e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
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For the Quarterly Period Ended June 30, 2009
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Commission File Number 001-14039 |
CALLON PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
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Delaware
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64-0844345 |
(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.) |
200 North Canal Street
Natchez, Mississippi 39120
(Address of principal executive offices)(Zip code)
(601) 442-1601
(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 has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files). Yes
o 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 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 þ
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Non-accelerated filer o
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Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act
Rule 12b-2). Yes o No þ
As of August 5, 2009, there were 21,703,705 shares of the Registrants Common Stock, par value
$0.01 per share, outstanding.
CALLON PETROLEUM COMPANY
TABLE OF CONTENTS
2
Callon Petroleum Company
Consolidated Balance Sheets
(In thousands, except share data)
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June 30, |
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December 31, |
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2009 |
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2008 |
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(Unaudited) |
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(Note 1) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
735 |
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$ |
17,126 |
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Accounts receivable |
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19,528 |
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44,290 |
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Fair market value of derivatives |
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7,064 |
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21,780 |
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Other current assets |
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1,971 |
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1,103 |
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Total current assets |
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29,298 |
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84,299 |
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Oil and gas properties, full-cost accounting method: |
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Evaluated properties |
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1,587,007 |
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1,581,698 |
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Less accumulated depreciation, depletion and amortization |
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(1,473,139 |
) |
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(1,455,275 |
) |
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113,868 |
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126,423 |
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Unevaluated properties excluded from amortization |
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26,147 |
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32,829 |
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Total oil and gas properties |
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140,015 |
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159,252 |
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Other property and equipment, net |
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2,392 |
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2,536 |
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Restricted investments |
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4,784 |
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4,759 |
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Investment in Medusa Spar LLC |
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11,926 |
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12,577 |
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Other assets, net |
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2,327 |
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2,667 |
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Total assets |
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$ |
190,742 |
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$ |
266,090 |
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LIABILITIES AND STOCKHOLDERS EQUITY (DEFICIT) |
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Current liabilities: |
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Accounts payable and accrued liabilities |
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$ |
11,379 |
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$ |
76,516 |
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Asset retirement obligations |
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22,374 |
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9,151 |
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33,753 |
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85,667 |
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Callon Entrada non-recourse credit facility (See Note 1) |
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82,841 |
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Total current liabilities |
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116,594 |
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85,667 |
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9.75% Senior Notes |
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195,729 |
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194,420 |
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Callon Entrada non-recourse credit facility (See Note 1) |
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78,435 |
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Senior secured credit facility |
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5,000 |
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Total long-term debt |
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200,729 |
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272,855 |
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Asset retirement obligations |
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12,631 |
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33,043 |
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Callon Entrada non-recourse credit facility interest payable (See Note 1) |
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2,719 |
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Other long-term liabilities |
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1,503 |
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1,610 |
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Total liabilities |
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331,457 |
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395,894 |
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Stockholders equity (deficit): |
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Preferred Stock, $.01 par value, 2,500,000 shares authorized; |
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Common Stock, $.01 par value, 30,000,000 shares authorized; 21,676,067 and 21,621,142
shares outstanding at June 30, 2009 and December 31, 2008, respectively |
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217 |
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216 |
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Capital in excess of par value |
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230,150 |
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227,803 |
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Other comprehensive income (loss) |
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(581 |
) |
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14,157 |
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Retained (deficit) earnings |
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(370,501 |
) |
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(371,980 |
) |
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Total stockholders equity (deficit) |
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(140,715 |
) |
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(129,804 |
) |
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Total liabilities and stockholders equity (deficit) |
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$ |
190,742 |
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$ |
266,090 |
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The accompanying notes are an integral part of these financial statements.
3
Callon Petroleum Company
Consolidated Statements of Operations
(In thousands, except per share amounts)
(Unaudited)
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Three Months Ended |
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Six Months Ended |
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June 30, |
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June 30, |
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2009 |
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2008 |
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2009 |
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2008 |
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Operating revenues: |
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Oil sales |
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$ |
18,971 |
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$ |
28,554 |
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$ |
34,923 |
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$ |
53,650 |
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Gas sales |
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6,054 |
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19,475 |
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14,917 |
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39,339 |
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Total operating revenues |
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25,025 |
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48,029 |
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49,840 |
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92,989 |
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Operating expenses: |
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Lease operating expenses |
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4,656 |
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4,870 |
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8,695 |
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|
10,048 |
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Depreciation, depletion and amortization |
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8,452 |
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|
15,218 |
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|
17,865 |
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30,247 |
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General and administrative |
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5,391 |
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2,943 |
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|
7,210 |
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|
5,595 |
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Accretion expense |
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|
795 |
|
|
|
952 |
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|
1,833 |
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|
1,984 |
|
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|
|
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|
|
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Total operating expenses |
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19,294 |
|
|
|
23,983 |
|
|
|
35,603 |
|
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|
47,874 |
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Income from operations |
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5,731 |
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|
24,046 |
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14,237 |
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|
45,115 |
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Other (income) expenses: |
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Interest expense |
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4,854 |
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|
|
4,434 |
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|
|
9,636 |
|
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|
14,374 |
|
Callon Entrada non-recourse credit facility interest expense
(See Note 1) |
|
|
1,935 |
|
|
|
321 |
|
|
|
3,491 |
|
|
|
321 |
|
Other (income) expense |
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|
61 |
|
|
|
(379 |
) |
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|
(34 |
) |
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|
(851 |
) |
Loss on early extinguishment of debt |
|
|
|
|
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|
11,871 |
|
|
|
|
|
|
|
11,871 |
|
|
|
|
|
|
|
|
|
|
|
|
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|
Total other (income) expenses |
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|
6,850 |
|
|
|
16,247 |
|
|
|
13,093 |
|
|
|
25,715 |
|
|
|
|
|
|
|
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|
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|
|
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|
|
|
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Income (loss) before income taxes |
|
|
(1,119 |
) |
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|
7,799 |
|
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|
1,144 |
|
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|
19,400 |
|
Income tax expense |
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|
24 |
|
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|
2,730 |
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|
6,812 |
|
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|
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|
|
|
|
|
|
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|
Income (loss) before equity in earnings of Medusa Spar LLC |
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|
(1,143 |
) |
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|
5,069 |
|
|
|
1,144 |
|
|
|
12,588 |
|
Equity in earnings of Medusa Spar LLC |
|
|
218 |
|
|
|
84 |
|
|
|
335 |
|
|
|
197 |
|
|
|
|
|
|
|
|
|
|
|
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|
|
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|
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|
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Net income (loss) available to common shares |
|
$ |
(925 |
) |
|
$ |
5,153 |
|
|
$ |
1,479 |
|
|
$ |
12,785 |
|
|
|
|
|
|
|
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|
|
|
|
|
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Net income (loss) per common share: |
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|
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|
|
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|
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|
|
|
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|
Basic |
|
$ |
(0.04 |
) |
|
$ |
0.25 |
|
|
$ |
0.07 |
|
|
$ |
0.61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(0.04 |
) |
|
$ |
0.23 |
|
|
$ |
0.07 |
|
|
$ |
0.58 |
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
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Shares used in computing net income per common share: |
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|
|
|
|
|
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|
|
|
|
|
|
|
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|
Basic |
|
|
21,645 |
|
|
|
20,966 |
|
|
|
21,626 |
|
|
|
20,919 |
|
|
|
|
|
|
|
|
|
|
|
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|
Diluted |
|
|
21,645 |
|
|
|
22,074 |
|
|
|
21,626 |
|
|
|
21,859 |
|
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|
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|
The accompanying notes are an integral part of these financial statements.
4
Callon Petroleum Company
Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)
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Six Months Ended |
|
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|
June 30, |
|
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June 30, |
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|
2009 |
|
|
2008 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
1,479 |
|
|
$ |
12,785 |
|
Adjustments to reconcile net income to
cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
18,285 |
|
|
|
30,615 |
|
Accretion expense |
|
|
1,833 |
|
|
|
1,984 |
|
Amortization of deferred financing costs |
|
|
1,481 |
|
|
|
1,580 |
|
Callon Entrada non-recourse credit facility non-cash interest expense |
|
|
1,687 |
|
|
|
|
|
Non-cash loss on early extinguishment of debt |
|
|
|
|
|
|
5,598 |
|
Equity in earnings of Medusa Spar LLC |
|
|
(335 |
) |
|
|
(197 |
) |
Deferred income tax expense |
|
|
|
|
|
|
6,812 |
|
Non-cash charge related to compensation plans |
|
|
1,184 |
|
|
|
1,546 |
|
Excess tax benefits from share-based payment arrangements |
|
|
|
|
|
|
(1,435 |
) |
Changes in current assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
6,441 |
|
|
|
(2,470 |
) |
Other current assets |
|
|
(868 |
) |
|
|
3,226 |
|
Current liabilities |
|
|
(28,993 |
) |
|
|
3,482 |
|
Change in gas balancing receivable |
|
|
155 |
|
|
|
732 |
|
Change in gas balancing payable |
|
|
(123 |
) |
|
|
359 |
|
Change in other long-term liabilities |
|
|
16 |
|
|
|
(6 |
) |
Change in other assets, net |
|
|
(189 |
) |
|
|
(702 |
) |
|
|
|
|
|
|
|
Cash provided by operating activities |
|
|
2,053 |
|
|
|
63,909 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(24,430 |
) |
|
|
(78,441 |
) |
Proceeds from sale of mineral interests |
|
|
|
|
|
|
167,493 |
|
Distribution from Medusa Spar LLC |
|
|
986 |
|
|
|
108 |
|
|
|
|
|
|
|
|
Cash (used in) provided by investing activities |
|
|
(23,444 |
) |
|
|
89,160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Proceeds from senior secured credit facility |
|
|
9,337 |
|
|
|
51,435 |
|
Payments on senior secured credit facility |
|
|
(4,337 |
) |
|
|
(216,000 |
) |
Equity issued related to stock incentive plans |
|
|
|
|
|
|
(1,133 |
) |
Excess tax benefits from share-based payment arrangements |
|
|
|
|
|
|
1,435 |
|
|
|
|
|
|
|
|
Cash provided by (used in) financing activities |
|
|
5,000 |
|
|
|
(164,263 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
|
(16,391 |
) |
|
|
(11,194 |
) |
Cash and cash equivalents: |
|
|
|
|
|
|
|
|
Balance, beginning of period |
|
|
17,126 |
|
|
|
53,250 |
|
|
|
|
|
|
|
|
Balance, end of period |
|
$ |
735 |
|
|
$ |
42,056 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial statements.
