e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2009
or
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 1-33615
Concho Resources Inc.
(Exact name of registrant as specified in its charter)
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Delaware
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76-0818600 |
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(State or other jurisdiction
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(I.R.S. Employer |
of incorporation or organization)
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Identification No.) |
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550 West Texas Avenue, Suite 100 |
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Midland, Texas
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79701 |
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(Address of principal executive offices)
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(Zip code) |
(432) 683-7443
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant 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 (§232.405 of this chapter) 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 the definitions of large
accelerated filer, accelerated filer, and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
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Large accelerated filer þ |
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Accelerated filer o |
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Non-accelerated filer o (Do not check if a smaller reporting company) |
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Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
Number of shares of the registrants common stock outstanding at August 3, 2009: 85,521,179 shares.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This report may contain forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 (the Securities Act) and Section 21E of the Securities Exchange Act of
1934 (the Exchange Act) that are subject to a number of risks and uncertainties, many of which
are beyond our control. All statements, other than statements of historical fact included in this
report, regarding our strategy, future operations, financial position, estimated revenues and
losses, projected costs, prospects, plans and objectives of management are forward-looking
statements. When used in this report, the words could, believe, anticipate, intend,
estimate, expect, may, continue, predict, potential, project and similar expressions
are intended to identify forward-looking statements, although not all forward-looking statements
contain such identifying words. In particular, the factors discussed below and in our Annual Report
on Form 10-K for the year ended December 31, 2008 and our Quarterly Report on Form 10-Q for the
quarter ended March 31, 2009, could affect our actual results and cause our actual results to
differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or
implied in such forward-looking statements.
Forward-looking statements may include statements about:
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our business and financial strategy; |
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the estimated quantities of oil and natural gas reserves; |
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our use of industry technology; |
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our realized oil and natural gas prices; |
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the timing and amount of the future production of our oil and natural
gas; |
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the amount, nature and timing of our capital expenditures; |
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the drilling of our wells; |
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our competition and government regulations; |
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the marketing of our oil and natural gas; |
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our exploitation activities or property acquisitions; |
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the costs of exploiting and developing our properties and conducting
other operations; |
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general economic and business conditions; |
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our cash flow and anticipated liquidity; |
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uncertainty regarding our future operating results; |
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our plans, objectives, expectations and intentions contained in this
report that are not historical; and |
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our ability to integrate acquisitions. |
You should not place undue reliance on these forward-looking statements. All forward-looking
statements speak only as of the date of this report. We do not undertake any obligation to release
publicly any revisions to any forward-looking statements to reflect events or circumstances after
the date of this report or to reflect the occurrence of unanticipated events, except as required by
law.
Although we believe that our plans, objectives, expectations and intentions reflected in or
suggested by the forward-looking statements we make in this report are reasonable, we can give no
assurance that they will be achieved. These cautionary statements qualify all forward-looking
statements attributable to us or persons acting on our behalf.
ii
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PART I FINANCIAL INFORMATION |
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Item 1. Consolidated Financial Statements (Unaudited) |
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1 |
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2 |
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3 |
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4 |
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5 |
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iii
Concho Resources Inc.
Consolidated Balance Sheets
Unaudited
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June 30, |
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December 31, |
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(in thousands, except share and per share data) |
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2009 |
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2008 |
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Assets
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Current assets: |
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Cash and cash equivalents |
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$ |
3,081 |
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$ |
17,752 |
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Accounts receivable, net of allowance for doubtful accounts: |
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Oil and natural gas |
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58,430 |
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48,793 |
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Joint operations and other |
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73,992 |
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92,833 |
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Related parties |
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174 |
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314 |
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Derivative instruments |
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26,272 |
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113,149 |
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Prepaid costs and other |
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5,330 |
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5,942 |
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Total current assets |
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167,279 |
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278,783 |
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Property and equipment, at cost: |
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Oil and natural gas properties, successful efforts method |
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2,885,275 |
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2,693,574 |
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Accumulated depletion |
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(413,252 |
) |
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(306,990 |
) |
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Total oil and natural gas properties, net |
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2,472,023 |
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2,386,584 |
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Other property and equipment, net |
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15,143 |
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14,820 |
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Total property and equipment, net |
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2,487,166 |
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2,401,404 |
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Deferred loan costs, net |
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13,988 |
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15,701 |
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Inventory |
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27,158 |
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19,956 |
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Intangible asset, net operating rights |
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37,319 |
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37,768 |
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Noncurrent derivative instruments |
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31,438 |
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61,157 |
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Other assets |
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451 |
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434 |
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Total assets |
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$ |
2,764,799 |
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$ |
2,815,203 |
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Liabilities and Stockholders Equity
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Current liabilities: |
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Accounts payable: |
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Trade |
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$ |
15,837 |
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$ |
7,462 |
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Related parties |
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1,352 |
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312 |
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Other current liabilities: |
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Bank overdrafts |
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2,628 |
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9,434 |
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Revenue payable |
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31,262 |
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22,286 |
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Accrued and prepaid drilling costs |
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111,172 |
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154,196 |
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Derivative instruments |
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15,731 |
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1,866 |
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Deferred income taxes |
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3,300 |
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37,205 |
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Other current liabilities |
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38,149 |
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38,057 |
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Total current liabilities |
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219,431 |
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270,818 |
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Long-term debt |
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660,000 |
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630,000 |
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Noncurrent derivative instruments |
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17,656 |
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Deferred income taxes |
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565,217 |
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573,763 |
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Asset retirement obligations and other long-term liabilities |
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12,940 |
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15,468 |
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Commitments and contingencies (Note K)
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Stockholders equity: |
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Common stock, $0.001 par value; 300,000,000 authorized; 85,529,591 and 84,828,824
shares issued at June 30, 2009 and December 31, 2008, respectively |
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86 |
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85 |
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Additional paid-in capital |
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1,020,060 |
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1,009,025 |
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Retained earnings |
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269,726 |
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316,169 |
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Treasury stock, at cost; 9,341 and 3,142 shares at June 30, 2009 and December 31, 2008,
respectively |
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(317 |
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(125 |
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Total stockholders equity |
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1,289,555 |
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1,325,154 |
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Total liabilities and stockholders equity |
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$ |
2,764,799 |
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$ |
2,815,203 |
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The accompanying notes are an integral part of these consolidated financial statements.
1
Concho Resources Inc.
Consolidated Statements of Operations
Unaudited
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Three Months Ended June 30, |
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Six Months Ended June 30, |
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(in thousands, except per share amounts) |
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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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$ |
101,511 |
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$ |
95,408 |
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$ |
166,485 |
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$ |
171,226 |
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Natural gas sales |
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25,821 |
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41,975 |
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46,849 |
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72,868 |
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Total operating revenues |
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127,332 |
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137,383 |
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213,334 |
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244,094 |
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Operating costs and expenses: |
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Oil and natural gas production |
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25,817 |
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21,979 |
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50,583 |
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38,874 |
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Exploration and abandonments |
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1,424 |
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723 |
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7,419 |
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3,464 |
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Depreciation, depletion and amortization |
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52,402 |
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22,010 |
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103,150 |
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43,294 |
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Accretion of discount on asset retirement obligations |
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301 |
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148 |
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579 |
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301 |
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Impairments of long-lived assets |
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4,499 |
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53 |
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8,555 |
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69 |
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General and administrative (including non-cash stock-based
compensation of $2,188 and $1,730 for the three months ended
June 30, 2009 and 2008, respectively, and $4,113 and $3,029 for
the six months ended June 30, 2009 and 2008, respectively) |
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14,172 |
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8,586 |
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25,918 |
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16,266 |
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Bad debt expense |
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1,799 |
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1,799 |
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Ineffective portion of cash flow hedges |
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(356 |
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(920 |
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Loss on derivatives not designated as hedges |
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81,606 |
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102,456 |
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86,652 |
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119,634 |
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Total operating costs and expenses |
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180,221 |
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157,398 |
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282,856 |
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222,781 |
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Income (loss) from operations |
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(52,889 |
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(20,015 |
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(69,522 |
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21,313 |
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Other income (expense): |
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Interest expense |
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(6,200 |
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(3,885 |
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(10,570 |
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(9,500 |
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Other, net |
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180 |
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311 |
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(148 |
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1,331 |
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Total other expense |
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(6,020 |
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(3,574 |
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(10,718 |
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(8,169 |
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Income (loss) before income taxes |
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(58,909 |
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(23,589 |
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(80,240 |
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13,144 |
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Income tax (expense) benefit |
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25,691 |
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9,169 |
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33,797 |
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(5,199 |
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Net income (loss) |
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$ |
(33,218 |
) |
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$ |
(14,420 |
) |
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$ |
(46,443 |
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$ |
7,945 |
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Basic earnings per share: |
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Net income (loss) per share |
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$ |
(0.39 |
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$ |
(0.19 |
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$ |
(0.55 |
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$ |
0.11 |
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Weighted average shares used in basic earnings per share |
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84,799 |
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75,665 |
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84,665 |
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75,569 |
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Diluted earnings per share: |
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Net income (loss) per share |
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$ |
(0.39 |
) |
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$ |
(0.19 |
) |
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$ |
(0.55 |
) |
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$ |
0.10 |
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Weighted average shares used in diluted earnings per share |
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84,799 |
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75,665 |
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84,665 |
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|
77,034 |
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The accompanying notes are an integral part of these consolidated financial statements.
2
Concho Resources Inc.
Consolidated Statement of Stockholders Equity
Unaudited
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Additional |
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Total |
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Common Stock |
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Paid-in |
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Retained |
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Treasury Stock |
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Stockholders |
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(in thousands) |
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Shares |
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Amount |
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Capital |
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Earnings |
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Shares |
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Amount |
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Equity |
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BALANCE AT DECEMBER 31, 2008 |
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84,829 |
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$ |
85 |
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$ |
1,009,025 |
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$ |
316,169 |
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3 |
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$ |
(125 |
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$ |
1,325,154 |
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Net loss |
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(46,443 |
) |
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(46,443 |
) |
Stock options exercised |
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446 |
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1 |
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3,930 |
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3,931 |
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Stock-based compensation for restricted stock |
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257 |
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2,200 |
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2,200 |
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Cancellation of restricted stock |
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(2 |
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Stock-based compensation for stock options |
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1,913 |
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1,913 |
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Excess tax benefits related to stock-based compensation
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2,992 |
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2,992 |
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Purchase of treasury stock |
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6 |
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(192 |
) |
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(192 |
) |
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BALANCE AT JUNE 30, 2009 |
|
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85,530 |
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|
$ |
86 |
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|
$ |
1,020,060 |
|
|
$ |
269,726 |
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9 |
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$ |
(317 |
) |
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$ |
1,289,555 |
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The accompanying notes are an integral part of these consolidated financial statements.
3
Concho Resources Inc.
Consolidated Statements of Cash Flows
Unaudited
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(46,443 |
) |
|
$ |
7,945 |
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
103,150 |
|
|
|
43,294 |
|
Impairments of long-lived assets |
|
|
8,555 |
|
|
|
69 |
|
Accretion of discount on asset retirement obligations |
|
|
579 |
|
|
|
301 |
|
Exploration expense, including dry holes |
|
|
6,294 |
|
|
|
1,147 |
|
Non-cash compensation expense |
|
|
4,113 |
|
|
|
3,029 |
|
Bad debt expense |
|
|
|
|
|
|
1,799 |
|
Deferred income taxes |
|
|
(39,799 |
) |
|
|
4,504 |
|
(Gain) loss on sale of assets |
|
|
191 |
|
|
|
(777 |
) |
Ineffective portion of cash flow hedges |
|
|
|
|
|
|
(920 |
) |
Loss on derivatives not designated as hedges |
|
|
86,652 |
|
|
|
119,634 |
|
Dedesignated cash flow hedges reclassified from accumulated other comprehensive income |
|
|
|
|
|
|
222 |
|
Other non-cash items |
|
|
1,686 |
|
|
|
558 |
|
Changes in operating assets and liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(18,401 |
) |
|
|
(12,003 |
) |
Prepaid costs and other |
|
|
612 |
|
|
|
793 |
|
Inventory |
|
|
(6,786 |
) |
|
|
(7,243 |
) |
Accounts payable |
|
|
9,415 |
|
|
|
(10,209 |
) |
Revenue payable |
|
|
8,976 |
|
|
|
7,718 |
|
Other current liabilities |
|
|
(562 |
) |
|
|
3,087 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
118,232 |
|
|
|
162,948 |
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Capital expenditures on oil and natural gas properties |
|
|
(223,283 |
) |
|
|
(122,757 |
) |
Additions to other property and equipment |
|
|
(2,014 |
) |
|
|
(4,017 |
) |
Proceeds from the sale of oil and natural gas properties and other assets |
|
|
1,004 |
|
|
|
1,034 |
|
Settlements received (paid) on derivatives not designated as hedges |
|
|
61,465 |
|
|
|
(16,387 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(162,828 |
) |
|
|
(142,127 |
) |
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt |
|
|
211,650 |
|
|
|
13,000 |
|
Payments of long-term debt |
|
|
(181,650 |
) |
|
|
(39,500 |
) |
Exercise of stock options |
|
|
3,931 |
|
|
|
2,373 |
|
Excess tax benefit from stock-based compensation |
|
|
2,992 |
|
|
|
2,146 |
|
Proceeds from repayment of employee notes |
|
|
|
|
|
|
333 |
|
Payments for loan origination costs |
|
|
|
|
|
|
(1,001 |
) |
Purchase of treasury stock |
|
|
(192 |
) |
|
|
(125 |
) |
Bank overdrafts |
|
|
(6,806 |
) |
|
|
3,245 |
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
29,925 |
|
|
|
(19,529 |
) |
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
(14,671 |
) |
|
|
1,292 |
|
Cash and cash equivalents at beginning of period |
|
|
17,752 |
|
|
|
30,424 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
3,081 |
|
|
$ |
31,716 |
|
|
|
|
|
|
|
|
SUPPLEMENTAL CASH FLOWS: |
|
|
|
|
|
|
|
|
Cash paid for interest and fees, net of $18 and $840 capitalized interest |
|
$ |
6,911 |
|
|
$ |
9,918 |
|
Cash paid for income taxes |
|
$ |
4,232 |
|
|
$ |
650 |
|
The accompanying notes are an integral part of these consolidated financial statements.
4
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
Note A. Organization and nature of operations
Concho Resources Inc. (the Company) is a Delaware corporation formed on February 22, 2006.
The Companys principal business is the acquisition, development, exploitation and exploration of
oil and natural gas properties in the Permian Basin region of Southeastern New Mexico and West
Texas.
Note B. Summary of significant accounting policies
Principles of consolidation. The consolidated financial statements of the Company include the
accounts of the Company and its wholly-owned subsidiaries. All material intercompany balances and
transactions have been eliminated.
Use of estimates in the preparation of financial statements. Preparation of financial
statements in conformity with generally accepted accounting principles in the United States of
America requires management to make estimates and assumptions that affect the reported amounts of
assets and liabilities, the disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during the reporting
periods. Actual results could differ from these estimates. Depletion of oil and natural gas
properties are determined using estimates of proved oil and natural gas reserves. There are
numerous uncertainties inherent in the estimation of quantities of proved reserves and in the
projection of future rates of production and the timing of development expenditures. Similarly,
evaluations for impairment of proved and unproved oil and natural gas properties are subject to
numerous uncertainties including, among others, estimates of future recoverable reserves and
commodity price outlooks. Other significant estimates include, but are not limited to, asset
retirement obligations, fair value of derivative financial instruments, purchase price allocations
for business and oil and natural gas property acquisitions and fair value of stock-based
compensation.
Interim financial statements. The accompanying consolidated financial statements of the
Company have not been audited by the Companys independent registered public accounting firm,
except that the consolidated balance sheet at December 31, 2008 is derived from audited
consolidated financial statements. In the opinion of management, the accompanying consolidated
financial statements reflect all adjustments necessary to present fairly the Companys financial
position at June 30, 2009, its results of operations for the three and six months ended June 30,
2009 and 2008, and its cash flows for the six months ended June 30, 2009 and 2008. All such
adjustments are of a normal recurring nature. In preparing the accompanying consolidated financial
statements, management has made certain estimates and assumptions that affect reported amounts in
the consolidated financial statements and disclosures of contingencies. Actual results may differ
from those estimates. The results for interim periods are not necessarily indicative of annual
results.
Certain disclosures have been condensed or omitted from these consolidated financial
statements. Accordingly, these consolidated financial statements should be read with the audited
consolidated financial statements and notes thereto included in the Companys Annual Report on Form
10-K for the year ended December 31, 2008.
Deferred loan costs. Deferred loan costs are stated at cost, net of amortization, which is
computed using the effective interest and straight-line methods. The Company had deferred loan
costs of $14.0 million and $15.7 million, net of accumulated amortization of $6.6 million and $4.9
million, at June 30, 2009 and December 31, 2008, respectively.
5
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
Future amortization expense of deferred loan costs at June 30, 2009 is as follows:
|
|
|
|
|
(in thousands) |
|
Total |
|
|
Remaining 2009 |
|
$ |
1,713 |
|
2010 |
|
|
3,426 |
|
2011 |
|
|
3,426 |
|
2012 |
|
|
3,426 |
|
2013 |
|
|
1,997 |
|
|
|
|
|
Total |
|
$ |
13,988 |
|
|
|
|
|
Intangible assets. The Company has capitalized certain operating rights acquired in an
acquisition, see Note D. The gross operating rights of approximately $38.7 million, which have no
residual value, are amortized over the estimated economic life of approximately 25 years.
Impairment will be assessed if indicators of potential impairment exist or when there is a material
change in the remaining useful economic life. Amortization expense for the three and six months
ended June 30, 2009 was approximately $0.4 million and $0.8 million, respectively. The following
table reflects the estimated aggregate amortization expense at June 30, 2009 for each of the
periods presented below:
|
|
|
|
|
(in thousands) |
|
Total |
|
|
Remaining 2009 |
|
$ |
775 |
|
2010 |
|
|
1,550 |
|
2011 |
|
|
1,550 |
|
2012 |
|
|
1,550 |
|
2013 |
|
|
1,550 |
|
Thereafter |
|
|
30,344 |
|
|
|
|
|
Total |
|
$ |
37,319 |
|
|
|
|
|
Oil and natural gas sales and imbalances. Oil and natural gas revenues are recorded at the
time of delivery of such products to pipelines for the account of the purchaser or at the time of
physical transfer of such products to the purchaser. The Company follows the sales method of
accounting for oil and natural gas sales, recognizing revenues based on the Companys share of
actual proceeds from the oil and natural gas sold to purchasers. Oil and natural gas imbalances are
generated on properties for which two or more owners have the right to take production in-kind
and, in doing so, take more or less than their respective entitled percentage. Imbalances are
tracked by well, but the Company does not record any receivable from or payable to the other owners
unless the imbalance has reached a level at which it exceeds the remaining reserves in the
respective well. If reserves are insufficient to offset the imbalance and the Company is in an
overtake position, a liability is recorded for the amount of shortfall in reserves valued at a
contract price or the market price in effect at the time the imbalance is generated. If the Company
is in an undertake position, a receivable is recorded for an amount that is reasonably expected to
be received, not to exceed the current market value of such imbalance.
6
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
The following table reflects the Companys natural gas imbalance positions at June 30, 2009
and December 31, 2008 as well as amounts reflected in oil and natural gas production expense for
the three and six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
(dollars in thousands) |
|
2009 |
|
2008 |
|
|
|
Natural gas imbalance receivable (included in other assets) |
|
$ |
423 |
|
|
$ |
406 |
|
Undertake position (Mcf) |
|
|
(94,102 |
) |
|
|
(90,321 |
) |
|
|
|
|
|
|
|
|
|
Natural gas imbalance liability (included in asset retirement
obligations and other long-term liabilities) |
|
$ |
449 |
|
|
$ |
472 |
|
Overtake position (Mcf) |
|
|
79,408 |
|
|
|
85,698 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
|
|
|
|
Value of net overtake (undertake) arising during the period
(increasing (reducing) oil and natural gas production expense) |
|
$ |
9 |
|
|
$ |
(133 |
) |
|
$ |
(40 |
) |
|
$ |
(137 |
) |
Net overtake (undertake) position arising during the period (Mcf) |
|
|
1,697 |
|
|
|
(9,117 |
) |
|
|
(10,069 |
) |
|
|
(8,103 |
) |
Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of
treasury shares held is reduced by the average purchase price per share of the aggregate treasury
shares held.
General and administrative expense. The Company receives fees for the operation of jointly
owned oil and natural gas properties and records such reimbursements as reductions of general and
administrative expense. Such fees totaled approximately $2.8 million and $0.3 million for the
three months ended June 30, 2009 and 2008, respectively, and $5.4 million and $0.5 million for the
six months ended June 30, 2009 and 2008, respectively.
Reclassifications. Certain prior period amounts have been reclassified to conform to the 2009
presentation. These reclassifications had no impact on net income (loss), total stockholders
equity or cash flows.
Recent accounting pronouncements. In December 2007, the Financial Accounting Standards Board
(FASB) issued SFAS No. 141(R), Business Combinations (SFAS No. 141(R)), which replaces FASB
Statement No. 141. SFAS No. 141(R) establishes principles and requirements for how an acquirer
recognizes and measures in its financial statements the identifiable assets acquired, the
liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired.
SFAS No. 141(R) also establishes disclosure requirements that will enable users to evaluate the
nature and financial effects of the business combination. SFAS No. 141(R) is effective for
acquisitions that occur in an entitys fiscal year that begins after December 15, 2008. The Company
adopted SFAS No. 141(R) effective January 1, 2009. There has been no impact on the Companys
consolidated financial statements, as it has not entered into any significant business combinations
during 2009.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements an amendment of ARB No. 51 (SFAS No. 160). SFAS No. 160 requires that
accounting and reporting for minority interests will be recharacterized as noncontrolling interests
and classified as a component of equity. SFAS No. 160 also establishes reporting requirements that
provide sufficient disclosures that clearly identify and distinguish between the interests of the
parent and the interests of the noncontrolling owners. SFAS No. 160 applies to all entities that
prepare consolidated financial statements, except not-for-profit organizations, but will affect
only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or
that deconsolidate a subsidiary. This statement is effective as of the beginning of an entitys
first fiscal year beginning after December 15, 2008. The Company adopted SFAS No. 160 effective
January 1, 2009, with no impact on the Companys consolidated financial statements.
