalized exploratory well costs that have been capitalized for a period of one year or less |
|
|
15,240 |
|
|
|
16,857 |
|
Capitalized exploratory well costs that have been capitalized for a period greater than one year |
|
|
|
|
|
|
|
|
|
|
|
Total exploratory well costs |
|
$ |
16,278 |
|
|
$ |
21,056 |
|
|
|
|
As of June 30, 2008, the capitalized exploratory well costs of approximately $16.3 million had
been deferred for a period of one year or less and were related primarily to the Companys New
Mexico shelf properties and emerging resource plays.
As of December 31, 2007, the capitalized exploratory well costs of approximately $21.1 million
had been deferred for a period of one year or less and were related primarily to the Companys New
Mexico shelf and New Mexico basin properties.
2
Note D. Fair value measurements
The Company adopted SFAS No. 157, Fair Value Measurements, (SFAS No. 157) effective
January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157
applies to all financial assets and financial liabilities that are being measured and reported on a
fair value basis. In February 2008, the FASB issued FSP No. 157-2, which delayed the effective date
of SFAS No. 157 by one year for nonfinancial assets and liabilities. As defined in SFAS No. 157,
fair value is the price that would be received to sell an asset or paid to transfer a liability in
an orderly transaction between market participants at the measurement date (exit price). SFAS No.
157 requires disclosure that establishes a framework for measuring fair value and expands
disclosure about fair value measurements. The statement requires fair value measurements be
classified and disclosed in one of the following categories:
|
Level 1: |
|
Unadjusted quoted prices in active markets that are accessible at the
measurement date for identical, unrestricted assets or liabilities. We consider active
markets as those in which transactions for the assets or liabilities occur in sufficient
frequency and volume to provide pricing information on an ongoing basis. |
|
|
Level 2: |
|
Quoted prices in markets that are not active, or inputs which are observable,
either directly or indirectly, for substantially the full term of the asset or liability.
This category includes those derivative instruments that we value using observable market
data. Substantially all of these inputs are observable in the marketplace throughout the
full term of the derivative instrument, can be derived from observable data, or supported
by observable levels at which transactions are executed in the marketplace. Level 2
instruments primarily include non-exchange traded derivatives such as over-the-counter
commodity price swaps, investments and interest rate swaps. Our valuation models are
primarily industry-standard models that consider various inputs including: (a) quoted
forward prices for commodities, (b) time value and (c) current market and contractual
prices for the underlying instruments, as well as other relevant economic measures. We
utilize our counterparties valuations to assess the reasonableness of our prices and
valuation techniques. |
|
|
Level 3: |
|
Measured based on prices or valuation models that require inputs that are both
significant to the fair value measurement and less observable from objective sources
(i.e., supported by little or no market activity). Level 3 instruments primarily include
derivative instruments, such as basis swaps, commodity price collars and floors, as well
as investments. Our valuation models are primarily industry-standard models that consider
various inputs including: (a) quoted forward prices for commodities, (b) time value, (c)
volatility factors and (d) current market and contractual prices for the underlying
instruments, as well as other relevant economic measures. Although we utilize our
counterparties valuations to assess the reasonableness of our prices and valuation
techniques, we do not have sufficient corroborating market evidence to support
classifying these assets and liabilities as Level 2. |
3
As required by SFAS No. 157, financial assets and liabilities are classified based on the
lowest level of input that is significant to the fair value measurement. The Companys assessment
of the significance of a particular input to the fair value measurement requires judgment, and may
affect the valuation of the fair value of assets and liabilities and their placement within the
fair value hierarchy levels. The following table summarizes the valuation of the Companys
financial instruments by SFAS No. 157 pricing levels as of June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements using |
|
|
Quoted |
|
Significant |
|
|
|
|
|
Total |
|
|
prices |
|
other |
|
Significant |
|
carrying value |
|
|
in active |
|
observable |
|
unobservable |
|
at |
|
|
markets |
|
inputs |
|
inputs |
|
June 30, |
(in thousands) |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
2008 |
|
Oil and natural gas derivative swap contracts |
|
$ |
|
|
|
$ |
(143,402 |
) |
|
$ |
|
|
|
$ |
(143,402 |
) |
Oil and natural gas derivative collar contracts |
|
|
|
|
|
|
|
|
|
|
(15,926 |
) |
|
|
(15,926 |
) |
|
|
|
Total financial liabilities |
|
$ |
|
|
|
$ |
(143,402 |
) |
|
$ |
(15,926 |
) |
|
$ |
(159,328 |
) |
|
|
|
The following table sets forth a reconciliation of changes in the fair value of financial
assets and liabilities classified as Level 3 in the fair value hierarchy (in thousands):
|
|
|
|
|
(in thousands) |
|
Derivatives |
|
|
Balance as of January 1, 2008 |
|
$ |
1,866 |
|
Total gains or (losses), realized or unrealized |
|
|
(18,214 |
) |
Purchases, issuances, and settlements |
|
|
422 |
|
|
|
|
|
Balance as of June 30, 2008 |
|
$ |
(15,926 |
) |
|
|
|
|
|
|
|
|
|
Total gains or losses for the period included in earnings attributable to the change in
unrealized gains or losses relating to assets and/or liabilities still held at the reporting date |
|
$ |
(17,792 |
) |
|
|
|
|
Note E. New accounting pronouncements
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 became
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 adopted this statement January 1, 2008, and the Company
did not elect the fair value option for any of its eligible financial instruments or other items.
As such, the adoption had no impact on the Companys consolidated financial statements.
In April 2007, the FASB issued FASB Staff Position FIN 39-1, Amendment of FASB Interpretation
No. 39 (FIN No. 39-1). FIN No. 39-1 clarifies that a reporting entity that is party to a master
netting arrangement can offset fair value amounts recognized for the right to reclaim cash
collateral (a receivable) or the obligation to return cash collateral (a payable) against fair
value amounts recognized for derivative instruments that have been offset under the same master
netting arrangement. FIN No. 39-1 is effective for financial statements issued for fiscal years
beginning after November 15, 2007. The Company adopted FIN No. 39-1 effective January 1, 2008, and
it has had no material impact on the Companys consolidated financial statements.
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
4
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 adoption of EITF Issue 06-11 has not had a significant effect on the
Companys financial statements since it historically has accounted for the income tax benefits of
dividends paid for share-based payment awards in the manner described in the consensus.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (SFAS
No. 141(R)), which replaces FASB Statement No. 141. SFAS No. 141(R) establishes principles and
requirements for how an acquirer recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree
and the goodwill acquired. The Statement also establishes disclosure requirements that will enable
users to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) is
effective for acquisitions that occur in an entitys fiscal year that begins after December 15,
2008, which will be the Companys fiscal year 2009. The impact, if any, will depend on the nature
and size of business combinations the Company consummates after the effective date.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements an Amendment of ARB No. 51. SFAS No. 160 requires that accounting and
reporting for minority interests will be recharacterized as noncontrolling interests and classified
as a component of equity. SFAS No. 160 also establishes reporting requirements that provide
sufficient disclosures that clearly identify and distinguish between the interests of the parent
and the interests of the noncontrolling owners. SFAS No. 160 applies to all entities that prepare
consolidated financial statements, except not-for-profit organizations, but will affect only those
entities that have an outstanding noncontrolling interest in one or more subsidiaries or that
deconsolidate a subsidiary. This statement is effective as of the beginning of an entitys first
fiscal year beginning after December 15, 2008, which will be the Companys fiscal year 2009. Based
upon the Companys June 30, 2008 consolidated balance sheet, the statement would have no impact.
In December 2007, the Securities and Exchange Commission (SEC) issued Staff Accounting
Bulletin (SAB) No. 110, Share-Based Payment (SAB No. 110). SAB No. 110 amends SAB No. 107,
Share-Based Payment, and allows for the continued use, under certain circumstances, of the
simplified method in developing an estimate of the expected term on stock options accounted for
under SFAS No. 123R, Share-Based Payment (revised 2004). SAB No. 110 is effective for stock
options granted after December 31, 2007. The Company continued to use the simplified method in
developing an estimate of the expected term on stock options granted in the first and second
quarters of 2008. The Company does not have sufficient historical exercise data to provide a
reasonable basis upon which to estimate expected term due to the limited period of time its shares
of common stock have been publicly traded.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities (SFAS No. 161), which amends and expands the disclosure requirements of SFAS
No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), to
provide an enhanced understanding of an entitys use of derivative instruments, how they are
accounted for under SFAS No. 133 and their effect on the entitys financial position, financial
performance and cash flows. The provisions of SFAS No. 161 are effective as of January 1, 2009. The
Company is currently evaluating the impact on its consolidated financial statements of adopting
SFAS No. 161.
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.
5
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, 2008 and
2007:
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
June 30, |
(in thousands) |
|
2008 |
|
2007 |
|
Asset retirement obligations, beginning of period |
|
$ |
9,418 |
|
|
$ |
8,700 |
|
Liability incurred upon acquiring and drilling wells |
|
|
309 |
|
|
|
131 |
|
Accretion expense |
|
|
301 |
|
|
|
228 |
|
Revisions to estimated cash flows |
|
|
328 |
|
|
|
(1,393 |
) |
|
|
|
|
Asset retirement obligations, end of period |
|
$ |
10,356 |
|
|
$ |
7,666 |
|
|
|
|
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 certain employees) on the dates that the various
subscription agreements were signed and the purchase commitments were made.
Capital calls. 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.
6% Series A preferred stock. Preferred stock dividends were generally paid on the anniversary
of date of issue. There were no dividend payments made during the three and six months ended June
30, 2008, because there was no outstanding preferred stock. Preferred stock dividends of
approximately $98,000 and $132,000 were paid during the three and six months ended June 30, 2007,
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.
Purchase Notes. On April 23, 2007, the Companys 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.
6
At June 30, 2008, all Purchase Notes from all employees had been paid in full. As such, the
repayment of the Purchase Notes represents the full exercise of the options on the Capital Options
the certain employees held.
The following table summarizes the Capital Options activity for the six months ended June 30,
2008:
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
Weighted |
|
|
Capital |
|
average |
|
|
Options |
|
exercise price |
|
Six months ended June 30, 2008 |
|
|
|
|
|
|
|
|
Outstanding at beginning of period |
|
|
38,385 |
|
|
$ |
8.34 |
|
$10 Capital Options exercised |
|
|
(38,385 |
) |
|
$ |
8.34 |
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
Vested outstanding at end of period |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
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, 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 A Organization and nature of
operations 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.
Treasury stock. On June 12, 2008, the restrictions on five executive officers restricted
stock awards lapsed. Immediately upon the lapse of restriction, these executive officers were
liable for certain federal income taxes on the value of such shares.
In accordance with the Companys 2006 Stock Incentive Plan and the applicable restricted stock award agreements,
four of such officers elected to deliver shares to the Company to satisfy such tax liability, and the Company
withheld 3,142 shares to be held as treasury stock in the approximate amount of $125,000, the amount of the
executive officers federal tax liability.
Note H. Stock incentive plan
The Concho Resources Inc. 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.
7
All restricted shares are treated as issued and outstanding in the accompanying consolidated
balance sheets. If a grantee terminates employment or other services prior the lapse date, the
awarded shares are forfeited and cancelled and are no longer considered issued and outstanding,
subject to the discretion of the compensation committee. A summary of the Companys restricted
stock awards during the six months ended June 30, 2008 is presented below:
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
Grant date |
|
|
common shares |
|
fair value |
|
Restricted stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007 |
|
|
371,549 |
|
|
|
|
|
Shares granted |
|
|
80,508 |
|
|
$ |
35.17 |
|
Shares cancelled / forfeited |
|
|
(35,262 |
) |
|
|
|
|
Lapse of restrictions |
|
|
(37,001 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2008 |
|
|
379,794 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company recorded stock-based compensation for restricted stock of $468,000 and $560,000,
which is recognized in General and administrative expense in the accompanying consolidated
statement of operations, for the three months ended June 30, 2008 and 2007, respectively. The
Company recorded stock-based compensation for restricted stock of $862,000 and $781,000, which is
recognized in General and administrative expense in the accompanying consolidated statement of
operations, for the six months ended June 30, 2008 and 2007, respectively. Future stock-based
compensation expense related to restricted stock outstanding at June 30, 2008 for the remaining six
months of 2008 and the years ending December 31, 2009, 2010 and 2011 is expected to be
approximately $1,358,000, $1,930,000, $1,162,000 and $354,000, respectively.
The income tax benefit recognized in the accompanying statement of operations for restricted
stock was approximately $187,000 and $235,000 for the three months ended June 30, 2008 and 2007,
respectively, and $341,000 and $327,000 for the six months ended June 30, 2008 and 2007,
respectively. The Company had deductions in current taxable income of
$771,000 and $340,000 for the three months ended June 30, 2008 and
2007, respectively, and $1.2 million and $425,000 for
the six months ended June 30, 2008 and 2007, respectively, related to restricted stock awards.
Stock option awards. In calculating compensation expense for options granted during the six
months ended June 30, 2008, the Company estimated the fair value of each grant using the
Black-Scholes option-pricing model. Assumptions utilized in the model are shown below.
|
|
|
|
|
|
|
2008 |
|
Risk-free interest rate |
|
|
3.18 |
% |
Expected term (years) |
|
|
6.22 |
|
Expected volatility |
|
|
37.28 |
% |
Expected dividend yield |
|
|
0.00 |
% |
As permitted by SAB No. 110, the Company used the simplified method to calculate the expected
term for stock options granted during the three and six months ended June 30, 2008, since it does
not have sufficient historical exercise data to provide a reasonable basis upon which to estimate
expected term due to the limited period of time its shares of common stock have been publicly
traded. Expected volatilities are based on a combination of historical and implied volatilities of comparable companies.