5
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2009
1. |
|
Callon Entrada Non-Recourse Credit Facility |
A wholly-owned subsidiary of Callon Petroleum Company (the Company or Callon), Callon
Entrada Company (Callon Entrada), entered into a credit agreement with CIECO Energy
(Entrada) LLC, (CIECO Entrada) pursuant to which Callon Entrada was entitled to borrow up
to $150 million, plus interest expense incurred of up to $12 million, to finance the
development of the Entrada project prior to the abandonment in November 2008. The debt was
to be repaid by production from the Entrada field. As a result of abandoning the project
and the lease expiring June 1, 2009, Callon Entradas only source of payment is from the
sale of equipment purchased but not used for the Entrada project. The agreement bears
interest at six-month LIBOR (as in effect on the first day of each interest period) plus
375 basis points and is subject to customary representations, warranties, covenants and
events of default. The interest rate increased by 400 basis points as of April 2, 2009 due
to a notice of default received from CIECO Entrada which is discussed below. As of June
30, 2009, $78.4 million of principal and $4.4 million of interest were outstanding under
this facility.
On April 2, 2009, Callon Entrada received a notice from CIECO Entrada advising Callon
Entrada that certain alleged events of default occurred under the non-recourse credit
agreement relating to failure to pay interest when due and the breach of various other
covenants related to the decision to abandon the Entrada project. The notice of default
received from CIECO Entrada invoked CIECO Entradas rights under the Callon Entrada
non-recourse credit agreement to accelerate payment of the principal and interest due. The
acceleration of payment causes the principal and interest balances under the Callon Entrada
non-recourse credit agreement to be reclassified as of June 30, 2009 to current liabilities
from long-term liabilities under U.S. generally accepted accounting principles (GAAP).
Under GAAP the Company is currently required to consolidate the financial statements and
results of operations of Callon Entrada. Callon Entradas non-recourse liability is
reflected in a separate line item in the consolidated financial statements. The assets of
Callon Entrada, including the stock, are pledged to CIECO Entrada and are shown in the
consolidating condensed financial statements below. Based on the advice of counsel, the
Company believes that Callon and its subsidiaries (other than Callon Entrada) did not
guarantee and are not otherwise obligated to repay the principal, accrued interest or any
other amount which may become due under the Callon Entrada credit facility. However,
Callon has entered into a customary indemnification agreement pursuant to which it agrees
to indemnify the lenders under the Callon Entrada credit facility against Callon Entradas
misappropriation of funds, non-performance of certain covenants, excluding the events of
default discussed above, and similar matters. In addition, Callon also guaranteed the
obligations of Callon Entrada to fund its proportionate share of any operating costs
related to the Entrada project that Callon Entrada may, from time to time, expressly
approve under the Entrada joint operating agreement. Callon also has guaranteed Callon
Entradas payment of all amounts to plug and abandon wells and related facilities for a
breach of law, rule or regulation (including environmental laws) and for any losses of
CIECO Entrada attributable to gross negligence of Callon Entrada. The well for which
Callon Entrada is responsible for was plugged and abandoned in the fourth of quarter of
2008 and the Company believes that there are no additional costs related to abandoning that
well.
6
Prior to abandonment of the Entrada project, CIECO Entrada failed to fund two loan requests
totaling $40 million under the Callon Entrada non-recourse credit agreement. These loan
requests were to cover Callon Entradas share of the cost incurred to develop the Entrada
field up to the suspension of the project. Such amounts were subsequently funded by the
Company. The Company continues to discuss with CIECO its failure to fund the $40 million in
loan requests. No assurances can be made regarding the outcome of discussions. The
Company does not believe that we have waived any of our rights under the agreements with
CIECO Entrada or its parent, CIECO Energy (U.S.) LLC (CIECO).
As of June 30, 2009, the wind down of the Entrada project was substantially complete and
substantially all of the costs had been paid. The lease expired June 1, 2009 and reverted
to the Minerals Management Service. In addition, the sale of equipment purchased for the
Entrada project, but not used, is in progress. As of June 2009, Callon Entrada has
collected $1.8 million in sales proceeds from the sale of equipment, net to its interest,
which was applied to unpaid interest expense as required under the Callon Entrada
non-recourse credit facility. The Company believes that the amount of future operating
costs of Callon Entrada, for which the Company would be responsible for, is not
significant.
Below are consolidating condensed financial statements of Callon Petroleum Company
presented to demonstrate that Callon Entrada does not have sufficient assets available to
pay down the balance owed under the Callon Entrada non-recourse credit facility as a result
of the abandonment and reversion of this lease of the Entrada project.
Callon Petroleum Company Consolidating Condensed Financial Information
as of and for the Six Months ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Callon |
|
|
|
|
|
|
Callon |
|
|
and Other |
|
|
Callon |
|
|
|
Entrada |
|
|
Subsidiaries |
|
|
Consolidated |
|
|
|
|
Balance Sheet (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
$ |
1,238 |
|
|
$ |
28,060 |
|
|
$ |
29,298 |
|
Total oil and gas properties |
|
|
|
|
|
|
140,015 |
|
|
|
140,015 |
|
Other property and equipment |
|
|
|
|
|
|
2,392 |
|
|
|
2,392 |
|
Other assets |
|
|
|
|
|
|
19,037 |
|
|
|
19,037 |
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,238 |
|
|
$ |
189,504 |
|
|
$ |
190,742 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current liabilities |
|
$ |
2,842 |
|
|
$ |
30,911 |
|
|
$ |
33,753 |
|
Callon Entrada non-recourse credit facility |
|
|
82,841 |
|
|
|
|
|
|
|
82,841 |
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
85,683 |
|
|
|
30,911 |
|
|
|
116,594 |
|
Total long-term debt |
|
|
|
|
|
|
200,729 |
|
|
|
200,729 |
|
Total other long-term liabilities |
|
|
|
|
|
|
14,134 |
|
|
|
14,134 |
|
Total stockholders equity (deficit) |
|
|
(84,445 |
) |
|
|
(56,270 |
) |
|
|
(140,715 |
) |
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders
equity (deficit) |
|
$ |
1,238 |
|
|
$ |
189,504 |
|
|
$ |
190,742 |
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Callon |
|
|
|
|
|
|
Callon |
|
|
and Other |
|
|
Callon |
|
|
|
Entrada |
|
|
Subsidiaries |
|
|
Consolidated |
|
|
|
|
Statement of Operations (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
$ |
|
|
|
$ |
49,840 |
|
|
$ |
49,840 |
|
Total operating expenses |
|
|
56 |
|
|
|
35,547 |
|
|
|
35,603 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
(56 |
) |
|
|
14,293 |
|
|
|
14,237 |
|
Interest expense |
|
|
3,491 |
|
|
|
9,636 |
|
|
|
13,127 |
|
Other (income) expenses |
|
|
(6 |
) |
|
|
(28 |
) |
|
|
(34 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
(3,541 |
) |
|
|
4,685 |
|
|
|
1,144 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before equity in earnings of
Medusa Spar LLC |
|
|
(3,541 |
) |
|
|
4,685 |
|
|
|
1,144 |
|
Equity in earnings of Medusa Spar LLC |
|
|
|
|
|
|
335 |
|
|
|
335 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income |
|
$ |
(3,541 |
) |
|
$ |
5,020 |
|
|
$ |
1,479 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Callon |
|
|
|
|
|
|
Callon |
|
|
and Other |
|
|
Callon |
|
|
|
Entrada |
|
|
Subsidiaries |
|
|
Consolidated |
|
|
|
|
Statement of Cash Flows (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by operating
activities |
|
$ |
(5,057 |
) |
|
$ |
7,110 |
|
|
$ |
2,053 |
|
Net cash used in investing activities |
|
|
|
|
|
|
(23,444 |
) |
|
|
(23,444 |
) |
Net cash provided by financing activities |
|
|
|
|
|
|
5,000 |
|
|
|
5,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
|
(5,057 |
) |
|
|
(11,334 |
) |
|
|
(16,391 |
) |
Cash and cash equivalents at beginning of
the period |
|
|
5,218 |
|
|
|
11,908 |
|
|
|
17,126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of the
period |
|
$ |
161 |
|
|
$ |
574 |
|
|
$ |
735 |
|
|
|
|
|
|
|
|
|
|
|
The financial information presented as of any date other than December 31, 2008 has been
prepared from the books and records of the Company without audit. Financial information as
of December 31, 2008 has been derived from the audited financial statements of the Company,
but does not include all disclosures required by U.S. generally accepted accounting
principles. In the opinion of management, all adjustments, consisting only of normal
recurring adjustments, necessary for the fair presentation of the financial information for
the periods indicated, have been included. For further information regarding the Companys
accounting policies, refer to the Consolidated Financial Statements and related notes for
the year ended December 31, 2008 included in the Companys Annual Report on Form 10-K filed
March 19, 2009. The results of operations for the three-month and six-month periods ended
June 30, 2009 are not necessarily indicative of future financial results.