7
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities (SFAS No. 161), which amends and expands the interim and annual disclosure
requirements of SFAS No. 133 to provide an enhanced understanding of an entitys use of derivative
instruments, how they are accounted for under SFAS No. 133 and their effect on the entitys
financial position, financial performance and cash flows. The provisions of SFAS No. 161 are
effective as of January 1, 2009. The Company adopted SFAS No. 161 effective January 1, 2009, with
no significant impact on the Companys consolidated financial statements, other than additional
disclosures which are set forth below in Notes H and I.
In April 2008, the FASB issued FASB Staff Position (FSP) No. SFAS 142-3, Determination of
the Useful Life of Intangible Assets (FSP SFAS No. 142-3). FSP SFAS No. 142-3 amends the factors
that should be considered in developing renewal or extension assumptions used to determine the
useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible
Assets (SFAS No. 142). The intent of FSP SFAS No. 142-3 is to improve the consistency between
the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash
flows used to measure the fair value of the asset under SFAS No. 141R and other applicable
accounting literature. FSP SFAS No. 142-3 is effective for financial statements issued for fiscal
years beginning after December 15, 2008 and must be applied prospectively to intangible assets
acquired after the effective date. The Company adopted FSP SFAS No. 142-3 effective January 1,
2009, with no significant impact on the Companys consolidated financial statements.
In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting
Principles (SFAS No. 162), which identifies the sources of accounting principles and the
framework for selecting the principles used in the preparation of financial
statements of nongovernmental entities that are presented in conformity with generally
accepted accounting principles (GAAP) in the United States of America. SFAS No. 162 arranges
these sources of GAAP in a hierarchy for users to apply accordingly. This statement became
effective for the Company on November 15, 2008. The adoption of SFAS No. 162 did not have a
significant impact on the Companys consolidated financial statements. In June 2009, this statement
was replaced with SFAS No. 168, The FASB Accounting Standards Codification (Codification) and
the Hierarchy of Generally Accepted Accounting Principles (SFAS No. 168). Once the Codification
is in effect, all of its content will carry the same level of authority, effectively superseding
SFAS No. 162. In other words, the GAAP hierarchy will be modified to include only two levels of
GAAP: authoritative and non authoritative. SFAS No. 168 is effective for financial statements
issued for interim and annual periods ending after September 15, 2009. The Company does not expect
the adoption of SFAS No. 168 to have an impact on its consolidated financial statements.
In June 2008, the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments Granted in
Share-Based Payment Transactions Are Participating Securities, (FSP EITF 03-6-1) which provides
that unvested share-based payment awards that contain non-forfeitable rights to dividends or
dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to
be included in the earnings allocation in computing earnings per share under the two class method.
FSP EITF 03-6-1 was effective for the Company on January 1, 2009. There was no impact on the
Companys consolidated financial statements.
In April 2009, the FASB issued FSP SFAS No. 141(R)-1, Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination That Arise from Contingencies. This FSP amends and
clarifies SFAS No. 141(R) 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. This FSP is effective for assets or liabilities arising from contingencies in
business combinations for which the acquisition date is on or after the beginning of the first
annual reporting period beginning on or after December 15, 2008. The Company has not made any
acquisitions during 2009, and as such, the adoption of this statement on January 1, 2009 did not
have a significant impact.
In April 2009, the FASB issued FSP SFAS No. 107-1 and APB Opinion No. 28-1, Interim
Disclosures about Fair Value of Financial Instrument (FSP SFAS No. 107-1). This FSP amends FASB
Statement 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 FSP also amends APB Opinion No. 28,
Interim Financial Reporting, to require those disclosures in summarized financial information at
interim reporting periods. This FSP is effective for interim reporting periods ending after June
15, 2009. This FSP does not require disclosures for earlier periods presented for comparative
purposes at initial adoption. In periods after initial adoption, this FSP requires comparative
disclosures only for periods ending after initial adoption. As of June 15, 2009, the Company
adopted the provisions of FSP SFAS No. 107-1 related to the fair value of financial
8
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
instruments.
The adoption of the provisions of FSP SFAS No. 107-1 did not have a material effect on the
financial condition or results of operations of the Company. See Note H for additional disclosures
required by FSP SFAS No. 107-1.
In April 2009, the FASB issued FSP SFAS No. 157-4, Determining Fair Value When the Volume and
Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying
Transactions That Are Not Orderly (FSP SFAS No. 157-4). This FSP:
|
|
|
Affirms that the objective of fair value when the market for an asset is not active
is the price that would be received to sell the asset in an orderly transaction; |
|
|
|
|
Clarifies and includes additional factors for determining whether there has been a
significant decrease in market activity for an asset when the market for that asset is
not active; |
|
|
|
|
Eliminates the proposed presumption that all transactions are distressed (not
orderly) unless proven otherwise. The FSP instead requires an entity to base its
conclusion about whether a transaction was not orderly on the weight of the evidence; |
|
|
|
|
Includes an example that provides additional explanation on estimating fair value
when the market activity for an asset has declined significantly; |
|
|
|
|
Requires an entity to disclose a change in valuation technique (and the related
inputs) resulting from the application of the FSP and to quantify its effects, if
practicable; and |
|
|
|
|
Applies to all fair value measurements when appropriate. |
FSP SFAS No. 157-4 must be applied prospectively and retrospective application is not
permitted. FSP SFAS No. 157-4 is effective for interim and annual periods ending after June 15,
2009. As of June 15, 2009, the Company adopted the provisions of FSP
SFAS No. 157-4 related to assets and liabilities that are measured at fair value on a
recurring and nonrecurring basis. The adoption of the provisions of FSP SFAS No. 157-4 did not
have a material effect on the financial condition or results of operations of the Company. See
Note H for additional information regarding the Companys adoption of FSP SFAS No. 157-4.
In May 2009, the FASB issued SFAS No. 165, Subsequent Events (SFAS No. 165) which
establishes general standards of accounting for and disclosure of events that occur after the
balance sheet date, but before financial statements are issued or are available to be issued. In
particular, SFAS No. 165 sets forth:
|
|
|
The period after the balance sheet date during which management of a reporting entity
should evaluate events or transactions that may occur for potential recognition or
disclosure in the financial statements; |
|
|
|
|
The circumstances under which a reporting entity should recognize events or
transactions occurring after the balance sheet date in its financial statements; and |
|
|
|
|
The disclosures that a reporting entity should make about events or transactions that
occurred after the balance sheet date. |
In accordance with this Statement, a reporting entity should apply the requirements to interim
or annual financial periods ending after June 15, 2009. See Note P.
In June 2009, the FASB issued SFAS No. 166, Accounting for Transfers of Financial Assets
(SFAS No. 166), which amends SFAS No. 140, Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities. This statement improves the relevance, representational
faithfulness, and comparability of the information that a reporting entity provides in its
financial reports about a transfer of financial assets; the effects of a transfer on its financial
position, financial performance, and cash
9
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
flows; and a transferors continuing involvement in
transferred financial assets. SFAS No. 166 must be applied as of the beginning of a reporting
entitys first annual reporting period that begins after November 15, 2009, for interim periods
within that first annual reporting period and for interim and annual reporting periods thereafter.
Earlier application is prohibited. SFAS No. 166 must be applied to transfers occurring on or after
the effective date. The Company does not expect the adoption of SFAS No. 166 to have an impact on
its consolidated financial statements.
Recent developments in reserves reporting. In December 2008, the United States Securities and
Exchange Commission (the SEC) released Final Rule, Modernization of Oil and Gas Reporting (the
Reserve Ruling). The Reserve Ruling revises oil and gas reporting disclosures. The Reserve
Ruling permits the use of new technologies to determine proved reserves estimates if those
technologies have been demonstrated empirically to lead to reliable conclusions about reserve
volume estimates. The Reserve Ruling will also allow, but not require, companies to disclose their
probable and possible reserves to investors in documents filed with the SEC. In addition, the new
disclosure requirements require companies to: (i) report the independence and qualifications of its
reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare
reserves estimates or conduct a reserves audit; and (iii) report oil and gas reserves using an
average price based upon the prior 12-month period rather than a year-end price. The Reserve
Ruling becomes effective for fiscal years ending on or after December 31, 2009. The Company is
currently assessing the impact that adoption of the provisions of the Reserve Ruling will have on
its financial position, results of operations and disclosures.
10
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
Note C. Exploratory well costs
The Company capitalizes exploratory well costs until a determination is made that the well has
either found proved reserves or that it is impaired. The capitalized exploratory well costs are
presented in unproved properties in the consolidated balance sheets. If the exploratory well is
determined to be impaired, the well costs are charged to expense.
The following table reflects the Companys capitalized exploratory well activity during the
three and six months ended June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
(in thousands) |
|
June 30, 2009 |
|
|
June 30, 2009 |
|
|
Beginning capitalized exploratory well costs |
|
$ |
2,536 |
|
|
$ |
25,553 |
|
Additions to exploratory well costs pending the determination of proved reserves |
|
|
91,305 |
|
|
|
93,842 |
|
Reclassifications due to determination of proved reserves |
|
|
(86,537 |
) |
|
|
(111,640 |
) |
Exploratory well costs charged to expense |
|
|
|
|
|
|
(451 |
) |
|
|
|
|
|
|
|
Ending capitalized exploratory well costs |
|
$ |
7,304 |
|
|
$ |
7,304 |
|
|
|
|
|
|
|
|
The following table provides an aging, at June 30, 2009 and December 31, 2008, of capitalized
exploratory well costs based on the date drilling was completed:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Wells in drilling progress |
|
$ |
533 |
|
|
$ |
7,765 |
|
Capitalized exploratory well costs that have been capitalized for a period of one year or less |
|
|
6,771 |
|
|
|
17,788 |
|
Capitalized exploratory well costs that have been capitalized for a period greater than one year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalized exploratory well costs |
|
$ |
7,304 |
|
|
$ |
25,553 |
|
|
|
|
|
|
|
|
At June 30, 2009, the Company had seven gross exploratory wells waiting on completion and two
exploratory wells drilling, all of which were in the New Mexico Permian area.
Note D. Acquisitions
Henry Entities acquisition. On July 31, 2008, the Company closed the acquisition of Henry
Petroleum LP and certain entities affiliated with Henry Petroleum LP (the Henry Entities) and
additional non-operated interests in oil and natural gas properties from persons affiliated with
the Henry Entities. In August 2008 and September 2008, the Company acquired additional
non-operated interests in oil and natural gas properties from persons affiliated with the Henry
Entities. The assets acquired in the Henry Entities acquisition, including the additional
non-operated interests, are referred to as the Henry Properties. The Company paid $583.5 million
in cash for the Henry Properties acquisition.
The cash paid for the Henry Properties acquisition was funded with (i) borrowings under the
Companys credit facility and (ii) proceeds from a private placement of approximately 8.3 million
shares of the Companys common stock.
The Henry Properties acquisition is being accounted for using the purchase method of
accounting for business combinations. Under the purchase method of accounting, the Company recorded
the Henry Properties assets and liabilities at fair value. The
11
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
purchase price of the acquired
Henry Properties net assets is based on the total value of the cash consideration. The initial
purchase price allocation is preliminary and subject to adjustment primarily due to resolution of
certain tax matters. Any future adjustments to the allocation of the total purchase price are not
anticipated to be material to the Companys consolidated financial statements.
The following tables represent the preliminary allocation of the total purchase price of the
Henry Properties to the acquired assets and liabilities of the Henry Properties and the
consideration paid for the Henry Properties. The allocation represents the fair values assigned to
each of the assets acquired and liabilities assumed:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Fair value of Henry Properties net assets: |
|
|
|
|
Current assets, net of cash acquired of $19,049 (a) |
|
$ |
86,005 |
|
Proved oil and natural gas properties |
|
|
593,984 |
|
Unproved oil and natural gas properties |
|
|
233,492 |
|
Other long-term assets |
|
|
7,392 |
|
Intangible assets operating rights |
|
|
38,740 |
|
|
|
|
|
Total assets acquired |
|
|
959,613 |
|
|
|
|
|
|
Current liabilities |
|
|
(113,729 |
) |
Asset retirement obligations and other long-term liabilities |
|
|
(7,529 |
) |
Noncurrent derivative liabilities |
|
|
(39,037 |
) |
Deferred tax liability |
|
|
(215,815 |
) |
|
|
|
|
Total liabilities assumed |
|
|
(376,110 |
) |
|
|
|
|
|
Net purchase price |
|
$ |
583,503 |
|
|
|
|
|
|
|
|
|
|
Consideration paid for Henry Properties net assets: |
|
|
|
|
Cash consideration paid, net of cash acquired of $19,049 |
|
$ |
577,853 |
|
Acquisition costs (b) |
|
|
5,650 |
|
|
|
|
|
Total purchase price |
|
$ |
583,503 |
|
|
|
|
|
|
|
|
(a) |
|
Includes a deferred tax asset of approximately $9.0 million. |
|
(b) |
|
Acquisition costs include legal and accounting fees, advisory fees and other
acquisition-related costs. |
12
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
The following unaudited pro forma combined condensed financial data for the three and six
months ended June 30, 2008 was derived from the historical financial statements of the Company and
Henry Properties giving effect to the acquisition as if it had occurred on January 1, 2008. The
unaudited pro forma combined condensed financial data has been included for comparative purposes
only and is not necessarily indicative of the results that might have occurred had the Henry
Properties acquisition taken place as of the date indicated and is not intended to be a projection
of future results.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
Six Months Ended |
(in thousands, except per share data) |
|
June 30, 2008 |
June 30, 2008 |
|
Operating revenues |
|
$ |
185,095 |
|
|
$ |
339,519 |
|
Net income |
|
$ |
5,941 |
|
|
$ |
20,483 |
|
Earnings per common share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.07 |
|
|
$ |
0.24 |
|
Diluted |
|
$ |
0.07 |
|
|
$ |
0.24 |
|
Note E. Asset retirement obligations
The Companys asset retirement obligations represent the estimated present value of the
estimated cash flows the Company will incur to plug, abandon and remediate its producing properties
at the end of their production lives, in accordance with applicable state laws. The Company does
not provide for a market risk premium associated with asset retirement obligations because a
reliable estimate cannot be determined. The Company has no assets that are legally restricted for
purposes of settling asset retirement obligations.
The following table summarizes the Companys asset retirement obligations (ARO) recorded
during the three and six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Asset retirement obligations, beginning of period |
|
$ |
18,254 |
|
|
$ |
8,795 |
|
|
$ |
16,809 |
|
|
$ |
9,418 |
|
Liabilities incurred from new wells |
|
|
102 |
|
|
|
275 |
|
|
|
270 |
|
|
|
309 |
|
Accretion expense |
|
|
301 |
|
|
|
148 |
|
|
|
579 |
|
|
|
301 |
|
Disposition of wells sold |
|
|
|
|
|
|
|
|
|
|
(142 |
) |
|
|
|
|
Liabilities settled upon plugging and abandoning wells |
|
|
(343 |
) |
|
|
|
|
|
|
(353 |
) |
|
|
|
|
Revision of estimates |
|
|
(3,928 |
) |
|
|
1,138 |
|
|
|
(2,777 |
) |
|
|
328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, end of period |
|
$ |
14,386 |
|
|
$ |
10,356 |
|
|
$ |
14,386 |
|
|
$ |
10,356 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note F. Stockholders equity
Common stock private placement. On June 5, 2008, the Company entered into a common stock
purchase agreement with certain unaffiliated third-party investors to sell certain shares of the
Companys common stock in a private placement (the Private Placement) contemporaneous with the
closing of the Henry Properties acquisition. On July 31, 2008, the Company issued 8,302,894 shares
of its common stock at $30.11 per share. The Private Placement resulted in net proceeds of
approximately $242.4 million to the Company, after payment of approximately $7.6 million for the
fee paid to the placement agent.
13
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
Treasury stock. On June 12, 2008, the restrictions on certain restricted stock awards issued
to five of the Companys executive officers lapsed. Immediately upon the lapse of restrictions,
these executive officers became liable for certain federal income taxes on the value of such
shares. In accordance with the Companys 2006 Stock Incentive Plan and the applicable restricted
stock award agreements, four of such officers elected to deliver shares of the Companys common
stock to the Company to satisfy such tax liability, and the Company acquired 3,142 shares to be
held as treasury stock in the approximate amount of $125,000.
During the second quarter of 2009, the restrictions on certain restricted stock awards issued
to five of the Companys executive officers lapsed. Immediately upon the lapse of restrictions,
these executive officers became liable for certain federal income taxes on the value of such
shares. In accordance with the Companys 2006 Stock Incentive Plan and the applicable restricted
stock award agreements, all of such officers elected to deliver shares of the Companys common
stock to the Company to satisfy such tax liability, and the Company acquired 6,199 shares to be
held as treasury stock in the approximate amount of $192,000.
Note G. Incentive plans
Defined contribution plan. The Company sponsors a 401(k) defined contribution plan for the
benefit of all employees and maintains certain other acquired plans. The Company matches 100
percent of employee contributions, not to exceed 6 percent of the employees annual salary. The
Company contributions to the plans for the three months ended June 30, 2009 and 2008 were
approximately $0.2 million and $0.1 million, respectively, and $0.5 million and $0.3 million for
the six months ended June 30, 2009 and 2008, respectively.
Stock incentive plan. The Companys 2006 Stock Incentive Plan (together with applicable
option agreements and restricted stock agreements, the Plan) provides for granting stock options
and restricted stock awards to employees and individuals associated with the Company. The
following table shows the number of awards available under the Companys Plan at June 30, 2009:
|
|
|
|
|
|
|
Number of |
|
|
Common Shares |
|
Approved and authorized awards |
|
|
5,850,000 |
|
Stock option grants, net of forfeitures |
|
|
(3,461,485 |
) |
Restricted stock grants, net of forfeitures |
|
|
(767,787 |
) |
|
|
|
|
|
Awards available for future grant |
|
|
1,620,728 |
|
|
|
|
|
|
Restricted stock awards. All restricted shares are treated as issued and outstanding in the
accompanying consolidated balance sheets. If an employee terminates employment prior to the lapse
date, restricted shares awarded to such employee are forfeited and cancelled and are no longer
considered issued and outstanding. A summary of the Companys restricted stock awards activity for
the six months ended June 30, 2009 is presented below:
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
Grant Date |
|
|
Restricted |
|
Fair Value |
|
|
Shares |
|
Per Share |
|
Outstanding at December 31, 2008 |
|
|
407,351 |
|
|
|
|
|
Shares granted |
|
|
257,398 |
|
|
$ |
25.14 |
|
Shares cancelled / forfeited |
|
|
(2,420 |
) |
|
|
|
|
Lapse of restrictions |
|
|
(169,519 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2009 |
|
|
492,810 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
A summary of the impact on the consolidated statements of operations for the Companys
restricted stock awards during the three and six months ended June 30, 2009 and 2008 is presented
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
(in thousands) |
|
2009 |
|
2008 |
|
2009 |
2008 |
|
Stock-based compensation expense related to restricted stock |
|
$ |
1,303 |
|
|
$ |
468 |
|
|
$ |
2,200 |
|
|
$ |
862 |
|
Income tax benefit related to restricted stock |
|
$ |
586 |
|
|
$ |
187 |
|
|
$ |
927 |
|
|
$ |
341 |
|
Deductions in current taxable income related to restricted stock |
|
$ |
3,989 |
|
|
$ |
771 |
|
|
$ |
4,367 |
|
|
$ |
1,200 |
|
Stock option awards. A summary of the Companys stock option award activity under the Plan
for the six months ended June 30, 2009 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Average |
|
|
Number of |
|
Exercise |
|
|
Options |
|
Price |
|
Outstanding at December 31, 2008 |
|
|
2,731,324 |
|
|
$ |
12.46 |
|
Options granted |
|
|
117,801 |
|
|
$ |
20.40 |
|
Options exercised |
|
|
(445,789 |
) |
|
$ |
8.82 |
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2009 |
|
|
2,403,336 |
|
|
$ |
13.53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at end of period |
|
|
1,637,752 |
|
|
$ |
10.38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested and exercisable at end of period |
|
|
812,760 |
|
|
$ |
12.62 |
|
|
|
|
|
|
|
|
|
|
15
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
The following table summarizes information about the Companys vested and exercisable stock
options outstanding at June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
Remaining |
|
|
Average |
|
|
|
|
|
|
|
|
|
|
Stock |
|
|
Contractual |
|
|
Exercise |
|
|
Intrinsic |
|
|
|
|
|
|
|
Options |
|
|
Life |
|
|
Price |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
Vested options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price |
|
$ |
8.00 |
|
|
|
1,183,214 |
|
|
2.64 years |
|
$ |
8.00 |
|
|
$ |
24,481 |
|
Exercise price |
|
$ |
12.00 |
|
|
|
122,516 |
|
|
4.85 years |
|
$ |
12.00 |
|
|
|
2,045 |
|
Exercise price |
|
$ |
15.35 |
|
|
|
210,000 |
|
|
6.98 years |
|
$ |
15.35 |
|
|
|
2,800 |
|
Exercise price |
|
$ |
21.85 |
|
|
|
103,500 |
|
|
8.67 years |
|
$ |
21.85 |
|
|
|
708 |
|
Exercise price |
|
$ |
31.33 |
|
|
|
18,522 |
|
|
8.90 years |
|
$ |
31.33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,637,752 |
|
|
|
|
|
|
$ |
10.38 |
|
|
$ |
30,034 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested and exercisable options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price |
|
$ |
8.00 |
|
|
|
394,183 |
|
|
3.93 years |
|
$ |
8.00 |
|
|
$ |
8,156 |
|
Exercise price |
|
$ |
12.00 |
|
|
|
86,555 |
|
|
6.04 years |
|
$ |
12.00 |
|
|
|
1,445 |
|
Exercise price |
|
$ |
15.35 |
|
|
|
210,000 |
|
|
6.98 years |
|
$ |
15.35 |
|
|
|
2,800 |
|
Exercise price |
|
$ |
21.85 |
|
|
|
103,500 |
|
|
8.67 years |
|
$ |
21.85 |
|
|
|
708 |
|
Exercise price |
|
$ |
31.33 |
|
|
|
18,522 |
|
|
8.90 years |
|
$ |
31.33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
812,760 |
|
|
|
|
|
|
$ |
12.62 |
|
|
$ |
13,109 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
The following table summarizes information about stock-based compensation for stock options
for the three months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Grant date fair value for awards during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time vesting options |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
183 |
|
Stock option grants under the Plan |
|
|
|
|
|
|
794 |
|
|
|
1,454 |
|
|
|
5,090 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
|
|
|
$ |
794 |
|
|
$ |
1,454 |
|
|
$ |
5,273 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense from stock options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time vesting options |
|
$ |
70 |
|
|
$ |
35 |
|
|
$ |
141 |
|
|
$ |
65 |
|
Performance vesting options- Officers |
|
|
|
|
|
|
133 |
|
|
|
71 |
|
|
|
284 |
|
Stock option grants under the Plan |
|
|
815 |
|
|
|
1,094 |
|
|
|
1,701 |
|
|
|
1,818 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
885 |
|
|
$ |
1,262 |
|
|
$ |
1,913 |
|
|
$ |
2,167 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes and other information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit related to stock options |
|
$ |
415 |
|
|
$ |
504 |
|
|
$ |
806 |
|
|
$ |
858 |
|
|
Deductions in current taxable income related to stock options exercised |
|
$ |
4,117 |
|
|
$ |
3,132 |
|
|
$ |
7,157 |
|
|
$ |
5,338 |
|
In calculating compensation expense for options granted during the six months ended June 30,
2009, the Company estimated the fair value of each grant using the Black-Scholes option-pricing
model. Assumptions utilized in the model are shown below:
|
|
|
|
|
Risk-free interest rate |
|
|
2.46 |
% |
Expected term (years) |
|
|
6.25 |
|
Expected volatility |
|
|
63.40 |
% |
Expected dividend yield |
|
|
|
|
As permitted by Staff Accounting Bulletin No. 110, Share-Based Payment, the Company used the
simplified method to calculate the expected term for stock options granted during the three and six
months ended June 30, 2009, since it does not have sufficient historical exercise data to provide a
reasonable basis upon which to estimate expected term due to the limited period of time its shares
of common stock have been publicly traded. Expected volatilities are based on a combination of
historical and implied volatilities of comparable companies.