8
A summary of the Companys stock option activity under the Plan for the six months ended June
30, 2008 is presented below:
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
June 30, 2008 |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Average |
|
|
Number of |
|
Exercise |
|
|
options (a) |
|
Price |
|
Stock options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of period |
|
|
3,011,722 |
|
|
$ |
9.71 |
|
Options granted |
|
|
545,555 |
|
|
$ |
22.80 |
|
Options forfeited |
|
|
(250,593 |
) |
|
$ |
14.91 |
|
Options exercised |
|
|
(262,713 |
) |
|
$ |
9.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period |
|
|
3,043,971 |
|
|
$ |
11.69 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period |
|
|
717,236 |
|
|
$ |
10.21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
One option can be exercised for one share of Resources common stock. |
The following table summarizes information about the Companys vested stock options
outstanding and exercisable at June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
average |
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Number |
|
|
remaining |
|
|
average |
|
|
|
|
|
|
|
|
|
|
vested and |
|
|
contractual |
|
|
exercise |
|
|
Intrinsic |
|
|
|
|
|
|
|
exercisable |
|
|
life |
|
|
price |
|
|
value |
|
|
Vested Options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price |
|
$ |
8.00 |
|
|
|
1,543,020 |
|
|
2.77 years |
|
$ |
8.00 |
|
|
$ |
45,210,000 |
|
Exercise price |
|
$ |
12.00 |
|
|
|
164,016 |
|
|
5.61 years |
|
$ |
12.00 |
|
|
|
4,150,000 |
|
Exercise price |
|
$ |
15.40 |
|
|
|
181,250 |
|
|
7.96 years |
|
$ |
15.40 |
|
|
|
3,969,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,888,286 |
|
|
|
|
|
|
$ |
9.06 |
|
|
$ |
53,329,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable Options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price |
|
$ |
8.00 |
|
|
|
454,224 |
|
|
3.42 years |
|
$ |
8.00 |
|
|
$ |
13,309,000 |
|
Exercise price |
|
$ |
12.00 |
|
|
|
106,762 |
|
|
7.28 years |
|
$ |
12.00 |
|
|
|
2,701,000 |
|
Exercise price |
|
$ |
15.40 |
|
|
|
156,250 |
|
|
7.96 years |
|
$ |
15.40 |
|
|
|
3,422,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
717,236 |
|
|
|
|
|
|
$ |
10.21 |
|
|
$ |
19,432,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
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, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
|
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
Grant date fair value: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time Vesting options (a) |
|
$ |
|
|
|
$ |
|
|
|
$ |
183,000 |
|
|
$ |
|
|
Current officer stock options (c) |
|
|
794,000 |
|
|
|
|
|
|
|
5,090,000 |
|
|
|
|
|
|
|
|
Total |
|
$ |
794,000 |
|
|
$ |
|
|
|
$ |
5,273,000 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense from stock options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time Vesting options (a) |
|
$ |
35,000 |
|
|
$ |
|
|
|
$ |
65,000 |
|
|
$ |
|
|
Performance Vesting options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Officers (b) |
|
|
123,000 |
|
|
|
141,000 |
|
|
|
264,000 |
|
|
|
279,000 |
|
Certain employee (b) |
|
|
10,000 |
|
|
|
10,000 |
|
|
|
20,000 |
|
|
|
20,000 |
|
Current officer stock options (c) |
|
|
1,094,000 |
|
|
|
418,000 |
|
|
|
1,818,000 |
|
|
|
874,000 |
|
|
|
|
Total |
|
$ |
1,262,000 |
|
|
$ |
569,000 |
|
|
$ |
2,167,000 |
|
|
$ |
1,173,000 |
|
|
|
|
|
|
|
(a) |
|
Options vest using a four year graded vesting schedule. |
|
(b) |
|
Options granted prior to February 27, 2006, vest using a three year graded
vesting schedule. |
|
(c) |
|
Vest using a three and four year graded vesting schedule as approved by the Board of
Directors. |
Future stock-based compensation expense related to stock options outstanding at June 30, 2008
for the remaining six months ended December 31, 2008 and the years ending December 31, 2009, 2010,
2011 and 2012 is expected to be approximately $2,288,000, $2,553,000, $1,151,000, $419,000 and
$42,000, respectively.
The income tax benefit recognized in the Companys statements of operations for stock options
was $504,000 and $239,000 for the three months ended June 30, 2008 and 2007, respectively, and
$858,000 and $492,000 for the six months ended June 30, 2008 and 2007, respectively. The Company
had deductions in current taxable income of $3.1 million for the three months ended June 30, 2008,
as options on 119,961 shares of common stock were exercised during such quarter. No amounts were
treated as deductions to the Companys current taxable income for the three months ended June 30,
2007, since no options were exercised during such quarter. The Company had deductions in current
taxable income of $5.3 million for the six months ended June 30, 2008, as options on 262,713 shares
of common stock were exercised during such period. No amounts were treated as deductions to the
Companys current taxable income for the six months ended June 30, 2007, since no options were
exercised during such quarter.
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 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. On
the respective trade dates, the Company has designated all of these derivative instruments as cash
flow hedges.
10
During the three months ended September 30, 2007, the Company determined that all of its
natural gas commodity contracts no longer qualified as hedges under the requirements of SFAS No.
133 for the reason stated in the following paragraph. These contracts are referred to as
dedesignated hedges.
A key requirement for designation of derivative instruments as cash flow hedges is that at
both at inception of the hedge and on an ongoing basis, the hedging relationship is expected to be
highly effective in achieving offsetting cash flows attributable to the hedged risk during the term
of the hedge. Generally, the hedging relationship can be considered to be highly effective if there
is a high degree of historical correlation between the hedging instrument and the forecasted
transaction. For all quarters ended prior to July 1, 2007, prices received for the Companys
natural gas were highly correlated with the Inside FERC El Paso Natural Gas index (the Index)
the Index referenced in all of the Companys natural gas derivative instruments. However, during
the quarter ended September 30, 2007, this historical relationship has not met the criteria as
being highly correlated. Natural gas produced from the Companys New Mexico shelf assets has a
substantial component of natural gas liquids. Prices received for natural gas liquids are not
highly correlated to the price of natural gas, but are more closely correlated to the price of oil.
During the third quarter of 2007, the price of oil and natural gas liquids, and therefore, the
prices the Company received for its natural gas (including natural gas liquids) have risen
substantially and at a significantly higher rate than the corresponding change in the Index. This
has resulted in a decrease in correlation between the prices received and the Index below the level
required for cash flow hedge accounting. According to SFAS No. 133, an entity shall discontinue
hedge accounting prospectively for an existing hedge if the hedge is no longer highly effective.
Hedge accounting must be discontinued regardless of whether the Company believes the hedge will be
prospectively highly effective. The hedge must be discontinued during the period the hedges became
ineffective. As a result, any changes in fair value must be recorded in earnings under (Gain) loss
on derivatives not designated as hedges. Because the gas and liquids prices fluctuate at different
rates over time, the loss of effectiveness does not relate to any single date.
Therefore, June 30, 2007, was considered the last date the Companys natural gas hedges were
highly effective, and the Company discontinued hedge accounting during the three months ended
September 30, 2007 and all periods thereafter. Mark-to-market adjustments related to these
dedesignated hedges is recorded each period to (Gain) loss on derivatives not designated as hedges.
Effective portions of dedesignated hedges, previously recorded in Accumulated other comprehensive
income (AOCI) as of June 30, 2007, remain in AOCI and are being reclassified into earnings under
Natural gas revenues, during the periods which the hedged forecasted transaction affects earnings.
11
Derivatives not designated as cash flow hedges. During the six months ended June 30, 2008,
the Company entered into crude oil price swaps, a crude oil costless collar and a natural gas price
swap to hedge a portion of its estimated production for the remainder of 2008, and for calendar
years 2009, 2010, 2011 and 2012. The following table summarizes information about these new
derivative instruments as of June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
|
|
|
|
|
|
|
remaining |
|
Daily |
|
Index |
|
Contract |
|
|
volume |
|
volume |
|
price |
|
period |
|
Derivatives not designated as cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar |
|
|
768,000 |
|
|
|
2,104 |
|
|
$120.00 - $134.60 (a) |
|
|
1/1/09 - 12/31/09 |
|
Price swap |
|
|
258,000 |
|
|
|
1,400 |
|
|
$99.25 (a) |
|
|
7/1/08 - 12/31/08 |
|
Price swap |
|
|
292,000 |
|
|
|
800 |
|
|
$98.35 (a) |
|
|
1/1/09 - 12/31/09 |
|
Price swap |
|
|
240,000 |
|
|
|
658 |
|
|
$128.80 (a) |
|
|
1/1/10 - 12/31/10 |
|
Price swap |
|
|
336,000 |
|
|
|
921 |
|
|
$128.66 (a) |
|
|
1/1/11 - 12/31/11 |
|
Price swap |
|
|
504,000 |
|
|
|
1,377 |
|
|
$127.80 (a) |
|
|
1/1/12 - 12/31/12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
1,825,000 |
|
|
|
5,000 |
|
|
$8.44 (b) |
|
|
1/1/09 - 12/31/09 |
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate monthly
average futures price. |
|
(b) |
|
The index price for the natural gas price collar is based on the Inside FERC-El Paso Permian
Basin first-of-the-month spot price. |
The Company has not designated these derivative instruments as cash flow hedges. Mark-to-market
adjustments related to these derivative instruments are recorded each period to (Gain) loss on
derivatives not designated as hedges.
12
Fair value and activity of derivative instruments. The following table sets forth the
Companys outstanding crude oil and natural gas zero cost price collars and price swaps at June 30,
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Market Value |
|
|
Aggregate |
|
|
|
|
|
|
|
|
|
|
|
Liability |
|
|
remaining |
|
|
Daily |
|
|
Index |
|
Contract |
|
|
|
(in thousands) |
|
|
volume |
|
|
volume |
|
|
price |
|
period |
|
|
Cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
$ |
(34,958 |
) |
|
|
478,400 |
|
|
|
2,600 |
|
|
$67.50 (a) |
|
|
7/1/08 - 12/31/08 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges dedesignated: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar |
|
|
(7,348 |
) |
|
|
2,484,000 |
|
|
|
13,500 |
|
|
$6.50 - $9.35 (b) |
|
|
7/1/08 - 12/31/08 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar |
|
|
(8,578 |
) |
|
|
768,000 |
|
|
|
2,104 |
|
|
$120.00 - $134.60 (a) |
|
|
1/1/09 - 12/31/09 |
|
Price swap |
|
|
(34,558 |
) |
|
|
625,600 |
|
|
|
3,400 |
|
|
$85.44 (a) (c) |
|
|
7/1/08 - 12/31/08 |
|
Price swap |
|
|
(60,264 |
) |
|
|
1,022,000 |
|
|
|
2,800 |
|
|
$80.13 (a) (c) |
|
|
1/1/09 - 12/31/09 |
|
Price swap |
|
|
(2,182 |
) |
|
|
240,000 |
|
|
|
658 |
|
|
$128.80 (a) |
|
|
1/1/10 - 12/31/10 |
|
Price swap |
|
|
(2,522 |
) |
|
|
336,000 |
|
|
|
921 |
|
|
$128.66 (a) |
|
|
1/1/11 - 12/31/11 |
|
Price swap |
|
|
(3,785 |
) |
|
|
504,000 |
|
|
|
1,377 |
|
|
$127.80 (a) |
|
|
1/1/12 - 12/31/12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
(5,133 |
) |
|
|
1,825,000 |
|
|
|
5,000 |
|
|
$8.44 (b) |
|
|
1/1/09 - 12/31/09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net liability |
|
$ |
(159,328 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate monthly
average futures price. |
|
(b) |
|
The index price for the natural gas price collar is based on the Inside FERC-El Paso Permian
Basin first-of-the-month spot price. |
|
(c) |
|
Amounts disclosed represent weighted average prices. |
The following table sets forth the Companys classification of derivative instruments as of
June 30, 2008:
|
|
|
|
|
|
|
Fair Market Value |
|
(in thousands) |
|
Liability |
|
|
Derivative liabilities: |
|
|
|
|
Short-term |
|
|
(114,504 |
) |
Long-term |
|
|
(44,824 |
) |
|
|
|
|
Net liability |
|
$ |
(159,328 |
) |
|
|
|
|
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 gains and losses
reported in earnings related to the commodity financial instruments and the net change in AOCI:
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
(in thousands) |
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
Increase (decrease) in oil and gas revenue from derivative activity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash (payments) receipts on cash flow hedges in oil sales |
|
$ |
(13,367 |
) |
|
$ |
(783 |
) |
|
$ |
(20,573 |
) |
|
$ |
244 |
|
Cash receipts from cash flow hedges in gas sales |
|
|
|
|
|
|
49 |
|
|
|
|
|
|
|
187 |
|
Dedesignated cash flow hedges reclassified from AOCI in gas sales |
|
|
74 |
|
|
|
|
|
|
|
(222 |
) |
|
|
|
|
|
|
|
Total increase (decrease) in oil and gas revenue from derivative activity |
|
$ |
(13,293 |
) |
|
$ |
(734 |
) |
|
$ |
(20,795 |
) |
|
$ |
431 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on derivatives not designated as cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market |
|
$ |
(90,055 |
) |
|
$ |
|
|
|
$ |
(103,247 |
) |
|
$ |
|
|
Cash payments on derivatives not designated as cash flow hedges |
|
|
(12,401 |
) |
|
|
|
|
|
|
(16,387 |
) |
|
|
|
|
|
|
|
Total loss on derivatives not designated as cash flow hedges |
|
$ |
(102,456 |
) |
|
$ |
|
|
|
$ |
(119,634 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) from ineffective portion of cash flow hedges |
|
$ |
356 |
|
|
$ |
99 |
|
|
$ |
920 |
|
|
$ |
(1,156 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market of cash flow hedges gain (loss) |
|
$ |
(25,903 |
) |
|
$ |
992 |
|
|
$ |
(32,510 |
) |
|
$ |
(7,457 |
) |
Reclassification adjustment for (gains) losses included in net income |
|
|
13,367 |
|
|
|
734 |
|
|
|
20,573 |
|
|
|
(431 |
) |
|
|
|
Net change, before taxes |
|
|
(12,536 |
) |
|
|
1,726 |
|
|
|
(11,937 |
) |
|
|
(7,888 |
) |
Tax effect |
|
|
4,899 |
|
|
|
(724 |
) |
|
|
4,665 |
|
|
|
3,288 |
|
|
|
|
Net change, net of tax |
|
$ |
(7,637 |
) |
|
$ |
1,002 |
|
|
$ |
(7,272 |
) |
|
$ |
(4,600 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dedesignated cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification adjustment for (gains) losses included in net income |
|
$ |
(74 |
) |
|
$ |
|
|
|
$ |
222 |
|
|
$ |
|
|
Tax effect |
|
|
29 |
|
|
|
|
|
|
|
(87 |
) |
|
|
|
|
|
|
|
Net change, net of tax |
|
$ |
(45 |
) |
|
$ |
|
|
|
$ |
135 |
|
|
$ |
|
|
|
|
|
All of the Companys derivatives are expected to settle by December 31, 2012. Based on futures
prices as of June 30, 2008, the Company expects a pre-tax loss of $34.5 million to be reclassified
into earnings and a pre-tax loss of $0.5 million to be reclassified out of AOCI into earnings
during the six months ended December 31, 2008 related to the cash flow hedges and the dedesignated
cash flow hedges, respectively.