8
Basic net income per share was computed by dividing net income by the weighted average
number of shares of common stock outstanding during the period. Diluted net income per
common share was determined on a weighted average basis using common shares issued and
outstanding adjusted for the effect of stock options and restricted stock considered common
stock equivalents computed using the treasury stock method.
A reconciliation of the basic and diluted net income per share computation is as follows
(in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Net income (loss) |
|
$ |
(925 |
) |
|
$ |
5,153 |
|
|
$ |
1,479 |
|
|
$ |
12,785 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) Weighted average shares outstanding |
|
|
21,645 |
|
|
|
20,966 |
|
|
|
21,626 |
|
|
|
20,919 |
|
Dilutive impact of stock options |
|
|
|
|
|
|
253 |
|
|
|
|
|
|
|
225 |
|
Dilutive impact of warrants |
|
|
|
|
|
|
599 |
|
|
|
|
|
|
|
526 |
|
Dilutive impact of restricted stock |
|
|
|
|
|
|
256 |
|
|
|
|
|
|
|
189 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) Weighted average shares outstanding
for diluted net income per share |
|
|
21,645 |
|
|
|
22,074 |
|
|
|
21,626 |
|
|
|
21,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income (loss) per share (a/b) |
|
$ |
(0.04 |
) |
|
$ |
0.25 |
|
|
$ |
0.07 |
|
|
$ |
0.61 |
|
Diluted net income (loss) per share (a/c) |
|
$ |
(0.04 |
) |
|
$ |
0.23 |
|
|
$ |
0.07 |
|
|
$ |
0.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares excluded due to the exercise / grant
price being greater than the average share
price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options |
|
|
1,003 |
|
|
|
|
|
|
|
1,003 |
|
|
|
|
|
Warrants |
|
|
365 |
|
|
|
|
|
|
|
365 |
|
|
|
|
|
Restricted stock |
|
|
634 |
|
|
|
|
|
|
|
634 |
|
|
|
|
|
Long-term debt consisted of the following at:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Senior Secured Credit Facility
(matures September 25, 2012) |
|
$ |
5,000 |
|
|
$ |
|
|
9.75% Senior Notes (due 2010), net of discount |
|
|
195,729 |
|
|
|
194,420 |
|
Callon Entrada non-recourse credit agreement |
|
|
|
|
|
|
78,435 |
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
200,729 |
|
|
$ |
272,855 |
|
|
|
|
|
|
|
|
Senior Secured Credit Facility. On September 25, 2008, the Company completed a $250 million second
amended and restated senior secured credit agreement, which matures on September 25, 2012, with
Union Bank N.A. (Union Bank) as administrative agent and
9
issuing lender.
On March 19, 2009, the Company entered into the first amendment of the Second
Amended and Restated Credit Agreement (the Amendment) which states that a default under
the Callon Entrada non-recourse credit facility (described in Note 1) would not constitute a
default under the Companys senior secured credit facility. The Amendment set the borrowing
base at $48 million and implemented a Monthly Commitment Reduction (MCR) commencing on June
1, 2009 in the amount of $4.33 million per month. The borrowing base and MCR are both
subject to re-determination August 1, 2009 and quarterly thereafter. As of August 1, 2009,
the Company had received a preliminary notice from Union Bank that the
redetermined borrowing base would be approximately $35.0 million
with the MCR increasing to approximately $4.7 million. Borrowings
under the credit agreement are secured by mortgages covering the Companys major fields
excluding the Entrada field. As of June 30, 2009, there was $5 million outstanding under
the agreement with a weighted average interest rate of 2.05% and $38.7 million, subject to
MCR, available for future borrowings under the senior secured credit agreement.
On April 1, 2009, Diamond Offshore Drilling, Inc. (Diamond) called on an outstanding
letter of credit for CIECOs share of the settlement for the termination of the Ocean
Victory drilling contract in the amount of $7.3 million. Callon paid its share, in the
amount of $7.3 million, in March 2009. The remaining balance of the letter of credit was
cancelled on April 2, 2009 by Diamond. The Company continues to discuss with CIECO its
failure to fund the settlement for the termination of the drilling contract. The $7.3
million due from CIECO for their share of the settlement for the termination of the drilling
contract is included in accounts receivable at June 30, 2009.
Fair Value of Debt. The fair value of the 9.75% senior notes due in December 2010 is
determined at the end of each reporting period using inputs based upon quoted prices for
such instruments in active markets. At June 30, 2009, the estimated fair value of the 9.75%
senior notes was $100 million.
Early Extinguishment of Debt. On April 8, 2008, the Company completed the sale of a 50%
working interest in the Entrada Field to CIECO Entrada for a purchase price of $175 million with a
cash payment of $155 million at closing and the additional $20 million payable after the
achievement of certain production milestones. Simultaneously with the closing of the CIECO
transaction, the Company used the proceeds from the sale, cash on hand and a draw of $16
million from the senior secured credit agreement, to extinguish a $200 million senior
secured revolving credit agreement, which was secured by a lien on the Entrada properties.
Due to the early extinguishment of the $200 million senior revolving credit facility on
April 8, 2008, Callon incurred expenses of $11.9 million consisting of $6.3 million in cash
pre-payment penalties plus a non-cash charge of $5.6 million related to the amortization
expense associated with the deferred financing costs related to the credit facility.
The Company periodically uses derivative financial instruments to manage oil and gas price
risk on a limited amount of its future production and does not use these instruments for
10
trading purposes. Settlements of oil and gas derivative contracts are generally based on the
difference between the contract price or prices specified in the derivative instrument and a
NYMEX price or other cash or futures index price. Such derivative contracts are accounted
for under Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities, (SFAS 133) as amended.
The Companys derivative contracts that are accounted for as cash flow hedges under SFAS 133
are recorded at fair market value and the changes in fair value are recorded through other
comprehensive income (loss), net of tax, in stockholders equity (deficit). The cash
settlements on contracts for future production are recorded as an increase or decrease in
oil and gas sales. The changes in fair value related to ineffective derivative contracts
are recognized as derivative expense (income). The cash settlements on these contracts are
also recorded within derivative expense (income).
Cash settlements on effective oil and gas cash flow hedges during the three-month and
six-month periods ended June 30, 2009 resulted in an increase in oil and gas sales of $4.5
million and $12.4 million, respectively. For the three-month and six-month periods ended
June 30, 2008 cash settlements on effective oil and gas cash flow hedges resulted in a
decrease in oil and gas sales of $6.0 million and $7.8 million, respectively.
The Companys derivative contracts are carried at fair value on our consolidated balance
sheet under the caption Fair Market Value of Derivatives. The oil and gas derivative
contracts are settled based upon reported prices on NYMEX. The estimated fair value of
these contracts is based upon closing exchange prices on NYMEX and in the case of collars
and floors, the time value of options. See Note 7, Fair Value Measurements.
Listed in the table below are the outstanding oil and gas derivative contracts as of June
30, 2009:
Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
Average |
|
|
|
|
Volumes per |
|
Quantity |
|
Floor |
|
Ceiling |
|
|
Product |
|
Month |
|
Type |
|
Price |
|
Price |
|
Period |
Oil |
|
|
30,000 |
|
|
Bbls |
|
$ |
110.00 |
|
|
$ |
175.75 |
|
|
|
07/09-12/09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
100,000 |
|
|
MMbtu |
|
$ |
4.50 |
|
|
$ |
6.30 |
|
|
|
10/09-12/09 |
|
Natural Gas |
|
|
75,000 |
|
|
MMbtu |
|
$ |
5.00 |
|
|
$ |
8.30 |
|
|
|
01/10-12/10 |
|
11
6. |
|
Comprehensive Income (Loss) |
A summary of the Companys comprehensive income (loss) is detailed below (in
thousands, net of tax):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Net income (loss) |
|
$ |
(925 |
) |
|
$ |
5,153 |
|
|
$ |
1,479 |
|
|
$ |
12,785 |
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivatives |
|
|
(7,815 |
) |
|
|
(8,579 |
) |
|
|
(14,738 |
) |
|
|
(10,794 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income (loss) |
|
$ |
(8,740 |
) |
|
$ |
(3,426 |
) |
|
$ |
(13,259 |
) |
|
$ |
1,991 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7. |
|
Fair Value Measurements |
Statement of Financial Accounting Standards No. 157, (SFAS 157), Fair Value
Measurements defines fair value, establishes a framework for measuring fair value and
requires enhanced disclosures about fair value measurements. SFAS 157 establishes
a fair value hierarchy which consists of three broad levels that prioritize the
inputs to valuation techniques used to measure fair value.