17
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
Future stock-based compensation expense. Future stock-based compensation expense at June 30,
2009 is summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted |
|
|
Stock |
|
|
|
|
(in thousands) |
|
Stock |
|
|
Options |
|
|
Total |
|
|
Remaining 2009 |
|
$ |
2,333 |
|
|
$ |
1,423 |
|
|
$ |
3,756 |
|
2010 |
|
|
3,431 |
|
|
|
1,694 |
|
|
|
5,125 |
|
2011 |
|
|
2,159 |
|
|
|
706 |
|
|
|
2,865 |
|
2012 |
|
|
643 |
|
|
|
166 |
|
|
|
809 |
|
2013 |
|
|
24 |
|
|
|
14 |
|
|
|
38 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
8,590 |
|
|
$ |
4,003 |
|
|
$ |
12,593 |
|
|
|
|
|
|
|
|
|
|
|
Note H. Disclosures about fair value of financial instruments
The Company adopted SFAS No. 157, Fair Value Measurements, (SFAS No. 157) effective
January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157
applies to all financial assets and financial liabilities that are being measured and reported on a
fair value basis. In February 2008, the FASB issued FSP No. 157-2, Effective Date of FASB Statement
No. 157, which delayed the effective date of SFAS No. 157 by one year for nonfinancial assets and
liabilities. As of January 1, 2009, the Company adopted the provisions of SFAS 157 related to the
Companys nonfinancial assets and liabilities, including nonfinancial assets and liabilities
measured at fair value in a business combination; impaired long-lived assets; and initial
recognition of asset retirement obligations. As defined in SFAS No. 157, fair value is the price
that would be received to sell an asset or paid to transfer a liability in an orderly transaction
between market participants at the measurement date. SFAS No. 157 requires disclosure that
establishes a framework for measuring fair value and expands disclosure about fair value
measurements. The statement requires fair value measurements be classified and disclosed in one of
the following categories:
|
Level 1: |
|
Unadjusted quoted prices in active markets that are accessible at the
measurement date for identical, unrestricted assets or liabilities. The Company considers
active markets to be those in which transactions for the assets or liabilities occur in
sufficient frequency and volume to provide pricing information on an ongoing basis. |
|
|
Level 2: |
|
Quoted prices in markets that are not active, or inputs which are observable,
either directly or indirectly, for substantially the full term of the asset or liability.
This category includes those derivative instruments that the Company values using
observable market data. Substantially all of these inputs are observable in the
marketplace throughout the full term of the derivative instrument, can be derived from
observable data, or supported by
observable levels at which transactions are executed in the marketplace. Level 2
instruments primarily include non-exchange traded derivatives such as over-the-counter
commodity price swaps, basis swaps, investments and interest rate swaps. The Companys
valuation models are primarily industry-standard models that consider various inputs
including: (i) quoted forward prices for commodities, (ii) time value and
(iii) current market and contractual prices for the underlying instruments, as well as
other relevant economic measures. The Company utilizes its counterparties valuations
to assess the reasonableness of its prices and valuation techniques. |
|
|
Level 3: |
|
Measured based on prices or valuation models that require inputs that are both
significant to the fair value measurement and less observable from objective sources
(i.e., supported by little or no market activity). Level 3 instruments primarily include
derivative instruments, such as commodity price collars and floors, as well as
investments. The Companys valuation models are primarily industry-standard models that
consider various inputs including: (i) quoted forward prices for commodities, (ii) time
value, (iii) volatility factors and (iv) current market and contractual prices for the
underlying instruments, as well as other relevant economic measures. Although the
Company utilizes its counterparties valuations to assess the reasonableness of our
prices and valuation techniques, the Company does not have sufficient corroborating
market evidence to support classifying these assets and liabilities as Level 2. |
18
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
The following represents information about the estimated fair values of the Companys
financial instruments:
Cash and cash equivalents, accounts receivable, other current assets, accounts payable,
interest payable and other current liabilities. The carrying amounts approximate fair value due to
the short maturity of these instruments.
Line of credit. The carrying amount of borrowings outstanding under the Companys credit
facility approximates fair value, because the instrument bears interest at variable market rates.
19
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Derivative instruments. The fair value of the Companys derivative instruments are estimated
by management considering various factors, including closing exchange and over-the-counter
quotations and the time value of the underlying commitments. As required by SFAS No. 157,
financial assets and liabilities are classified based on the lowest level of input that is
significant to the fair value measurement. The Companys assessment of the significance of a
particular input to the fair value measurement requires judgment, and may affect the valuation of
the fair value of assets and liabilities and their placement within the fair value hierarchy
levels. The following table (i) summarizes the valuation of each of the Companys financial
instruments by SFAS No. 157 pricing levels and (ii) summarizes the gross fair value by the
appropriate balance sheet classification, in accordance with SFAS No. 161, even when the derivative
instruments are subject to netting arrangements and qualify for net presentation in the Companys
consolidated balance sheets at June 30, 2009 and December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements using |
|
|
|
|
|
|
Quoted |
|
|
Significant |
|
|
|
|
|
|
Total |
|
|
|
prices |
|
|
other |
|
|
Significant |
|
|
carrying value |
|
|
|
in active |
|
|
observable |
|
|
unobservable |
|
|
at |
|
|
|
markets |
|
|
inputs |
|
|
inputs |
|
|
June 30, |
|
(in thousands) |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
2009 |
|
|
Assets (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
$ |
|
|
|
$ |
26,408 |
|
|
$ |
|
|
|
$ |
26,408 |
|
Commodity derivative basis swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivative swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
18,856 |
|
|
|
18,856 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,408 |
|
|
|
18,856 |
|
|
|
45,264 |
|
Noncurrent: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
43,604 |
|
|
|
|
|
|
|
43,604 |
|
Commodity derivative basis swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivative swap contracts |
|
|
|
|
|
|
3,541 |
|
|
|
|
|
|
|
3,541 |
|
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47,145 |
|
|
|
|
|
|
|
47,145 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
(27,650 |
) |
|
|
|
|
|
|
(27,650 |
) |
Commodity derivative basis swap contracts |
|
|
|
|
|
|
(2,456 |
) |
|
|
|
|
|
|
(2,456 |
) |
Interest rate derivative swap contracts |
|
|
|
|
|
|
(3,624 |
) |
|
|
|
|
|
|
(3,624 |
) |
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
(993 |
) |
|
|
(993 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(33,730 |
) |
|
|
(993 |
) |
|
|
(34,723 |
) |
Noncurrent: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
(29,782 |
) |
|
|
|
|
|
|
(29,782 |
) |
Commodity derivative basis swap contracts |
|
|
|
|
|
|
(1,476 |
) |
|
|
|
|
|
|
(1,476 |
) |
Interest rate derivative swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
(2,105 |
) |
|
|
(2,105 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,258 |
) |
|
|
(2,105 |
) |
|
|
(33,363 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial assets (liabilities) |
|
$ |
|
|
|
$ |
8,565 |
|
|
$ |
15,758 |
|
|
$ |
24,323 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Total current financial assets (liabilities), gross basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
10,541 |
|
(b) Total noncurrent financial assets (liabilities), gross basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,782 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial assets (liabilities) |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
24,323 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements using |
|
|
|
|
|
|
Quoted |
|
|
Significant |
|
|
|
|
|
|
Total |
|
|
|
prices |
|
|
other |
|
|
Significant |
|
|
carrying value |
|
|
|
in active |
|
|
observable |
|
|
unobservable |
|
|
at |
|
|
|
markets |
|
|
inputs |
|
|
inputs |
|
|
December 31, |
|
(in thousands) |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
2008 |
|
|
Assets (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
$ |
|
|
|
$ |
64,162 |
|
|
$ |
|
|
|
$ |
64,162 |
|
Commodity derivative basis swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivative swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
49,562 |
|
|
|
49,562 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
64,162 |
|
|
|
49,562 |
|
|
|
113,724 |
|
Noncurrent: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
60,995 |
|
|
|
|
|
|
|
60,995 |
|
Commodity derivative basis swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivative swap contracts |
|
|
|
|
|
|
678 |
|
|
|
|
|
|
|
678 |
|
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61,673 |
|
|
|
|
|
|
|
61,673 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative basis swap contracts |
|
|
|
|
|
|
(680 |
) |
|
|
|
|
|
|
(680 |
) |
Interest rate derivative swap contracts |
|
|
|
|
|
|
(1,761 |
) |
|
|
|
|
|
|
(1,761 |
) |
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,441 |
) |
|
|
|
|
|
|
(2,441 |
) |
Noncurrent: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
(516 |
) |
|
|
|
|
|
|
(516 |
) |
Commodity derivative basis swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivative swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(516 |
) |
|
|
|
|
|
|
(516 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial assets (liabilities) |
|
$ |
|
|
|
$ |
122,878 |
|
|
$ |
49,562 |
|
|
$ |
172,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Total current financial assets (liabilities), gross basis |
|
|
|
|
|
|
|
|
|
$ |
111,283 |
|
(b) Total noncurrent financial assets (liabilities), gross basis |
|
|
|
|
|
|
|
|
|
|
61,157 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial assets (liabilities) |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
172,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
|
|
|
(1) |
|
The fair value of derivative instruments reported in the Companys consolidated
balance sheets are subject to netting arrangements and qualify for net presentation. The
following table reports the net basis derivative fair values as reported in the
consolidated balance sheets at June 30, 2009 and December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Consolidated Balance Sheet Classification: |
|
|
|
|
|
|
|
|
|
Current derivative contracts: |
|
|
|
|
|
|
|
|
Assets |
|
$ |
26,272 |
|
|
$ |
113,149 |
|
Liabilities |
|
|
(15,731 |
) |
|
|
(1,866 |
) |
|
|
|
|
|
|
|
Net current |
| $ |
10,541 |
|
|
$ |
111,283 |
|
|
|
|
|
|
|
|
|
Noncurrent derivative contracts: |
|
|
|
|
|
|
|
|
Assets |
|
$ |
31,438 |
|
|
$ |
61,157 |
|
Liabilities |
|
|
(17,656 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net noncurrent |
|
$ |
13,782 |
|
|
$ |
61,157 |
|
|
|
|
|
|
|
|
The following table sets forth a reconciliation of changes in the fair value of financial
assets and liabilities classified as Level 3 in the fair value hierarchy:
|
|
|
|
|
(in thousands) |
Balance at December 31, 2008 |
|
$ |
49,562 |
|
Realized and unrealized losses |
|
|
(9,686 |
) |
Purchases, issuances, and settlements |
|
|
(24,118 |
) |
|
|
|
|
Balance at June 30, 2009 |
|
$ |
15,758 |
|
|
|
|
|
|
|
|
|
|
Total losses for the period included in
earnings attributable to the change in
unrealized losses relating to assets
still held at the reporting date |
|
$ |
(33,804 |
) |
|
|
|
|
For additional information on the Companys derivative instruments see Note I.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a nonrecurring basis in the
Companys consolidated balance sheets. The following methods and assumptions were used to estimate
the fair values:
Impairments of long-lived assets In accordance with SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets, the Company reviews its long-lived assets to be held
and used, including proved oil and gas properties, whenever events or circumstances indicate that
the carrying value of those assets may not be recoverable. An impairment loss is indicated if the
sum of the expected future cash flows is less than the carrying amount of the assets. In this
circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount
of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and gas
properties by amortization base or by individual well for those wells not constituting part of an
amortization base. For each property determined to be impaired, an impairment loss equal to the
difference between the carrying value of the properties and the estimated fair value (discounted
future cash flows) of the properties would be recognized at that time. Estimating future cash flows
involves the use of judgments, including estimation of the proved and unproved oil and gas reserve
quantities, timing of development and production, expected future commodity prices, capital
expenditures and production costs.
22
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
The Company periodically reviews its proved oil and gas properties that are sensitive to
oil and natural gas prices for impairment. Due to downward adjustments to the economically
recoverable resource potential associated with declines in commodity prices and well performance,
the Company recognized impairment expense of $4.5 million and $8.6 million for the three and six
months ended June 30, 2009, respectively, related to its proved oil and gas properties. For the
three months ended June 30, 2009, the impaired assets, which had a total carrying amount of $7.3
million, were reduced to their estimated fair value of $2.8 million. For the six months ended June
30, 2009, the impaired assets, which had a total carrying amount of $14.2 million, were reduced to
their estimated fair value of $5.6 million.
Asset Retirement Obligations The Company estimates the fair value of AROs based on
discounted cash flow projections using numerous estimates, assumptions and judgments regarding such
factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the
credit-adjusted risk-free rate to be used; and inflation rates. See Note E for a summary of changes
in AROs.
Measurement information for assets that are measured at fair value on a nonrecurring basis was
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements using |
|
|
Quoted |
|
Significant |
|
|
|
|
|
|
prices |
|
other |
|
Significant |
|
|
|
|
in active |
|
observable |
|
unobservable |
|
Total |
|
|
markets |
|
inputs |
|
inputs |
|
Impairment |
(in thousands) |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
Loss |
|
Three months ended June 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
2,733 |
|
|
$ |
(4,499 |
) |
Asset retirement obligations
incurred in current period |
|
|
|
|
|
|
|
|
|
|
102 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
7 |
|
|
$ |
(53 |
) |
Asset retirement obligations
incurred in current period |
|
|
|
|
|
|
|
|
|
|
275 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
5,620 |
|
|
$ |
(8,555 |
) |
Asset retirement obligations
incurred in current period |
|
|
|
|
|
|
|
|
|
|
270 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
7 |
|
|
$ |
(69 |
) |
Asset retirement obligations
incurred in current period |
|
|
|
|
|
|
|
|
|
|
309 |
|
|
|
|
|
23
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
Note I. Derivative financial instruments
The Company uses derivative financial contracts to manage exposures to commodity price and
interest rate fluctuations. Commodity hedges are used to (i) reduce the effect of the volatility of
price changes on the natural gas and oil the Company produces and sells, (ii) support the Companys
capital budget and expenditure plans and (iii) support the economics associated with acquisitions.
Interest rate hedges are used to mitigate the cash flow risk associated with rising interest rates.
The Company does not enter into derivative financial instruments for speculative or trading
purposes. The Company also may enter into physical delivery contracts to effectively provide
commodity price hedges. Because these contracts are not expected to be net cash settled, they are
considered to be normal sales contracts and not derivatives. Therefore, these contracts are not
recorded in the Companys consolidated financial statements.
Currently, the Company does not designate its derivative instruments to qualify for hedge
accounting. Accordingly, the Company reflects changes in the fair value of its derivative
instruments in its statements of operations. All of the Companys remaining hedges that
historically qualified for hedge accounting or were dedesignated from hedge accounting were settled
in 2008.
24
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
New commodity derivatives contracts in 2009. During the six months ended June 30, 2009, the
Company entered into additional commodity derivative contracts to hedge a portion of its estimated
future production. The following table summarizes information about these additional commodity
derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
Index |
|
Contract |
|
|
Volume |
|
Price |
|
Period |
|
Oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
Price collar |
|
|
600,000 |
|
|
$ |
45.00 $49.00 |
(a)(d) |
|
3/1/09 5/31/09 |
Price swap |
|
|
270,000 |
|
|
$ |
69.50 |
(a) |
|
7/1/09 9/30/09 |
Price swap |
|
|
540,000 |
|
|
$ |
51.62 |
(a) (d) |
|
7/1/09 12/31/09 |
Price swap |
|
|
150,000 |
|
|
$ |
69.50 |
(a) |
|
10/1/09 12/31/09 |
Price swap |
|
|
2,508,000 |
|
|
$ |
62.15 |
(a) (d) |
|
1/1/10 12/31/10 |
Price swap |
|
|
1,800,000 |
|
|
$ |
72.17 |
(a) (d) |
|
1/1/11 12/31/11 |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus): |
|
|
|
|
|
|
|
|
|
|
Price collar |
|
|
1,500,000 |
|
|
$ |
5.00 $5.81 |
(b) |
|
10/1/09 12/31/09 |
Price collar |
|
|
1,500,000 |
|
|
$ |
5.00 $5.81 |
(b) |
|
1/1/10 3/31/10 |
Price collar |
|
|
3,000,000 |
|
|
$ |
5.25 $5.75 |
(b) |
|
4/1/10 9/30/10 |
Price collar |
|
|
1,500,000 |
|
|
$ |
6.00 $6.80 |
(b) |
|
10/1/10 12/31/10 |
Price collar |
|
|
1,500,000 |
|
|
$ |
6.00 $6.80 |
(b) |
|
1/1/11 3/31/11 |
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
3,000,000 |
|
|
$ |
4.31 |
(b) |
|
4/1/09 9/30/09 |
Price swap |
|
|
600,000 |
|
|
$ |
4.66 |
(b) |
|
7/1/09 9/30/09 |
Price swap |
|
|
450,000 |
|
|
$ |
4.66 |
(b) |
|
10/1/09 12/31/09 |
Price swap |
|
|
2,400,000 |
|
|
$ |
6.31 |
(b) |
|
1/1/10 12/31/10 |
Price swap |
|
|
300,000 |
|
|
$ |
7.29 |
(b) |
|
1/1/11 3/31/11 |
Price swap |
|
|
5,400,000 |
|
|
$ |
6.96 |
(b) (d) |
|
4/1/11 12/31/11 |
|
|
|
|
|
|
|
|
|
|
|
Basis swap |
|
|
600,000 |
|
|
$ |
0.79 |
(c) |
|
7/1/09 9/30/09 |
Basis swap |
|
|
450,000 |
|
|
$ |
0.89 |
(c) |
|
10/1/09 12/31/09 |
Basis swap |
|
|
8,400,000 |
|
|
$ |
0.85 |
(c) (d) |
|
1/1/10 12/31/10 |
Basis swap |
|
|
1,800,000 |
|
|
$ |
0.87 |
(c) (d) |
|
1/1/11 3/31/11 |
Basis swap |
|
|
5,400,000 |
|
|
$ |
0.76 |
(c) |
|
4/1/11 12/31/11 |
|
|
|
(a) |
|
The index prices for the oil price swaps and collars are based on the NYMEX-West Texas Intermediate monthly average futures price. |
|
(b) |
|
The index prices for the natural gas price swaps and collars are based on the NYMEX-Henry Hub last trading day futures price. |
|
(c) |
|
The basis differential between the El Paso Permian delivery point and NYMEX Henry Hub delivery point. |
|
(d) |
|
Prices represent weighted average prices. |
25
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
In July 2009, the Company entered into the following oil price swaps to hedge an
additional portion of its estimated oil production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
Index |
|
Contract |
|
|
Volume |
|
Price |
|
Period |
|
Oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
273,000 |
|
|
$ |
67.50 |
(a) |
|
8/1/09 - 12/31/09 |
Price swap |
|
|
799,000 |
|
|
$ |
67.50 |
(a) |
|
1/1/10 - 12/31/10 |
Price swap |
|
|
801,000 |
|
|
$ |
70.53 |
(a) (b) |
|
1/1/11 - 12/31/11 |
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate monthly average futures price. |
|
(b) |
|
Prices represent weighted average prices. |
26
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
Commodity derivative contracts at June 30, 2009. The following table sets forth the
Companys outstanding commodity derivative contracts at June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
Total |
|
Oil Swaps: (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
|
|
|
|
|
|
|
|
995,473 |
|
|
|
875,473 |
|
|
|
1,870,946 |
|
Price per Bbl (e) |
|
|
|
|
|
|
|
|
|
$ |
72.71 |
|
|
$ |
73.15 |
|
|
$ |
72.92 |
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
787,436 |
|
|
|
787,436 |
|
|
|
787,436 |
|
|
|
787,436 |
|
|
|
3,149,744 |
|
Price per Bbl (e) |
|
$ |
68.49 |
|
|
$ |
68.49 |
|
|
$ |
68.49 |
|
|
$ |
68.49 |
|
|
$ |
68.49 |
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
589,436 |
|
|
|
589,436 |
|
|
|
589,436 |
|
|
|
589,436 |
|
|
|
2,357,744 |
|
Price per Bbl (e) |
|
$ |
79.91 |
|
|
$ |
79.91 |
|
|
$ |
79.91 |
|
|
$ |
79.91 |
|
|
$ |
79.91 |
|
2012: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
126,000 |
|
|
|
126,000 |
|
|
|
126,000 |
|
|
|
126,000 |
|
|
|
504,000 |
|
Price per Bbl |
|
$ |
127.80 |
|
|
$ |
127.80 |
|
|
$ |
127.80 |
|
|
$ |
127.80 |
|
|
$ |
127.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Collars: (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
|
|
|
|
|
|
|
|
192,000 |
|
|
|
192,000 |
|
|
|
384,000 |
|
Price per Bbl |
|
|
|
|
|
|
|
|
|
$ |
120.00 - $134.60 |
|
|
$ |
120.00 - $134.60 |
|
|
$ |
120.00 - $134.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
|
|
|
|
460,000 |
|
|
|
460,000 |
|
|
|
920,000 |
|
Price per MMBtu |
|
|
|
|
|
|
|
|
|
$ |
8.44 |
|
|
$ |
8.44 |
|
|
$ |
8.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps: (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
|
|
|
|
2,100,000 |
|
|
|
450,000 |
|
|
|
2,550,000 |
|
Price per MMBtu |
|
|
|
|
|
|
|
|
|
$ |
4.41 |
|
|
$ |
4.66 |
|
|
$ |
4.45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
600,000 |
|
|
|
600,000 |
|
|
|
600,000 |
|
|
|
600,000 |
|
|
|
2,400,000 |
|
Price per MMBtu |
|
$ |
6.31 |
|
|
$ |
6.31 |
|
|
$ |
6.31 |
|
|
$ |
6.31 |
|
|
$ |
6.31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
300,000 |
|
|
|
1,800,000 |
|
|
|
1,800,000 |
|
|
|
1,800,000 |
|
|
|
5,700,000 |
|
Price per MMBtu |
|
$ |
7.29 |
|
|
$ |
6.96 |
|
|
$ |
6.96 |
|
|
$ |
6.96 |
|
|
$ |
6.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Collars: (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,500,000 |
|
|
|
1,500,000 |
|
Price per MMBtu |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
5.00 - $5.81 |
|
|
$ |
5.00 - $5.81 |
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
1,500,000 |
|
|
|
1,500,000 |
|
|
|
1,500,000 |
|
|
|
1,500,000 |
|
|
|
6,000,000 |
|
Price per MMBtu |
|
$ |
5.00 - $5.81 |
|
|
$ |
5.25 - $5.75 |
|
|
$ |
5.25 - $5.75 |
|
|
$ |
6.00 - $6.80 |
|
|
$ |
5.38 - $6.03 |
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
1,500,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,500,000 |
|
Price per MMBtu |
|
$ |
6.00 - $6.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
6.00 - $6.80 |
|
27
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
Total |
|
Natural Gas Basis Swaps: (d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
|
|
|
|
2,118,000 |
|
|
|
1,968,000 |
|
|
|
4,086,000 |
|
Price per MMBtu (e) |
|
|
|
|
|
|
|
|
|
$ |
0.99 |
|
|
$ |
1.03 |
|
|
$ |
1.01 |
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
2,100,000 |
|
|
|
2,100,000 |
|
|
|
2,100,000 |
|
|
|
2,100,000 |
|
|
|
8,400,000 |
|
Price per MMBtu (e) |
|
$ |
0.85 |
|
|
$ |
0.85 |
|
|
$ |
0.85 |
|
|
$ |
0.85 |
|
|
$ |
0.85 |
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
1,800,000 |
|
|
|
1,800,000 |
|
|
|
1,800,000 |
|
|
|
1,800,000 |
|
|
|
7,200,000 |
|
Price per MMBtu (e) |
|
$ |
0.87 |
|
|
$ |
0.76 |
|
|
$ |
0.76 |
|
|
$ |
0.76 |
|
|
$ |
0.79 |
|
|
|
|
(a) |
|
The index prices for the oil price swaps and collars are based on the NYMEX-West Texas
Intermediate monthly average futures price. |
|
(b) |
|
The index price for the natural gas price swap is based on the Inside FERC-El Paso Permian
Basin first-of-the-month spot price. |
|
(c) |
|
The index prices for the natural gas price swaps and collars are based on the NYMEX-Henry Hub
last trading day futures price. |
|
(d) |
|
The basis differential between the El Paso Permian delivery point and NYMEX Henry Hub delivery
point. |
|
(e) |
|
Prices represent weighted average prices. |
Interest rate derivative contracts at June 30, 2009. The Company has an interest rate
swap which fixes the LIBOR interest rate on $300 million of the Companys bank debt at 1.90 percent
for three years, commencing in May of 2009. For this portion of the Companys bank debt, the
all-in interest rate will be calculated by adding the fixed rate of 1.90 percent to a margin that
ranges from 2.00 percent to 3.00 percent depending on the amount of bank debt outstanding.