14
Note J. Long-term debt
The Companys long-term debt consisted of the following as of the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
(in thousands) |
|
2008 |
|
2007 |
|
Bank debt: |
|
|
|
|
|
|
|
|
1st Lien Credit Facility |
|
$ |
190,000 |
|
|
$ |
216,000 |
|
New 2nd Lien Credit Facility |
|
|
108,900 |
|
|
|
109,900 |
|
Unamortized original issue discount on New 2nd Lien Credit Facility |
|
|
(447 |
) |
|
|
(496 |
) |
|
|
|
Total long-term debt |
|
$ |
298,453 |
|
|
$ |
325,404 |
|
Current portion of New 2nd Lien Credit Facility |
|
|
2,500 |
|
|
|
2,000 |
|
|
|
|
Total debt |
|
$ |
300,953 |
|
|
$ |
327,404 |
|
|
|
|
Refinancing of debt facilities. As of March 27, 2007, the Company amended its revolving
credit facility (1st Lien Credit Facility) with a syndicate of banks (1st Lien Banks), repaid
its term loan facility, and entered into a new second lien credit facility (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 existing second 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 amount outstanding under the 1st Lien Credit Facility at June 30,
2008 was $190.0 million.
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 term loan facility repaid in full on March 27, 2007,
were written off and included in Interest expense in the first quarter of 2007.
The Company paid an arrangement fee of $2.5 million at the date of closing of the New 2nd Lien
Credit Facility. This fee is being amortized to Interest expense over the five-year term of the
facility beginning in April 2007.
The Company entered into the Third Amendment to the 1st Lien Credit Facility on May 19, 2008,
which redetermined the borrowing base under the 1st Lien Credit Facility to $550 million at June
30, 2008 and extended the maturity date to February 24, 2011. The Company incurred approximately
$1.0 million in deferred loan costs associated with this amendment. These costs will be amortized
to Interest expense over the new term of the facility.
The New 2nd Lien Credit Facility provides a $200 million term loan, which bears interest, at
the Companys option, based on (a) the Bank of America Prime Rate (5.00 percent at June 30, 2008)
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 August 7, 2007, when the Company completed its
initial public offering; thereafter, interest margins on Eurodollar rate advances and prime rate
advances increased to 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. These payments began on June 30, 2007. The maturity date of the New
2nd Lien Credit Facility is March 27, 2012. The Company has the right to prepay the outstanding
balance under the New 2nd Lien Credit Facility at any time; however, 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 following the closing.
Thereafter, 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 only 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
15
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; (c)
restrictions as to merger and sale or transfer of assets; and (d) a restriction on the payment of
cash dividends. The Company was in compliance with all covenants of the New 2nd Lien Credit
Facility at June 30, 2008.
The amount outstanding under New 2nd Lien Credit Facility at June 30, 2008 was $111.0 million,
net of a discount of $0.4 million, all of which was at the Eurodollar rate.
Repayment of a portion of New 2nd Lien Credit Facility. As described in Note A Organization
and nature of operations, 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 $112.4 million. As set
forth by this facilitys credit agreement, 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, and remain in effect at June 30, 2008.
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.
Principal maturities of long-term debt. Principal maturities of long-term debt outstanding,
excluding the unamortized discount of approximately $0.4 million, at June 30, 2008, for the six months ended
December 31, 2008 and the years ended December 31, 2009,
2010, 2011 and 2012, are as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2008 |
|
$ |
1,500 |
|
2009 |
|
|
2,000 |
|
2010 |
|
|
192,000 |
|
2011 |
|
|
2,000 |
|
2012 |
|
|
103,900 |
|
|
|
|
|
Total |
|
$ |
301,400 |
|
|
|
|
|
As of July 31, 2008, the Company amended its 1st Lien Credit Facility, increasing the
borrowing base 75% from $550 million to $960 million and extended the maturity date from February
24, 2011 to July 31, 2013. See further discussion in Note O Subsequent events.
Note K. Commitments and contingencies
Daywork drilling contract commitments. The Company signed a daywork drilling contract with a
drilling contractor 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 contract drilling fees of approximately $1.3 million related to this stacked rig
during the year ended December 31, 2007. These costs were minimized as the drilling contractor
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 the drilling contractor on June 26,
2007, that provided the Company exclusive use of one rig for a term that commenced on July 3, 2007
and ended 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 the drilling
contractor is liable for its employees, subcontractors and invitees. In addition, the drilling
contractor is responsible for pollution or contamination from their equipment. The drilling
contractor will release the Company of any liability for negligence of any party in connection with
the drilling contractor. The
operating day rate is $14,000. The operating day rate can be revised to reflect changes in
costs incurred by the drilling contractor 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 the drilling contractor secures work
for the subject rig with a new customer prior to the end of the contract
16
term, the drilling
contractor 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. Beginning on January 4,
2008, this contract was extended through July 31, 2008. The amended contract changed the operating
day rate from $14,000 to $13,250. Beginning on March 12, 2008, this contract was amended to change
the operating day rate from $13,250 to $12,850 and to extend the term through July 31, 2009. On
June 24, 2008, this contract was amended to include an additional rig with an operating day rate of
$13,250 for a term ending on July 15, 2009.
The Company signed daywork drilling contracts with Silver Oak Drilling, LLC (Silver Oak), an
affiliate of the Chase Group, on August 1, 2006, that provided the Company use of four drilling
rigs for a term that commenced on August 1, 2006 and ended on July 31, 2007. The Company could
direct the rig to locations located in New Mexico as needed. If the Company moved 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 was solely responsible and assumes liability
for all consequences of operations by both parties while on a daywork basis, with the exception
that Silver Oak was liable for its employees, subcontractors and invitees. In addition, Silver Oak
was responsible for pollution or contamination from their equipment. Silver Oak released the
Company of any liability for negligence of any party connected to Silver Oak. The operating day
rate was $14,500 for two of the contracts and $13,500 for the other two contracts. The operating
day rate could 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 contracts, 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 contracts, Silver Oak
had a duty to mitigate damages to the Company by reasonably attempting to secure replacement
contracts for the rigs if they were 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 would then be entitled
to a 75 percent credit for any revenues received by Silver Oak. Even if the Company released the
rigs, the Company, with 20 days notice, could withdraw its release and reactivate the contract for
the remainder of the term to the extent the rig had 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 contract drilling fees of approximately
$2,973,000 related to these stacked rigs during the year ended December 31, 2007, based on the
drilling contracts 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 commenced on August 1, 2007 and are
in effect until drilling operations are completed on specified wells or for a term of one year. If
any well commenced during the term of the contract is drilling at the expiration of the one year
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 contracts for the remainder of the term to the extent the
subject rig has not been committed to a third party in mitigation of damages. Beginning on June 30,
2008, these contracts were amended to change the operating day rates from $14,500 to $15,000 and
from $13,500 to $14,000 and to extend the term through August 1, 2009.
Note L. 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 No. 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, 2008, the Company did not have any significant uncertain tax positions
requiring recognition in the financial statements. The tax years 2004 through 2007 remain subject
to examination by major tax jurisdictions.
The FASB issued FIN No. 48-1, Definition of Settlement in FASB Interpretation No. 48, (FIN
No. 48-1) to clarify when a tax position is effectively settled. FIN No. 48-1 provides guidance in
determining the proper timing for recognizing tax benefits and applying the new information
relevant to the technical merits of a tax position obtained during a tax authority examination. FIN
No.
17
48-1 provides criteria to determine whether a tax position is effectively settled after
completion of a tax authority examination, even if the potential legal obligation remains under the
statute of limitations. The Companys adoption of this pronouncement did not have a significant
effect on its consolidated financial statements.
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.
Note M. Related parties
Contract Operator Agreement and Transition Services Agreement. 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. 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 continued to provide certain field level operating services on the
Chase Group Properties. Under the Transition Services Agreement, MEC provided 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 prior Contract Operator Agreement prior to its
termination. In accordance with its terms, the Transition Services Agreement was terminated
automatically by its terms on August 7, 2007 upon the Companys completion of the IPO. Upon
termination, the Companys employees along with third party contractors assumed the operation of
the subject properties.
The Company incurred charges from MEC of approximately $260,000 and $1.5 million for the three
and six months ended June 30, 2008, respectively.
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 and Transition Services Agreement.
At June 30, 2008, the Company had outstanding invoices payable to MEC of approximately $5,000
which are reflected in Accounts payablerelated parties in the accompanying consolidated balance
sheet.
At December 31, 2007, the Company had outstanding invoices payable to MEC of approximately
$0.4 million which are reflected in Accounts payablerelated parties in the accompanying
consolidated balance sheet.
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 $5.7 million
and $13.1 million for the three and six months ended June 30, 2008, respectively, for services
rendered and charges 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 had outstanding invoices payable to the other related party vendors identified
above of approximately $264,000 and $1.7 million at June 30, 2008 and December 31, 2007,
respectively, which are reflected in Accounts payablerelated parties in the accompanying
consolidated balance sheets.
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 $816,000 and $1.6 million for the three and six months ended June 30,
2008, respectively. The amount paid attributable to such interests was approximately $458,000 and
$1.0 million for the three and six months ended June 30, 2007, respectively. The Company owed
these owners royalty payments of approximately $322,000 and $315,000 as of June 30, 2008 and
December 31, 2007, respectively.
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 this partnership approximately $81,000 and $164,000 for the three and
six months ended June 30, 2008, respectively. The Company paid approximately $36,000 and $59,000
for the three and six months ended June 30, 2007, respectively. The Company owed this partnership
royalty payments of approximately $30,000 and $29,000 as of June 30, 2008 and December 31, 2007,
respectively.
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
18
acquisition. In connection with this
acquisition, such entity retained a 2% overriding royalty interest in the acquired properties,
which overriding royalty interest later became owned equally by such officer and a non-officer
employee of the Company. During the three and six months ended June 30, 2008, no payments were made
related to this overriding royalty interest. The amount attributable to such interest was
approximately $2,000 during the three and six months ended June 30, 2007. Effective March 31, 2008,
the referenced executive officer resigned from the Company.
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.
There were no amounts paid to Caza for these interests during the three and six months ended
June 30, 2008, and during the three months ended June 30, 2007. The Company paid Caza approximately
$3,000 for the six months ended June 30, 2007 for delay rentals.
At June 30, 2008 and December 31, 2007, the Company had no outstanding invoices owed to Caza.
Note N. Net income per share
Basic net 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. All Bundled Capital Options were
exercised prior to June 30, 2007. All Capital Options were exercised prior to March 31, 2008.
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 and restricted stock (as issued under the Plan, as described in Note H
Stock incentive plan. Potentially dilutive effects are calculated using the treasury stock method.
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, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
(in thousands) |
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
75,665 |
|
|
|
57,747 |
|
|
|
75,569 |
|
|
|
56,369 |
|
Dilutive Bundled Capital Options |
|
|
|
|
|
|
660 |
|
|
|
|
|
|
|
1,695 |
|
Dilutive Capital Options |
|
|
|
|
|
|
160 |
|
|
|
12 |
|
|
|
204 |
|
Dilutive common stock options |
|
|
|
|
|
|
996 |
|
|
|
1,206 |
|
|
|
921 |
|
Dilutive restrictive stock |
|
|
|
|
|
|
62 |
|
|
|
247 |
|
|
|
71 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
75,665 |
|
|
|
59,625 |
|
|
|
77,034 |
|
|
|
59,260 |
|
|
|
|
For the three months ended June 30, 2008, the computation of diluted net loss per share was
antidilutive; therefore, the amounts reported for basic and diluted net loss per share were the
same. Restricted stock and options equivalent to 379,794 and 3,043,971
shares of common stock were not included in the computation of diluted income (loss) per share
for the three months ended June 30, 2008, respectively, as inclusion of these items would be
antidilutive.
For the three and six months ended June 30, 2007, and for the six months ended June 30, 2008,
the effects of all potentially dilutive 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.
19
Note O. Subsequent events
New derivative instruments. On July 25, 2008, the Company entered into two crude oil price
swaps to hedge a portion of its estimated crude oil production for calendar years 2008 and 2009.
The contracts are for 49,000 Bbls per month for the remainder of 2008 (August through December) at
a fixed price of $124.35 per Bbl, and 29,000 Bbls per month for calendar year 2009 at a fixed price
of $125.10 per Bbl. The Company has not designated these derivative instruments as cash flow
hedges. Mark-to-market adjustments related to these derivative instruments will be recorded each
period to (Gain) loss on derivatives not designated as hedges.
Henry Acquisition. On July 31, 2008, the Company closed the acquisition of Henry Petroleum LP
and certain affiliated entities (collectively Henry) (the Acquisition). Cash paid at closing
totaled approximately $560 million. The Company financed the Acquisition with proceeds raised from
a $250.0 million private placement of 8.3 million shares of the Companys common stock, together
with funds available under a new amended and restated senior credit facility (the Senior Credit
Facility), as further described below. After the closing of the Henry transaction and the
additional interests acquired concurrently as described below, the Company has approximately $285 million of availability under the Senior
Credit Facility.
In connection with the Acquisition, the Company also purchased certain additional non-operated
rights and interests in Henrys oil and gas properties from certain persons affiliated with Henry (such
transactions, collectively, the Along-side Transactions) for aggregate cash consideration of
approximately $28.0 million.