|
|
|
Level 1 valuations consist of unadjusted quoted prices in active markets for
identical assets and liabilities and have the highest priority. |
|
|
|
|
Level 2 valuations rely on quoted market information for the calculation of
fair market value. |
|
|
|
|
Level 3 valuations are internal estimates and have the lowest priority. |
12
Per SFAS 157, the Company has classified its derivatives into these levels depending
upon the data relied on to determine the fair values of the derivative instruments. The
fair values of collars and natural gas basis swaps are estimated using internal discounted
cash flow calculations based upon forward commodity price curves or quotes obtained from
counterparties to the agreements and are designated as Level 3. The following table
summarizes the valuation of our assets and liabilities measured at fair value on a recurring
basis at June 30, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
Quoted |
|
|
Significant |
|
|
|
|
|
|
Prices in |
|
|
Other |
|
Significant |
|
|
|
|
Active |
|
|
Observable |
|
Unobservable |
|
Assets |
|
|
Markets |
|
|
Inputs |
|
Inputs |
|
(Liabilities) |
|
|
(Level 1) |
|
|
(Level 2) |
|
(Level 3) |
|
At Fair Value |
Derivative assets
|
|
$ |
|
|
|
$ |
|
|
$ |
7,064 |
|
|
$ |
7,064 |
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
|
(22 |
) |
|
|
(22 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
|
|
|
$ |
|
|
$ |
7,042 |
|
|
$ |
7,042 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The table below presents a reconciliation for assets and liabilities measured at fair value
on a recurring basis using significant unobservable inputs (Level 3) during the six-month
period ended June 30, 2009. The fair values of Level 3 derivative instruments are estimated
using proprietary valuation models that utilize both market observable and unobservable
parameters. Level 3 instruments presented in the table consist of net derivatives valued
using pricing models incorporating assumptions that, in managements judgment, reflect the
assumptions a marketplace participant would have used at June 30, 2009 (in thousands):
|
|
|
|
|
|
|
Derivatives |
|
Balance at January 1, 2009 |
|
$ |
21,780 |
|
Total gains or losses (realized or unrealized): |
|
|
|
|
Included in earnings |
|
|
12,392 |
|
Included in other comprehensive (income) loss |
|
|
(14,738 |
) |
Purchases, issuances and settlements |
|
|
(12,392 |
) |
|
|
|
|
Balance at June 30, 2009 |
|
$ |
7,042 |
|
|
|
|
|
|
|
|
|
|
Change in
unrealized gains (losses) included in earnings relating to
derivatives still held as of June 30, 2009 |
|
$ |
|
|
|
|
|
|
13
Below is an analysis of deferred income taxes as of June 30, 2009 and December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Deferred tax asset: |
|
|
|
|
|
|
|
|
Federal net operating loss carryforwards |
|
$ |
107,072 |
|
|
$ |
68,432 |
|
State net operating loss carryforwards |
|
|
55,188 |
|
|
|
45,939 |
|
Statutory depletion carryforwards |
|
|
4,575 |
|
|
|
4,561 |
|
Alternative minimum tax credit carryforward |
|
|
375 |
|
|
|
375 |
|
Asset retirement obligations |
|
|
10,577 |
|
|
|
13,102 |
|
Oil and gas properties |
|
|
|
|
|
|
58,061 |
|
Other |
|
|
30,426 |
|
|
|
2,241 |
|
Valuation allowance |
|
|
(187,920 |
) |
|
|
(174,062 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax asset |
|
|
20,293 |
|
|
|
18,649 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liability: |
|
|
|
|
|
|
|
|
Oil and gas properties |
|
|
6,833 |
|
|
|
|
|
Other |
|
|
13,460 |
|
|
|
18,649 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liability |
|
|
20,293 |
|
|
|
18,649 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax asset |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
The Company follows the asset and liability method of accounting for deferred income
taxes prescribed by Statement of Financial Accounting Standards No. 109 (SFAS 109)
Accounting for Income Taxes. The statement provides for the recognition of a deferred tax
asset for deductible temporary timing differences, capital and operating loss carryforwards,
statutory depletion carryforward and tax credit carryforwards, net of a valuation
allowance. The valuation allowance is provided for that portion of the asset, for which it
is deemed more likely than not, that it, will not be realized.
As discussed in Notes 5 of the Consolidated Financial Statements for the year ended December
31, 2008 included in the Companys Annual Report on Form 10-K filed March 19, 2009, the
Company established a valuation allowance of $174 million as of December 31, 2008. The
Companys tax net operating loss carryforwards increased during the period, due primarily to
the abandonment of the Entrada lease which loss had previously been recognized for financial
reporting purposes, unrealized hedging losses and other activity generated additional net
deferred tax assets of $14 million during the six months ended June 30, 2009 requiring
additional valuation allowance of the same amount.
14
9. |
|
Asset Retirement Obligations |
The following table summarizes the activity for the Companys asset retirement obligations:
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, 2009 |
|
Asset retirement obligations at beginning of period |
|
$ |
42,194 |
|
Accretion expense |
|
|
1,833 |
|
Liabilities incurred |
|
|
|
|
Liabilities settled |
|
|
(4,250 |
) |
Revisions to estimate |
|
|
(4,772 |
) |
|
|
|
|
Asset retirement obligations at end of period |
|
|
35,005 |
|
Less: current asset retirement obligations |
|
|
(22,374 |
) |
|
|
|
|
Long-term asset retirement obligations |
|
$ |
12,631 |
|
|
|
|
|
Assets, primarily U.S. government securities, of approximately $4.8 million at June 30,
2009, are recorded as restricted investments. These assets are held in abandonment trusts
dedicated to pay future abandonment costs for several of the Companys oil and gas
properties.
10. |
|
Accounting Pronouncements |
In December 2007, the FASB issued Statement of Financial Accounting Standard No. 141R as
amended, Business Combinations, (SFAS 141R). The objective of SFAS 141R is to improve
the relevance, representational faithfulness, and comparability of the information that a
reporting entity provides in its financial reports about a business combination and its
effects. To accomplish that, SFAS 141R establishes principles and requirements for how the
acquirer (a) recognizes and measurers in its financial statements the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, (b)
recognizes and measures the goodwill acquired in the business combination or a gain from a
bargain purchase, and (c) determines what information to disclose to enable users of the
financial statements to evaluate the nature and financial effects of the business
combination. SFAS 141R is effective for business combinations with an acquisition date on or
after the beginning of annual reporting period beginning on or after December 15, 2008. The
Company adopted SFAS 141(R) on January 1, 2009 with no impact to its financial statements.
In December 2007, the FASB issued Statement of Financial Accounting Standard No. 160 as
amended, Noncontrolling Interest in Consolidated Financial Statement, (SFAS 160). The
objective of SFAS 160 is to improve the relevance, comparability, and transparency of the
financial information that a reporting entity provides in its consolidated financial
statements by establishing accounting and reporting standards for the noncontrolling
interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 is effective
for first year and interim periods within the fiscal year, beginning on or after December
15, 2008. The Company adopted SFAS 160 on January 1, 2009 with no impact to its financial
statements.
15
Effective January 1, 2009, the Company adopted Statement of Financial Accounting Standard
No. 161, Disclosures about Derivative Instruments and Hedging Activities an amendment
of SFAS Statement No. 133 (SFAS 161). SFAS 161 changes the disclosure requirements for
derivative instruments and hedging activities. Under SFAS 161, entities are required to
provide enhanced disclosures about (a) how and why an entity uses
derivative instruments, (b) how derivative instruments and related hedged items are
accounted for under SFAS 133 and its related interpretations, and (c) how derivative
instruments and related hedged items affect an entitys financial position, financial
performance, and cash flows. SFAS No. 161 must be applied prospectively to all derivative
instruments and non-derivative instruments that are designated and qualify as hedging
instruments and related hedged items accounted for under SFAS No 133 for all financial
statements issued for fiscal years and interim periods beginning after November 15, 2008,
with early application encouraged. The Company adopted SFAS No. 161 on January 1, 2009 and
has added certain additional disclosures to its financial statements.
In December 2008, the SEC unanimously approved amendments to revise its oil and gas
reserves estimation and disclosure requirements. The amendments, among other things;
|
|
|
allows the use of new technologies to determine proved reserves; |
|
|
|
|
permits the optional disclosure of probable and possible reserves; |
|
|
|
|
modifies the prices used to estimate reserves for SEC disclosure purposed to a
12 month average price instead of a period-end price; and |
|
|
|
|
requires that if a third party is primarily responsible for preparing or
auditing the reserve estimates, the company make disclosures relating to the
independence and qualifications of the third party, including filing as an
exhibit any report received from the third party. |
The revised rules are effective January 1, 2010. The new requirements have no
impact on the Companys 2009 interim financial statements, but the requirements will be
effective for the Companys year-end 2009 financial statements and its 2009 Annual Report on
Form 10-K for the year ended December 31, 2009.
In June 2008, FASB issued FASB Staff Position No. EITF 03-6-1, Determining Whether
Instruments Granted in Share-Based Payment Transactions Are Participating Securities. This
FASB Staff Position (FSP) addresses whether instruments granted in share-based payment
transactions are participating securities prior to vesting and, therefore, need to be
included in the earnings allocation in computing earnings per share under the two-class
method described in FASB Statement No. 128, Earning per Share. The Company adopted this
FSP on January 1, 2009 with no impact to its financial statements.
In May 2008, the FASB issued FASB Staff Position No. APB 14-1, Accounting for Convertible
Debt Instruments that may not be settled in cash upon conversion (including partial cash
settlement). This clarifies that convertible debt instruments that may be settled in cash
upon conversion (including partial cash settlement) are not addressed by APB Opinion No. 14,
Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants. Additionally,
this FSP specifies that issuers of such instruments should separately account for the
liability and equity components in a manner that will reflect the entitys nonconvertible
debt borrowing rate when interest cost is recognized in subsequent periods. The Company
adopted this FSP on January 1, 2009 with no impact to its financial statements.
16
In May 2009, the FASB issued Statement of Financial Accounting Standard No. 165, Subsequent
Events (SFAS 165). The objective of SFAS 165 is to establish general standards of
accounting for and disclosures of events that occur after the balance sheet date but before
financial statements are issued or are available to be issued. SFAS 165 is effective for
interim and annual financial periods ending after June 15, 2009.