28
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
The Companys reported oil and natural gas revenue and average oil and natural gas prices
includes the effects of oil quality and Btu content, gathering and transportation costs, natural
gas processing and shrinkage, and the net effect of the commodity hedges that qualified for cash
flow hedge accounting. The following table summarizes the gains and losses reported in earnings
related to the commodity and interest rate derivative instruments and the net change in accumulated
other comprehensive income (AOCI) for the three and six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Decrease in oil and natural gas revenue from derivative activity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments on cash flow hedges in oil sales |
|
$ |
|
|
|
$ |
(13,367 |
) |
|
$ |
|
|
|
$ |
(20,573 |
) |
Dedesignated cash flow hedges reclassified from AOCI in natural gas sales |
|
|
|
|
|
|
74 |
|
|
|
|
|
|
|
(222 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total decrease in oil and natural gas revenue from derivative activity |
|
$ |
|
|
|
$ |
(13,293 |
) |
|
$ |
|
|
|
$ |
(20,795 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on derivatives not designated as hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market gain (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
$ |
(109,374 |
) |
|
$ |
(90,055 |
) |
|
$ |
(149,117 |
) |
|
$ |
(103,247 |
) |
Interest rate derivatives |
|
|
3,427 |
|
|
|
|
|
|
|
1,000 |
|
|
|
|
|
Cash (payments) receipts on derivatives not designated as hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
|
25,120 |
|
|
|
(12,401 |
) |
|
|
62,244 |
|
|
|
(16,387 |
) |
Interest rate derivatives |
|
|
(779 |
) |
|
|
|
|
|
|
(779 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total loss on derivatives not designated as hedges |
|
$ |
(81,606 |
) |
|
$ |
(102,456 |
) |
|
$ |
(86,652 |
) |
|
$ |
(119,634 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain from ineffective portion of cash flow hedges |
|
$ |
|
|
|
$ |
356 |
|
|
$ |
|
|
|
$ |
920 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market loss of cash flow hedges |
|
$ |
|
|
|
$ |
(25,903 |
) |
|
$ |
|
|
|
$ |
(32,510 |
) |
Reclassification
adjustment of losses to earnings |
|
|
|
|
|
|
13,367 |
|
|
|
|
|
|
|
20,573 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change, before income taxes |
|
|
|
|
|
|
(12,536 |
) |
|
|
|
|
|
|
(11,937 |
) |
Income tax effect |
|
|
|
|
|
|
4,899 |
|
|
|
|
|
|
|
4,665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change, net of income taxes |
|
$ |
|
|
|
$ |
(7,637 |
) |
|
$ |
|
|
|
$ |
(7,272 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dedesignated cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification adjustment of (gains) losses to earnings |
|
$ |
|
|
|
$ |
(74 |
) |
|
$ |
|
|
|
$ |
222 |
|
Income tax effect |
|
|
|
|
|
|
29 |
|
|
|
|
|
|
|
(87 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change, net of income taxes |
|
$ |
|
|
|
$ |
(45 |
) |
|
$ |
|
|
|
$ |
135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
Note J. Debt
The Companys debt consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Credit facility |
|
$ |
660,000 |
|
|
$ |
630,000 |
|
Less: current portion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
660,000 |
|
|
$ |
630,000 |
|
|
|
|
|
|
|
|
Credit facility. The Companys credit facility, as amended, has a maturity date of July 31,
2013 (the Credit Facility). At June 30, 2009, the Company had letters of credit outstanding under
the Credit Facility of approximately $25,000 and its availability to borrow additional funds was
approximately $300 million. In April 2009, the lenders reaffirmed the Companys $960 million
borrowing base under the Credit Facility until the next scheduled borrowing base redetermination in
October 2009. Between scheduled borrowing base redeterminations, the Company and, if requested by
66 2/3 percent of the lenders, the lenders, may each request one special redetermination.
Advances on the Credit Facility bear interest, at the Companys option, based on (i) the prime
rate of JPMorgan Chase Bank (JPM Prime Rate) (3.25 percent at June 30, 2009) or (ii) a Eurodollar
rate (substantially equal to the London Interbank Offered Rate). At June 30, 2009, the interest
rates of Eurodollar rate advances and JPM Prime Rate advances vary, with interest margins ranging
from 200 to 300 basis points and 112.5 to 212.5 basis points, respectively, per annum depending on
the debt balance outstanding. At June 30, 2009, the Company pays commitment fees on the unused
portion of the available borrowing base of 50 basis points per annum.
The Credit Facility also includes a same-day advance facility under which the Company may
borrow funds from the administrative agent. Same day advances cannot exceed $25 million and the
maturity dates cannot exceed fourteen days. The interest rate on this facility is the JPM Prime
Rate plus the applicable interest margin.
The Companys obligations under the Credit Facility are secured by a first lien on
substantially all of the Companys oil and natural gas properties. In addition, all of the
Companys subsidiaries are guarantors and all general partner, limited partner and membership
interests in the Companys subsidiaries owned by the Company have been pledged to secure borrowings
under the Credit Facility. The credit agreement contains various restrictive covenants and
compliance requirements which include (a) maintenance of certain financial ratios, including (i) a
quarterly ratio of total debt to consolidated earnings before interest expense, income taxes,
depletion, depreciation, and amortization, exploration expense and other noncash income and
expenses to be no greater than 4.0 to 1.0, and (ii) a ratio of current assets to current
liabilities, excluding noncash assets and liabilities related to financial derivatives and asset
retirement obligations and including the unfunded amounts under the Credit Facility, to be no less
than 1.0 to 1.0; (b) limits on the incurrence of additional indebtedness and certain types of
liens; (c) restrictions as to mergers, combinations and dispositions of assets; and
(d) restrictions on the payment of cash dividends. At June 30, 2009, the Company was in compliance
with its debt covenants under the Credit Facility.
30
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
Principal maturities of debt. Principal maturities of debt outstanding at June 30, 2009 are
as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Remaining 2009 |
|
$ |
|
|
2010 |
|
|
|
|
2011 |
|
|
|
|
2012 |
|
|
|
|
2013 |
|
|
660,000 |
|
|
|
|
|
Total |
|
$ |
660,000 |
|
|
|
|
|
Interest expense. The following amounts have been incurred and charged to interest expense
for the three and six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Cash payments for interest |
|
$ |
3,457 |
|
|
$ |
3,982 |
|
|
$ |
6,929 |
|
|
$ |
10,758 |
|
Amortization of original issue discount |
|
|
|
|
|
|
25 |
|
|
|
|
|
|
|
50 |
|
Amortization of deferred loan origination costs |
|
|
857 |
|
|
|
314 |
|
|
|
1,713 |
|
|
|
626 |
|
Write-off of deferred loan origination costs
and original issue discount |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net changes in accruals |
|
|
1,889 |
|
|
|
(71 |
) |
|
|
1,946 |
|
|
|
(1,094 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest costs incurred |
|
|
6,203 |
|
|
|
4,250 |
|
|
|
10,588 |
|
|
|
10,340 |
|
Less: capitalized interest |
|
|
(3 |
) |
|
|
(365 |
) |
|
|
(18 |
) |
|
|
(840 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest expense |
|
$ |
6,200 |
|
|
$ |
3,885 |
|
|
$ |
10,570 |
|
|
$ |
9,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note K. Commitments and contingencies
Severance agreements. The Company has entered into severance and change of control agreements
with all of its officers. The current annual salaries for the Companys officers covered under
such agreements total approximately $1.9 million.
Indemnifications. The Company has agreed to indemnify its directors and officers, with
respect to claims and damages arising from certain acts or omissions taken in such capacity.
Legal actions. The Company is a party to proceedings and claims incidental to its business.
While many of these matters involve inherent uncertainty, the Company believes that the amount of
the liability, if any, ultimately incurred with respect to any such proceedings or claims will not
have a material adverse effect on the Companys consolidated financial position as a whole or on
its liquidity, capital resources or future results of operations. The Company will continue to
evaluate proceedings and claims involving the Company on a quarter-by-quarter basis and will
establish and adjust any reserves as appropriate to reflect its assessment of the then current
status of the matters.
Acquisition commitments. In connection with the acquisition of the Henry Entities, the
Company agreed to pay certain employees, who were formerly employed by the Henry Entities, bonuses
of approximately $11.0 million in the aggregate at each of the first and second anniversaries of
the closing of the acquisition, respectively. Except as described below, these employees must
remain employed with the Company to receive the bonus. A former Henry Entities employee who is
otherwise entitled to a full bonus will receive the full bonus (i) if the Company terminates the
employee without cause, (ii) upon the death or disability of such employee or (iii) upon a change
in control of the Company. If any such employee resigns or is terminated for cause, the employee
will not receive the bonus and, subject to certain conditions, the Company will be required to
reimburse the sellers in the acquisition of the Henry Entities 65 percent of the bonus amount not
paid to the employee. The Company will reflect the bonus amounts to be paid
31
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
to these employees as a
period cost, which will be included in the Companys results of operations over the period earned.
Amounts that ultimately are determined to be paid to the sellers will be treated as a contingent
purchase price and reflected as an adjustment to the purchase price. During the three and six
months ended June 30, 2009, the Company recognized $2.8 million and $5.3 million, respectively, of
this obligation in its results of operations.
Daywork commitments. The Company periodically enters into contractual arrangements under
which the Company is committed to expend funds to drill wells in the future, including agreements
to secure drilling rig services, which require the Company to make future minimum payments to the
rig operators. The Company records drilling commitments in the periods in which well capital is
incurred or rig services are provided. The following table summarizes the Companys future
drilling commitments at June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due By Period |
|
|
|
|
|
|
Less than |
|
|
1 - 3 |
|
|
3 - 5 |
|
|
More than |
|
(in thousands) |
|
Total |
|
|
1 year |
|
|
years |
|
|
years |
|
|
5 years |
|
|
Daywork drilling contracts |
|
$ |
299 |
|
|
$ |
299 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Daywork drilling contracts with related parties (a) |
|
|
1,000 |
|
|
|
1,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Daywork drilling contracts assumed in the Henry Properties acquisition (b) |
|
|
1,629 |
|
|
|
1,629 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual drilling commitments |
|
$ |
2,928 |
|
|
$ |
2,928 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Consists of daywork drilling contracts with Silver Oak Drilling, LLC, an
affiliate of Chase Oil Corporation. |
|
(b) |
|
A major oil and gas company which owns an interest in the wells being drilled and
the Company are parties to these contracts. Only the Companys 25% share of the contract
obligation has been reflected above. |
Operating leases. The Company leases vehicles, equipment and office facilities under
non-cancellable operating leases. Lease payments associated with these operating leases for the
three months ended June 30, 2009 and 2008 were approximately $582,000 and $116,000, respectively,
and $1,253,000 and $280,000 for the six months ended June 30, 2009 and 2008, respectively. Future
minimum lease commitments under non-cancellable operating leases at June 30, 2009 are as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Remaining 2009 |
|
$ |
523 |
|
2010 |
|
|
1,077 |
|
2011 |
|
|
1,083 |
|
2012 |
|
|
1,077 |
|
2013 |
|
|
1,084 |
|
Thereafter |
|
|
3,261 |
|
|
|
|
|
Total |
|
$ |
8,105 |
|
|
|
|
|
Note L. Income taxes
The Company accounts for income taxes in accordance with the provisions of SFAS No. 109,
Accounting for Income Taxes. The Company and its subsidiaries file federal corporate income tax
returns on a consolidated basis. The tax returns and the amount of taxable income or loss are
subject to examination by federal and state taxing authorities. In determining the interim period
income tax provision, the Company utilizes an estimated annual effective tax rate.
The Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty
in Income Taxes, an interpretation of FASB Statement No. 109, Accounting for Income Taxes, on
January 1, 2007. At the time of adoption and at June 30, 2009, the Company did not have any
significant uncertain tax positions requiring recognition in the financial statements. The tax
years 2004 through 2008 remain subject to examination by major tax jurisdictions.
32
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
The FASB issued FIN No. 48-1, Definition of Settlement in FASB Interpretation No. 48 (FIN No.
48-1), to clarify when a tax position is effectively settled. FIN No. 48-1 provides guidance in
determining the proper timing for recognizing tax benefits and applying the new information
relevant to the technical merits of a tax position obtained during a tax authority examination. FIN
No. 48-1 provides criteria to determine whether a tax position is effectively settled after
completion of a tax authority examination, even if the potential legal obligation remains under the
statute of limitations. The Companys adoption of this pronouncement did not have a significant
effect on its consolidated financial statements.
Income tax provision. The Companys income tax provision and amounts separately allocated
were attributable to the following items for the three and six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Income (loss) from operations |
|
$ |
(25,691 |
) |
|
$ |
(9,169 |
) |
|
$ |
(33,797 |
) |
|
$ |
5,199 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in stockholders equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred hedge losses |
|
|
|
|
|
|
(10,123 |
) |
|
|
|
|
|
|
(12,705 |
) |
Net settlement losses included in earnings |
|
|
|
|
|
|
5,195 |
|
|
|
|
|
|
|
8,127 |
|
Tax benefits related to stock-based compensation |
|
|
(2,188 |
) |
|
|
(1,553 |
) |
|
|
(2,992 |
) |
|
|
(2,146 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(27,879 |
) |
|
$ |
(15,650 |
) |
|
$ |
(36,789 |
) |
|
$ |
(1,525 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys income tax provision (benefit) attributable to income (loss) from operations
consisted of the following for the three and six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
$ |
2,856 |
|
|
$ |
523 |
|
|
$ |
5,294 |
|
|
$ |
585 |
|
U.S. state and local |
|
|
381 |
|
|
|
98 |
|
|
|
708 |
|
|
|
110 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,237 |
|
|
|
621 |
|
|
|
6,002 |
|
|
|
695 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
|
(25,518 |
) |
|
|
(8,201 |
) |
|
|
(35,103 |
) |
|
|
3,790 |
|
U.S. state and local |
|
|
(3,410 |
) |
|
|
(1,589 |
) |
|
|
(4,696 |
) |
|
|
714 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(28,928 |
) |
|
|
(9,790 |
) |
|
|
(39,799 |
) |
|
|
4,504 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(25,691 |
) |
|
$ |
(9,169 |
) |
|
$ |
(33,797 |
) |
|
$ |
5,199 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
The reconciliation between the tax expense computed by multiplying pretax income (loss)
by the U.S. federal statutory rate and the reported amounts of income tax expense (benefit) is as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Income (loss) at U.S. federal statutory rate |
|
$ |
(20,618 |
) |
|
$ |
(8,256 |
) |
|
$ |
(28,084 |
) |
|
$ |
4,600 |
|
State income taxes (net of federal tax effect) |
|
|
(1,969 |
) |
|
|
(968 |
) |
|
|
(2,592 |
) |
|
|
537 |
|
Nondeductible expense & other |
|
|
(3,104 |
) |
|
|
55 |
|
|
|
(3,121 |
) |
|
|
62 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) |
|
$ |
(25,691 |
) |
|
$ |
(9,169 |
) |
|
$ |
(33,797 |
) |
|
$ |
5,199 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note M. Related party transactions
Consulting Agreement. On June 30, 2009, Steven L. Beal, the Companys President and Chief
Operating Officer, retired from such positions. Mr. Beal was recently re-elected to the Companys
Board of Directors and is continuing to serve as a member of the
Companys Board of Directors. On June 9, 2009, the Company entered into a consulting agreement
(the Consulting Agreement ) with Mr. Beal, under which Mr. Beal began serving as a consultant to
the Company on July 1, 2009. Either the Company or Mr. Beal may terminate the consulting
relationship at any time by giving ninety days written notice to the other party; however, the
Company may terminate the relationship immediately for cause. During the term of the consulting
relationship, Mr. Beal will receive a consulting fee of $20,000 per month and a monthly
reimbursement for his medical and dental coverage costs. If Mr. Beal dies during the term of the
Consulting Agreement, his estate will receive a $60,000 lump sum payment.
Chase Group transactions. The Company incurred charges from Mack Energy Corporation (MEC),
an affiliate of Chase Oil Corporation (Chase Oil), of approximately $0.4 million and $0.3 million
for the three months ended June 30, 2009 and 2008, respectively, and $0.7 million and $1.5 million
for the six months ended June 30, 2009 and 2008, respectively, for services rendered in the
ordinary course of business.
The Company had $112,000 in outstanding receivables due from MEC at June 30, 2009 and no
outstanding receivables due from MEC at December 31, 2008. The Company had $49,000 in outstanding
payables to MEC at June 30, 2009 and no outstanding payables to MEC at December 31, 2008.
Saltwater disposal services agreement. Among the assets the Company acquired from Chase Oil
is an undivided interest in a saltwater gathering and disposal system, which is owned and
maintained under a written agreement among the Company and Chase Oil and certain of its affiliates,
and under which the Company as operator gathers and disposes of produced water. The system is owned
jointly by the Company and Chase Oil and its affiliates in undivided ownership percentages, which
are annually redetermined as of January 1 on the basis of each partys percentage contribution of
the total volume of produced water disposed of through the system during the prior calendar year.
As of January 1, 2009, the Company owned 95.4% of the system and Chase Oil and its affiliates owned
4.6%.
Other related party transactions. The Company also has engaged in transactions with certain
other affiliates of Chase Oil, Caza Energy LLC (Caza) and certain other parties thereto
(collectively the Chase Group), including a drilling contractor, an oilfield services company, a
supply company, a drilling fluids supply company, a pipe and tubing supplier, a fixed base operator
of aircraft services and a software company.
The Company incurred charges from these related party vendors of approximately $6.2 million
and $5.7 million for the three months ended June 30, 2009 and 2008, respectively, and $12.6 million
and $13.1 million for the six months ended June 30, 2009 and 2008, respectively.
34
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
The Company had outstanding amounts payable to these related party vendors identified above of
approximately $1.0 million and $21,000 at June 30, 2009 and December 31, 2008, respectively, which
are reflected in accounts payablerelated parties in the accompanying consolidated balance
sheets.
Overriding royalty and royalty interests. Certain members of the Chase Group own overriding
royalty interests in certain of the Chase Group properties. The amount paid attributable to such
interests was approximately $258,000 and $816,000 for the three months ended June 30, 2009 and
2008, respectively, and $499,000 and $1,600,000 for the six months ended June 30, 2009 and 2008,
respectively. The Company owed these owners royalty payments of approximately $132,000 and $146,000
at June 30, 2009 and December 31, 2008, respectively.