The following table shows the sources and uses of funds for the above referenced transactions
on July 31, 2008:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Sources of Funds: |
|
|
|
|
Proceeds from Issuance of Common Shares |
|
$ |
250,000 |
|
Initial Borrowing under Senior Credit Facility |
|
|
675,000 |
|
|
|
|
|
Total Sources of Funds |
|
$ |
925,000 |
|
|
|
|
|
|
|
|
|
|
Uses of Funds: |
|
|
|
|
Purchase of Henry Equity Interests |
|
$ |
536,830 |
|
Repay 1st Lien Credit Facility |
|
|
194,389 |
|
Repay 2nd Lien Credit Facility |
|
|
113,189 |
|
Purchase of Along-side Property Interests |
|
|
28,039 |
|
Fees and Expenses |
|
|
24,829 |
|
Working Capital and General Corporate Purposes |
|
|
27,724 |
|
|
|
|
|
Total uses of Funds |
|
$ |
925,000 |
|
|
|
|
|
Common Stock Purchase Agreement. On June 5, 2008, the Company also entered into a Common Stock
Purchase Agreement (the Purchase Agreement) with certain unaffiliated third-party investors (the
Purchasers) to sell approximately 8.3 million shares
of the Companys common stock in a private placement (the Private Placement) for aggregate
cash consideration of approximately $250.0 million, for a negotiated price of $30.11 per share. The
Private Placement closed simultaneously with the Acquisition on July 31, 2008.
The closing of the Private Placement was subject to customary closing conditions, as well as
certain other conditions, including (i) the closing of the Acquisition and (ii) the execution by
the Company and the Purchasers of a registration rights agreement that will require the Company to
file a shelf registration statement for the benefit of the Purchasers within 60 days after the
closing of the Private Placement.
The Private Placement is being made in reliance upon an exemption from the registration
requirements of the Securities Act of 1933, pursuant to Section 4(2) thereof.
Amended and Restated Credit Facility. As of July 31, 2008, the Company amended and restated
its senior credit facility in various respects including, increasing the borrowing base to $960 million, subject to semiannual
redetermination, and extending the maturity date from February 24, 2011 to July 31, 2013 (the
Senior Credit Facility, as defined above). The initial borrowing under the Senior Credit Facility
was
20
$675 million. The Company paid an arrangement fee of $14.4 million at the date of closing
of the Senior Credit Facility. This fee is being amortized to Interest expense over the remaining
five year term of the facility beginning in August 2008.
Advances on the Senior Credit Facility bear interest, at the Companys option, based on
(a) the prime rate of JPMorgan Chase Bank (JPM Prime Rate) (5.00 percent at July 31, 2008) 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 125 - 275 basis points and 0 - 125 basis points, respectively, per annum depending on the
balance outstanding. The Company pays commitment fees on the unused portion of the available
borrowing base ranging from 25 - 50 basis points per annum.
The Senior 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.
The Companys obligations under the Senior Credit Facility are secured by a first lien on
substantially all of the Companys oil and gas properties. In addition, all of the
Companys subsidiaries are guarantors, and all subsidiary general partner, limited partner and
membership interests owned by the Company have been pledged to secure borrowings under the Senior
Credit Facility. 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 4.0 to 1.0, 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; (c) restrictions as to merger and sale or transfer of
assets; and (d) a restriction on the payment of cash dividends.
Note P. Supplementary information
Capitalized costs
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
(in thousands) |
|
2008 |
|
2007 |
|
Oil and gas properties: |
|
|
|
|
|
|
|
|
Proved |
|
$ |
1,432,392 |
|
|
$ |
1,303,665 |
|
Unproved |
|
|
242,771 |
|
|
|
251,353 |
|
Less accumulated depletion
|
|
|
(209,688 |
) |
|
|
(167,109 |
) |
|
|
|
Net capitalized costs for oil and gas properties |
|
$ |
1,465,475 |
|
|
$ |
1,387,909 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred for oil and gas producing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
(in thousands) |
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
(104 |
) |
|
$ |
113 |
|
|
$ |
1 |
|
|
$ |
113 |
|
Unproved |
|
|
587 |
|
|
|
3,001 |
|
|
|
1,349 |
|
|
|
3,791 |
|
Exploration |
|
|
20,942 |
|
|
|
30,027 |
|
|
|
50,507 |
|
|
|
41,734 |
|
Development |
|
|
45,146 |
|
|
|
2,072 |
|
|
|
70,799 |
|
|
|
17,373 |
|
Capitalized asset retirement obligations |
|
|
1,412 |
|
|
|
(922 |
) |
|
|
637 |
|
|
|
(1,289 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred for oil and gas properties |
|
$ |
67,983 |
|
|
$ |
34,291 |
|
|
$ |
123,293 |
|
|
$ |
61,722 |
|
|
|
|
21
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 our historical consolidated financial statements and notes, as well as the
selected historical consolidated financial data included in our Annual Report on Form 10-K for the
year ended December 31, 2007.
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 producing oil and natural gas properties. Our conventional
operations are primarily focused in the Permian Basin of Southeast New Mexico and West Texas. We
have also acquired significant acreage positions in unconventional emerging resource plays located
in the Permian Basin of Southeast New Mexico, the Central Basin Platform and the Western Delaware
Basin of West Texas, the Williston Basin in North Dakota and the Arkoma Basin in Arkansas, where we
intend to apply horizontal drilling, advanced fracture stimulation and enhanced recovery
technologies. Crude oil comprised 59% of our 546.0 Bcfe of estimated net proved reserves as of
December 31, 2007, and 60% of our 30.1 Bcfe of production for the year ended December 31, 2007. We
seek to operate the wells in which we own an interest, and we operated wells that accounted for 90%
of our PV-10 and 50% of our 2,067 wells as of December 31, 2007. By controlling operations, we are
able to more effectively manage the cost and timing of exploration and development of our
properties, including the drilling and stimulation methods used.
Recent Events
Short-term interruptions in production. During the first quarter of 2008, we experienced
short-term interruptions in our production on the New Mexico shelf properties due to operational
problems with a natural gas processing plant. There were a total of 10 days of curtailment during
the first quarter, and approximately 100 MMcfe of our production was curtailed during this period.
Additionally, on April 7, 2008, a natural gas processing plant through which we process and
sell a portion of the production from our New Mexico shelf properties was curtailed for its annual
routine maintenance. The plant resumed full operation on April 19, 2008, and we thereafter began
restoring production from all of our properties that had been affected. Approximately 450 MMcfe of
our production was shut-in as a result of this plant shut-down.
On May 16, 2008, a refinery located in New Mexico shut down for ten days due to repairs. As a
result, the Company shut-in approximately 221 MMCFE of production during the ten day period.
Amended credit agreement. We entered into the Third Amendment to the 1st Lien Credit Facility
on May 19, 2008, which redetermined the borrowing base under the 1st Lien Credit Facility to $550
million at June 30, 2008.We incurred approximately $1.0 million in deferred loan costs associated
with this amendment. These costs will be amortized to Interest expense over the new term of the
facility. As of July 31, 2008, we amended and restated our 1st Lien Credit Facility, increasing
the borrowing base to $960 million and extending
the maturity date from February 24, 2011 to July 31, 2013. See further discussion below in
Subsequent events.
Treasury stock. On June 12, 2008, the restrictions on five executive officers restricted
stock awards lapsed. Immediately upon the lapse of restriction, these executive officers were
liable for certain federal income taxes on the value of such shares.
In accordance with our 2006 Stock Incentive Plan and the applicable
restricted stock award agreements, four of such officers elected to
deliver shares to the Company to satisfy such tax liability, and the
Company withheld 3,142 shares to be held as treasury stock in the
approximate amount of $125,000, the amount of the executive
officers federal tax liability.
New derivative instruments. On June 5, 2008, the Company entered into a crude oil costless
collar to hedge a portion of its estimated crude oil production for calendar year 2009. The
contract is for 64,000 Bbls per month (or 2,104 Bbls per day) for calendar year 2009 with a ceiling
of $134.60 per Bbl and a floor of $120.00 per Bbl. The Company has not designated this derivative
instrument as a cash flow hedge. Mark-to-market adjustments related to this derivative instrument
will be recorded each period to (Gain) loss on derivatives not designated as hedges.
22
On June 6, 2008, the Company entered into three crude oil price swaps to hedge a portion of
its estimated crude oil production for the calendar years 2010, 2011 and 2012.
Additionally, on July 25, 2008, the Company entered into two crude oil price swaps to hedge a
portion of its estimated crude oil production for the calendar years 2008 and 2009. The contracts
are for 49,000 Bbls per month for the remainder of 2008 (August through December) at a fixed price
of $124.35 per Bbl, and 29,000 Bbls per month for calendar year 2009 at a fixed price of $125.10
per Bbl. The Company has not designated these derivative instruments as cash flow hedges.
Mark-to-market adjustments related to these derivative instruments will be recorded each period to
(Gain) loss on derivatives not designated as hedges.
Subsequent events
Henry Acquisition. On July 31, 2008, we closed the acquisition of Henry Petroleum LP and
certain affiliated entities (collectively Henry) (the Acquisition). Cash paid at closing
totaled approximately $560 million. We financed the Acquisition with proceeds raised from a
$250.0 million private placement of 8.3 million shares of our common stock, together with funds
available under a new amended and restated senior credit facility (the Senior Credit Facility),
as further described below. After the closing of the Henry transaction and the additional
interests acquired concurrently as described below, we have approximately $285 million of availability under the Senior Credit Facility.
In connection with the Acquisition, we also purchased certain additional non-operated rights
and interests in Henrys oil and gas properties from certain persons affiliated with Henry (such transactions,
collectively, the Along-side Transactions) for aggregate cash consideration of approximately
$28.0 million.
The following table shows the sources and uses of funds for the above referenced transactions
on July 31, 2008:
|
|
|
|
|
(in thousands) |
|
|
|
|
Sources of Funds: |
|
|
|
|
Proceeds from Issuance of Common Shares |
|
$ |
250,000 |
|
Initial Borrowing under Senior Credit Facility |
|
|
675,000 |
|
|
|
|
|
Total Sources of Funds |
|
$ |
925,000 |
|
|
|
|
|
|
|
|
|
|
Uses of Funds: |
|
|
|
|
Purchase of Henry Equity Interests |
|
$ |
536,830 |
|
Repay 1st Lien Credit Facility |
|
|
194,389 |
|
Repay 2nd Lien Credit Facility |
|
|
113,189 |
|
Purchase of Along-side Property Interests |
|
|
28,039 |
|
Fees and Expenses |
|
|
24,829 |
|
Working Capital and General Corporate Purposes |
|
|
27,724 |
|
|
|
|
|
Total uses of Funds |
|
$ |
925,000 |
|
|
|
|
|
Common Stock Purchase Agreement. On June 5, 2008, we also entered into a Common Stock Purchase
Agreement (the Purchase Agreement) with certain unaffiliated third-party investors (the
Purchasers) to sell approximately 8.3 million shares of our common stock in a private placement
(the Private Placement) for aggregate cash consideration of approximately $250.0 million, for a
negotiated price of $30.11 per share. The Private Placement closed simultaneously with the
Acquisition on July 31, 2008.
The closing of the Private Placement was subject to customary closing conditions, as well
as certain other conditions, including (i) the closing of the Acquisition and (ii) the execution by
us and the Purchasers of a registration rights agreement that will require us to file a shelf
registration statement for the benefit of the Purchasers within 60 days after the closing of the
Private Placement.
The Private Placement is being made in reliance upon an exemption from the registration
requirements of the Securities Act of 1933, pursuant to Section 4(2) thereof.
Amended and Restated Credit Facility. As of July 31, 2008, we amended and restated our Senior
Credit Facility in various respects including, increasing the borrowing base to $960 million, subject to semiannual
redetermination, and extending the maturity date from February 24, 2011 to
July 31, 2013. The initial borrowing under the Senior Credit Facility was $675 million. We paid
an arrangement fee of $14.4 million
23
at the date of closing of the Senior Credit Facility. This fee
is being amortized to Interest expense over the remaining five year term of the facility
beginning in August 2008.
Advances on the Senior Credit Facility bear interest, at our option, based on (a) the prime
rate of JPMorgan Chase Bank (JPM Prime Rate) (5.00 percent at July 31, 2008) 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 125 - 275 basis
points and 0 - 125 basis points, respectively, per annum depending on the balance outstanding. We
pay commitment fees on the unused portion of the available borrowing base ranging from 25 -
50 basis points per annum.
The Senior Credit Facility also includes a same-day advance facility under which we 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.
Our obligations under the Senior Credit Facility are secured by a first lien on substantially
all of our oil and gas properties. In addition, all of our subsidiaries are guarantors, and
all subsidiary general partner, limited partner and membership interests owned by us have been
pledged to secure borrowings under the Senior Credit Facility. 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 4.0 to 1.0, 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; (c) restrictions as to
merger and sale or transfer of assets; and (d) a restriction on the payment of cash dividends.
24
Results of operations of Concho Resources Inc.