Accordingly, the Company adopted SFAS as of the quarter ended June 30, 2009 with limited
impact to its financial statements. The Company has evaluated subsequent events through
August 10, 2009
In April 2009, the FASB issued FASB Staff Position No. FAS 141 (R)-1, Accounting for Assets
Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies
(FSP 141R). FSP 141R amends and clarifies SFAS 141R to address application issues raised
by preparers, auditors, and members of the legal profession on initial recognition and
measurement, subsequent measurement and accounting, and disclosure of assets and liabilities
arising from contingencies in a business combination. FSP 141R is effective for assets and
liabilities arising from contingencies in business combinations for which the acquisition
date is on or after the beginning of the fires annual reporting period beginning on or after
December 15, 2008. Accordingly, the Company adopted FSP 141R as of the quarter ended June
30, 2009 with no impact to the Companys financial statements.
In April 2009, the FASB issued FASB Staff Position No. FAS 107-1 and APB 28-1, Interim
Disclosures about Fair Value of Financial Instruments. This FASB Staff Position amends
FASB Statement of Financial Accounting Standard No. 107, Disclosures about Fair Value of
Financial Instruments, to require disclosures about fair value of financial instruments for
interim reporting periods of publicly traded companies as well as in annual financial
statements. This FASB Staff Position also amends APB Opinion No. 28, Interim Financial
Reporting, to require those disclosures in summarized financial information at interim
reporting periods. Accordingly, the Company adopted this FASB Staff Position as of the
quarter ended June 30, 2009 with limited impact to the Companys financial statements.
17
|
|
|
Item 2. |
|
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS |
Forward-Looking Statements
This report includes 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. All statements
other than statements of historical facts included in this report, including statements regarding
our financial position, adequacy of resources, estimated reserve quantities, business strategies,
plans, objectives and expectations for future operations and covenant compliance, are
forward-looking statements. We can give no assurances that the assumptions upon which such
forward-looking statements are based will prove to have been correct. Important factors that could
cause actual results to differ materially from our expectations (Cautionary Statements) are
disclosed in the section entitled Risk Factors included in our Annual Report on Form 10-K for our
most recent fiscal year, elsewhere in this report and from time to time in other filings made by us
with the Securities and Exchange Commission. All subsequent written and oral forward-looking
statements attributable to us or persons acting on our behalf are expressly qualified by the
Cautionary Statements.
General
The following discussion is intended to assist in an understanding of our financial condition and
results of operations. Our consolidated financial statements and notes thereto contain detailed
information that should be referred to in conjunction with the following discussion. See Item 8
Financial Statements and Supplementary Data.
We have been engaged in the exploration, development, acquisition and production of oil and gas
properties since 1950. In the past several years, our activities have been focused in the shelf and
deepwater areas of the Gulf of Mexico. Production from wells in this area is characterized by high
initial production rates and steep decline curves. Accordingly, we are required to make material
expenditures to purchase proved oil and gas reserves and to explore for and discover reserves to
replace those produced.
Disruptions in Capital Markets. The capital markets are experiencing significant disruptions, and
many financial institutions have liquidity concerns, prompting government intervention to mitigate
pressure on the credit markets. Our primary exposure to the current credit market crisis includes
our senior secured credit facility, 9.75% senior notes due December 2010 and counterparty
nonperformance risks.
Our senior secured credit facility was committed in the amount of $70 million as of December 31,
2008. Subsequent to December 31, 2008, our borrowing base redetermination was completed and reduced
to $48 million due to lower commodity prices and reserves. In addition, a Monthly Commitment
Reduction (MCR) was implemented commencing June 1, 2009 in the amount of $4.33 million per month.
As of August 1, 2009, we received a preliminary notice that
our redetermined borrowing base would be approximately
$35.0 million with the MCR increasing to approximately
$4.7 million.
If not extended, the senior secured credit facility matures
in September 25, 2012. Should current credit market tightening be prolonged for several years,
future extensions of our senior secured credit facility may contain terms that are less favorable
than those of our current credit facility. The amounts which may be outstanding under our senior
secured credit facility are limited by a borrowing base, which is established by our lenders and
based on the value of our proved reserves using prices, costs and
18
other assumptions determined by our lenders. Continued disruptions in the capital markets could
cause our lenders to be more restrictive in calculating our borrowing base. See Note 4 to the
Consolidated Financial Statements.
We have outstanding $200 million of 9.75% senior notes due in December 2010. We are actively
evaluating several options for a restructuring of our balance sheet and are hopeful to achieve
resolution before our 9.75% senior notes become a current liability in December 2009. No
assurances can be made as to the results of these efforts. Continued disruptions in the capital
markets could make it more difficult or expensive to refinance or restructure these notes when they
come due.
Current market conditions also elevate the concern over counterparty risks related to our commodity
derivative contracts and trade credit. At June 30, 2009, our open commodity derivative instruments
were in a net receivable position with a fair value of $7.0 million. All of our commodity
derivative instruments are with a major financial institution. Should the financial counterparty
not perform, we may not realize the benefit of some of our derivative instruments under lower
commodity prices and we could incur a loss.
We sell our production to a variety of purchasers. Some of these parties may experience liquidity
problems. Credit enhancements have been obtained from some parties in the way of parental
guarantees or letters of credit; however, we do not have all of our trade credit enhanced through
guarantees or credit support.
Impairment of Oil and Gas Properties. If oil and gas prices decrease further or remain depressed
for extended periods of time, we may be required to take additional writedowns of the carrying
value of our oil and gas properties. We may be required to writedown the carrying value of our oil
and gas properties when oil and gas prices are low or if we have substantial downward adjustments
to our estimated net proved reserves, increases in our estimates of development costs or
deterioration in our exploration results. Under the full-cost method which we use to account for
our oil and gas properties, the net capitalized costs of our oil and gas properties may not exceed
the present value, discounted at 10%, of future net cash flows from estimated net proved reserves,
using period end oil and gas prices or prices as of the date of our auditors report, plus the
lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil
and gas properties exceed this limit, we must charge the amount of the excess to earnings. This
type of charge will not affect our cash flows, but will reduce the book value of our stockholders
equity. We review the carrying value of our properties quarterly, based on prices in effect as of
the end of each quarter or at the time of reporting our results. Once incurred, a writedown of oil
and gas properties is not reversible at a later date, even if prices increase.
19
Reduced Prices for Oil and Gas Production. The United States and world economies are currently in a
recession which could last through 2009 and perhaps longer. Both oil and gas prices have undergone
significant decline during the second half of 2008 and into 2009 as a result of the reduced
economic activity brought on by the recession. Continued lower commodity prices will reduce our
cash flows from operations. To mitigate the impact of lower commodity prices on our cash flows, we
have entered into crude oil and natural gas commodity derivative contracts for 2009. See Note 5 to
our Consolidated Financial Statements. Depending on the length of the current recession, commodity
prices may stay depressed or decline further, thereby causing a prolonged downturn, which would
further reduce our cash flows from operations. This could cause us to alter our business plans
including reducing or delaying our exploration and development program spending and other cost
reduction initiatives.
Abandonment of the Entrada Project. In late November 2008, we and our joint working interest owner,
CIECO Entrada, decided to abandon the Entrada project. Under the terms of our agreements with CIECO Entrada, Callon
Entrada is responsible for its share of the costs to plug and abandon the Entrada project, which we
estimate to be $46 million, $23 million net to Callon Entrada. As of June 30, 2009 the wind down of
the Entrada project was substantially complete and most of the costs had been paid. In addition,
prior to abandonment of the project, CIECO Entrada failed to fund two loan requests totaling $40 million
under the Callon Entrada non-recourse credit agreement with CIECO Entrada. CIECO Entrada also failed to fund its
working interest share of a settlement payment in the amount of $7.3 million to terminate a
drilling contract for the Entrada project. Callon has paid its share of the settlement payment.
We continue to discuss with CIECO Entrada its failure to fund $40 million in loan requests and its share of
a settlement payment to terminate a drilling contract. No assurances can be made regarding the
outcome of these discussions. We do not believe that we have waived any of our rights under the
agreements with CIECO Entrada or its parent, CIECO.
The Callon Entrada Non-Recourse Credit Facility. The Callon Entrada non-recourse credit facility is
a direct obligation of Callon Entrada, an indirect, wholly-owned subsidiary of Callon Petroleum
Company. The Callon Entrada non-recourse credit facility is secured by a lien on the assets of
Callon Entrada which generally are comprised of the Entrada Field and related equipment. Neither
Callon Petroleum Company nor any other subsidiary of Callon Petroleum Company guaranteed or
otherwise agreed to pay the principal or interest payments due on the Callon Entrada non-recourse
credit facility, so such facility is non-recourse to Callon Petroleum Company and its other
subsidiaries.
On April 2, 2009, Callon Entrada received a notice from CIECO Entrada advising Callon Entrada that certain
alleged events of default occurred under the Callon Entrada non-recourse credit agreement relating
to failure to pay interest when due and the breach of various other covenants related to the
decision to abandon the Entrada project. The lenders under our senior secured credit facility have
amended the Second Amended and Restated Credit Agreement dated September 25, 2008 to state that a
default under the Callon Entrada non-recourse credit facility is not a default under their
facility. In addition, this amendment eliminates a possible cross default with regard to our 9.75%
senior notes due in December 2010. Accordingly, we do not believe that a default under the Callon
Entrada non-recourse credit agreement will have a material negative impact on our financial
position, results of operations and cash flows. See Note 1 to the Consolidated Financial
Statements.
20
Other Events
On March 16, 2009, we were notified by the New York Stock Exchange that we had fallen below one of
the NYSEs continued listing standards. We received this notification pursuant to Rule 802.01B(I)
of the NYSE Listed Company Manual because our average market capitalization has been less than $75
million over a 30-day trading period and our last reported stockholders equity was less than $75
million.