Royalties are paid on certain properties located in Andrews County, Texas to a partnership of
which one of the Companys directors is the general partner and owner of a 3.5% partnership
interest. The Company paid this partnership approximately $30,000 and $81,000 for the three months
ended June 30, 2009 and 2008, respectively, and $56,000 and $164,000 for the six months ended
June 30, 2009 and 2008, respectively. The Company owed this partnership royalty payments of
approximately $13,000 at June 30, 2009 and December 31, 2008.
In April 2005, the Company acquired certain working interests in 46,861 gross (26,908 net)
acres located in Culberson County, Texas from an entity partially owned by a person who became an
executive officer of the Company immediately following such acquisition. In connection with this
acquisition, such entity retained a 2% overriding royalty interest in the acquired properties,
which overriding royalty interest later became owned equally by such officer and a non-officer
employee of the Company. During the three
and six months ended June 30, 2009 and 2008, no payments were made related to this overriding
royalty interest. Effective March 31, 2008, the executive officer involved in this matter resigned
from the Company.
Working interests owned by employees. As part of the Henry Properties acquisition, the Company
purchased oil and natural gas properties in which certain employees owned interests. The Company
distributed revenues to these employees totaling approximately $32,000 and $62,000 for the three
and six months ended June 30, 2009, respectively, and received joint interest payments from these
employees of approximately $245,000 and $884,000 for the three and six months ended June 30, 2009,
respectively. At June 30, 2009 and December 31, 2008, the Company was owed by these employees
approximately $63,000 and $300,000, respectively, which is reflected in accounts receivable
related parties.
Note N. Net income (loss) per share
Basic net income (loss) per share is computed by dividing net income (loss) applicable to
common shareholders by the weighted average number of common shares treated as outstanding for the
period. All capital options were exercised prior to March 31, 2008.
The computation of diluted income (loss) per share reflects the potential dilution that could
occur if securities or other contracts to issue common stock that are dilutive to income (loss)
were exercised or converted into common stock or resulted in the issuance of common stock that
would then share in the earnings of the Company. These amounts include unexercised stock options
and restricted stock (as issued under the Plan and described in Note G). Potentially dilutive
effects are calculated using the treasury stock method.
35
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
The following table is a reconciliation of the basic weighted average common shares
outstanding to diluted weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
(in thousands) |
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
84,799 |
|
|
|
75,665 |
|
|
|
84,665 |
|
|
|
75,569 |
|
Dilutive capital options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12 |
|
Dilutive common stock options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,206 |
|
Dilutive restricted stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
247 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
84,799 |
|
|
|
75,665 |
|
|
|
84,665 |
|
|
|
77,034 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three and six months ended June 30, 2009, the computation of diluted net loss per
share was anti-dilutive due to the net loss reported by the Company; therefore, the amounts
reported for basic and diluted net loss per share were the same. For the three and six months
ended June 30, 2009, 492,810 shares of restricted stock, respectively, and 2,403,336 stock options,
respectively, were not included in the computation of diluted loss per share, as inclusion of these
items would be anti-dilutive.
For the three months ended June 30, 2008, the computation of diluted net loss per share was
anti-dilutive due to the net loss reported by the Company; therefore, the amounts reported for
basic and diluted net loss per share were the same. For the three and six months ended June 30,
2008, 379,794 and 24,914 shares of restricted stock, respectively, and 3,043,971 and 305,278 stock
options, respectively, were not included in the computation of diluted loss per share, as inclusion
of these items would be anti-dilutive.
Note O. Other current liabilities
The following table provides the components of the Companys other current liabilities at
June 30, 2009 and December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Other current liabilities: |
|
|
|
|
|
|
|
|
Accrued production costs |
|
$ |
18,229 |
|
|
$ |
15,489 |
|
Payroll related matters |
|
|
11,843 |
|
|
|
11,290 |
|
Accrued interest |
|
|
2,299 |
|
|
|
353 |
|
Asset retirement obligations |
|
|
2,706 |
|
|
|
2,611 |
|
Other |
|
|
3,072 |
|
|
|
8,314 |
|
|
|
|
|
|
|
|
Other current liabilities |
|
$ |
38,149 |
|
|
$ |
38,057 |
|
|
|
|
|
|
|
|
Note P. Subsequent events
The Company has evaluated subsequent events through August 6, 2009, which was the date these
financial statements were issued.
36
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2009
Unaudited
Note Q. Supplementary information
Capitalized costs
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Oil and natural gas properties: |
|
|
|
|
|
|
|
|
Proved |
|
$ |
2,608,138 |
|
|
$ |
2,316,330 |
|
Unproved |
|
|
277,137 |
|
|
|
377,244 |
|
Less: accumulated depletion |
|
|
(413,252 |
) |
|
|
(306,990 |
) |
|
|
|
|
|
|
|
Net capitalized costs for oil and natural gas properties |
|
$ |
2,472,023 |
|
|
$ |
2,386,584 |
|
|
|
|
|
|
|
|
Costs incurred for oil and natural gas producing activities (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
Property acquisition costs:(b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
(68 |
) |
|
$ |
(104 |
) |
|
$ |
(1,008 |
) |
|
$ |
1 |
|
Unproved |
|
|
3,361 |
|
|
|
587 |
|
|
|
4,582 |
|
|
|
1,349 |
|
Exploration |
|
|
61,131 |
|
|
|
21,136 |
|
|
|
84,940 |
|
|
|
50,701 |
|
Development |
|
|
31,450 |
|
|
|
46,365 |
|
|
|
115,229 |
|
|
|
71,242 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred for oil and natural gas properties |
|
$ |
95,874 |
|
|
$ |
67,984 |
|
|
$ |
203,743 |
|
|
$ |
123,293 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The costs incurred for oil and natural gas producing activities includes the following
amounts of asset retirement obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
Proved property acquisition costs |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Exploration costs |
|
|
52 |
|
|
|
168 |
|
|
|
220 |
|
|
|
194 |
|
Development costs |
|
|
(3,878 |
) |
|
|
1,245 |
|
|
|
(2,727 |
) |
|
|
443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(3,826 |
) |
|
$ |
1,413 |
|
|
$ |
(2,507 |
) |
|
$ |
637 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) |
|
During the three and six months ended June 30, 2009, the Company adjusted the purchase price
allocation related to the acquisition of the Henry Properties. This adjustment reduced the
proved acquisition costs by $80,000 and $1,020,000 during the three and six months ended June
30, 2009, respectively, while the unproved acquisition costs were decreased by $298,000 and
increased by $293,000 during the three and six months ended June 30, 2009, respectively. |
37
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
The following discussion is intended to assist in understanding our business and results
of operations together with our present financial condition. This section should be read in
conjunction with our historical consolidated financial statements and notes, as well as the
selected historical consolidated financial data included in our Annual Report on Form 10-K for the
year ended December 31, 2008.
During the third quarter of 2008, we closed a significant acquisition as discussed below. As
a result of the acquisition many comparisons between periods will be difficult or impossible.
Statements in this discussion may be forward-looking statements. These forward-looking
statements involve risks and uncertainties. We caution that a number of factors could cause future
production, revenue and expenses to differ materially from our expectations. See Cautionary
statement regarding forward-looking statements.
Overview
We are an independent oil and natural gas company engaged in the acquisition, development,
exploitation and exploration of producing oil and natural gas properties. Our operations are
primarily focused in the Permian Basin of Southeastern New Mexico and West Texas. We have also
acquired significant acreage positions in and are actively involved in drilling or participating in
drilling in emerging plays located in the Permian Basin of Southeastern New Mexico and the
Williston Basin in North Dakota, where we are applying horizontal drilling and advanced fracture
stimulation. Oil comprised 62.9 percent of our 137.3 MMBoe of estimated net proved reserves at
December 31, 2008, and 64.8 percent of our 7.1 MMBoe of production in 2008. We seek to operate the
wells in which we own an interest, and we operated wells that accounted for 93.1 percent of our
proved developed producing PV-10 and 64.7 percent of our 3,553 gross wells at December 31, 2008. By
controlling operations, we believe that we are able to more effectively manage the cost and timing
of exploration and development of our properties, including the drilling and stimulation methods
used.
Commodity prices
Factors that may impact future commodity prices, including the price of oil and natural gas,
include:
|
|
|
developments generally impacting the Middle East, including Iraq and Iran; |
|
|
|
|
the extent to which members of the Organization of Petroleum Exporting Countries and
other oil exporting nations are able to continue to manage oil supply through export
quotas; |
|
|
|
|
the overall global demand for oil; and |
|
|
|
|
overall North American natural gas supply and demand fundamentals, including: |
|
§ |
|
the impact of the decline of the United States economy, |
|
|
§ |
|
weather conditions, and |
|
|
§ |
|
liquefied natural gas deliveries to the United States. |
Although we cannot predict the occurrence of events that may affect future commodity prices or
the degree to which these prices will be affected, the prices for any commodity that we produce
will generally approximate current market prices in the geographic region of the production. From
time to time, we expect that we may economically hedge a portion of our commodity price risk to
mitigate the impact of price volatility on our business. See Note I of the Condensed Notes to
Consolidated Financial Statements included in Item 1. Consolidated Financial Statements
(Unaudited) for additional information regarding our commodity hedge positions at June 30, 2009.
38
Oil prices in 2008 were high and particularly volatile compared to historical prices. In
addition, natural gas prices have been subject to significant fluctuations during the past several
years. In general, oil and natural gas prices were substantially lower during the comparable
periods of 2009 measured against 2008. The following table sets forth the average NYMEX oil and
natural gas prices for the three and six months ended June 30, 2009 and 2008, as well as, the high
and low NYMEX price for the same periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Average NYMEX prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) |
|
$ |
59.83 |
|
|
$ |
124.28 |
|
|
$ |
51.61 |
|
|
$ |
110.98 |
|
Natural gas (MMBtu) |
|
$ |
3.80 |
|
|
$ |
11.48 |
|
|
$ |
4.15 |
|
|
$ |
10.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High / Low NYMEX prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
72.68 |
|
|
$ |
140.21 |
|
|
$ |
72.68 |
|
|
$ |
140.21 |
|
Low |
|
$ |
45.88 |
|
|
$ |
100.98 |
|
|
$ |
33.98 |
|
|
$ |
86.99 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMBtu): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
4.45 |
|
|
$ |
13.35 |
|
|
$ |
6.07 |
|
|
$ |
13.35 |
|
Low |
|
$ |
3.25 |
|
|
$ |
9.32 |
|
|
$ |
3.25 |
|
|
$ |
7.48 |
|
Further demonstrating the continuing volatility, the NYMEX oil price and NYMEX natural gas
price reached lows of $59.52 per Bbl and $3.26 per MMBtu, respectively, during the period from July
1, 2009 to August 3, 2009. At August 3, 2009, the NYMEX oil price and NYMEX natural gas price were
$71.58 per Bbl and $4.03 per MMBtu, respectively.
Henry Entities acquisition
On July 31, 2008, we closed the acquisition of Henry Petroleum LP and certain entities
affiliated with Henry Petroleum LP (the Henry Entities) and additional non-operated interests in
oil and natural gas properties from persons affiliated with the Henry Entities. In August 2008 and
September 2008, we acquired additional non-operated interests in oil and natural gas properties
from persons affiliated with the Henry Entities. The assets acquired in the Henry Entities
acquisition, including the additional non-operated interests, are referred to as the Henry
Properties. We paid $583.5 million in cash for the Henry Properties acquisition, which was funded
with borrowings under our credit facility, which was amended and restated on July 31, 2008, and net
proceeds of approximately $242.4 million from our private placement of 8,302,894 shares of our
common stock.
2009 capital budget
On November 6, 2008, our board of directors approved the following capital budget for 2009,
predicated on funding it substantially within our cash flow:
|
|
|
|
|
|
|
2009 |
|
(in millions) |
|
Budget |
|
|
Drilling and recompletion opportunities in our core operating area |
|
$ |
398 |
|
Projects operated by third parties |
|
|
8 |
|
Emerging plays, acquisition of leasehold acreage and other property interests, and geological and geophysical |
|
|
72 |
|
Maintenance capital in our core operating areas |
|
|
22 |
|
|
|
|
|
Total 2009 capital budget |
|
$ |
500 |
|
|
|
|
|
In January 2009, in light of the drop in commodity prices, we took actions to reduce our
capital activities to a level that would allow us to fund our capital expenditures substantially
within our cash flow, which at the time resulted in estimated annual capital expenditures of
approximately $300 million. Currently, based on current capital costs and commodity prices, we
estimate our capital expenditures to be approximately $400 million for 2009, which we believe we
can substantially fund within our cash flow. We will
39
continue to monitor our capital expenditures,
at least on a quarterly basis, in relation to our cash flow and expect to adjust our activity and
capital spending level based on changes in commodity prices and the cost of goods and services and
other considerations.
During the first half of 2009, we incurred approximately $207.0 million of capital
expenditures (excluding the effects of asset retirement obligations and adjustments to the
acquisition of the Henry Properties). These costs were modestly in excess of our cash flows
(including effects of derivative cash receipts/payments) during the first half of 2009.
Reaffirmed borrowing base
We amended our credit agreement on April 7, 2009, to (i) reaffirm our borrowing base of
$960 million; (ii) add certain provisions relating to defaulting lenders which, among other things,
require us, at the request of the administrative agent, to cash collateralize or prepay a
defaulting lenders pro rata share of letter of credit and swingline loan exposure; (iii) amend the
calculation of alternate base rate interest, which is used in connection with non-Eurodollar rate
loans from the greater of (a) the JPMorgan Chase Bank prime rate
or (b) the federal funds rate plus 0.50% to the greatest of the (x) JPMorgan Chase Bank prime
rate, (y) the federal funds rate plus 0.50% and (z) the rate for one-month U.S. dollar deposits in
the London interbank market plus 1.00% and (iv) revise the pricing schedule to increase (a) the
Eurodollar rate margin from a range of 1.25% to 2.75% to a range of 2.00% to 3.00% (depending on
the then-current borrowing base usage), (b) the alternate base rate margin from a range of 0.00%
to 1.25% to a range of 1.125% to 2.125% (depending on the then-current borrowing base usage), and
(c) the unused commitment fee rate from a range of 0.25% to 0.50% to a flat rate of 0.50%.
Derivative financial instrument exposure
At June 30, 2009, the fair value of our financial derivatives was a net asset of
$24.3 million. All of our counterparties to these financial derivatives are parties to our credit
facility and have their outstanding debt commitments and derivative exposures collateralized
pursuant to our credit facility. Pursuant to the terms of our financial derivative instruments and
their collateralization under our credit facility, we do not have exposure to potential margin
calls on our financial derivative instruments.
We currently have no reason to believe that our counterparties to these commodity derivative
contracts are not financially viable. Our credit facility does not allow us to offset amounts we
may owe a lender under our credit facility against amounts we may be owed related to our derivative
financial instruments with such party.
40
New commodity derivative contracts. During the six months ended June 30, 2009, we entered
into additional commodity derivative contracts to economically hedge a portion of our estimated
future production. The following table summarizes information about these additional commodity
derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
Index |
|
Contract |
|
|
Volume |
|
Price |
|
Period |
|
Oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
Price collar |
|
|
600,000 |
|
|
$ |
45.00 $49.00 |
(a) (d) |
|
3/1/09 5/31/09 |
Price swap |
|
|
270,000 |
|
|
$ |
69.50 |
(a) |
|
7/1/09 9/30/09 |
Price swap |
|
|
540,000 |
|
|
$ |
51.62 |
(a) (d) |
|
7/1/09 12/31/09 |
Price swap |
|
|
150,000 |
|
|
$ |
69.50 |
(a) |
|
10/1/09 12/31/09 |
Price swap |
|
|
2,508,000 |
|
|
$ |
62.15 |
(a) (d) |
|
1/1/10 12/31/10 |
Price swap |
|
|
1,800,000 |
|
|
$ |
72.17 |
(a) (d) |
|
1/1/11 12/31/11 |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus): |
|
|
|
|
|
|
|
|
|
|
Price collar |
|
|
1,500,000 |
|
|
$ |
5.00 $5.81 |
(b) |
|
10/1/09 12/31/09 |
Price collar |
|
|
1,500,000 |
|
|
$ |
5.00 $5.81 |
(b) |
|
1/1/10 3/31/10 |
Price collar |
|
|
3,000,000 |
|
|
$ |
5.25 $5.75 |
(b) |
|
4/1/10 9/30/10 |
Price collar |
|
|
1,500,000 |
|
|
$ |
6.00 $6.80 |
(b) |
|
10/1/10 12/31/10 |
Price collar |
|
|
1,500,000 |
|
|
$ |
6.00 $6.80 |
(b) |
|
1/1/11 3/31/11 |
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
3,000,000 |
|
|
$ |
4.31 |
(b) |
|
4/1/09 9/30/09 |
Price swap |
|
|
600,000 |
|
|
$ |
4.66 |
(b) |
|
7/1/09 9/30/09 |
Price swap |
|
|
450,000 |
|
|
$ |
4.66 |
(b) |
|
10/1/09 12/31/09 |
Price swap |
|
|
2,400,000 |
|
|
$ |
6.31 |
(b) |
|
1/1/10 12/31/10 |
Price swap |
|
|
300,000 |
|
|
$ |
7.29 |
(b) |
|
1/1/11 3/31/11 |
Price swap |
|
|
5,400,000 |
|
|
$ |
6.96 |
(b) (d) |
|
4/1/11 12/31/11 |
|
|
|
|
|
|
|
|
|
|
|
Basis swap |
|
|
600,000 |
|
|
$ |
0.79 |
(c) |
|
7/1/09 9/30/09 |
Basis swap |
|
|
450,000 |
|
|
$ |
0.89 |
(c) |
|
10/1/09 12/31/09 |
Basis swap |
|
|
8,400,000 |
|
|
$ |
0.85 |
(c) (d) |
|
1/1/10 12/31/10 |
Basis swap |
|
|
1,800,000 |
|
|
$ |
0.87 |
(c) (d) |
|
1/1/11 3/31/11 |
Basis swap |
|
|
5,400,000 |
|
|
$ |
0.76 |
(c) |
|
4/1/11 12/31/11 |
|
|
|
(a) |
|
The index prices for the oil price swaps and collars are based on the NYMEX-West Texas Intermediate monthly average futures price. |
|
(b) |
|
The index prices for the natural gas price swaps and collars are based on the NYMEX-Henry Hub last trading day futures price. |
|
(c) |
|
The basis differential between the El Paso Permian delivery point and NYMEX Henry Hub delivery point. |
|
(d) |
|
Prices represent weighted average prices. |
41
In July 2009, the Company entered into the following oil price swaps to hedge an
additional portion of its estimated oil production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
Index |
|
Contract |
|
|
Volume |
|
Price |
|
Period |
|
Oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
273,000 |
|
|
$ |
67.50 |
(a) |
|
8/1/09 - 12/31/09 |
Price swap |
|
|
799,000 |
|
|
$ |
67.50 |
(a) |
|
1/1/10 - 12/31/10 |
Price swap |
|
|
801,000 |
|
|
$ |
70.53 |
(a) (b) |
|
1/1/11 - 12/31/11 |
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate monthly average futures price. |
|
(b) |
|
Prices represent weighted average prices. |
42
Results of Operations
The following table presents selected volume and price information for the three months
ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Net production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
|
1,831 |
|
|
|
899 |
|
|
|
3,518 |
|
|
|
1,786 |
|
Natural gas (MMcf) |
|
|
5,414 |
|
|
|
3,346 |
|
|
|
10,369 |
|
|
|
6,451 |
|
Total (MBoe) |
|
|
2,733 |
|
|
|
1,457 |
|
|
|
5,246 |
|
|
|
2,861 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) |
|
|
20,121 |
|
|
|
9,879 |
|
|
|
19,436 |
|
|
|
9,813 |
|
Natural gas (Mcf) |
|
|
59,495 |
|
|
|
36,769 |
|
|
|
57,287 |
|
|
|
35,445 |
|
Total (Boe) |
|
|
30,037 |
|
|
|
16,007 |
|
|
|
28,984 |
|
|
|
15,721 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without hedges (Bbl) |
|
$ |
55.44 |
|
|
$ |
121.00 |
|
|
$ |
47.32 |
|
|
$ |
107.39 |
|
Oil, with hedges(a) (Bbl) |
|
$ |
55.44 |
|
|
$ |
106.13 |
|
|
$ |
47.32 |
|
|
$ |
95.87 |
|
Natural gas, without hedges (Mcf) |
|
$ |
4.77 |
|
|
$ |
12.52 |
|
|
$ |
4.52 |
|
|
$ |
11.33 |
|
Natural gas, with hedges(a) (Mcf)
|
|
$ |
4.77 |
|
|
$ |
12.54 |
|
|
$ |
4.52 |
|
|
$ |
11.30 |
|
Total, without hedges (Boe) |
|
$ |
46.59 |
|
|
$ |
103.42 |
|
|
$ |
40.67 |
|
|
$ |
92.59 |
|
Total, with hedges(a) (Boe) |
|
$ |
46.59 |
|
|
$ |
94.29 |
|
|
$ |
40.67 |
|
|
$ |
85.32 |
|
|
|
|
(a) |
|
These prices do not reflect the cash receipts/payments related to the oil and natural gas
derivatives that were not designated as hedges and are reflected in loss on derivatives not
designated as hedges in our statements of operations. If the cash receipts/payments related
to the oil and natural gas derivatives that were not designated as hedges were included in our
oil and natural gas sales our oil and natural gas prices would be as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Oil (Bbl) |
|
$ |
67.36 |
|
|
$ |
92.86 |
|
|
$ |
63.36 |
|
|
$ |
86.93 |
|
Natural gas (Mcf)
|
|
$ |
5.38 |
|
|
$ |
12.40 |
|
|
$ |
5.08 |
|
|
$ |
11.23 |
|
Total (Boe) |
|
$ |
55.78 |
|
|
$ |
85.78 |
|
|
$ |
52.53 |
|
|
$ |
79.59 |
|
The presentation above provides the full effect of our oil and natural gas derivatives
program without consideration for the financial presentation of the cash receipts/payments on
the oil and natural gas derivatives.