The following table presents selected financial and operating information of Concho Resources
Inc. for the three and six months ended June 30, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
|
|
2008 |
|
2007 |
|
2008 |
|
2007 |
(in thousands, except price data) |
|
(unaudited) |
|
(unaudited) |
|
Oil sales |
|
$ |
95,408 |
|
|
$ |
43,096 |
|
|
$ |
171,226 |
|
|
$ |
82,467 |
|
Natural gas sales |
|
|
41,975 |
|
|
|
23,007 |
|
|
|
72,868 |
|
|
|
43,982 |
|
|
|
|
Total operating revenues |
|
|
137,383 |
|
|
|
66,103 |
|
|
|
244,094 |
|
|
|
126,449 |
|
Operating costs and expenses |
|
|
54,942 |
|
|
|
46,324 |
|
|
|
103,147 |
|
|
|
88,262 |
|
Loss on derivatives not designated as hedges |
|
|
102,456 |
|
|
|
|
|
|
|
119,634 |
|
|
|
|
|
Interest, net and other revenue |
|
|
3,574 |
|
|
|
9,866 |
|
|
|
8,169 |
|
|
|
20,276 |
|
|
|
|
Income (loss) before income taxes |
|
|
(23,589 |
) |
|
|
9,913 |
|
|
|
13,144 |
|
|
|
17,911 |
|
Income tax benefit (expense) |
|
|
9,169 |
|
|
|
(3,988 |
) |
|
|
(5,199 |
) |
|
|
(7,363 |
) |
|
|
|
Net income (loss) |
|
$ |
(14,420 |
) |
|
$ |
5,925 |
|
|
$ |
7,945 |
|
|
$ |
10,548 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
|
899 |
|
|
|
730 |
|
|
|
1,786 |
|
|
|
1,438 |
|
Natural gas (MMcf) |
|
|
3,346 |
|
|
|
2,953 |
|
|
|
6,451 |
|
|
|
5,905 |
|
Natural gas equivalent (MMcfe) |
|
|
8,740 |
|
|
|
7,330 |
|
|
|
17,167 |
|
|
|
14,536 |
|
Average prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without hedges ($/Bbl) |
|
$ |
121.00 |
|
|
$ |
60.15 |
|
|
$ |
107.39 |
|
|
$ |
57.16 |
|
Oil, with hedges ($/Bbl) |
|
$ |
106.13 |
|
|
$ |
59.07 |
|
|
$ |
95.87 |
|
|
$ |
57.33 |
|
Natural gas, without hedges ($/Mcf) |
|
$ |
12.52 |
|
|
$ |
7.77 |
|
|
$ |
11.33 |
|
|
$ |
7.42 |
|
Natural gas, with hedges ($/Mcf) |
|
$ |
12.54 |
|
|
$ |
7.79 |
|
|
$ |
11.30 |
|
|
$ |
7.45 |
|
Natural gas equivalent, without hedges ($/Mcfe) |
|
$ |
17.24 |
|
|
$ |
9.12 |
|
|
$ |
15.43 |
|
|
$ |
8.67 |
|
Natural gas equivalent, with hedges ($/Mcfe) |
|
$ |
15.72 |
|
|
$ |
9.02 |
|
|
$ |
14.22 |
|
|
$ |
8.70 |
|
|
|
|
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) |
25
Three months ended June 30, 2008, compared to three months ended June 30, 2007
Oil and gas revenues. Revenue from oil and gas operations was $137.4 million for the three
months ended June 30, 2008, an increase of $71.3 million (108%) from $66.1 million for the three
months ended June 30, 2007. This increase was primarily because of increased production due to
successful drilling efforts during 2008 coupled with substantial increases in realized oil and gas
prices. In addition:
average realized oil prices (after giving effect to hedging activities) were $106.13
per Bbl during the three months ended June 30, 2008, an increase of 80% from $59.07 per
Bbl during the three months ended June 30, 2007;
total oil production was 899 MBbl for the three months ended June 30, 2008, an
increase of 169 MBbl (23%) from 730 MBbl for the three months ended June 30, 2007;
average realized natural gas prices (after giving effect to hedging activities) were
$12.54 per Mcf during the three months ended June 30, 2008, an increase of 61% from
$7.79 per Mcf during the three months ended June 30, 2007;
total natural gas production was 3,346 MMcf for the three months ended June 30, 2008,
an increase of 393 MMcf (13%) from 2,953 MMcf for the three months ended June 30,
2007;
average realized natural gas equivalent prices (after giving effect to hedging
activities) were $15.72 per Mcfe during the three months ended June 30, 2008, an
increase of 74% from $9.02 per Mcfe during the three months ended June 30, 2007; and
total production was 8,740 MMcfe for the three months ended June 30, 2008, an
increase of 1,410 MMcfe (19%) from 7,330 MMcfe for the three months ended June 30, 2007.
See discussion in Recent events about 2007 and 2008 production interruptions due to plant
and refinery shut-downs.
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. The following is a
summary of the effects of commodity hedges for the three months ended June 30, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Hedges |
|
Natural Gas Hedges |
|
|
Three months ended |
|
Three months ended |
|
|
June 30, |
|
June 30, |
|
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
|
(unaudited) |
|
(unaudited) |
Hedging revenue increase (decrease) |
|
$ |
(13,367,000 |
) |
|
$ |
(783,000 |
) |
|
$ |
74,000 |
|
|
$ |
49,000 |
|
Hedged volumes (Bbls and MMBtus, respectively) |
|
|
236,000 |
|
|
|
268,000 |
|
|
|
1,228,000 |
|
|
|
1,647,000 |
|
Hedged revenue increase (decrease) per hedged volume |
|
$ |
(56.64 |
) |
|
$ |
(2.92 |
) |
|
$ |
0.06 |
|
|
$ |
0.03 |
|
During the three months ended June 30, 2008, our commodity price hedges decreased oil revenues
by $13.4 million ($14.87 per Bbl). During the three months ended June 30, 2007, our commodity price
hedges decreased oil revenues by $0.8 million ($1.07 per Bbl). The effect of the commodity price
hedges in decreasing oil revenues during the three months ended June 30, 2008 compared to their
effect of decreasing oil revenues during the three months ended June 30, 2007 was the result of
(1) a higher average market price of NYMEX crude oil of $124.28 per Bbl in 2008 as compared to
$65.08 per Bbl in 2007 and (2) the greater price difference between NYMEX and the weighted average
hedge price in 2008 as compared to 2007, partially offset by a lower amount of hedged volumes of
236,000 Bbls in 2008 as compared to 268,000 Bbls in 2007.
During
the three months ended June 30, 2008, our commodity price hedges increased gas revenues by $0.07
million ($0.02 per Mcf) as a result of the amount reclassified from AOCI into natural gas
revenues from cash flow hedges that were dedesignated as of June 30, 2007. Cash settlements
for these dedesignated natural gas contracts are being recorded to (Gain) loss on derivatives
not designated as hedges. During the three months ended June 30, 2007, our commodity price
hedges increased gas revenues by $0.05 million ($0.02 per Mcf) as a result of the price
difference between the market reference price of natural gas and the commodity contract price.
26
in 2008 as compared to settlements in 2007, partially offset by a lower amount of hedged
volumes of 1,228,000 MMBtus in 2008 as compared to 1,647,000 MMBtus in 2007.
Production expenses. Production expenses (including production taxes) were $22.0 million
($2.51 per Mcfe) for the three months ended June 30, 2008, an increase of $9.8 million (80%) from
$12.2 million ($1.66 per Mcfe) for the three months ended June 30, 2007. The increase in production
expenses is due to: (1) production expenses associated with new wells that were successfully
completed in 2008 as a result of our drilling activities and (2) an increase in production taxes as
discussed below. Lease operating expenses and workover costs comprised approximately 45% and 57% of
production expenses for the three months ended June 30, 2008 and 2007, respectively. These costs
per unit of production were $1.14 per Mcfe during the three months ended June 30, 2008, an increase
of 20% from $0.95 per Mcfe during the three months ended June 30, 2007. 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 the three months ended June 30,
2008 and 2007.
The secondary component of production expenses is production taxes, which is directly related
to commodity price changes. These costs comprised approximately 55% and 43% of production expenses
during the three months ended June 30, 2008 and 2007, respectively. Production taxes per unit of
production were $1.38 per Mcfe during the three months ended June 30, 2008, an increase of 92% from
$0.72 per Mcfe during the three months ended June 30, 2007. This increase was primarily due to an
increase in average natural gas equivalent prices we received.
Exploration and abandonments expense. The following table provides a breakdown of our
exploration and abandonments expense for the three months ended June 30, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
June 30, |
|
|
2008 |
|
2007 |
(in thousands) |
|
(unaudited) |
|
Geological and geophysical |
|
$ |
424 |
|
|
$ |
225 |
|
Exploratory dry holes |
|
|
(19 |
) |
|
|
5,635 |
|
Leasehold abandonments and other |
|
|
318 |
|
|
|
4 |
|
|
|
|
Total exploration and abandonments |
|
$ |
723 |
|
|
$ |
5,864 |
|
|
|
|
Our geological and geophysical expense, which primarily consists of the costs of acquiring and
processing seismic data, geophysical data and core analysis, during the three months ended June 30,
2008 was $0.4 million, an increase of $0.2 million from $0.2 million for the three months ended
June 30, 2007. This increase is primarily attributable to a comprehensive seismic survey on our New
Mexico shelf properties which was initiated in December 2007.
Our exploratory dry holes expense during the three months ended June 30, 2007 was 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
was completed in a shallower zone which was found to be productive.
For the three months ended June 30, 2008, we recorded $0.3 million of leasehold abandonments,
which are primarily related to prospects in Chaves County, New Mexico and Crane County, Texas. We
had minimal leasehold abandonments during the three months ended June 30, 2007.
Depreciation and depletion expense. Depreciation and depletion expense was $22.0 million
($2.52 per Mcfe), including $21.6 million associated with oil and gas properties ($2.47 per Mcfe),
for the three months ended June 30, 2008, an increase of $4.4 million from $17.6 million ($2.40 per
Mcfe), including $17.4 million associated with oil and gas properties ($2.37 per Mcfe), for the
three months ended June 30, 2007. The increase in depreciation and depletion expense was primarily
due to capitalized costs associated with new wells that were successfully completed in 2007 and
2008 as a result of our drilling activities. Despite an increase in total proved reserves, the
depreciation and depletion rate per Mcfe increased from the three months ended June 30, 2007 to the
three months ended June 30, 2008, due to an increase in capitalized costs as a result of our
successful development and exploratory drilling program. The crude oil price utilized for our
estimate of proved oil and gas reserves was $136.50 as of June 30, 2008, an increase of
27
$69.25 (103%) from $67.25 as of June 30, 2007. The natural gas price utilized for our estimate
of proved oil and gas reserves was $13.10 as of June 30, 2008, an increase of $6.30 (93%) from
$6.80 as of June 30, 2007.
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 three months ended June 30, 2008, we recognized a
non-cash charge against earnings of $0.1 million, which was comprised primarily of a well located
in Lea County, New Mexico. For the three months ended June 30, 2007, we recognized a non-cash
charge against earnings of $2.1 million, primarily related to a well drilled on acreage in
Schleicher County, Texas.
Contract drilling fees stacked rigs. As discussed in our Annual Report on Form 10-K for the
year ended December 31, 2007, 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 three months ended
June 30, 2007 of approximately $0.9 million 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 that period and charged us only the difference between the then-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 $8.6 million
($0.98 per Mcfe) for the three months ended June 30, 2008, an increase of $1.0 million (13%) from
$7.6 million ($1.04 per Mcfe) for the three months ended June 30, 2007. Included in general and
administrative expense was non-cash stock-based compensation of $1.7 million during the three
months ended June 30, 2008 and $1.1 million during the three months ended June 30, 2007. General
and administrative expenses, excluding non-cash stock-based compensation, (Net general expense)
were $6.9 million ($0.78 per Mcfe) for the three months ended June 30, 2008, an increase of
$0.4 million (6%) from $6.5 million ($0.89 per Mcfe) for the three months ended June 30, 2007. The
increase in Net general expenses during the three months ended June 30, 2008 was primarily due to
an increase in the number of employees and related personnel expenses.
We earn revenue as operator of certain oil and gas properties in which we own interests. As
such, we earned revenue of $0.3 million and $0.2 million during the three months ended June 30,
2008 and 2007, respectively. This revenue is reflected as a reduction of general and administrative
expenses in the consolidated statements of operations.
Bad debt expense. On May 20, 2008, we entered into a temporary purchase agreement with an oil
purchaser to buy a portion of the oil affected as a result of the New Mexico refinery shut down due to repairs. On July
22, 2008, this purchaser declared Chapter 11 bankruptcy in a Delaware federal bankruptcy court. We
fully reserved the receivable amount due from this purchaser of approximately $1.8 million as of
June 30, 2008.
Loss on derivatives not designated as cash flow hedges. As explained in Hedging activities,
during the three months ended September 30, 2007, we determined that all of our natural gas
commodity contracts no longer qualified as hedges under the requirements of SFAS No. 133. If the
hedge is no longer highly effective, according to SFAS No. 133, an entity shall discontinue hedge
accounting for an existing hedge, prospectively and during the period the hedges became
ineffective. In addition, for our new derivative contracts entered into after August 2007, we chose
not to designate any of these contracts as cash flow hedges. As a result, any changes in fair value
must be recorded in earnings under Loss on derivatives not designated as hedges and any related
cash settlements are recorded to Loss on derivatives not designated as hedges . For the three
months ended June 30, 2008, the related cash settlement payments for derivative instruments not
designated as cash flow hedges was approximately $12.4 million. The non-cash mark-to-market
adjustment for other derivative instruments not designated as cash flow hedges was a loss of
$90.1 million.
Interest expense. Interest expense was $3.9 million for the three months ended June 30, 2008,
a decrease of $6.2 million from $10.1 million for the three months ended June 30, 2007. The
weighted average interest rate for the three months ended June 30, 2008 and 2007 was 4.9% and 7.8%,
respectively. The weighted average debt balance during the three months ended June 30, 2008 and
2007 was approximately $302.1 million and $454.4 million, respectively. The decrease in weighted
average debt balance during the three months ended June 30, 2008 was due to the partial prepayment
in August 2007 of $86.6 million on the New 2nd Lien Credit Facility and the repayment in
August 2007 of $86.6 million on the 1st Lien Credit Facility as well as partial
prepayment in March 2008 on the 1st Lien Credit Facility utilizing cash from operations.
The decrease in interest expense is due to a decrease in the weighted average interest rate and the
decrease in the weighted average debt. In March 2007, we reduced the 1st Lien Credit Facility
borrowing base by $100.00 million, or 21%, resulting in accelerated deferred loan cost amortization
of $0.77 million, and the full repayment of the 2nd Lien Credit Facility resulting in accelerated
deferred loan cost amortization of $0.43 million.
Income tax provisions. We recorded an income tax benefit of $9.2 million and income tax
expense of $4.0 million for the three months ended June 30, 2008 and 2007, respectively. The
effective income tax rate for the three months ended June 30, 2008 and 2007 was 38.9% and 40.2%,
respectively.
28
Six months ended June 30, 2008, compared to six months ended June 30, 2007
Oil and gas revenues. Revenue from oil and gas operations was $244.1 million for the six
months ended June 30, 2008, an increase of $117.7 million (93%) from $126.4 million for the six
months ended June 30, 2007. This increase was primarily because of increased production due to
successful drilling efforts during 2008 coupled with substantial increases in realized oil and gas
prices. In addition:
average realized oil prices (after giving effect to hedging activities) were $95.87
per Bbl during the six months ended June 30, 2008, an increase of 67% from $57.33 per
Bbl during the six months ended June 30, 2007;
total oil production was 1,786 MBbl for the six months ended June 30, 2008, an
increase of 348 MBbl (24%) from 1,438 MBbl for the six months ended June 30, 2007;
average realized natural gas prices (after giving effect to hedging activities) were
$11.30 per Mcf during the six months ended June 30, 2008, an increase of 52% from $7.45
per Mcf during the six months ended June 30, 2007;
total natural gas production was 6,451 MMcf for the six months ended June 30, 2008,
an increase of 546 MMcf (9%) from 5,905 MMcf for the six months ended June 30, 2007;
average realized natural gas equivalent prices (after giving effect to hedging
activities) were $14.22 per Mcfe during the six months ended June 30, 2008, an increase
of 63% from $8.70 per Mcfe during the six months ended June 30, 2007; and
total production was 17,167 MMcfe for the six months ended June 30, 2008, an increase
of 2,631 MMcfe (18%) from 14,536 MMcfe for the six months ended June 30, 2007.