We submitted a plan with the NYSE on April 30, 2009, which demonstrated our ability to achieve
compliance with Rule 802.01B(I) within an 18 month cure period. On June 12, 2009, the NYSE
accepted the plan and our common stock will continue to be listed on the NYSE during the cure
period, subject to ongoing monitoring and our compliance with other NYSE continued listing
requirements.
Liquidity and Capital Resources
Our primary sources of capital are cash flows from operations, borrowings from financial
institutions and the sale of debt and equity securities. On June 30, 2009, we had cash and cash
equivalents of $735,000 and $38.7 million of availability under our senior secured credit
agreement. Cash provided by operating activities during the six-month period ended June 30, 2009
totaled $2.1 million, a 97% decrease when compared to the corresponding period in 2008. The
decrease in liquidity is attributable to the reduction of accounts payable during the first half of
2009, lower commodity prices and lower production rates on an equivalent basis.
On September 25, 2008, we completed a $250 million second amended and restated senior secured
credit agreement with Union Bank as issuing lender, which matures September 25, 2012. We received
preliminary notice from Union Bank that the borrowing base and MCR, which are still under review as of
August 1, 2009, are approximately $35.0 million and $4.7 million, respectively. Borrowings under the credit agreement are secured by mortgages covering our major fields excluding
Entrada. As of June 30, 2009, there was $5.0 outstanding under the agreement with $38.7 million,
subject to MCR, available for future borrowings. See Note 4 to the Consolidated Financial
Statements.
On April 1, 2009, Diamond Offshore Drilling, Inc. (Diamond) called on the outstanding letter of
credit for CIECO Energy (US) Limiteds (CIECO) share of the settlement for the termination of the
Ocean Victory drilling contract in the amount of $7.3 million. We paid our share, in the amount of
$7.3 million, in March 2009. The remaining balance of the letter of credit was cancelled on April
2, 2009 by Diamond. We continue to discuss with CIECO its failure to fund the settlement for the
termination of the drilling contract. The $7.3 million due from CIECO for their share of the
settlement for the termination of the drilling contract is recorded as a receivable as of June 30,
2009.
Due to the uncertain economic and commodity price environment, we have designed a flexible capital
spending program that will be responsive to conditions that develop during 2009. Our preliminary
base capital program, including plugging and abandonment, for 2009 is $75 million, which is
relatively flat with the 2008 budget of $71 million, excluding the Entrada project. The program
includes $50 million for the acquisition of proved oil and gas properties with development and
exploitation upside. However, depending on commodity prices and other economic conditions we
experience in 2009, this base capital program may be adjusted up or down. See Capital
Expenditures for more detail on our capital expenditure forecast for 2009.
21
We expect that the 2009 budget will be funded primarily from cash flows from operations, cash on
hand, and borrowings under our senior secured credit facility and/or other financing. We would
expect an increase in our senior secured credit facility borrowing base upon executing an
acquisition. We will evaluate the level of capital spending throughout the year based on commodity
prices, cash flows from operations and property acquisitions and divestitures.
Inflation has not had a material impact on us and is not expected to have a material impact on us
in the immediate future.
The Callon Entrada non-recourse credit facility, which has a balance of $82.4 million, is a direct
obligation of Callon Entrada, an indirect, wholly-owned subsidiary of Callon Petroleum Company.
The Callon Entrada non-recourse credit facility is secured by a lien on the stock of Callon Entrada
and the assets of Callon Entrada which generally are comprised of the Entrada Field and related
equipment. On June 1, 2009 the lease expired and reverted to the Minerals Management Service. At
June 30, 2009, there was no value included on the balance sheet for the lease or related equipment.
Neither Callon Petroleum Company nor any other subsidiary of Callon Petroleum Company guaranteed or
otherwise agreed to pay the principal or interest payments due on the Callon Entrada non-recourse
credit facility, so such facility is non-recourse to Callon Petroleum Company and its other
subsidiaries.
On April 2, 2009, Callon Entrada received a notice of default from CIECO Entrada advising Callon
Entrada that certain events of default occurred under the non-recourse credit agreement relating to
failure to pay interest when due and the breach of various other covenants related to the decision
to abandon the Entrada project. This notice of default invoked CIECOs Entrada rights under the
Callon Entrada non-recourse credit agreement to accelerate payment of the principal and interest
due. The acceleration of payment causes the principal and interest balances under the Callon
Entrada non-recourse credit agreement to be reclassified as current liabilities from long-term
liabilities under U.S. generally accepted accounting principles (GAAP). Under GAAP, we are
currently required to consolidate the financial statements and results of operations of Callon
Entrada which results in Callon Entradas non-recourse liability being reflected in a separate line
item in the consolidated financial statements. See Note 1 to the Consolidated Financial Statements
for more information regarding the deficiency in assets of Callon Entrada with which to repay the
non-recourse credit facility.
The Indenture governing our 9.75% Senior Notes due 2010 and our senior secured credit facility
contain various covenants, including restrictions on additional indebtedness and payment of cash
dividends. In addition, our senior secured credit agreement contains covenants for maintenance of
certain financial ratios. We were in compliance with these covenants at June 30, 2009. See Note 7
of the Consolidated Financial Statements for the year ended December 31, 2008 included in our
Annual Report on Form 10-K filed March 19, 2009 for a more detailed discussion of long-term debt.
22
The following table describes our outstanding contractual obligations (in thousands) as of June 30,
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contractual |
|
|
|
|
|
Less Than |
|
|
One-Three |
|
|
Four-Five |
|
|
After-Five |
|
Obligations |
|
Total |
|
|
One Year |
|
|
Years |
|
|
Years |
|
|
Years |
|
Senior Secured Credit Facility |
|
$ |
5,000 |
|
|
$ |
|
|
|
$ |
5,000 |
|
|
$ |
|
|
|
$ |
|
|
9.75% Senior Notes |
|
|
200,000 |
|
|
|
|
|
|
|
200,000 |
|
|
|
|
|
|
|
|
|
Throughput Commitments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Medusa Oil Pipeline |
|
|
188 |
|
|
|
56 |
|
|
|
81 |
|
|
|
31 |
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
205,188 |
|
|
$ |
56 |
|
|
$ |
205,081 |
|
|
$ |
31 |
|
|
$ |
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
Capital expenditures on an accrual basis
were $7.7 million for the six-months ended June 30, 2009.
Included in this amount was capitalized interest of approximately
$1.7 million and capitalized
general and administrative costs allocable directly to exploration and development projects of
approximately $4.4 million. The remainder of the capital expended primarily includes the cost of
seismic data, leases and plugging and abandonment costs.
Capital expenditures for the remainder of 2009 are
projected to be $60.5 million and include:
|
|
|
proved producing property acquisitions; |
|
|
|
|
development costs on our legacy properties; |
|
|
|
|
the cost of seismic data and leases; and |
|
|
|
|
capitalized interest and general and administrative costs. |
In addition, we are projecting to spend $6.8 million for the remainder of 2009 for asset retirement
obligations.
Off-Balance Sheet Arrangements
We have a 10% ownership interest in Medusa Spar LLC (LLC), which is a limited liability company
that owns a 75% undivided ownership interest in the deepwater Spar production facilities on our
Medusa Field in the Gulf of Mexico. We contributed a 15% undivided ownership interest in the
production facility to the LLC in return for approximately $25 million in cash and a 10% ownership
interest in the LLC. The LLC earns a tariff based upon production volume throughput from the
Medusa area. We are obligated to process our share of production from the Medusa Field and any
future discoveries in the area through the Spar production facilities. This arrangement allowed us
to defer the cost of the Spar production facility over the life of the Medusa Field. The balance of
Medusa Spar LLC is owned by Oceaneering International, Inc. and Murphy Oil Corporation. We are
accounting for our 10% ownership interest in the LLC under the equity method.
23
Results of Operations
The following table sets forth certain unaudited operating information with respect to the
Companys oil and gas operations for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Net production : |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
263 |
|
|
|
286 |
|
|
|
526 |
|
|
|
575 |
|
Gas (MMcf) |
|
|
1,433 |
|
|
|
1,668 |
|
|
|
2,880 |
|
|
|
3,759 |
|
Total production (MMcfe) |
|
|
3,010 |
|
|
|
3,382 |
|
|
|
6,036 |
|
|
|
7,211 |
|
Average daily production (MMcfe) |
|
|
33.1 |
|
|
|
37.2 |
|
|
|
33.3 |
|
|
|
39.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) (a) |
|
$ |
72.22 |
|
|
$ |
99.99 |
|
|
$ |
66.39 |
|
|
$ |
93.27 |
|
Gas (Mcf) |
|
|
4.22 |
|
|
|
11.67 |
|
|
|
5.18 |
|
|
|
10.46 |
|
Total (Mcfe) |
|
|
8.32 |
|
|
|
14.20 |
|
|
|
8.26 |
|
|
|
12.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue |
|
$ |
18,971 |
|
|
$ |
28,554 |
|
|
$ |
34,923 |
|
|
$ |
53,650 |
|
Gas revenue |
|
|
6,054 |
|
|
|
19,475 |
|
|
|
14,917 |
|
|
|
39,339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
25,025 |
|
|
$ |
48,029 |
|
|
$ |
49,840 |
|
|
$ |
92,989 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
4,656 |
|
|
$ |
4,870 |
|
|
$ |
8,695 |
|
|
$ |
10,048 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional per Mcfe data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales price |
|
$ |
8.32 |
|
|
$ |
14.20 |
|
|
$ |
8.26 |
|
|
$ |
12.90 |
|
Lease operating expense |
|
|
1.55 |
|
|
|
1.44 |
|
|
|
1.44 |
|
|
|
1.39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin |
|
$ |
6.77 |
|
|
$ |
12.76 |
|
|
$ |
6.82 |
|
|
$ |
11.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization |
|
$ |
2.81 |
|
|
$ |
4.50 |
|
|
$ |
2.96 |
|
|
$ |
4.19 |
|
General and
administrative (net of management fees) |
|
$ |
1.79 |
|
|
$ |
0.87 |
|
|
$ |
1.19 |
|
|
$ |
0.78 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per
barrel of oil: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average NYMEX oil price |
|
$ |
59.62 |
|
|
$ |
123.98 |
|
|
$ |
51.35 |
|
|
$ |
110.94 |
|
Basis differential and quality adjustments |
|
|
(3.30 |
) |
|
|
(4.06 |
) |
|
|
(3.68 |
) |
|
|
(3.95 |
) |
Transportation |
|
|
(1.36 |
) |
|
|
(1.34 |
) |
|
|
(1.35 |
) |
|
|
(1.30 |
) |
Hedging |
|
|
17.26 |
|
|
|
(18.59 |
) |
|
|
20.07 |
|
|
|
(12.42 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized oil price |
|
$ |
72.22 |
|
|
$ |
99.99 |
|
|
$ |
66.39 |
|
|
$ |
93.27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
Comparison of Results of Operations for the Three Months Ended June 30, 2009 and the Three
Months Ended June 30, 2008.