43
Three months ended June 30, 2009, compared to three months ended June 30, 2008
Oil and natural gas revenues. Revenue from oil and natural gas operations was $127.3
million for the three months ended June 30, 2009, a decrease of $10.1 million (7 percent) from
$137.4 million for the three months ended June 30, 2008. This decrease was primarily due to
substantial decreases in realized oil and natural gas prices, offset by increased production (i) as
a result of the acquisition of the Henry Properties on July 31, 2008 and (ii) due to successful
drilling efforts during 2008 and 2009. Specifically the:
|
|
|
average realized oil price (after giving effect to hedging activities) was $55.44 per
Bbl during the three months ended June 30, 2009, a decrease of 48 percent from $106.13
per Bbl during the three months ended June 30, 2008; |
|
|
|
|
total oil production was 1,831 MBbl for the three months ended June 30, 2009, an
increase of 932 MBbl (104 percent) from 899 MBbl for the three months ended June 30,
2008; |
|
|
|
|
average realized natural gas price (after giving effect to hedging activities) was
$4.77 per Mcf during the three months ended June 30, 2009, a decrease of 62 percent from
$12.54 per Mcf during the three months ended June 30, 2008; |
|
|
|
|
total natural gas production was 5,414 MMcf for the three months ended June 30, 2009,
an increase of 2,068 MMcf (62 percent) from 3,346 MMcf for the three months ended
June 30, 2008; |
|
|
|
|
average realized barrel of oil equivalent price (after giving effect to hedging
activities) was $46.59 per Boe during the three months ended June 30, 2009, a decrease
of 51 percent from $94.29 per Boe during the three months ended June 30, 2008; and |
|
|
|
|
total production was 2,733 MBoe for the three months ended June 30, 2009, an increase
of 1,276 MBoe (88 percent) from 1,457 MBoe for the three months ended June 30, 2008. |
Hedging activities. The oil and natural gas prices that we report are based on the market
price received for the commodities adjusted to give effect to the results of our cash flow hedging
activities. We utilize commodity derivative instruments in order to (i) reduce the effect of the
volatility of price changes on the commodities we produce and sell, (ii) support our capital budget
and expenditure plans and (iii) support the economics associated with acquisitions.
Currently, we do not designate our derivative instruments to qualify for hedge accounting.
Accordingly, we reflect the changes in the fair value of our derivative instruments in the
statements of operations as (gain) loss on derivatives not designated as hedges. All of our
remaining hedges that historically qualified or were dedesignated from hedge accounting were
settled in 2008.
The following is a summary of the effects of commodity hedges that qualify for hedge
accounting treatment for the three months ended June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Hedges |
|
Natural Gas Hedges |
|
|
Three Months Ended |
|
Three Months Ended |
|
|
June 30, 2008 |
|
June 30, 2008 |
Hedging revenue increase (decrease) (in thousands) |
|
|
|
|
|
$ |
(13,367 |
) |
|
|
|
|
|
$ |
74 |
|
Hedged volumes (Bbls and MMBtus, respectively) |
|
|
|
|
|
|
236,000 |
|
|
|
|
|
|
|
1,228,000 |
|
Hedged revenue increase (decrease) per hedged volume |
|
|
|
|
|
$ |
(56.64 |
) |
|
|
|
|
|
$ |
0.06 |
|
44
Production expenses. The following tables provide the components of our total oil and natural
gas production costs for the three months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Lease operating expenses |
|
$ |
15,726 |
|
|
$ |
5.75 |
|
|
$ |
9,296 |
|
|
$ |
6.38 |
|
Taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem |
|
|
989 |
|
|
|
0.36 |
|
|
|
518 |
|
|
|
0.36 |
|
Production |
|
|
9,090 |
|
|
|
3.33 |
|
|
|
12,030 |
|
|
|
8.26 |
|
Workover costs |
|
|
12 |
|
|
|
|
|
|
|
135 |
|
|
|
0.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas production expenses |
|
$ |
25,817 |
|
|
$ |
9.44 |
|
|
$ |
21,979 |
|
|
$ |
15.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, in general, we have some control over lease
operating expenses and workover costs on properties we operate, but production and ad valorem taxes
are directly related to commodity price changes.
The lease operating expenses during the second quarter of 2008 include approximately $1.2
million ($0.82 per Boe) of costs that were associated with activity that occurred in the first
quarter of 2008.
Lease operating expenses were $15.7 million ($5.75 per Boe) for the three months ended
June 30, 2009, an increase of $6.4 million (69 percent) from $9.3 million ($6.38 per Boe) for the
three months ended June 30, 2008. The total increase, taking into consideration details in the
preceding paragraph, in lease operating expenses is due to (i) the wells acquired in the Henry
Properties acquisition, which increased the absolute amount because those wells have a higher per
unit cost as compared to our historical per unit cost and (ii) our wells successfully drilled and
completed in 2008 and 2009.
Ad valorem taxes have increased primarily as a result of the Henry Properties acquisition,
which were highly concentrated in Texas, a state which has a higher ad valorem rate than New
Mexico, where substantially all of our properties prior to the acquisition were located.
Production taxes per unit of production were $3.33 per Boe during the three months ended
June 30, 2009, a decrease of 60 percent from $8.26 per Boe during the three months ended June 30,
2008. The decrease is directly related to the decrease in commodity prices offset by the increase
in oil and natural gas revenues related to increased volumes. Over the same period, our Boe prices
(before the effects of hedging) decreased 55 percent.
Workover expenses were approximately $0.01 million and $0.1 million for the three months ended
June 30, 2009 and 2008, respectively. The 2008 amounts related primarily to workovers in Andrews
County, Texas and Lea County, New Mexico.
Exploration and abandonments expense. The following table provides a breakdown of our
exploration and abandonments expense for the three months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Geological and geophysical |
|
$ |
448 |
|
|
$ |
424 |
|
Exploratory dry holes |
|
|
445 |
|
|
|
(19 |
) |
Leasehold abandonments and other
|
|
|
531 |
|
|
|
318 |
|
|
|
|
|
|
|
|
Total exploration and abandonments
|
|
$ |
1,424 |
|
|
$ |
723 |
|
|
|
|
|
|
|
|
45
Our geological and geophysical expense, which primarily consists of the costs of acquiring and
processing seismic data, geophysical data and core analysis, during the three months ended June 30,
2009, was comparable to the three months ended June 30, 2008.
During the three months ended June 30, 2009, we wrote-off two unsuccessful exploratory wells
in our Texas Permian area.
For the three months ended June 30, 2009, we recorded approximately $0.5 million of leasehold
abandonments, which relates primarily to the write-off of a non-core prospect in New Mexico. For
the three months ended June 30, 2008, we recorded $0.3 million of leasehold abandonments, which
were primarily related to non-core prospects in Chaves County, New Mexico and Crane County, Texas.
Depreciation, depletion and amortization expense. The following table provides components of
our depreciation, depletion and amortization expense for the three months ended June 30, 2009 and
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Depletion of proved oil and natural gas properties
|
|
$ |
51,218 |
|
|
$ |
18.74 |
|
|
$ |
21,584 |
|
|
$ |
14.81 |
|
Depreciation of other property and equipment
|
|
|
796 |
|
|
|
0.29 |
|
|
|
426 |
|
|
|
0.29 |
|
Amortization of intangible asset operating rights
|
|
|
388 |
|
|
|
0.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depletion, depreciation and amortization
|
|
$ |
52,402 |
|
|
$ |
19.17 |
|
|
$ |
22,010 |
|
|
$ |
15.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil price used to estimate proved oil reserves at period end |
|
$ |
66.25 |
|
|
|
|
|
|
$ |
136.50 |
|
|
|
|
|
Natural gas price used to estimate proved gas reserves at period end |
|
$ |
3.72 |
|
|
|
|
|
|
$ |
13.10 |
|
|
|
|
|
Depletion of proved oil and natural gas properties was $51.2 million ($18.74 per Boe) for the
three months ended June 30, 2009, an increase of $29.6 million from $21.6 million ($14.81 per Boe)
for the three months ended June 30, 2008. The increase in depletion expense, on a total and a per
Boe basis, was primarily due to (i) the Henry Properties acquisition, for which the depletion rate
was higher than that of our historical assets, (ii) capitalized costs associated with new wells
that were successfully drilled and completed in 2008 and 2009 and (iii) the decrease in the oil and
natural gas prices between the years utilized to determine proved reserves.
The amortization of the intangible asset is a result of the value assigned to the operating
rights that we acquired in the Henry Properties acquisition. The intangible asset is currently
being amortized over an estimated life of approximately 25 years.
Impairment of long-lived assets. We periodically review our long-lived assets to be held and
used, including proved oil and natural gas properties accounted for under the successful efforts
method of accounting. Due to downward adjustments to the economically recoverable resource
potential associated with declines in commodity prices and well performance, we recognized a
non-cash charge against earnings of $4.5 million, which was primarily attributable to non-core
natural gas related properties in Eddy and Lea Counties, New Mexico. For the three months ended
June 30, 2008, we recognized a non-cash charge against earnings of $0.05 million, which was
primarily attributable to a non-core lease located in Lea County, New Mexico.
46
General and administrative expenses. The following table provides components of our general
and administrative expenses for the three months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
General and administrative expenses recurring |
|
$ |
12,025 |
|
|
$ |
4.40 |
|
|
$ |
7,121 |
|
|
$ |
4.89 |
|
Non-recurring bonus paid to former Henry Entities employees
|
|
|
2,750 |
|
|
|
1.01 |
|
|
|
|
|
|
|
|
|
Non-cash stock-based compensation stock options |
|
|
885 |
|
|
|
0.32 |
|
|
|
1,262 |
|
|
|
0.87 |
|
Non-cash stock-based compensation restricted stock |
|
|
1,303 |
|
|
|
0.48 |
|
|
|
468 |
|
|
|
0.32 |
|
Less: Third-party operating fee reimbursements |
|
|
(2,791 |
) |
|
|
(1.02 |
) |
|
|
(265 |
) |
|
|
(0.18 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses |
|
$ |
14,172 |
|
|
$ |
5.19 |
|
|
$ |
8,586 |
|
|
$ |
5.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were $14.2 million ($5.19 per Boe) for the three months
ended June 30, 2009, an increase of $5.6 million (65 percent) from $8.6 million ($5.90 per Boe) for
the three months ended June 30, 2008. The increase in general and administrative expenses during
the three months ended June 30, 2009 over 2008 was primarily due to (i) the non-recurring bonus
paid to former Henry Entities employees, (ii) an increase in non-cash stock-based compensation for
both stock options and restricted stock awards and (iii) an increase in the number of employees and
related personnel expenses, partially offset by an increase in third-party operating fee
reimbursements.
In connection with the Henry Entities acquisition, we agreed to pay certain of our employees,
who were formerly Henry Entities employees, a predetermined bonus amount, in addition to the
compensation we pay these employees, over the next two years. Since these employees will earn this
bonus over the next two years, we are reflecting the cost in our general and administrative costs
as non-recurring, as it is not controlled by us. See Note K of the Condensed Notes to Consolidated
Financial Statements included in Item 1. Consolidated Financial Statements (Unaudited) for
additional information related to this bonus.
We earn reimbursements as operator of certain oil and natural gas properties in which we own
interests. As such, we earned reimbursements of $2.8 million and $0.3 million during the three
months ended June 30, 2009 and 2008, respectively. This reimbursement is reflected as a reduction
of general and administrative expenses in the consolidated statements of operations. The increase
in this reimbursement is directly related to the Henry Properties acquisition, as we own a lower
working interest in these operated properties compared to our historical property base, so we
receive a larger third-party reimbursement as compared to our historical property base.
Bad debt expense. On May 20, 2008, we entered into a short-term purchase agreement with an
oil purchaser to buy a portion of our oil affected as a result of the New Mexico refinery shut down
due to repairs. On July 22, 2008, this purchaser declared bankruptcy. We fully reserved the
receivable amount due from this purchaser of approximately $1.8 million as of June 30, 2008, and
are pursuing our claim in the bankruptcy proceedings.
Loss on derivatives not designated as hedges. During the three months ended June 30, 2007, we
determined that all of our natural gas commodity derivative contracts no longer qualified as
hedges. Because we no longer considered these hedges to be highly effective, we discontinued hedge
accounting for those existing hedges, prospectively, and during the period the hedges became
ineffective. In addition, for our new commodity and interest rate derivative contracts entered into
after August 2007, we chose not to designate any of these contracts as hedges. As a result, any
changes in fair value and any cash settlements related to these contracts are recorded in earnings
during the related period. All amounts previously recorded in accumulated other comprehensive
income were reclassified to earnings prior to 2009.
47
The following table sets forth the cash receipts for settlements and the non-cash
mark-to-market adjustment for the derivative contracts not designated as hedges for the three
months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Cash payments (receipts): |
|
|
|
|
|
|
|
|
Commodity derivatives oil |
|
$ |
(21,828 |
) |
|
$ |
11,929 |
|
Commodity derivatives natural gas
|
|
|
(3,292 |
) |
|
|
472 |
|
Financial derivatives interest |
|
|
779 |
|
|
|
|
|
Mark-to-market (gain) loss: |
|
|
|
|
|
|
|
|
Commodity derivatives oil |
|
|
105,062 |
|
|
|
82,951 |
|
Commodity derivatives natural gas
|
|
|
4,312 |
|
|
|
7,104 |
|
Financial derivatives interest |
|
|
(3,427 |
) |
|
|
|
|
|
|
|
|
|
|
|
Loss on derivatives not designated as hedges |
|
$ |
81,606 |
|
|
$ |
102,456 |
|
|
|
|
|
|
|
|
Interest expense. Interest expense was $6.2 million for the three months ended June 30, 2009,
an increase of $2.3 million from $3.9 million for the three months ended June 30, 2008. The
weighted average interest rate for the three months ended June 30, 2009
and 2008 was 2.9% and 4.9%, respectively. The weighted average debt balance during the three
months ended June 30, 2009 and 2008 was approximately $680.0 million and $302.1 million,
respectively.
The increase in weighted average debt balance during the three months ended June 30, 2009 was
due primarily to borrowings in July 2008 for the acquisition of the Henry Properties. The increase
in interest expense is due to an increase in the weighted average debt balance offset by a decrease
in the weighted average interest rate. The decrease in the weighted average interest rate is
primarily due to an improvement in market interest rates.
Income tax provisions. We recorded an income tax benefit of $25.7 million and $9.2 million
for the three months ended June 30, 2009 and 2008, respectively. The effective income tax rate for
the three months ended June 30, 2009 and 2008 was 43.6 percent and 38.9 percent, respectively. The
higher effective tax rate in 2009 compared to 2008 is primarily due to the estimated annual 2009
permanent tax differences compared to the related current estimated pre-tax book income.
Six months ended June 30, 2009, compared to six months ended June 30, 2008
Oil and natural gas revenues. Revenue from oil and natural gas operations was $213.3
million for the six months ended June 30, 2009, a decrease of $30.8 million (13 percent) from
$244.1 million for the six months ended June 30, 2008. This decrease was primarily due to
substantial decreases in realized oil and natural gas prices, offset by increased production (i) as
a result of the acquisition of the Henry Properties on July 31, 2008 and (ii) due to successful
drilling efforts during 2008 and 2009. Specifically the:
|
|
|
average realized oil price (after giving effect to hedging activities) was $47.32 per
Bbl during the six months ended June 30, 2009, a decrease of 51 percent from $95.87 per
Bbl during the six months ended June 30, 2008; |
|
|
|
|
total oil production was 3,518 MBbl for the six months ended June 30, 2009, an
increase of 1,732 MBbl (97 percent) from 1,786 MBbl for the six months ended June 30,
2008; |
|
|
|
|
average realized natural gas price (after giving effect to hedging activities) was
$4.52 per Mcf during the six months ended June 30, 2009, a decrease of 60 percent from
$11.30 per Mcf during the six months ended June 30, 2008; |
|
|
|
|
total natural gas production was 10,369 MMcf for the six months ended June 30, 2009,
an increase of 3,918 MMcf (61 percent) from 6,451 MMcf for the six months ended June 30,
2008; |
|
|
|
|
average realized barrel of oil equivalent price (after giving effect to hedging
activities) was $40.67 per Boe during the six months ended June 30, 2009, a decrease of
52 percent from $85.32 per Boe during the six months ended June 30, 2008; and |
48
|
|
|
total production was 5,246 MBoe for the six months ended June 30, 2009, an increase
of 2,385 MBoe (83 percent) from 2,861 MBoe for the six months ended June 30, 2008. |
Hedging activities. The oil and natural gas prices that we report are based on the market
price received for the commodities adjusted to give effect to the results of our cash flow hedging
activities. We utilize commodity derivative instruments in order to (i) reduce the effect of the
volatility of price changes on the commodities we produce and sell, (ii) support our capital budget
and expenditure plans and (iii) support the economics associated with acquisitions.
Currently, we do not designate our derivative instruments to qualify for hedge accounting.
Accordingly, we reflect the changes in the fair value of our derivative instruments in the
statements of operations as (gain) loss on derivatives not designated as hedges. All of our
remaining hedges that historically qualified or were dedesignated from hedge accounting were
settled in 2008.
The following is a summary of the effects of commodity hedges that qualify for hedge
accounting treatment for the six months ended June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
Oil Hedges |
|
|
Natural Gas Hedges |
|
|
|
Six Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, 2008 |
|
|
June 30, 2008 |
|
|
Hedging revenue increase (decrease) (in thousands) |
|
$ |
(20,573 |
) |
|
$ |
(222 |
) |
Hedged volumes (Bbls and MMBtus, respectively) |
|
|
473,000 |
|
|
|
2,457,000 |
|
|
|
|
|
|
|
|
Hedged revenue increase (decrease) per hedged volume |
|
$ |
(43.49 |
) |
|
$ |
(0.09 |
) |
|
|
|
|
|
|
|
Production expenses. The following tables provide the components of our total oil and natural
gas production costs for the six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Lease operating expenses |
|
$ |
32,294 |
|
|
$ |
6.16 |
|
|
$ |
16,238 |
|
|
$ |
5.68 |
|
Taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem |
|
|
2,491 |
|
|
|
0.47 |
|
|
|
1,006 |
|
|
|
0.35 |
|
Production |
|
|
15,365 |
|
|
|
2.93 |
|
|
|
21,108 |
|
|
|
7.38 |
|
Workover costs |
|
|
433 |
|
|
|
0.08 |
|
|
|
522 |
|
|
|
0.18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas production expenses |
|
$ |
50,583 |
|
|
$ |
9.64 |
|
|
$ |
38,874 |
|
|
$ |
13.59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, in general, we have some control over lease
operating expenses and workover costs on properties we operate, but production and ad valorem taxes
are directly related to commodity price changes.
Lease operating expenses were $32.3 million ($6.16 per Boe) for the six months ended June 30,
2009, an increase of $16.1 million (99 percent) from $16.2 million ($5.68 per Boe) for the six
months ended June 30, 2008. The increase in lease operating expenses is due to (i) the wells
acquired in the Henry Properties acquisition, which increased the absolute and per unit amount
because those wells have a higher per unit cost as compared to our historical per unit cost and
(ii) our wells successfully drilled and completed in 2008 and 2009.
Ad valorem taxes have increased primarily as a result of the Henry Properties acquisition,
which were highly concentrated in Texas, a state which has a higher ad valorem rate than New
Mexico, where substantially all of our properties prior to the acquisition were located.
Production taxes per unit of production were $2.93 per Boe during the six months ended
June 30, 2009, a decrease of 60 percent from $7.38 per Boe during the six months ended June 30,
2008. The decrease is directly related to the decrease in commodity prices
49
offset by the increase
in oil and natural gas revenues related to increased volumes. Over the same period, our Boe prices
(before the effects of hedging) decreased 56 percent.
Workover expenses were approximately $0.4 million and $0.5 million for the six months ended
June 30, 2009 and 2008, respectively. The 2009 and 2008 amounts related primarily to workovers in
Andrews County, Texas.
Exploration and abandonments expense. The following table provides a breakdown of our
exploration and abandonments expense for the six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Geological and geophysical |
|
$ |
1,125 |
|
|
$ |
2,317 |
|
Exploratory dry holes |
|
|
1,866 |
|
|
|
(1 |
) |
Leasehold abandonments and other
|
|
|
4,428 |
|
|
|
1,148 |
|
|
|
|
|
|
|
|
Total exploration and abandonments
|
|
$ |
7,419 |
|
|
$ |
3,464 |
|
|
|
|
|
|
|
|
Our geological and geophysical expense, which primarily consists of the costs of acquiring and
processing seismic data, geophysical data and core analysis, during the six months ended June 30,
2009, was $1.1 million, a decrease of $1.2 million from $2.3 million for the six months ended
June 30, 2008. This decrease is primarily attributable to a comprehensive seismic survey on our New
Mexico shelf properties which was initiated in December 2007 and completed in 2008.
During the six months ended June 30, 2009, we wrote-off an unsuccessful exploratory well in
our Arkansas emerging play and two unsuccessful exploratory wells in our Texas Permian area.
For the six months ended June 30, 2009, we recorded approximately $4.4 million of leasehold
abandonments, which relate primarily to the write-off of four non-core prospects in New Mexico and
three non-core prospects in Texas. For the six months ended June 30, 2008, we recorded
$1.1 million of leasehold abandonments, which were primarily related to non-core prospects in
Chaves and Eddy Counties, New Mexico and Andrews and Crane Counties, Texas.
Depreciation, depletion and amortization expense. The following table provides components of
our depreciation, depletion and amortization expense for the six months ended June 30, 2009 and
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Depletion of proved oil and natural gas properties
|
|
$ |
100,995 |
|
|
$ |
19.25 |
|
|
$ |
42,510 |
|
|
$ |
14.86 |
|
Depreciation of other property and equipment
|
|
|
1,374 |
|
|
|
0.26 |
|
|
|
784 |
|
|
|
0.27 |
|
Amortization of intangible asset operating rights
|
|
|
781 |
|
|
|
0.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depletion, depreciation and amortization
|
|
$ |
103,150 |
|
|
$ |
19.66 |
|
|
$ |
43,294 |
|
|
$ |
15.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil price used to estimate proved oil reserves at period end |
|
$ |
66.25 |
|
|
|
|
|
|
$ |
136.50 |
|
|
|
|
|
Natural gas price used to estimate proved gas reserves at period end |
|
$ |
3.72 |
|
|
|
|
|
|
$ |
13.10 |
|
|
|
|
|
Depletion of proved oil and natural gas properties was $101.0 million ($19.25 per Boe) for the
six months ended June 30, 2009, an increase of $58.5 million from $42.5 million ($14.86 per Boe)
for the six months ended June 30, 2008. The increase in depletion expense, on a total and per Boe
basis, was primarily due to (i) the Henry Properties acquisition, for which the depletion rate was
higher than that of our historical assets, (ii) capitalized costs associated with new wells that
were successfully drilled and completed in 2008 and 2009 and (iii) the decrease in the oil and
natural gas prices between the years utilized to determine proved reserves.