See discussion in Recent events about 2007 and 2008 production interruptions due to plant
and refinery shut-downs.
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. The following is a
summary of the effects of commodity hedges for the six months ended June 30, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Hedges |
|
Natural Gas Hedges |
|
|
Six months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
|
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
|
(unaudited) |
|
(unaudited) |
|
|
|
Hedging revenue increase (decrease) |
|
$ |
(20,573,000 |
) |
|
$ |
244,000 |
|
|
$ |
(222,000 |
) |
|
$ |
187,000 |
|
Hedged volumes (Bbls and MMBtus, respectively) |
|
|
473,000 |
|
|
|
534,000 |
|
|
|
2,457,000 |
|
|
|
3,152,000 |
|
Hedged revenue increase (decrease) per hedged volume |
|
$ |
(43.49 |
) |
|
$ |
0.46 |
|
|
$ |
(0.09 |
) |
|
$ |
0.06 |
|
During the six months ended June 30, 2008, our commodity price hedges decreased oil revenues
by $20.6 million ($11.52 per Bbl). During the six months ended June 30, 2007, our commodity price
hedges increased oil revenues by $0.2 million ($0.17 per Bbl). The effect of the commodity price
hedges in decreasing oil revenues during the six months ended June 30, 2008 compared to their
effect of decreasing oil revenues during the six months ended June 30, 2007 was the result of (1) a
higher average market price of NYMEX crude oil of $110.98 per Bbl in 2008 as compared to $61.70 per
Bbl in 2007 and (2) the greater price difference between NYMEX and the weighted average hedge price
in 2008 as compared to 2007, partially offset by a lower amount of hedged volumes of 473,000 Bbls
in 2008 as compared to 534,000 Bbls in 2007.
During
the six months ended June 30, 2008, our commodity price hedges decreased gas revenues by $0.2
million ($0.03 per Mcf) as a result of the amount reclassified from AOCI into natural gas
revenues from cash flow hedges that were dedesignated as of June 30, 2007. Cash settlements
for these dedesignated natural gas contracts are being recorded to (Gain) loss on derivatives
not designated as hedges. During the six months ended June 30, 2007, our commodity price hedges
increased gas revenues by $0.2 million ($0.03 per Mcf) as a result of the price difference
between the market reference price of natural gas and the commodity contract price.
29
Production expenses. Production expenses (including production taxes) were $38.9 million
($2.26 per Mcfe) for the six months ended June 30, 2008, an increase of $14.7 million (61%) from
$24.2 million ($1.66 per Mcfe) for the six months ended June 30, 2007. The increase in production
expenses is due to: (1) production expenses associated with new wells that were successfully
completed in 2008 as a result of our drilling activities and (2) an increase in production taxes as
discussed below. Lease operating expenses and workover costs comprised approximately 46% and 59% of
production expenses for the six months ended June 30, 2008 and 2007, respectively. These costs per
unit of production were $1.03 per Mcfe during the six months ended June 30, 2008, an increase of 6%
from $0.98 per Mcfe during the six months ended June 30, 2007. Lease operating expenses include ad
valorem taxes that are affected by commodity price changes and ad valorem tax rates. Ad valorem
taxes were approximately 6% and 7% of lease operating expenses for the six months ended June 30,
2008 and 2007, respectively.
The secondary component of production expenses is production taxes, which is directly related
to commodity price changes. These costs comprised approximately 54% and 41% of production expenses
during the six months ended June 30, 2008 and 2007, respectively. Production taxes per unit of
production were $1.23 per Mcfe during the six months ended June 30, 2008, an increase of 80% from
$0.68 per Mcfe during the six months ended June 30, 2007. This increase was primarily due to an
increase in average natural gas equivalent prices we received.
Exploration and abandonments expense. The following table provides a breakdown of our
exploration and abandonments expense for the six months ended June 30, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
June 30, |
|
|
2008 |
|
2007 |
(in thousands) |
|
(unaudited) |
|
Geological and geophysical |
|
$ |
2,316 |
|
|
$ |
624 |
|
Exploratory dry holes |
|
|
|
|
|
|
5,665 |
|
Leasehold abandonments and other |
|
|
1,148 |
|
|
|
16 |
|
|
|
|
Total exploration and abandonments |
|
$ |
3,464 |
|
|
$ |
6,305 |
|
|
|
|
Our geological and geophysical expense, which primarily consists of the costs of acquiring and
processing seismic data, geophysical data and core analysis, during the six months ended June 30,
2008 was $2.3 million, an increase of $1.7 million from $0.6 million for the six months ended June
30, 2007. This increase is primarily attributable to a comprehensive seismic survey on our New
Mexico shelf properties which was initiated in December 2007.
Our exploratory dry holes expense during the six months ended June 30, 2007 was 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
was completed in a shallower zone which was found to be productive.
For the six months ended June 30, 2008, we recorded $1.1 million of leasehold abandonments,
which are primarily related to prospects in Chaves and Eddy Counties, New Mexico and Andrews and
Crane Counties, Texas. We had minimal leasehold abandonments during the six months ended June 30,
2007.
Depreciation and depletion expense. Depreciation and depletion expense was $43.3 million
($2.52 per Mcfe), including $42.5 million associated with oil and gas properties ($2.48 per Mcfe),
for the six months ended June 30, 2008, an increase of $6.3 million from $37.0 million ($2.55 per
Mcfe), including $36.6 million associated with oil and gas properties ($2.51 per Mcfe), for the six
months ended June 30, 2007. The increase in depreciation and depletion expense was primarily due to
capitalized costs associated with new wells that were successfully completed in 2007 and 2008 as a
result of our drilling activities. 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 as well as an increase of commodity prices
utilized for the reserve estimates, partially offset by increased production. The crude oil price
utilized for our estimate of proved oil and gas reserves was $136.50 as of June 30,
30
2008, an
increase of $69.25 (103%) from $67.25 as of June 30, 2007. The natural gas price utilized for our
estimate of proved oil and gas reserves was $13.10 as of June 30, 2008, an increase of $6.30 (93%)
from $6.80 as of June 30, 2007.
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, 2008, we recognized a
non-cash charge against earnings of $0.1 million, which was comprised primarily of a wells drilled
on acreage in Eddy County, New Mexico and Lea County, New Mexico. For the six months ended June 30,
2007, we recognized a non-cash charge against earnings of $3.2 million, 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.
Contract drilling fees stacked rigs. As discussed in our Annual Report on Form 10-K for the
year ended December 31, 2007, 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 $4.3 million 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 that period and charged us only the difference between the then-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 $16.3 million
($0.95 per Mcfe) for the six months ended June 30, 2008, an increase of $4.4 million (37%) from
$11.9 million ($0.82 per Mcfe) for the six months ended June 30, 2007. Included in general and
administrative expense was non-cash stock-based compensation of $3.0 million during the six months
ended June 30, 2008 and $2.0 million during the six months ended June 30, 2007. General and
administrative expenses, excluding non-cash stock-based compensation, (Net general expense) were
$13.2 million ($0.77 per Mcfe) for the six months ended June 30, 2008, an increase of $3.2 million
(32%) from $10.0 million ($0.69 per Mcfe) for the six months ended June 30, 2007. The increase in
Net general expenses during the six months ended June 30, 2008 was primarily due to an increase in
the number of employees and related personnel expenses.
We earn revenue as operator of certain oil and gas properties in which we own interests. As
such, we earned revenue of $0.5 million and $0.6 million during the six months ended June 30, 2008
and 2007, respectively. This revenue is reflected as a reduction of general and administrative
expenses in the consolidated statements of operations.
Bad debt expense. On May 20, 2008, we entered into a temporary purchase agreement with an oil
purchaser to buy a portion of the oil affected as a result of the New Mexico refinery shut down due to repairs. On July
22, 2008, this purchaser declared Chapter 11 bankruptcy in a Delaware federal bankruptcy court. We
fully reserved the receivable amount due from this purchaser of approximately $1.8 million as of
June 30, 2008.
Loss on derivatives not designated as cash flow hedges. As explained in Hedging activities,
during the three months ended September 30, 2007, we determined that all of our natural gas
commodity contracts no longer qualified as hedges under the requirements of SFAS No. 133. If the
hedge is no longer highly effective, according to SFAS No. 133, an entity shall discontinue hedge
accounting for an existing hedge, prospectively and during the period the hedges became
ineffective. In addition, for our new derivative contracts entered into after August 2007, we chose
not to designate any of these contracts as cash flow hedges. As a result, any changes in fair value
must be recorded in earnings under Loss on derivatives not designated as hedges and any related
cash settlements are recorded to Loss on derivatives not designated as hedges . For the six months
ended June 30, 2008, the related cash settlement payments for derivative instruments not designated
as cash flow hedges was approximately $16.4 million. The non-cash mark-to-market adjustment for
other derivative instruments not designated as cash flow hedges was a loss of $103.2 million.
Interest expense. Interest expense was $9.5 million for the six months ended June 30, 2008, a
decrease of $11.2 million from $20.7 million for the six months ended June 30, 2007. The weighted
average interest rate for the six months ended June 30, 2008 and 2007 was 5.8% and 7.8%,
respectively. The weighted average debt balance during the six months ended June 30, 2008 and 2007
was approximately $313.3 million and $501.3 million, respectively. The decrease in weighted average
debt balance during the six months ended June 30, 2008 was due to the partial prepayment in August
2007 of $86.6 million on the New 2nd Lien Credit Facility and the repayment in August
2007 of $86.6 million on the 1st Lien Credit Facility as well as partial prepayment in
March 2008 on the 1st Lien Credit Facility utilizing cash from operations. The decrease in interest
expense is due to a decrease in the weighted average interest rate and the decrease in the weighted
average debt. In March 2007, we reduced the 1st Lien Credit Facility borrowing base by
$100.0 million, or 21%, resulting in accelerated deferred loan cost amortization of $0.8 million,
and the full repayment of the 2nd Lien Credit Facility resulting in accelerated deferred loan cost
amortization of $0.4 million.
31
Income tax provisions. We recorded income tax expense of $5.2 million and $7.4 million for
the six months ended June 30, 2008 and 2007, respectively. The effective income tax rate for the
six months ended June 30, 2008 and 2007 was 39.6% and 41.1%, respectively.
We had a net deferred tax liability of $243.3 million and $245.57 million at June 30, 2008 and
December 31, 2007, 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 2008
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 have been cash flows generated from operating activities and
financing provided by our bank credit facilities. 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 2008 exploration and development budget.
Cash Flow from Operating Activities
Our net cash provided by operating activities was $162.9 million and $63.6 million for the six
months ended June 30, 2008 and 2007, respectively. The increase in operating cash flows during the
six months ended June 30, 2008 over 2007 was principally due to increases in our oil and gas
production as a result of our exploration and development program and increases in average realized
oil and natural gas prices.
Cash Flow Used in Investing Activities
During the six months ended June 30, 2008 and 2007, we invested $122.8 million and
$70.1 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, 2008, primarily due to increased drilling activity in 2008. In
order to preserve liquidity, we reduced our drilling activities and curtailed capital expenditures
during the six months ended June 30, 2007, until we were able to complete our second lien term loan
facility in March 2007.
Cash Flow from Financing Activities
Net cash used in financing activities was $19.5 million for the six months ended June 30, 2008
and net cash provided by financing activities was $16.3 million for the six months ended June 30,
2007. During the six months ended June 30, 2008, we reduced our outstanding balance by $26.0
million on our 1st Lien Credit Facility utilizing cash from operations. In March 2007, we entered
into a $200.0 million second lien term loan facility. The proceeds were principally used to repay
the outstanding balance under our prior term loan facility and to reduce the outstanding balance
under our 1st Lien Credit Facility.
Bank Credit Facilities
We have two separate bank credit facilities. The first is our credit facility agreement, dated
February 24, 2006, with JPMorgan Chase Bank, N.A. as the administrative agent for a group of
lenders that provides a revolving line of credit having a total commitment of $550.0 million, which
we refer to as our 1st Lien Credit Facility. The total amount that we can borrow and have
outstanding at any one time is limited to the lesser of the total commitment of $550.0 million or
the borrowing base established by the lenders. Various amendments have redetermined the borrowing
base under the 1st Lien Credit Facility, which was $550.0 million as of June 30, 2008. The amount
outstanding under the 1st Lien Credit Facility at June 30, 2008 was $190.0 million.
The second bank credit facility is our term loan agreement, dated 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, the New 2nd Lien Credit Facility. Upon execution of
the New 2nd Lien Credit Facility, we funded the full amount under that facility and received net
proceeds of $199.0 million to repay the $39.8 million outstanding under our 2nd Lien Credit
Facility, to reduce the outstanding balance under our 1st Lien Credit Facility by $154.0 million
and the remaining $5.2 million to pay loan fees, accrued interest and for general corporate
purposes. We used net proceeds of approximately $173.0 million from our initial public offering
that was completed in August 2007 to retire outstanding borrowings under our New 2nd Lien Credit
Facility totaling $86.5 million and to retire outstanding borrowings under our 1st Lien Credit
Facility totaling $86.5 million.
1st Lien Credit Facility. The 1st Lien Credit Facility allows us to borrow, repay and
reborrow amounts available under the borrowing base. 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 1st Lien Credit Facility is re-determined at least semi-annually. The 1st Lien Credit Facility
matures on
32
February 24, 2011, and borrowings 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 1st Lien Credit Facility, plus an
applicable margin ranging from 125 275 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 1st Lien Credit Facility bore interest at 3.73% per
annum as of June 30, 2008. We pay quarterly commitment fees under our 1st Lien 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 1st Lien Credit Facility are secured by a first lien on substantially all
of our assets and properties. Our 1st Lien Credit Facility also contains restrictive covenants that
may limit our ability to, among other things, pay cash dividends, incur 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
1st Lien Credit Facility also requires us to maintain certain ratios as defined and further
described in our 1st Lien Credit Facility agreement, 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
1st Lien Credit Facility, we had a one-time requirement to enter into derivative contracts 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, 2008, we were in compliance with all such covenants.