Oil and Gas Production and Revenues
Total oil and gas revenues were $25.0 million in the second quarter of 2009 compared to $48.0
million in the second quarter of 2008. Total production on an equivalent basis for the second
quarter of 2009 decreased by 12% compared to the second quarter of 2008 and oil and gas prices on a
Mcfe basis for the second quarter of 2009 decreased 41% compared to 2008.
Gas production during the second quarter of 2009 totaled 1.4 billion cubic feet (Bcf) and generated
$6.1 million in revenues compared to 1.7 Bcf and $19.5 million in revenues during the same period
in 2008. The average gas price after hedging impact for the second quarter of 2009 was $4.22 per
thousand cubic feet of natural gas (Mcf) compared to $11.67 per Mcf for the same period in 2008.
Approximately 14% of the 15% decrease in 2009 production was due to a lower number of producing
wells, with the remaining 1% resulting from normal and expected declines in production from our
older properties. Four of our gas wells were shut-in during 2008 due to early water production and
are now scheduled for plugging and abandonment. In addition, our High Island Block A-540 well was
shut in during the second quarter of 2008, due to a plugged flowline, which management has
determined uneconomic to repair.
Oil production during the second quarter of 2009 totaled 263,000 barrels and generated $19.0
million in revenues compared to 286,000 barrels and $28.6 million in revenues for the same period
in 2008. The average oil price received after hedging impact in the second quarter of 2009 was
$72.22 per barrel compared to $99.99 per barrel in the second quarter of 2008. The 8% decrease in
2009 production was attributable to normal and expected declines in production and our High Island
Block A-540, described above.
Lease Operating Expenses
Lease operating expenses were $4.7 million for the three-month period ended June 30, 2009, a 4%
decrease when compared to the same period in 2008. The decrease was primarily due to a lower
number of producing wells. Four of our gas wells were shut-in during 2008 due to early water
production and are now scheduled for plugging and abandonment. In addition, our High Island Block
A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, which
management determined uneconomic to repair.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the three-month period ended June 30, 2009 and 2008
was $8.5 million and $15.2 million, respectively. The 44% decrease was due to lower production
volumes as well as a lower depletion rate resulting from the full-cost ceiling writedown which was
recorded in the fourth quarter of 2008.
Accretion Expense
Accretion expense was $795,000 and $952,000 for the three-month periods ended June 30, 2009 and
2008 and represents accretion of our asset retirement obligations. See Note 9 to the Consolidated
Financial Statements.
25
General and Administrative
General and administrative expenses, net of amounts capitalized, were $5.4 million and $2.9 million
for the three-month period ended June 30, 2009 and 2008, respectively. The 83% increase was
primary due to the $2.2 million of nonrecurring expenses for staffing reductions and retirements
which were incurred during the second quarter of 2009.
Interest Expense
Interest expense on Callon related debt obligations increased to $4.9 million during the
three-month period ended June 30, 2009, compared to $4.4 million during the three-month period
ended June 30, 2008. The increase is due to a larger outstanding loan balance for our senior
secured credit facility. See Note 4 to the Consolidated Financial Statements for details.
Callon Entrada Non- Recourse Credit Facility Interest Expense
The Callon Entrada non-recourse credit facility incurred interest expense for the three-month
periods ended June 30, 2009 and 2008 of $1.9 million and $321,000, respectively. The increase was
due to a larger outstanding loan balance for the three-month period ended June 30, 2009 and an
increase in the interest rate due to the notice of default received from CIECO on April 2, 2009.
See Note 1 to the Consolidated Financial Statements for details.
Loss on Early Extinguishment of Debt
Due to the early extinguishment of the $200 million senior revolving credit facility on April 8,
2008, Callon incurred expenses of $11.9 million consisting of $6.3 million in cash pre-payment
penalties plus a non-cash charge of $5.6 million in the second quarter of 2008 related to the
amortization expense associated with the deferred financing costs related to the credit facility.
See Note 4 to the Consolidated Financial Statements.
Income Taxes
Income tax expense was $24,000 and $2.7 million for the three-month periods ended June 30, 2009 and
2008, respectively. We established a valuation allowance of $174 million as of December 31, 2008.
We revised the valuation allowance in the second quarter of 2009 as a result of current year
ordinary income, the impact of which is included in our effective tax rate. See Note 8 to the
Consolidated Financial Statements.
26
Comparison of Results of Operations for the Six Months Ended June 30, 2009 and the Six Months
Ended June 30, 2008.
Oil and Gas Production and Revenues
Total oil and gas revenues were $49.8 million in the first six-months of 2009 compared to $93.0
million in the same period in 2008. Total production on an equivalent basis during the six-month
period ended June 30, 2009 decreased by 17% compared to the six-month period ended June 30, 2008
and oil and gas prices on a Mcfe basis for the same period of 2009 decreased 36% compared to 2008.
Gas production during the first half of 2009 totaled 2.9 billion cubic feet (Bcf) and generated
$14.9 million in revenues compared to 3.8 Bcf and $39.3 million in revenues during the same period
in 2008. The average gas price after hedging impact for the six-month period ended June 30, 2009
was $5.18 per Mcf compared to $10.46 per Mcf for the same period in 2008. Approximately 21% of the
24% decrease in 2009 production was due to a lower number of producing wells, with the remaining 3%
resulting from normal and expected declines in production from our older properties. Four of our
gas wells were shut-in during 2008 due to early water production and are now scheduled for plugging
and abandonment. In addition, our High Island Block A-540 well was shut in during the second
quarter of 2008, due to a plugged flowline, which management has determined uneconomic to repair.
Oil production during the six-months ended June 30, 2009 totaled 526,000 barrels and generated
$34.9 million in revenues compared to 575,000 barrels and $53.7 million in revenues for the same
period in 2008. The average oil price received after hedging impact for the six-month period ended
June 30, 2009 was $66.39 per barrel compared to $93.27 per barrel during the same period in 2008.
The 9% decrease in 2009 production was attributable to normal and expected declines in production
and our High Island Block A-540, described above.
Lease Operating Expenses
Lease operating expenses were $8.7 million for the six-month period ended June 30, 2009, a 13%
decrease when compared to the same period in 2008. The decrease was primarily due to a lower
number of producing wells. Four of our gas wells were shut-in during 2008 due to early water
production and are now scheduled for plugging and abandonment. In addition, our High Island Block
A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, which
management determined uneconomic to repair.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the six-month period ended June 30, 2009 and 2008 was
$17.9 million and $30.2 million, respectively. The 41% decrease was due to lower production
volumes as well as a lower depletion rate resulting from the full-cost ceiling writedown which was
recorded in the fourth quarter of 2008.
Accretion Expense
Accretion expense was $1.8 million and $2.0 million for the six-month periods ended June 30, 2009
and 2008 and represents accretion of our asset retirement obligations. See Note 9 to the
Consolidated Financial Statements.
General and Administrative
General and administrative expenses, net of amounts capitalized, were $7.2 million and $5.6 million
for the six-month period ended June 30, 2009 and 2008, respectively. The 29% increase was
27
primarily due to the $2.2 million of nonrecurring expenses for staffing reductions and
retirements. The increase was slightly offset by the adjustment recorded in the first quarter for
75% of the incentive compensation pool which was not awarded, due to current industry conditions
and its impact on our recent performance.
Interest Expense
Interest expense due to Callon related debt obligations decreased to $9.6 million during the
six-month period ended June 30, 2009, compared to $14.4 million during the six-month period ended
June 30, 2008. The 33% decrease was due to the retirement in April 2008 of the $200 million senior
revolving credit facility associated with the Entrada acquisition. See Note 4 to the Consolidated
Financial Statements for details.
Callon Entrada Non- Recourse Credit Facility Interest Expense
Callon Entrada non-recourse credit facility incurred interest expense for the six-month periods
ended June 30, 2009 and 2008 of $3.5 million and $321,000, respectively. The increase was due to a
larger outstanding loan balance for the six-month period ended June 30, 2009 and an increase in the
interest rate due to the notice of default received from CIECO on April 2, 2009. See Note 1 to the
Consolidated Financial Statements for details.