50
The amortization of the intangible asset is a result of the value assigned to the operating
rights that we acquired in the Henry Properties acquisition. The intangible asset is currently
being amortized over an estimated life of approximately 25 years.
Impairment of long-lived assets. We periodically review our long-lived assets to be held and
used, including proved oil and natural gas properties accounted for under the successful efforts
method of accounting. Due to downward adjustments to the economically recoverable resource
potential associated with declines in commodity prices and well performance, we recognized a
non-cash charge against earnings of $8.6 million, which was primarily attributable to non-core
natural gas related properties in Eddy and Lea Counties, New Mexico. For the six months ended June
30, 2008, we recognized a non-cash charge against earnings of $0.07 million, which was primarily
attributable to a non-core lease located in Eddy and Lea Counties, New Mexico.
General and administrative expenses. The following table provides components of our general
and administrative expenses for the six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
General and administrative expenses recurring |
|
$ |
21,939 |
|
|
$ |
4.18 |
|
|
$ |
13,741 |
|
|
$ |
4.80 |
|
Non-recurring bonus paid to former Henry Entities employees |
|
|
5,311 |
|
|
|
1.01 |
|
|
|
|
|
|
|
|
|
Non-cash stock-based compensation stock options |
|
|
1,913 |
|
|
|
0.36 |
|
|
|
2,167 |
|
|
|
0.76 |
|
Non-cash stock-based compensation restricted stock |
|
|
2,200 |
|
|
|
0.42 |
|
|
|
862 |
|
|
|
0.30 |
|
Less: Third-party operating fee reimbursements |
|
|
(5,445 |
) |
|
|
(1.04 |
) |
|
|
(504 |
) |
|
|
(0.17 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses |
|
$ |
25,918 |
|
|
$ |
4.93 |
|
|
$ |
16,266 |
|
|
$ |
5.69 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were $25.9 million ($4.93 per Boe) for the six months
ended June 30, 2009, an increase of $9.6 million (59 percent) from $16.3 million ($5.69 per Boe)
for the six months ended June 30, 2008. The increase in general and administrative expenses during
the six months ended June 30, 2009 over 2008 was primarily due to (i) the non-recurring bonus paid
to former Henry Entities employees, (ii) an increase in non-cash stock-based compensation for both
stock options and restricted stock awards and (iii) an increase in the number of employees and
related personnel expenses, partially offset by an increase in third-party operating fee
reimbursements.
In connection with the Henry Entities acquisition, we agreed to pay certain of our employees,
who were formerly Henry Entities employees, a predetermined bonus amount, in addition to the
compensation we pay these employees, over the next two years. Since these employees will earn this
bonus over the next two years, we are reflecting the cost in our general and administrative costs
as non-recurring, as it is not controlled by us. See Note K of the Condensed Notes to Consolidated
Financial Statements included in Item 1. Consolidated Financial Statements (Unaudited) for
additional information related to this bonus.
We earn reimbursements as operator of certain oil and natural gas properties in which we own
interests. As such, we earned reimbursements of $5.4 million and $0.5 million during the six months
ended June 30, 2009 and 2008, respectively. This reimbursement is reflected as a reduction of
general and administrative expenses in the consolidated statements of operations. The increase in
this reimbursement is directly related to the Henry Properties acquisition, as we own a lower
working interest in these operated properties compared to our historical property base, so we
receive a larger third-party reimbursement as compared to our historical property base.
Bad debt expense. On May 20, 2008, we entered into a short-term purchase agreement with an
oil purchaser to buy a portion of our oil affected as a result of the New Mexico refinery shut down
due to repairs. On July 22, 2008, this purchaser declared bankruptcy. We fully reserved the
receivable amount due from this purchaser of approximately $1.8 million as of June 30, 2008, and
are pursuing our claim in the bankruptcy proceedings.
Loss on derivatives not designated as hedges. During the six months ended June 30, 2007, we
determined that all of our natural gas commodity derivative contracts no longer qualified as
hedges. Because we no longer considered these hedges to be highly effective, we discontinued hedge
accounting for those existing hedges, prospectively, and during the period the hedges became
ineffective. In addition, for our new commodity and interest rate derivative contracts entered into
after August 2007, we chose not to designate any of these contracts as hedges. As a result, any
changes in fair value and any cash settlements related to these contracts are
51
recorded in earnings during the related period. All amounts previously recorded in
accumulated other comprehensive income were reclassified to earnings prior to 2009.
The following table sets forth the cash receipts for settlements and the non-cash
mark-to-market adjustment for the derivative contracts not designated as hedges for the six months
ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Cash payments (receipts): |
|
|
|
|
|
|
|
|
Commodity derivatives oil |
|
$ |
(56,412 |
) |
|
$ |
15,965 |
|
Commodity derivatives natural gas |
|
|
(5,832 |
) |
|
|
422 |
|
Financial derivatives interest |
|
|
779 |
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market (gain) loss: |
|
|
|
|
|
|
|
|
Commodity derivatives oil |
|
|
144,099 |
|
|
|
88,900 |
|
Commodity derivatives natural gas |
|
|
5,018 |
|
|
|
14,347 |
|
Financial derivatives interest |
|
|
(1,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
Loss on derivatives not designated as hedges |
|
$ |
86,652 |
|
|
$ |
119,634 |
|
|
|
|
|
|
|
|
Interest expense. Interest expense was $10.6 million for the six months ended June 30, 2009,
an increase of $1.1 million from $9.5 million for the six months ended June 30, 2008. The weighted
average interest rate for the six months ended June 30, 2009 and 2008 was 2.5% and 5.8%,
respectively. The weighted average debt balance during the six months ended June 30, 2009 and 2008
was approximately $668.0 million and $313.3 million, respectively.
The increase in weighted average debt balance during the six months ended June 30, 2009 was
due primarily to borrowings in July 2008 for the acquisition of the Henry Properties. The increase
in interest expense is due to an increase in the weighted average debt balance offset by a decrease
in the weighted average interest rate. The decrease in the weighted average interest rate is
primarily due to an improvement in market interest rates.
Income tax provisions. We recorded an income tax benefit of $33.8 million and income tax
expense of $5.2 million for the six months ended June 30, 2009 and 2008, respectively. The
effective income tax rate for the six months ended June 30, 2009 and 2008 was 42.1 percent and 39.6
percent, respectively. The higher effective tax rate in 2009 compared to 2008 is primarily due to
the estimated annual 2009 permanent tax differences compared to the related current estimated
pre-tax book income.
Capital Commitments, Capital Resources and Liquidity
Capital commitments. Our primary needs for cash are development, exploration and acquisition
of oil and natural gas assets, payment of contractual obligations and working capital obligations.
Funding for these cash needs may be provided by any combination of internally-generated cash flow,
financing under our Credit Facility, proceeds from the disposition of assets or alternative
financing sources, as discussed in Capital resources below.
Oil and natural gas properties. Our capital expenditures on oil and natural gas properties,
excluding acquisitions and asset retirement obligations, during the three months ended June 30,
2009 and 2008 totaled $96.4 million and $66.1 million, respectively, and $202.7 million and $121.3
million for the six months ended June 30, 2009 and 2008, respectively. These expenditures were
primarily funded by cash flow from operations (including effects of derivative cash
receipts/payments).
On November 6, 2008, our board of directors approved a capital budget for 2009 of up to
approximately $500 million. The capital budget is predicated on funding it substantially within
cash flow. In January 2009, in light of the drop in commodity prices, we took actions to reduce our
capital activities to a level that would allow us to fund our capital expenditures substantially
within our cash flow, which at the time resulted in estimated annual capital expenditures of
approximately $300 million. Currently, based on current capital costs and commodity prices we
estimate our capital expenditures to be approximately $400 million for 2009, which we believe we
can substantially fund within our cash flow. We will continue to monitor our capital expenditures,
at least on a quarterly basis, in relation to our cash flow and expect to adjust our activity and
capital spending level based on changes in commodity prices and the cost of goods and services and
other considerations.
52
Other than the purchase of leasehold acreage and other miscellaneous property interests, our
2009 capital budget is exclusive of acquisitions. We do not have a specific acquisition budget
since the timing and size of acquisitions are difficult to forecast. We evaluate opportunities to
purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer
or seller of properties at various times. We seek to acquire oil and natural gas properties that
provide opportunities for the addition of reserves and production through a combination of
exploitation, development, high-potential exploration and control of operations and that will allow
us to apply our operating expertise.
Although we cannot provide any assurance, we believe that our available cash and cash flows
will be sufficient to fund our 2009 capital expenditures, as adjusted from time to time; however,
we could also use our credit facility or other alternative financing sources to fund such
expenditures. The actual amount and timing of our expenditures may differ materially from our
estimates as a result of, among other things, actual drilling results, the timing of expenditures
by third parties on projects that we do not operate, the availability of drilling rigs and other
services and equipment, regulatory, technological and competitive developments and market
conditions. In addition, under certain circumstances we would consider increasing or reallocating
our 2009 capital budget.
Acquisitions. Our expenditures for acquisitions of proved and unproved properties during the
three months ended June 30, 2009 and 2008 totaled $3.3 million and $0.5 million, respectively, and
$3.6 million and $1.4 million for the six months ended June 30, 2009 and 2008, respectively.
Included in previous acquisition amounts are adjustments to the purchase price allocation related
to the acquisition of the Henry Properties of $0.4 million and $0.7 million for the three and six
months ended June 30 , 2009, respectively. The Henry Properties acquisition in July 2008 was
primarily funded by a private placement of our common stock and borrowings under our credit
facility.
Contractual obligations. Our contractual obligations include long-term debt, operating lease
obligations, drilling commitments (including commitments to pay day rates for drilling rigs),
employment agreements, contractual bonus payments, derivative obligations and other liabilities.
Since December 31, 2008, the material changes in our contractual obligations included a $30.0
million increase in outstanding long-term borrowings, a $148.1 million decrease in our net
commodity derivative assets, and a $25.8 million decrease in our drilling commitments. See Note J
of Condensed Notes to Consolidated Financial Statements included in Item 1. Consolidated Financial
Statements (Unaudited) for additional information regarding our long-term debt and Item 3.
Quantitative and Qualitative Disclosures About Market Risk for information regarding the interest
on our long-term debt and information on changes in the fair value of our open derivative
obligations during the three and six months ended June 30, 2009.
Off-balance sheet arrangements. Currently, we do not have any material off-balance sheet
arrangements.
Capital resources. Our primary sources of liquidity have been cash flows generated from
operating activities and financing provided by our credit facility. We believe that funds from
operating cash flows and our credit facility should be sufficient to meet both our short-term
working capital requirements and our 2009 capital budget plans.
Cash flow from operating activities. Our net cash provided by operating activities was $118.2
million and $162.9 million for the six months ended June 30, 2009 and 2008, respectively. The
decrease in operating cash flows during the six months ended June 30, 2009 over 2008 was
principally due to (i) decreases in average realized oil and natural gas prices, offset by
increased production, (ii) increases in oil and natural gas production costs and general and
administrative expenses and (iii) uses of funds associated with working capital.
Cash flow used in investing activities. During the six months ended June 30, 2009 and 2008, we
invested $223.9 million and $122.8 million, respectively, for additions to, and acquisitions of,
oil and natural gas properties, inclusive of dry hole costs. Cash flows used in investing
activities were substantially higher during the three months ended June 30, 2009 over 2008, due to
an increase in our exploration and development activities, offset by the receipts/payments
associated with derivatives not designated as hedges.
Cash flow from financing activities. Net cash provided by (used in) financing activities was
$29.9 million and $(19.5) million for the six months ended June 30, 2009 and 2008, respectively.
During the six months ended June 30, 2009, we had net borrowings of $30.0 million under our credit
facility. During the six months ended June 30, 2008, we reduced our outstanding balance by $26.5
million on our credit facilities.
Our credit facility, as amended, and has a maturity date of July 31, 2013 (the Credit
Facility). At June 30, 2009, we had letters of credit outstanding under the Credit Facility of
approximately $25,000 and our availability to borrow additional funds was approximately $300
million. In April 2009, the lenders reaffirmed our $960 million borrowing base under the Credit
Facility until the next scheduled borrowing base redetermination in October 2009. Between scheduled
borrowing base redeterminations, we and, if requested by 66 2/3 percent of the lenders, the
lenders, may each request one special redetermination.
53
Advances on the Credit Facility bear interest, at our option, based on (i) the prime rate of
JPMorgan Chase Bank (JPM Prime Rate) (3.25 percent at June 30, 2009) or (ii) a Eurodollar rate
(substantially equal to the London Interbank Offered Rate). At June 30,
2009, the interest rates of Eurodollar rate advances and JPM Prime Rate advances vary, with
interest margins ranging from 200 to 300 basis points and 112.5 to 212.5 basis points,
respectively, per annum depending on the debt balance outstanding. At June 30, 2009, we pay
commitment fees on the unused portion of the available borrowing base of 50 basis points per annum.
In conducting our business, we may utilize various financing sources, including the issuance
of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock (iv) common
stock and (v) other securities. We may also sell assets and issue securities in exchange for oil
and natural gas assets or interests in oil and natural gas companies. Additional securities may be
of a class senior to common stock with respect to such matters as dividends and liquidation rights
and may also have other rights and preferences as determined from time to time by our board of
directors. Utilization of some of these financing sources may require approval from the lenders
under our Credit Facility.
Financial markets. The current state of the financial markets is uncertain. There have been
financial institutions that have (i) failed and been forced into government receivership, (ii)
declared bankruptcy, (iii) been forced to seek additional capital and liquidity to maintain
viability or (iv) merged. The United States and world economy is experiencing volatility, which is
having an adverse impact on the financial markets.
At June 30, 2009, we had $300.0 million of available borrowing capacity under our Credit
Facility. Even in light of the current volatility in the financial markets, we currently believe
that the lenders under our Credit Facility have the ability to fund additional borrowings we may
need for our business.
We currently pay floating rate interest under our Credit Facility and we are unable to
predict, especially in light of the current uncertainty in the financial markets, whether we will
incur increased interest costs due to rising interest rates. We have utilized the use of interest
rate derivatives to mitigate the cost of rising interest rates, and we may enter into additional
interest rate derivatives in the future. Additionally, we may issue fixed rate debt in the future
to increase available borrowing capacity under our Credit Facility or to reduce our exposure to the
volatility of interest rates.
In the current financial markets, we do not believe that we could refinance our Credit
Facility and obtain comparable terms. Since our Credit Facility matures in July 2013, we have no
immediate need to seek refinancing of our Credit Facility.
To the extent we need additional funds, beyond those available under our Credit Facility, to
operate our business or make acquisitions we would have to pursue other financing sources. These
sources could include issuance of (i) fixed and floating rate debt, (ii) convertible securities,
(iii) preferred stock, (iv) common stock or (v) other securities. We may also sell assets.
However, in light of the current financial market conditions there are no assurances that we could
obtain additional funding, or if available, at what cost and terms.
Liquidity. Our principal sources of short-term liquidity are cash on hand and available
borrowing capacity under our Credit Facility. At June 30, 2009, we had $3.1 million of cash on
hand.
At June 30, 2009, the borrowing base under our credit facility was $960 million, which
provided us with $300.0 million of available borrowing capacity. Our borrowing base is
redetermined semi-annually, with the next redetermination occurring in October 2009. In addition to
such semi-annual redeterminations, our lenders may request one additional redetermination during
any twelve-month period. In general, redeterminations are based upon a number of factors,
including commodity prices and reserve levels. Upon a redetermination, our borrowing base could be
substantially reduced. In light of the current commodity prices and the state of the financial
markets, there is no assurance that our borrowing base will not be reduced.
Book capitalization and current ratio. Our book capitalization at June 30, 2009 was $1,949.6
million, consisting of debt of $660.0 million and stockholders equity of $1,289.6 million. Our
debt to book capitalization was 34 percent and 32 percent at June 30, 2009 and December 31, 2008,
respectively. Our ratio of current assets to current liabilities was 0.76 to 1.00 at June 30, 2009
as compared to 1.03 to 1.00 at December 31, 2008.
Inflation and changes in prices. Our revenues, the value of our assets, and our ability to
obtain bank financing or additional capital on attractive terms have been and will continue to be
affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are
subject to significant fluctuations that are beyond our ability to control or predict. During the
three months ended
54
June 30, 2009, we received an average of $55.44 per barrel of oil and $4.77 per
Mcf of natural gas before consideration of commodity derivative contracts compared to $121.00 per
barrel of oil and $12.52 per Mcf of natural gas in the three months ended June 30, 2008. Although
certain of our costs are affected by general inflation, inflation does not normally have a
significant effect on our business. In a trend that began in 2004 and continued through the first
six months of 2008, commodity prices for oil and natural gas increased significantly. The higher
prices have led to increased activity in the industry and, consequently, rising costs. These cost
trends have put pressure not only on our operating costs but also on capital costs. We expect these
costs to continue to moderate during the remainder of 2009 as a result of the recent rapid
diminution in prices for oil and natural gas from 2008 peaks.
Critical Accounting Policies, Practices and Estimates
Our historical consolidated financial statements and related notes to consolidated financial
statements contain information that is pertinent to our managements discussion and analysis of
financial condition and results of operations. Preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires that our management
make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities,
revenues and expenses, and the disclosure of contingent assets and liabilities. However, the
accounting principles used by us generally do not change our reported cash flows or liquidity.
Interpretation of the existing rules must be done and judgments made on how the specifics of a
given rule apply to us.
In managements opinion, the more significant reporting areas impacted by managements
judgments and estimates are revenue recognition, the choice of accounting method for oil and
natural gas activities, oil and natural gas reserve estimation, asset retirement obligations,
impairment of long-lived assets and valuation of stock-based compensation. Managements judgments
and estimates in these areas are based on information available from both internal and external
sources, including engineers, geologists and historical experience in similar matters. Actual
results could differ from the estimates, as additional information becomes known.
There have been no material changes in our critical accounting policies and procedures during
the three months ended June 30, 2009. See our disclosure of critical accounting policies in the
consolidated financial statements on our Annual Report on Form 10-K for the year ended December 31,
2008, filed with the SEC on February 27, 2009.
Recent Accounting Pronouncements and Developments
Recent accounting pronouncements. In December 2007, the Financial Accounting Standards Board
(FASB) issued SFAS No. 141(R), Business Combinations (SFAS No. 141(R)), which replaces FASB
Statement No. 141. SFAS No. 141(R) establishes principles and requirements for how an acquirer
recognizes and measures in its financial statements the identifiable assets acquired, the
liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS
No. 141(R) also establishes disclosure requirements that will enable users to evaluate the nature
and financial effects of the business combination. SFAS No. 141(R) is effective for acquisitions
that occur in an entitys fiscal year that begins after December 15, 2008. We adopted SFAS No.
141(R) effective January 1, 2009. There has been no impact on our consolidated financial
statements, as we have not entered into any significant business combinations during 2009.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements an amendment of ARB No. 51 (SFAS No. 160). SFAS No. 160 requires that
accounting and reporting for minority interests will be recharacterized as noncontrolling interests
and classified as a component of equity. SFAS No. 160 also establishes reporting requirements that
provide sufficient disclosures that clearly identify and distinguish between the interests of the
parent and the interests of the noncontrolling owners. SFAS No. 160 applies to all entities that
prepare consolidated financial statements, except not-for-profit organizations, but will affect
only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or
that deconsolidate a subsidiary. This statement is effective as of the beginning of an entitys
first fiscal year beginning after December 15, 2008. We adopted SFAS No. 160 effective January 1,
2009, with no impact on our consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities (SFAS No. 161), which amends and expands the interim and annual disclosure
requirements of SFAS No. 133 to provide an enhanced understanding of an entitys use of derivative
instruments, how they are accounted for under SFAS No. 133 and their effect on the entitys
financial position, financial performance and cash flows. The provisions of SFAS No. 161 are
effective as of January 1, 2009. We adopted SFAS No. 161 effective January 1, 2009, with no
significant impact on our consolidated financial statements, other than additional disclosures
which are set forth in Notes H and I of the Condensed Notes to Consolidated Financial Statements
included in Item 1. Consolidated Financial Statements (Unaudited).
In April 2008, the FASB issued FASB Staff Position (FSP) No. SFAS 142-3, Determination of
the Useful Life of Intangible Assets (FSP SFAS No. 142-3). FSP SFAS No. 142-3 amends the factors
that should be considered in developing renewal or extension assumptions used to determine the
useful life of a recognized intangible asset
55
under SFAS No. 142, Goodwill and Other Intangible
Assets (SFAS No. 142). The intent of FSP SFAS No. 142-3 is to improve the consistency between
the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash
flows used to measure the fair value of the asset under SFAS No. 141R and other applicable
accounting literature. FSP SFAS No. 142-3 is effective for financial statements issued for fiscal
years beginning after December 15, 2008 and must be applied prospectively to intangible assets
acquired after the effective date. We adopted FSP SFAS No. 142-3 effective January 1, 2009, with
no significant impact on our consolidated financial statements.
In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting
Principles (SFAS No. 162), which identifies the sources of accounting principles and the
framework for selecting the principles used in the preparation of financial statements of
nongovernmental entities that are presented in conformity with generally accepted accounting
principles (GAAP) in the United States of America. SFAS No. 162 arranges these sources of GAAP in
a hierarchy for users to apply accordingly. This
statement became effective for us on November 15, 2008. The adoption of SFAS No. 162 did not
have a significant impact on our consolidated financial statements. In June 2009, this statement
was replaced with SFAS No. 168, The FASB Accounting Standards Codification (Codification) and
the Hierarchy of Generally Accepted Accounting Principles (SFAS No. 168). Once the Codification
is in effect, all of its content will carry the same level of authority, effectively superseding
SFAS No. 162. In other words, the GAAP hierarchy will be modified to include only two levels of
GAAP: authoritative and nonauthoritative. SFAS No. 168 is effective for financial statements issued
for interim and annual periods ending after September 15, 2009. We do not expect the adoption of
SFAS No. 168 to have an impact on our consolidated financial statements.
In June 2008, the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments Granted in
Share-Based Payment Transactions Are Participating Securities, (FSP EITF 03-6-1) which provides
that unvested share-based payment awards that contain non-forfeitable rights to dividends or
dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to
be included in the earnings allocation in computing earnings per share under the two class method.
FSP EITF 03-6-1 was effective for us on January 1, 2009. There was no impact on our consolidated
financial statements.