New 2nd Lien Credit Facility. The New 2nd Lien Credit Facility provides a $200.0 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 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
$0.5 million of the outstanding balance 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 New 2nd Lien
Credit Facility bore interest at 6.73% per annum as of June 30, 2008. We have the right to prepay
the outstanding balance 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.
Borrowings under the New 2nd Lien Credit Facility are secured by a second lien on the same
assets as are securing our 1st Lien Credit Facility, and are subordinated to liens securing our 1st
Lien Credit Facility. The New 2nd Lien Credit Facility also contains various restrictive financial
covenants and compliance requirements that are similar to those contained in the 1st Lien Credit
Facility, including the maintenance of certain financial ratios. As of June 30, 2008, we were in
compliance with all such covenants.
Amended and Restated Credit Facility
As of July 31, 2008, we amended and restated our Senior Credit Facility in various respects including, increasing the
borrowing base to $960 million, subject to semiannual redetermination, and extending the maturity
date from February 24, 2011 to July 31, 2013 (the Senior Credit Facility, as defined above). The
initial borrowing under the Senior Credit Facility was $675 million. We paid an arrangement fee of
$14.4 million at the date of closing of the Senior Credit Facility. This fee is being amortized to
Interest expense over the remaining five year term of the facility beginning in August 2008.
Advances on the Senior Credit Facility bear interest, at our option, based on (a) the prime
rate of JPMorgan Chase Bank (JPM Prime Rate) (5.00 percent at July 31, 2008) 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 125 - 275 basis
points and 0 - 125 basis points, respectively, per annum depending on the balance outstanding. We
pay commitment fees on the unused portion of the available borrowing base ranging from 25 -
50 basis points per annum.
The Senior Credit Facility also includes a same-day advance facility under which we 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.
Our obligations under the Senior Credit Facility are secured by a first lien on substantially all
of our oil and gas properties. In addition, all of our subsidiaries are guarantors, and all
subsidiary general partner, limited partner and membership interests owned by us have been pledged
to secure borrowings under the Senior Credit Facility. 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 4.0 to 1.0, 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;
33
(b) limits on the incurrence of additional indebtedness and certain types of liens;
(c) restrictions as to merger and sale or transfer of assets; and (d) a restriction on the payment
of cash dividends.
Future Capital Expenditures and Commitments
On August 7, 2008, our board of directors approved an increase in our 2008 exploration and
development budget in the amount of $71.1 million from the amended budget of $318.2 million to
$389.3 million. Our 2008 capital budget is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
Original |
|
Revised |
(in millions) |
|
Budget |
|
Budget |
|
Drilling and recompletion opportunities in our core operating area |
|
$ |
209.5 |
|
|
$ |
310.8 |
|
Projects operated by third parties |
|
|
14.3 |
|
|
|
14.3 |
|
Emerging plays, acquisition of leasehold acreage and other property interests, and geological and geophysical |
|
|
20.0 |
|
|
|
57.6 |
|
Maintenance capital in our core operating areas |
|
|
6.6 |
|
|
|
6.6 |
|
|
|
|
Total 2008 exploration and development budget |
|
$ |
250.4 |
|
|
$ |
389.3 |
|
|
|
|
We anticipate that this incremental $71.1 million in our 2008 exploration and development
budget will be funded primarily by cash flow from operations.
Other than leasehold acreage and other property interests shown above, our 2008 exploration
and development budget is exclusive of acquisitions. We do not have a specific acquisition budget
since the timing and size of acquisitions are difficult to forecast. 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.
On July 31, 2008, we closed the acquisition of Henry (the Acquisition), as defined above.
Cash paid at closing totaled approximately $560 million. We financed the Acquisition with proceeds
raised from a $250.0 million private placement of 8.3 million shares of our common stock, together
with funds available under the Senior Credit Facility. After the closing of the Acquisition and the
additional interests acquired concurrently as described below, we have approximately $285 million of availability under the Senior Credit
Facility.
In connection with the Acquisition, we also purchased certain additional non-operated rights
and interests in Henrys oil and gas properties from the Along-side Transactions for aggregate cash
consideration of approximately $28.0 million.
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 will be
sufficient to satisfy our 2008 exploration and development budget; however, we could use our
revolving credit facility to fund such expenditures. 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. In addition, under certain circumstances we would consider increasing
or reallocating our 2008 capital budget.
Commodity Derivatives and Hedging
On March 3, 2008, we entered into two crude oil price swaps to hedge an additional portion of
our estimated crude oil production for calendar years 2008 and 2009. The contracts are for 1,400
Bbls per day for the remainder of 2008 (April through December) at a fixed price of $99.25 per Bbl,
and 800 Bbls per day for calendar year 2009 at a fixed price of $98.35 per Bbl. We have not
designated these derivative instruments as cash flow hedges. Mark-to-market adjustments related to
these derivative instruments will be recorded each period to (Gain) loss on derivatives not
designated as hedges.
On March 11, 2008, we entered into a natural gas price swap to hedge an additional portion of
our estimated natural gas production for calendar year 2009. The contract is for 5,000 MMBtus per
day with a fixed price of $8.44. We have not designated this derivative instrument as a cash flow
hedge. Mark-to-market adjustments related to this derivative instrument will be recorded each
period to (Gain) loss on derivatives not designated as hedges.
On June 5, 2008, the Company entered into a crude oil costless collar to hedge a portion of
its estimated crude oil production for calendar year 2009. The contract is for 64,000 Bbls per
month (or 2,104 Bbls per day) for calendar year 2009 with a ceiling of $134.60
34
per Bbl and a floor
of $120.00 per Bbl. The Company has not designated this derivative instrument as a cash flow hedge.
Mark-to-market adjustments related to this derivative instrument will be recorded each period to
(Gain) loss on derivatives not designated as hedges.
On June 6, 2008, the Company entered into three crude oil price swaps to hedge a portion of
its estimated crude oil production for calendar years 2010, 2011 and 2012.
As of June 30, 2008, we have oil price swaps and collars that settle on a monthly basis
covering future oil production from July 1, 2008 through December 31, 2012. The volumes are
detailed in the table below. Subsequent to June 30, 2008, oil futures prices have decreased;
however, they continue to exceed the weighted average swap fixed price and collar ceiling price of
$97.60 for all oil contracts and $77.67 for oil contracts settling in 2008. The average NYMEX oil
futures price for the quarter ended June 30, 2008, was $124.28. As of August 7, 2008, the NYMEX oil
futures price was $120.02. At this pricing level, for each monthly settlement period, we will
continue to remit the excess of the monthly average NYMEX oil futures price for each settlement
period over the weighted average swap fixed price and collar ceiling price from above. These
payments to the counterparties could significantly affect our cash flow but the impact should be
reduced or partially offset by (1) increased commodity prices received on the sale of our unhedged
oil production and (2) only a portion of the total remaining contract volume settles each month.
The decrease in oil prices, should it continue through the end of the third quarter of 2008, should
increase the fair value of our commodities contracts from their recorded balance at June 30, 2008.
Changes in the recorded fair value of the undesignated commodity derivatives are marked to market
through earnings as unrealized gains or losses. The potential increase in fair value would be
recorded in earnings as unrealized gains. However, an increase in the average NYMEX oil futures
price above the second quarter average would result in a decrease in fair value and unrealized
losses in earnings. We are currently unable to estimate the effects on the earnings of future
periods resulting from changes in the market value of our derivative contracts.
The table below provides the volumes and related data associated with our oil and natural gas
derivatives as of June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Market Value |
|
|
Aggregate |
|
|
|
|
|
|
|
|
|
|
|
|
Liability |
|
|
remaining |
|
|
Daily |
|
|
Index |
|
Contract |
|
|
|
(in thousands) |
|
|
volume |
|
|
volume |
|
|
price |
|
period |
|
|
Cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
$ |
(34,958 |
) |
|
|
478,400 |
|
|
|
2,600 |
|
|
$67.50 (a) |
|
|
7/1/08 - 12/31/08 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges dedesignated: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar |
|
|
(7,348 |
) |
|
|
2,484,000 |
|
|
|
13,500 |
|
|
$6.50 - $9.35 (b) |
|
|
7/1/08 - 12/31/08 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar |
|
|
(8,578 |
) |
|
|
768,000 |
|
|
|
2,104 |
|
|
$120.00 - $134.60 (a) |
|
|
1/1/09 - 12/31/09 |
|
Price swap |
|
|
(34,558 |
) |
|
|
625,600 |
|
|
|
3,400 |
|
|
$85.44 (a) (c) |
|
|
7/1/08 - 12/31/08 |
|
Price swap |
|
|
(60,264 |
) |
|
|
1,022,000 |
|
|
|
2,800 |
|
|
$80.13 (a) (c) |
|
|
1/1/09 - 12/31/09 |
|
Price swap |
|
|
(2,182 |
) |
|
|
240,000 |
|
|
|
658 |
|
|
$128.80 (a) |
|
|
1/1/10 - 12/31/10 |
|
Price swap |
|
|
(2,522 |
) |
|
|
336,000 |
|
|
|
921 |
|
|
$128.66 (a) |
|
|
1/1/11 - 12/31/11 |
|
Price swap |
|
|
(3,785 |
) |
|
|
504,000 |
|
|
|
1,377 |
|
|
$127.80 (a) |
|
|
1/1/12 - 12/31/12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
(5,133 |
) |
|
|
1,825,000 |
|
|
|
5,000 |
|
|
$8.44 (b) |
|
|
1/1/09 - 12/31/09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net liability |
|
$ |
(159,328 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate monthly average futures price. |
|
(b) |
|
The index price for the natural gas price collar is based on the Inside FERC-El Paso Permian Basin first-of-the-month spot price. |
|
(c) |
|
Amounts disclosed represent weighted average prices.
|
35
Valuation of Derivative Instruments
We measure our derivative instruments at fair value. Both realized and unrealized gains or
losses from derivative instruments are reflected in Oil and natural gas sales and Loss on
derivatives not designated as hedges in the consolidated statements of operations.
We adopted SFAS No. 157, Fair Value Measurements (SFAS No. 157), in the first quarter of
2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value,
establishes a fair value hierarchy based on the inputs used to measure fair value and enhances
disclosure requirements for fair value measurements.
SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid
to transfer a liability in an orderly transaction between market participants at the measurement
date, or an exit price. The degree of judgment utilized in measuring the fair value of derivative
instruments generally correlates to the level of pricing observability. Derivative instruments with
readily available active quoted prices or for which fair value can be measured from actively quoted
prices in active markets generally have more pricing observability and less judgment utilized in
measuring fair value. Conversely, derivative instruments rarely traded or not quoted have less
observability and are measured at fair value using valuation models that require more judgment.
Pricing observability is impacted by a number of factors, including the type of derivative
instrument, whether the derivative instrument is new to the market and not yet established, the
characteristics specific to the transaction and overall market conditions generally.
The overall valuation process for derivative instruments may include adjustments to valuations
derived from pricing models. These adjustments may be made when, in managements judgment, either
the size of the position in the derivative instrument or other features of the derivative
instrument such as its complexity, or the market in which the derivative instrument is traded (such
as counterparty, credit, concentration or liquidity) require that an adjustment be made to the
value derived from the pricing models. An adjustment may be made if the sale of a derivative
instrument is subject to sales restrictions that would result in a price less than the computed
fair value measurement from a quoted market price. Additionally, an adjustment from the price
derived from a model typically reflects managements judgment that other participants in the market
for the derivative instrument being measured at fair value would also consider such an adjustment
in pricing that same derivative instrument.
We have categorized our derivative instruments measured at fair value into a three-level
classification in accordance with SFAS No. 157. Fair value measurements of derivative instruments
that use quoted prices in active markets for identical assets or liabilities are generally
categorized as Level 1, and fair value measurements of derivative instruments that have no direct
observable levels are generally categorized as Level 3. The lowest level input that is significant
to the fair value measurement of a derivative instrument is used to categorize the instrument and
reflects the judgment of management. Derivative assets and liabilities presented at fair value in
our consolidated balance sheet generally are categorized as follows:
Level 1 Inputs are unadjusted, quoted prices in active markets for identical,
unrestricted assets or liabilities at the measurement date.
Level 2 Inputs (other than quoted prices included in Level I) are either directly
or indirectly observable for the asset or liability through correlation with market
data at the measurement date and for the duration of the instruments anticipated
life.
Generally, assets and liabilities carried at fair value included in this category
are commodity price swaps.
Level 3 Inputs reflect managements best estimate of what market participants
would use in pricing the asset or liability at the measurement date. Consideration
is given to the risk inherent in the valuation technique and the risk inherent in
the inputs to the model.
Generally, assets and liabilities carried at fair value included in this category
are commodity price collars.
Derivative assets and liabilities presented at fair value and categorized as Level 3 are
generally those that are marked to model using relevant empirical data to extrapolate an estimated
fair value. The models inputs reflect assumptions that market participants would use in pricing
the instrument in a current period transaction and outcomes from the models represent an exit price
and expected future cash flows. Valuation models are calibrated to the market on a frequent basis.
The parameters and inputs are adjusted for assumptions about risk and current market
conditions. Changes to inputs in valuation models are not changes to valuation methodologies;
rather, the inputs are modified to reflect direct or indirect impacts on asset classes from changes
in market conditions. Accordingly, results from valuation models in one period may not be
indicative of future period measurements.