Loss on Early Extinguishment of Debt
Due to the early extinguishment of the $200 million senior revolving credit facility on April 8,
2008, Callon incurred expenses of $11.9 million consisting of $6.3 million in cash pre-payment
penalties plus a non-cash charge of $5.6 million in the second quarter of 2008 related to the
amortization expense associated with the deferred financing costs related to the credit facility.
See Note 4 to the Consolidated Financial Statements.
Income Taxes
Income tax expense was zero and $6.8 million for the six-month periods ended June 30, 2009 and
2008, respectively. We established a valuation allowance of $174 million as of December 31, 2008.
We revised the valuation allowance in the second half of 2009 as a result of current year ordinary
income, the impact of which is included in our effective tax rate. See Note 8 to the Consolidated
Financial Statements.
28
|
|
|
Item 3. |
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Commodity Price Risk
The Companys revenues are derived from the sale of its crude oil and natural gas production. The
prices for oil and gas remain extremely volatile and sometimes experience large fluctuations as a
result of relatively small changes in supply, weather conditions, economic conditions and
government actions. From time to time, the Company enters into derivative financial instruments to
manage oil and gas price risk.
The Company may utilize fixed price swaps, which reduce the Companys exposure to decreases in
commodity prices and limit the benefit the Company might otherwise have received from any increases
in commodity prices.
The Company may utilize price collars to reduce the risk of changes in oil and gas prices. Under
these arrangements, no payments are due by either party as long as the market price is above the
floor price and below the ceiling price set in the collar. If the price falls below the floor, the
counter-party to the collar pays the difference to the Company, and if the price rises above the
ceiling, the counter-party receives the difference from the Company.
Callon may purchase puts which reduce the Companys exposure to decreases in oil and gas prices
while allowing realization of the full benefit from any increases in oil and gas prices. If the
price falls below the floor, the counter-party pays the difference to the Company.
The Company enters into these various agreements from time to time to reduce the effects of
volatile oil and gas prices and does not enter into derivative transactions for speculative
purposes. However, certain of the Companys derivative positions may not be designated as hedges
for accounting purposes.
See Note 5 to the Consolidated Financial Statements for a description of the Companys outstanding
derivative contracts at June 30, 2009.
|
|
|
Item 4. |
|
CONTROLS AND PROCEDURES |
Evaluation of Disclosure Controls and Procedures. Disclosure controls and procedures
include, without limitation, controls and procedures designed to ensure that information required
to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange
Act of 1934, as amended, is accumulated and communicated to the issuers management, including its
principal executive and principal financial officers, or persons performing similar functions, as
appropriate to allow timely decisions regarding required disclosure. The Companys principal
executive and principal financial officers have concluded that the Companys disclosure controls
and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of
1934 (the Exchange Act)) were effective as of June 30, 2009.
There were no changes in the Companys internal control over financial reporting that occurred
during the Companys last fiscal quarter that have materially affected, or are reasonably likely to
materially affect, the Companys internal control over financial reporting.
29
CALLON PETROLEUM COMPANY
PART II. OTHER INFORMATION
Item 1A. RISK FACTORS
There have been no material changes from the Risk Factors disclosed in Item 1. of our Annual Report
on Form 10-K for the year ended December 31, 2008.
Item 6. EXHIBITS
Exhibits
|
3. |
|
Articles of Incorporation and By-Laws |
|
3.1 |
|
Certificate of Incorporation of the Company, as amended (incorporated by reference from Exhibit 3.1 of the
Companys Annual Report on Form 10-K for the year ended
December 31, 2003 filed March 15, 2004, File No. 001-14039) |
|
|
3.2 |
|
Bylaws of the Company (incorporated by
reference from Exhibit 3.2 of the Companys Registration
Statement on Form S-4, filed August 4, 1994, Reg. No.
33-82408) |
|
4. |
|
Instruments defining the rights of security holders,
including indentures |
|
4.1 |
|
Specimen Common Stock Certificate
(incorporated by reference from Exhibit 4.1 of the Companys
Registration Statement on Form S-4, filed August 4, 1994,
Reg. No. 33-82408) |
|
|
4.2 |
|
Rights Agreement between Callon Petroleum
Company and American Stock Transfer & Trust Company, Rights
Agent, dated March 30, 2000 (incorporated by reference from
Exhibit 99.1 of the Companys Registration Statement on Form
8-A, filed April 6, 2000, File No. 001- 14039) |
|
|
4.3 |
|
Form of Warrant entitling certain holders
of the Companys 10.125% Senior Subordinated Notes due 2002
to purchase common stock from the Company (incorporated by
reference to Exhibit 4.13 of the Companys Form 10-Q for the
period ended June 30, 2002, File No. 001-14039) |
|
|
4.4 |
|
Form of Warrants dated December 8, 2003
and December 29, 2003 entitling lenders under the Companys
$185 million amended and restated Senior Unsecured Credit
Agreement, dated December 23, 2003, to purchase common stock
from the Company (incorporated by reference to Exhibit 4.14
of the Companys Annual Report on Form 10- |
30
|
|
|
K for the year
ended December 31, 2003, File No. 001-14039) |
|
|
4.5 |
|
Indenture for the Companys 9.75% Senior
Notes due 2010, dated March 15, 2004, between Callon
Petroleum Company and American Stock Transfer & Trust Company
(incorporated by reference to Exhibit 4.16 of the Companys
Quarterly Report on Form 10-Q for the period ended March 31,
2004, File No. 001-14039) |
|
|
4.6 |
|
Supplemental Indenture dated April 4,
2008 (incorporated by reference to Exhibit 10.1 of the
Companys Report on Form 8-K filed on April 9, 2008) |
|
10.1 |
|
Callon Petroleum Company Nonqualified
Stock Option Award Agreement, dated June 1, 2009, between
Callon Petroleum Company and Steven B. Hinchman |
|
|
10.2 |
|
Callon Petroleum Company Performance
Share Award Agreement, dated June 1, 2009, between Callon
Petroleum Company and Steven B. Hinchman |
|
31.1 |
|
Certification of Chief Executive Officer
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
|
|
31.2 |
|
Certification of Chief Financial Officer
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
|
32. |
|
Section 1350 Certifications |
|
32.1 |
|
Certification of Chief Executive Officer
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
32.2 |
|
Certification of Chief Financial Officer
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
31
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.
|
|
|
|
|
|
CALLON PETROLEUM COMPANY
|
|
Date: August 10, 2009 |
By: |
/s/ B.F. Weatherly
|
|
|
|
B.F. Weatherly, Executive Vice-President |
|
|
|
and Chief Financial Officer |
|
32
Exhibit Index
|
|
|
Exhibit Number
|
|
Title of Document |
|
|
|
|
3. |
|
Articles of Incorporation and By-Laws |
|
3.1 |
|
Certificate of Incorporation of the Company, as amended
(incorporated by reference from Exhibit 3.1 of the
Companys Annual Report on Form 10-K for the year ended
December 31, 2003 filed March 15, 2004, File No. 001-14039) |
|
|
3.2 |
|
Bylaws of the Company (incorporated by
reference from Exhibit 3.2 of the Companys Registration
Statement on Form S-4, filed August 4, 1994, Reg. No.
33-82408) |
|
4. |
|
Instruments defining the rights of security holders,
including indentures |
|
4.1 |
|
Specimen Common Stock Certificate
(incorporated by reference from Exhibit 4.1 of the Companys
Registration Statement on Form S-4, filed August 4, 1994,
Reg. No. 33-82408) |
|
|
4.2 |
|
Rights Agreement between Callon Petroleum
Company and American Stock Transfer & Trust Company, Rights
Agent, dated March 30, 2000 (incorporated by reference from
Exhibit 99.1 of the Companys Registration Statement on Form
8-A, filed April 6, 2000, File No. 001- 14039) |
|
|
4.3 |
|
Form of Warrant entitling certain holders
of the Companys 10.125% Senior Subordinated Notes due 2002
to purchase common stock from the Company (incorporated by
reference to Exhibit 4.13 of the Companys Form 10-Q for the
period ended June 30, 2002, File No. 001-14039) |
|
|
4.4 |
|
Form of Warrants dated December 8, 2003
and December 29, 2003 entitling lenders under the Companys
$185 million amended and restated Senior Unsecured Credit
Agreement, dated December 23, 2003, to purchase common stock
from the Company (incorporated by reference to Exhibit 4.14
of the Companys Annual Report on Form 10-K for the year
ended December 31, 2003, File No. 001-14039) |
|
|
4.5 |
|
Indenture for the Companys 9.75% Senior
Notes due 2010, dated March 15, 2004, between Callon
Petroleum Company |
33
|
|
|
and American Stock Transfer & Trust Company
(incorporated by reference to Exhibit 4.16 of the Companys
Quarterly Report on Form 10-Q for the period ended March 31,
2004, File No. 001-14039) |
|
|
4.6 |
|
Supplemental Indenture dated April 4,
2008 (incorporated by reference to Exhibit 10.1 of the
Companys Report on Form 8-K filed on April 9, 2008) |
|
10.1 |
|
Callon Petroleum Company Nonqualified
Stock Option Award Agreement, dated June 1, 2009, between
Callon Petroleum Company and Steven B. Hinchman |
|
|
10.2 |
|
Callon Petroleum Company Performance
Share Award Agreement, dated June 1, 2009, between Callon
Petroleum Company and Steven B. Hinchman |
|
31.1 |
|
Certification of Chief Executive Officer
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
|
|
31.2 |
|
Certification of Chief Financial Officer
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
|
32. |
|
Section 1350 Certifications |
|
32.1 |
|
Certification of Chief Executive Officer
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
32.2 |
|
Certification of Chief Financial Officer
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
34