In April 2009, the FASB issued FSP SFAS No. 141(R)-1, Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination That Arise from Contingencies. This FSP amends and
clarifies SFAS No. 141(R) 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. This FSP is effective for assets or liabilities arising from contingencies in
business combinations for which the acquisition date is on or after the beginning of the first
annual reporting period beginning on or after December 15, 2008. We have not made any acquisitions
during 2009, and as such, the adoption of this statement on January 1, 2009 did not have a
significant impact.
In April 2009, the FASB issued FSP SFAS No. 107-1 and APB Opinion No. 28-1, Interim
Disclosures about Fair Value of Financial Instrument (FSP SFAS No. 107-1). This FSP amends FASB
Statement 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 FSP also amends APB Opinion No. 28,
Interim Financial Reporting, to require those disclosures in summarized financial information at
interim reporting periods. This FSP is effective for interim reporting periods ending after June
15, 2009. This FSP does not require disclosures for earlier periods presented for comparative
purposes at initial adoption. In periods after initial adoption, this FSP requires comparative
disclosures only for periods ending after initial adoption. As of June 15, 2009, we adopted the
provisions of FSP SFAS No. 107-1 related to the fair value of financial instruments. The adoption
of the provisions of FSP SFAS No. 107-1 did not have a material effect on our financial condition
or results of operations. See Note H for additional disclosures required by FSP SFAS No. 107-1.
In April 2009, the FASB issued FSP SFAS No. 157-4, Determining Fair Value When the Volume and
Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying
Transactions That Are Not Orderly (FSP SFAS No. 157-4). This FSP:
|
|
|
Affirms that the objective of fair value when the market for an asset is not active
is the price that would be received to sell the asset in an orderly transaction; |
|
|
|
|
Clarifies and includes additional factors for determining whether there has been a
significant decrease in market activity for an asset when the market for that asset is
not active; |
|
|
|
|
Eliminates the proposed presumption that all transactions are distressed (not
orderly) unless proven otherwise. The FSP instead requires an entity to base its
conclusion about whether a transaction was not orderly on the weight of the evidence; |
|
|
|
|
Includes an example that provides additional explanation on estimating fair value
when the market activity for an asset has declined significantly; |
56
|
|
|
Requires an entity to disclose a change in valuation technique (and the related
inputs) resulting from the application of the FSP and to quantify its effects, if
practicable; and |
|
|
|
|
Applies to all fair value measurements when appropriate. |
FSP SFAS No. 157-4 must be applied prospectively and retrospective application is not
permitted. FSP SFAS No. 157-4 is effective for interim and annual periods ending after June 15,
2009. As of June 15, 2009, we adopted the provisions of FSP SFAS No. 157-4 related to assets and
liabilities that are measured at fair value on a recurring and nonrecurring basis. The adoption of
the provisions of FSP SFAS No. 157-4 did not have a material effect on our financial condition or
results of operations. See Note H of the Condensed Notes to Consolidated Financial Statements
included in Item 1. Consolidated Financial Statements (Unaudited) for additional information
regarding our adoption of FSP SFAS No. 157-4.
In May 2009, the FASB issued SFAS No. 165, Subsequent Events (SFAS No. 165) which
establishes general standards of accounting for and disclosure of events that occur after the
balance sheet date, but before financial statements are issued or are available to be issued. In
particular, SFAS No. 165 sets forth:
|
|
|
The period after the balance sheet date during which management of a reporting entity
should evaluate events or transactions that may occur for potential recognition or
disclosure in the financial statements; |
|
|
|
|
The circumstances under which a reporting entity should recognize events or
transactions occurring after the balance sheet date in its financial statements; and |
|
|
|
|
The disclosures that a reporting entity should make about events or transactions that
occurred after the balance sheet date. |
In accordance with this Statement, a reporting entity should apply the requirements to interim
or annual financial periods ending after June 15, 2009. See Note P of the Condensed Notes to
Consolidated Financial Statements included in Item 1. Consolidated Financial Statements
(Unaudited).
In June 2009, the FASB issued SFAS No. 166, Accounting for Transfers of Financial Assets
(SFAS No. 166), which amends SFAS No. 140, Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities. This statement improves the relevance, representational
faithfulness, and comparability of the information that a reporting entity provides in its
financial reports about a transfer of financial assets; the effects of a transfer on its financial
position, financial performance, and cash flows; and a transferors continuing involvement in
transferred financial assets. SFAS No. 166 must be applied as of the beginning of each reporting
entitys first annual reporting period that begins after November 15, 2009, for interim periods
within that first annual reporting period and for interim and annual reporting periods thereafter.
Earlier application is prohibited. SFAS No. 166 must be applied to transfers occurring on or after
the effective date. We do not expect the adoption of SFAS No. 166 to have an impact on our
consolidated financial statements.
Recent developments in reserves reporting. In December 2008, the United States Securities and
Exchange Commission (the SEC) released Final Rule, Modernization of Oil and Gas Reporting (the
Reserve Ruling). The Reserve Ruling revises oil and gas reporting disclosures. The Reserve
Ruling permits the use of new technologies to determine proved reserves estimates if those
technologies have been demonstrated empirically to lead to reliable conclusions about reserve
volume estimates. The Reserve Ruling will also allow, but not require, companies to disclose their
probable and possible reserves to investors in documents filed with the SEC. In addition, the new
disclosure requirements require companies to: (i) report the independence and qualifications of its
reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare
reserves estimates or conduct a reserves audit; and (iii) report oil and gas reserves using an
average price based upon the prior 12-month period rather than a year-end price. The Reserve
Ruling becomes effective for fiscal years ending on or after December 31, 2009. We are currently
assessing the impact that adoption of the provisions of the Reserve Ruling will have on our
financial position, results of operations and disclosures.
57
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The following market risk disclosures should be read in conjunction with the quantitative and
qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year
ended December 31, 2008.
We are exposed to a variety of market risks including credit risk, commodity price risk and
interest rate risk. We address these risks through a program of risk management which includes the
use of derivative instruments. The following quantitative and qualitative information is provided
about financial instruments to which we are a party at June 30, 2009, and from which we may incur
future gains or losses from changes in market interest rates or commodity prices and losses from
extension of credit. We do not enter into derivative or other financial instruments for
speculative or trading purposes.
Hypothetical changes in interest rates and commodity prices chosen for the following estimated
sensitivity analysis are considered to be reasonably possible near-term changes generally based on
consideration of past fluctuations for each risk category. However, since it is not possible to
accurately predict future changes in interest rates and commodity prices, these hypothetical
changes may not necessarily be an indicator of probable future fluctuations.
Credit risk. We monitor our risk of loss due to non-performance by counterparties of their
contractual obligations. Our principal exposure to credit risk is through the sale of our oil and
natural gas production, which we market to energy marketing companies and refineries. We monitor
our exposure to these counterparties primarily by reviewing credit ratings, financial statements
and payment history. We extend credit terms based on our evaluation of each counterpartys
creditworthiness. Although we have not generally required our counterparties to provide collateral
to support their obligation to us, we may, if circumstances dictate, require collateral in the
future. In this manner, we reduce credit risk.
Commodity price risk. We are exposed to market risk as the prices of oil and natural gas are
subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to
changes in the prices of oil and natural gas we have entered into, and may in the future enter into
additional commodity price risk management arrangements for a portion of our oil and natural gas
production. The agreements that we have entered into generally have the effect of providing us with
a fixed price for a portion of our expected future oil and natural gas production over a fixed
period of time. Our commodity price risk management activities could have the effect of reducing
net income and the value of our common stock. At June 30, 2009, the net unrealized asset on our
commodity price risk management contracts was $24.3 million. An average increase in the commodity
price of $10.00 per barrel of oil and $1.00 per Mcf for natural gas from the commodity prices at
June 30, 2009, would have resulted in a net unrealized liability on our commodity price risk
management contracts, as reflected on our consolidated balance sheet at June 30, 2009, of
approximately $81.0 million.
At June 30, 2009, we had (i) an oil price collar and oil price swaps that settle on a monthly
basis covering future oil production from July 1, 2009 through December 31, 2012 and (ii) a natural
gas price swap, natural gas price collars and natural gas basis swaps covering future natural gas
production from July 1, 2009 to December 31, 2011, see Note I of the Condensed Notes to
Consolidated Financial Statements included in Item 1. Consolidated Financial Statements
(Unaudited) for additional information on the commodity derivative contracts. The average NYMEX
oil futures price and average NYMEX natural gas futures prices for the three months ended June 30,
2009, was $59.83 per Bbl and $3.80 per MMBtu, respectively. At August 3, 2009, the NYMEX oil
futures price and NYMEX natural gas futures price was $71.58 per Bbl and $4.03 per MMBtu,
respectively. The decrease in oil and natural gas prices, should it continue during 2009, should
increase the fair value asset of our commodity derivative contracts from their recorded balance at
June 30, 2009. Changes in the recorded fair value of the undesignated commodity derivative
contracts are marked to market through earnings as unrealized gains or losses. The potential
increase in fair value asset would be recorded in earnings as unrealized gains. However, an
increase in the average NYMEX oil and natural gas futures price above those at June 30, 2009 would
result in an decrease in fair value asset and unrealized losses in earnings. We are currently
unable to estimate the effects on the earnings of future periods resulting from changes in the
market value of our commodity derivative contracts.
Interest rate risk. Our exposure to changes in interest rates relates primarily to long-term
debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a
certain percentage of total capitalization and by monitoring the effects of market changes in
interest rates. To reduce our exposure to changes in interest rates we have entered into, and may
in the future enter into additional interest rate risk management arrangements for a portion of our
outstanding debt. The agreements that we have entered into generally have the effect of providing
us with a fixed interest rate for a portion of our variable rate debt. We may utilize interest rate
derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related
to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure
and not to modify the overall leverage of the debt portfolio. We are exposed to changes in interest
rates as a result of our credit facility, and the terms of our credit facility require us to pay
higher interest rate margins as we utilize a larger percentage of our available borrowing base.
58
At June 30, 2009, we had interest rate swaps on $300 million of notional principal that fixed
the LIBOR interest rate (does not include the interest rate margins discussed above) at 1.90
percent for the three years beginning in May 2009. An average decrease in future interest rates of
25 basis points from the future rate at June 30, 2009, would have resulted in a net unrealized
liability on our
interest rate risk management contracts, as reflected on our consolidated balance sheet at
June 30, 2009, of approximately $2.1 million.
We had total indebtedness of $660 million outstanding under our credit facility at June 30,
2009. The impact of a 1 percent increase in interest rates on this amount of debt would result in
increased annual interest expense of approximately $6.6 million.
The fair value of our derivative instruments is determined based on our valuation models. We
did not change our valuation method during 2009. During 2009, we were party to commodity
derivative instruments. See Note I of the Condensed Notes to Consolidated Financial Statements
included in Item 1. Consolidated Financial Statements (Unaudited) for additional information
regarding our derivative instruments. The following table reconciles the changes that occurred in
the fair values of our derivative instruments during the six months ended June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Instruments Net Assets (Liabilities) (a) |
|
(in thousands) |
|
Commodities |
|
|
Interest Rate |
|
|
Total |
|
|
Fair value of contracts outstanding at December 31, 2008 |
|
$ |
173,523 |
|
|
$ |
(1,083 |
) |
|
$ |
172,440 |
|
Changes in fair values (b) |
|
|
(86,873 |
) |
|
|
221 |
|
|
|
(86,652 |
) |
Contract maturities |
|
|
(62,244 |
) |
|
|
779 |
|
|
|
(61,465 |
) |
|
|
|
|
|
|
|
|
|
|
Fair value of contracts outstanding at June 30, 2009 |
|
$ |
24,406 |
|
|
$ |
(83 |
) |
|
$ |
24,323 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Represents the fair values of open derivative contracts subject to market risk. |
|
(b) |
|
At inception, new derivative contracts entered into by us have no intrinsic value. |
59
Item 4. Controls and Procedures
Evaluation of disclosure controls and procedures. The Companys management, with the
participation of its principal executive officer and principal financial officer, have evaluated,
as required by Rule 13a-15(b) under the Exchange Act, the Companys disclosure controls and
procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this
report. Based on that evaluation, the Companys principal executive officer and principal financial
officer concluded that the design and operation of the Companys disclosure controls and procedures
are effective in ensuring that information required to be disclosed by the Company in the reports
that it files or submits under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the SECs rules and forms.
Changes in internal control over financial reporting. There have been no changes in the
Companys internal controls over financial reporting (as defined in Rule 13a-15(f) under the
Exchange Act) that occurred during the Companys last fiscal quarter that have materially affected
or are reasonably likely to materially affect the Companys internal controls over financial
reporting.
60
PART II OTHER INFORMATION
Item 1. Legal Proceedings
We are party to the legal proceedings described under Legal actions in Note K of Notes to
Consolidated Financial Statements included in Item 1. Consolidated Financial Statements
(Unaudited). We are also party to other proceedings and claims incidental to our business. While
many of these other matters involve inherent uncertainty, we believe that the amount of the
liability, if any, ultimately incurred with respect to such proceedings and claims will not have a
material adverse effect on our consolidated financial position as a whole or on our liquidity,
capital resources or future results of operations.
Item 1A. Risk Factors
In addition to the other information set forth in this Report, you should carefully consider
the risks discussed in the Companys Annual Report on Form 10-K for the year ended December 31,
2008, under the headings Item 1. Business Competition, Marketing Arrangements and Applicable
Laws and Regulations, Item 1A. Risk Factors and Item 7A. Quantitative and Qualitative
Disclosures About Market Risk, which risks could materially affect the Companys business,
financial condition or future results. Except for the risk factors set forth below, there have
been no material changes in the Companys risk factors from those described in its Annual Report on
Form 10-K for the year ended December 31, 2008.
Certain federal income tax deductions currently available with respect to oil and gas
exploration and development may be eliminated as a result of future legislation.
President Obamas Proposed Fiscal Year 2010 Budget includes proposed legislation that would,
if enacted into law, make significant changes to United States tax laws, including the elimination
of certain key U.S. federal income tax incentives currently available to oil and natural gas
exploration and production companies. These changes include, but are not limited to (i) the repeal
of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of
current deductions for intangible drilling and development costs, (iii) the elimination of the
deduction for certain domestic production activities, and (iv) an extension of the amortization
period for certain geological and geophysical expenditures. It is unclear whether any such changes
will be enacted or how soon any such changes could become effective. The passage of any
legislation as a result of these proposals or any other similar changes in U.S. federal income tax
laws could eliminate or otherwise limit certain tax deductions that are currently available with
respect to oil and gas exploration and development, and any such change could negatively impact our
financial condition and results of operations.
The adoption of climate change legislation by Congress could result in increased operating
costs and reduced demand for the oil and natural gas we produce.
On June 26, 2009, the U.S. House of Representatives approved adoption of the American Clean
Energy and Security Act of 2009, also known as the Waxman-Markey cap-and-trade legislation or
ACESA. The purpose of ACESA is to control and reduce emissions of greenhouse gases, or GHGs,
in the United States. GHGs are certain gases, including carbon dioxide and methane, that may be
contributing to warming of the Earths atmosphere and other climatic changes. ACESA would
establish an economy-wide cap on emissions of GHGs in the United States and would require an
overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050.
Under ACESA, most sources of GHG emissions would be required to obtain GHG emission allowances
corresponding to their annual emissions of GHGs. The number of emission allowances issued each
year would decline as necessary to meet ACESAs overall emission reduction goals. As the number of
GHG emission allowances declines each year, the cost or value of allowances is expected to escalate
significantly. The net effect of ACESA will be to impose increasing costs on the combustion of
carbon-based fuels such as oil, refined petroleum products, and natural gas.
The U.S. Senate has begun work on its own legislation for controlling and reducing emissions
of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA,
the Senate legislation would need to be reconciled with ACESA and both chambers would be required
to approve identical legislation before it could become law. President Obama has indicated that he
is in support of the adoption of legislation to control and reduce emissions of GHGs through an
emission allowance permitting system that results in fewer allowances being issued each year but
that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission
obligations. Although it is not possible at this time to predict whether or when the Senate may
act on climate change legislation or how any bill approved by the Senate would be reconciled with
ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could
require us to incur increased operating costs, and could have an adverse effect on demand for the
oil and natural gas we produce.
61
The adoption of derivatives legislation by Congress could have an adverse impact on our
ability to hedge risks associated with our business.
Congress is currently considering legislation to impose restrictions on certain transactions
involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA
contains provisions that would prohibit private energy commodity derivative and hedging
transactions. ACESA would expand the power of the Commodity Futures Trading Commission, or CFTC,
to regulate derivative transactions related to energy commodities, including oil and natural gas,
and to mandate clearance of such derivative contracts through registered derivative clearing
organizations. Under ACESA, the CFTCs expanded authority over energy derivatives would terminate
upon the adoption of general legislation covering derivative regulatory reform. The CFTC is
conducting hearings to determine whether to set limits on trading and positions in commodities with
finite supply, particularly energy commodities, such as crude oil, natural gas and other energy
products. The CFTC also is evaluating whether position limits should be applied consistently
across all markets and participants. In addition, the Treasury Department recently has indicated
that it intends to propose legislation to subject all over-the-counter, or OTC, derivative dealers
and all other major OTC derivatives market participants to substantial supervision and regulation,
including by imposing conservative capital and margin requirements and strong business conduct
standards. Derivatives contracts that are not cleared through central clearinghouses and exchanges
may be subject to substantially higher capital and margin requirements. Although it is not
possible at this time to predict whether or when the Senate may act on derivatives legislation or
how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that
may be adopted that subject us to additional capital or margin requirements relating to, or
additional restrictions on, our trading and commodity positions could have an adverse impact on our
ability to hedge risks associated with our business.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing
could result in increased costs and additional operating restrictions or delays.
Congress is currently considering legislation to amend the federal Safe Drinking Water Act to
require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing
process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure
into rock formations to stimulate oil and natural gas production. Sponsors of bills currently
pending before the Senate and House of Representatives have asserted that chemicals used in the
fracturing process may be impacting drinking water supplies. The proposed legislation would require
the reporting and public disclosure of chemicals used in the fracturing process, which could make
it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings
based on allegations that specific chemicals used in the fracturing process are impairing
groundwater or causing other damage. In addition, these bills, if adopted, could establish an
additional level of regulation at the federal level that could lead to operational delays or
increased operating costs and could result in additional regulatory burdens that could make it more
difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total number |
|
|
Maximum |
|
|
|
|
|
|
|
|
|
|
|
of shares |
|
|
number of |
|
|
|
|
|
|
|
|
|
|
|
purchased as |
|
|
shares that |
|
|
|
Total number |
|
|
|
|
|
|
part of publicly |
|
|
may yet be |
|
|
|
of shares |
|
|
Average price |
|
|
announced |
|
|
purchased |
|
Period |
|
withheld (1) |
|
|
per share |
|
|
plans |
|
|
under the plan |
|
April 1, 2009 - April 30, 2009 |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
May 1, 2009 - May 31, 2009 |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
June 1, 2009 - June 30, 2009 |
|
|
6,199 |
|
|
$ |
31.14 |
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents shares that were withheld by the Company to satisfy tax withholding obligations of certain executive officers that
arose upon the lapse of restrictions on restricted stock. |
62
Item 4. Submission of Matters to a Vote of Security Holders
The 2009 Annual Meeting of Stockholders of Concho Resources Inc. (Annual Meeting) was held
on June 2, 2009, in Midland, Texas for the following purposes: (i) to elect two Class II directors,
each for a term of three years; (ii) to ratify the Audit Committee of the Board of Directors
selection of Grant Thornton LLP as the independent registered public accounting firm of the Company
for the fiscal year ending December 31, 2009; and (iii) to transact such other business as may
properly come before the Annual Meeting or any adjournments or postponements thereof.
Proxies for the Annual Meeting were solicited by the Board pursuant to Regulation 14A under
the Securities Exchange Act of 1934 as amended and there was no solicitation in opposition to the
Boards nominees for director.
Each of the nominees for director was duly elected, with votes as follows:
|
|
|
|
|
|
|
|
|
Nominee |
|
Shares for |
|
Shares
withheld |
Steven L. Beal |
|
|
75,380,942 |
|
|
|
529,097 |
|
Tucker S. Bridwell |
|
|
74,692,704 |
|
|
|
1,217,335 |
|
The appointment of Grant Thornton LLP, independent public accountants, as the Companys
auditors for the year ending December 31, 2009, was ratified by the Companys stockholders by the
following vote: 74,781,613 for; 1,122,272 shares against; and 6,152 shares abstaining.
Item 6. Exhibits
|
|
|
Exhibit Number |
|
Exhibit |
|
|
|
4.1
|
|
First Amendment to Amended and Restated Credit Agreement dated as of April 7, 2009, with the
lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 4.1
to the Companys Current Report on Form 8-K on April 9, 2009, and incorporated herein by
reference). |
|
|
|
10.1
|
|
Consulting Agreement dated June 9, 2009, by and between Concho Resources Inc. and Steven L. Beal
(filed as Exhibit 10.1 to the Companys Current Report on Form 8-K on June 12, 2009, and
incorporated herein by reference). |
|
|
|
31.1 (a)
|
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
31.2 (a)
|
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.1 (b)
|
|
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.2 (b)
|
|
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
(a) |
|
Filed herewith. |
|
(b) |
|
Furnished herewith. |
63
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
|
|
CONCHO RESOURCES INC.
|
|
Date: August 6, 2009 |
By |
|
/s/ Timothy A. Leach |
|
|
| |
Timothy A. Leach |
|
| |
|
Director, Chairman of the Board of Directors,
Chief Executive Officer, and President
(Principal Executive Officer) |
|
|
|
|
|
|
By |
|
/s/ Darin G. Holderness |
|
| |
|
Darin G. Holderness |
|
| |
|
Vice President, Chief Financial Officer and Treasurer
(Principal Financial and Accounting Officer) |
|
64
EXHIBIT INDEX
|
|
|
Exhibit Number |
|
Exhibit |
|
|
|
4.1
|
|
First Amendment to Amended and Restated Credit Agreement dated as of April 7, 2009, with the
lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 4.1
to the Companys Current Report on Form 8-K on April 9, 2009, and incorporated herein by
reference). |
|
|
|
10.1
|
|
Consulting Agreement dated June 9, 2009, by and between Concho Resources Inc. and Steven L. Beal
(filed as Exhibit 10.1 to the Companys Current Report on Form 8-K on June 12, 2009, and
incorporated herein by reference). |
|
|
|
31.1 (a)
|
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
31.2 (a)
|
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.1 (b)
|
|
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.2 (b)
|
|
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
(a) |
|
Filed herewith. |
|
(b) |
|
Furnished herewith. |