36
The following table presents comparative metrics of the Companys Level 3 liabilities at June
30, 2008 and December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
(in thousands) |
|
2008 |
|
2007 |
|
Level 3 derivative assets |
|
$ |
|
|
|
$ |
1,866 |
|
Less: Level 3 derivative liabilities |
|
|
(15,926 |
) |
|
|
|
|
|
|
|
Level 3 net derivative assets (liabilities) |
|
$ |
(15,926 |
) |
|
$ |
1,866 |
|
|
|
|
|
|
|
|
|
|
Total assets (liabilities) |
|
$ |
(850,274 |
) |
|
$ |
1,508,229 |
|
|
|
|
|
|
|
|
|
|
Total derivative assets measured at fair value |
|
$ |
|
|
|
$ |
1,866 |
|
Less: Total derivative liabilities measured at fair value |
|
|
(159,328 |
) |
|
|
(46,931 |
) |
|
|
|
Net derivative assets (liabilities) measured at fair value |
|
$ |
(159,328 |
) |
|
$ |
(45,065 |
) |
|
|
|
|
|
|
|
|
|
Level 3 derivative assets (liabilities) as a percent of total assets (liabilities) |
|
|
2 |
% |
|
|
0 |
% |
Level 3 derivative assets (liabilities) as a percent of total derivative assets (liabilities) measured at fair value
|
|
|
10 |
% |
|
|
100 |
% |
Level 3 net derivative assets (liabilities) as a percent of net derivative assets (liabilities) measured at fair value
|
|
|
10 |
% |
|
|
4 |
% |
For a further discussion regarding the measurement of derivative instruments at fair value,
see Note D Fair Value Measurements, to the consolidated financial statements.
Contractual obligations and commitments
We had the following material changes in our contractual obligations and commitments as of
June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by period |
|
|
Total |
|
Less than |
|
1 - 3 |
|
3 - 5 |
|
More than |
(in thousands) |
|
|
|
1 year |
|
years |
|
years |
|
5 years |
|
Employment
agreements with executive officers (a) |
|
|
2,562 |
|
|
|
2,008 |
|
|
|
554 |
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
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. |
|
|
|
Effective March 1, 2008, Messrs. Leach and Beal each received an annual pay increase of $100,000. |
|
|
|
An executive officer resigned as of March 31, 2008, and the Company will be obligated to pay such person 1/12th of his base salary for each
month from April 2008 through March 2009 as consideration for such persons covenant not to compete with the Company in accordance with
his employment agreement. |
|
|
|
Effective May 21, 2008, the Board of Directors appointed Matthew G. Hyde Vice President Exploration and entered into an employment
agreement with him. |
|
|
|
An executive officer resigned as of June 23, 2008. The Company is no longer obligated to pay such person as the non-compete clause of his
employment agreement was not executed by the Board of Directors. As such, his annual salary is no longer included in the table above. |
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.
37
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, 2008. See our disclosure of critical accounting policies in the
consolidated financial statements on our Annual Report on Form 10-K for the year ended December 31,
2007, filed with the SEC on March 28, 2007.
Recent accounting pronouncements
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. We adopted this statement January 1, 2008 and did not elect the fair
value option for any of its eligible financial instruments or other items. As such, the adoption
had no impact on the consolidated financial statements.
In April 2007, the FASB issued FASB Staff Position FIN 39-1, Amendment of FASB Interpretation
No. 39 (FIN No. 39-1). FIN No. 39-1 clarifies that a reporting entity that is party to a master
netting arrangement can offset fair value amounts recognized for the right to reclaim cash
collateral (a receivable) or the obligation to return cash collateral (a payable) against fair
value amounts recognized for derivative instruments that have been offset under the same master
netting arrangement. FIN No. 39-1 is effective for financial statements issued for fiscal years
beginning after November 15, 2007. Adoption of FIN No. 39-1 has not had a material impact on our
consolidated financial statements.
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 did not adopt EITF
Issue 06-11 until the required effective date of January 1, 2008. The adoption of EITF Issue 06-11
has not had 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.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations
(SFAS No. 141(R)), which replaces FASB Statement No. 141. SFAS No. 141(R) establishes principles
and requirements for how an acquirer recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, any non- controlling interest in the
acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that
will enable users to evaluate the
nature and financial effects of the business combination. SFAS No. 141(R) is effective for
acquisitions that occur in an entitys fiscal year that begins after December 15, 2008, which will
be our fiscal year 2009. The impact, if any, will depend on the nature and size of business
combinations we consummate after the effective date.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements an amendment of ARB No. 51. SFAS No. 160 requires that accounting and
reporting for minority interests will be recharacterized as noncontrolling interests and classified
as a component of equity. SFAS No. 160 also establishes reporting requirements that provide
sufficient disclosures that clearly identify and distinguish between the interests of the parent
and the interests of the noncontrolling owners. SFAS No. 160 applies to all entities that prepare
consolidated financial statements, except not-for-profit organizations, but will affect only those
entities that have an outstanding noncontrolling interest in one or more subsidiaries or that
deconsolidate a subsidiary. This statement is effective as of the beginning of an entitys first
fiscal year beginning after December 15, 2008, which will be our fiscal year 2009. Based upon our
June 30, 2008 balance sheet, the statement would have no impact.
In December 2007, the SEC issued Staff Accounting Bulletin (SAB) No. 110, Share-Based
Payment (SAB No. 110). SAB No. 110 amends SAB No. 107, Share-Based Payment, and allows for the
continued use, under certain circumstances, of the
38
simplified method in developing an estimate of
the expected term on stock options accounted for under SFAS No. 123R, Share-Based Payment (revised
2004). SAB No. 110 is effective for stock options granted after December 31, 2007. We continued to
use the simplified method in developing an estimate of the expected term on stock options granted
in the first and second quarters of 2008. We do not have sufficient historical exercise data to provide a
reasonable basis upon which to estimate expected term due to the limited period of time our shares
of common stock have been publicly traded.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities (SFAS No. 161), which amends and expands the disclosure requirements of SFAS
No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), to
provide an enhanced understanding of an entitys use of derivative instruments, how they are
accounted for under SFAS No. 133 and their effect on the entitys financial position, financial
performance and cash flows. The provisions of SFAS No. 161 are effective as of January 1, 2009. We
are currently evaluating the impact on our consolidated financial statements of adopting SFAS No.
161.
Cautionary statement regarding forward-looking statements
This report may contain forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E 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 Annual Report on Form 10-K for the year
ended December 31, 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. |
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 Annual Report on Form 10-K for the year
ended December 31, 2007, as well as with the consolidated financial statements and notes thereto
included in this Quarterly Report on Form 10-Q.
39
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.
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.
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, as described
under Item 1. Business Marketing Arrangements in our Annual Report on Form 10-K for the year
ended December 31, 2007. 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.
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 reduce our exposure
to changes in the prices of oil and natural gas we have entered into, and may in the future enter
into additional commodity price risk management arrangements for a portion of our oil and natural
gas production. The agreements that we have entered into generally have the effect of providing us
with a fixed price for a portion of our expected future oil and natural gas production over a fixed
period of time. Our commodity price risk management activities could have the effect of reducing
our revenues, net income and the value of our common stock. As of June 30, 2008, the net unrealized
loss on our commodity price risk management contracts was $159.3 million. An average increase in
the commodity price of $1.00 per barrel of crude oil and $0.10 per Mcf for natural gas from the
commodity prices as of June 30, 2008, would have resulted in an increase in the net unrealized loss
on our commodity price risk management contracts, as reflected on our balance sheet as of June 30,
2008, of approximately $4.1 million.
At
June 30, 2008, we have an oil price collar and oil price swaps that settle on a monthly basis covering future oil
production from July 1, 2008 through December 31, 2012. See Commodity Derivatives and Hedging.
Subsequent to June 30, 2008, oil futures prices have decreased; however, they continue
to exceed the weighted average swap fixed price and collar ceiling price of $97.60 for all oil
contracts and $77.67 for oil contracts settling in 2008. The average NYMEX oil futures price for
the quarter ended June 30, 2008, was $124.28. As of August 7, 2008, the NYMEX oil futures price was
$120.02. At this pricing level, for each monthly settlement period, we will continue to remit the
excess of the monthly average NYMEX oil futures price for each settlement period over the weighted
average swap fixed price and collar ceiling price from above. These payments to the counterparties
could significantly affect our cash flow but the impact should be reduced or partially offset by
(1) increased commodity prices received on the sale of our unhedged oil production and (2) only a
portion of the total remaining contract volume settles each month. The decrease in oil prices,
should it continue through the end of the third quarter of 2008, should increase the fair value of
our commodities contracts from their recorded balance at June 30, 2008. Changes in the recorded
fair value of the undesignated commodity derivatives are marked to market through earnings as
unrealized gains or losses. The potential increase in fair value would be recorded in earnings as
unrealized gains. However, an increase in the average NYMEX oil futures price above the second
quarter average would result in a decrease in fair value and unrealized losses in earnings. We are
currently unable to estimate the effects on the earnings of future periods resulting from changes
in the market value of our derivative contracts.
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
$190.0 million outstanding under our revolving credit facility at June 30, 2008. The impact of a 1%
increase in interest rates on this amount of debt would result in increased interest expense of
approximately $1.9 million and a corresponding decrease in net income before income tax. As of June
30, 2008, we had $111.4 million of outstanding indebtedness under our 2nd Lien Credit Facility. 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 $1.1 million and a
corresponding decrease in net income before income tax.
40
Item 4. CONTROLS AND PROCEDURES
Our management, with the participation of our Chief Executive Officer and Chief Financial
Officer, evaluated the effectiveness of the design and operation of our disclosure controls and
procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end
of the period covered by this quarterly report. Our disclosure controls and procedures are designed
to provide reasonable assurance that the information required to be disclosed by us in reports that
we file under the Securities Exchange Act of 1934 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. Our Chief Executive Officer and Chief
Financial Officer have concluded that, as of June 30, 2008, 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 and
reported within the time periods specified in SEC rules and forms.
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 connection with our filing of our Annual Report on
Form 10-K for the year ending December 2008. 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 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
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Total number of |
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Maximum number of |
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shares purchased as |
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shares that may yet |
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Total number of |
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Average price |
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part of publicly |
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be purchased under |
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Period |
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shares
purchased(1) |
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paid per share |
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announced plans |
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the plan |
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April 1, 2008 - April 30, 2008 |
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$ |
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May 1, 2008 - May 31, 2008 |
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$ |
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June 1, 2008 - June 30, 2008 |
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3,142 |
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$ |
39.78 |
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(1) |
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Represents shares that were withheld by the Company to satisfy tax withholding
obligations that arose upon the lapse of restrictions on restricted stock. |
Item 4. Submission of Matters to a Vote of Security Holders
The 2008 Annual Meeting of Stockholders of Concho Resources Inc. (Annual Meeting) was held on June 17, 2008, in Midland, Texas for the following purposes: (i) to elect three Class I directors, each for a term of three years; (ii) to ratify the Audit Committee of the Board of Directors selection of Grant Thornton LLP as the independent registered public accounting firm of the Company for the fiscal year ending December 31, 2008; and (iii) to transact such other business as may properly come before the Annual Meeting or any adjournments or postponements thereof.
Proxies for the Annual Meeting were solicited by the Board pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended and there was no solicitation in opposition to the Boards nominees for director.
Each of the nominees for director was duly elected, with votes as follows:
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Shares |
Nominee |
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Shares for |
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withheld |
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Timothy A. Leach |
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65,024,406 |
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634,794 |
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William H. Easter III |
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65,611,891 |
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47,309 |
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W. Howard Keenan, Jr. |
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65,611,955 |
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47,245 |
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The appointment of Grant Thornton LLP, independent public accountants, as the Companys auditors for the year ending December 31, 2008, was ratified by the Companys stockholders by the following vote: 65,591,133 for; 60,644 shares against,; and 7,423 shares abstaining.
41
Item 6. Exhibits
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Exhibit |
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Number |
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Exhibit |
10.1
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Third Amendment to Credit Agreement, dated as of May 19, 2008 by and among Concho Resources Inc.,
certain of its subsidiaries, JPMorgan Chase Bank, N.A. and other lenders party thereto (filed as
Exhibit 10.1 to the Companys Current Report on Form 8-K on May 23, 2008 and incorporated herein
by reference). |
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10.2
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Indemnification Agreement, dated May 21, 2008, by and between Concho Resources Inc. and Matthew
G. Hyde (filed as Exhibit 10.1 to the Companys Current Report on Form 8-K on May 28, 2008, and
incorporated herein by reference). |
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10.3
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Employment Agreement, dated May 21, 2008, by and between Concho Resources Inc. and Matthew G.
Hyde (filed as Exhibit 10.2 to the Companys Current Report on Form 8-K on May 28, 2008, and
incorporated herein by reference). |
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10.4
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Purchase Agreement, dated June 5, 2008, by and among Concho Resources Inc., James C. Henry and
Paula Henry, Henry Securities Ltd., Henchild LLC, Henry Family Investment Group, Henry Holding
Lap, Henry Energy LP, Aguasal Holding, HELP Investment LLC, Henry Capital LLC, Henry Operating
LLC, Henry Petroleum LP, Quail Ranch LLC, Aguasal Management LLC and Aguasal LP (filed as Exhibit
2.1 to the Companys Current Report on Form 8-K on June 9, 2008, and incorporated herein by
reference). |
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10.5
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Common Stock Purchase Agreement, dated June 5, 2008, by and among Concho Resources Inc. and the
Purchasers named therein (filed as Exhibit 10.1 to the Companys Current Report on Form 8-K on
June 9, 2008, and incorporated herein by reference). |
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10.6
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Registration Rights Agreement, dated July 31, 2008, by and between Concho Ressources Inc. and the
Purchasers named therein (filed as Exhibit 10.1 to the Companys Current Report on Form 8-K on
August 6, 2008, and incorporated herein by reference). |
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10.7
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Amended and Restated Credit Agreement, dated July 31, 2008, by and between Concho Resources Inc.,
JPMorgan Chase Bank, N.A., Bank of America, N.A., Calyon New York Branch, ING Capital LLC and BNP
Paribas and certain other lenders party thereto (filed as Exhibit 10.2 to the Companys Current
Report on Form 8-K on August 6, 2008, and incorporated herein by reference). |
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31.1
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Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
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31.2
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Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
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32.1
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Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
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32.2
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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.
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CONCHO RESOURCES INC.
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Date: August 13, 2008 |
By |
/S/ Timothy A. Leach
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Timothy A. Leach |
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Director, Chairman of the Board of Directors and
Chief Executive Officer
(Principal Executive Officer) |
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By |
/S/ Steven L. Beal
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Steven L. Beal |
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Director, President, Chief Operating Officer and Chief Financial Officer
(Principal Financial
and Accounting Officer)
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43