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 March 31, 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.
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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 May 6,
2009: 85,379,988 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, as amended, (the Securities Act) and Section 21E of the Securities
Exchange Act of 1934, as amended, (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 detailed in our Annual Report on Form 10-K for the year ended December 31, 2008 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
PART I FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements (Unaudited)
iii
Concho Resources Inc.
Consolidated Balance Sheets
Unaudited
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March 31, |
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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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$ |
2,407 |
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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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50,799 |
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48,793 |
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Joint operations and other |
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108,670 |
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92,833 |
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Related parties |
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260 |
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314 |
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Derivative instruments |
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86,082 |
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113,149 |
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Prepaid costs and other |
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4,361 |
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5,942 |
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Total current assets |
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252,579 |
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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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2,791,035 |
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2,693,574 |
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Accumulated depletion and depreciation |
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(357,585 |
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(306,990 |
) |
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Total oil and natural gas properties, net |
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2,433,450 |
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2,386,584 |
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Other property and equipment, net |
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15,155 |
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14,820 |
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Total property and equipment, net |
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2,448,605 |
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2,401,404 |
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Deferred loan costs, net |
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14,845 |
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15,701 |
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Inventory |
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26,277 |
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19,956 |
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Intangible asset, net operating rights |
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37,724 |
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37,768 |
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Noncurrent derivative instruments |
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48,649 |
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61,157 |
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Other assets |
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467 |
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434 |
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Total assets |
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$ |
2,829,146 |
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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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$ |
22,082 |
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$ |
7,462 |
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Related parties |
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895 |
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312 |
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Other current liabilities: |
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Bank overdrafts |
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4,431 |
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9,434 |
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Revenue payable |
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24,559 |
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22,286 |
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Accrued and prepaid drilling costs |
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133,006 |
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154,196 |
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Derivative instruments |
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2,685 |
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1,866 |
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Deferred income taxes |
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26,504 |
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37,205 |
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Other current liabilities |
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36,343 |
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38,057 |
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Total current liabilities |
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250,505 |
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270,818 |
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Long-term debt |
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670,750 |
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630,000 |
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Noncurrent derivative instruments |
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1,777 |
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Deferred income taxes |
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572,789 |
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573,763 |
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Asset retirement obligations and other long-term liabilities |
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16,662 |
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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, $0.001 par value; 300,000,000 authorized; 85,166,705 and 84,828,824
shares issued at March 31, 2009 and December 31, 2008, respectively |
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85 |
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85 |
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Additional paid-in capital |
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1,013,759 |
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1,009,025 |
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Retained earnings |
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302,944 |
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316,169 |
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Treasury stock, at cost; 3,142 shares at March 31, 2009 and December 31, 2008 |
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(125 |
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(125 |
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Total stockholders equity |
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1,316,663 |
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1,325,154 |
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Total liabilities and stockholders equity |
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$ |
2,829,146 |
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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 March 31, |
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(in thousands, except per share amounts) |
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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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$ |
64,974 |
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$ |
75,818 |
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Natural gas sales |
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21,028 |
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30,893 |
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Total operating revenues |
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86,002 |
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106,711 |
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Operating costs and expenses: |
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Oil and natural gas production |
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24,766 |
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16,895 |
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Exploration and abandonments |
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5,995 |
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2,741 |
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Depreciation, depletion and amortization |
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50,748 |
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21,284 |
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Accretion of discount on asset retirement obligations |
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278 |
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153 |
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Impairments of long-lived assets |
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4,056 |
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16 |
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General and administrative (including non-cash stock-based
compensation of $1,925 and $1,299 for the three months ended
March 31, 2009 and 2008, respectively) |
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11,746 |
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7,680 |
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Ineffective portion of cash flow hedges |
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(564 |
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Loss on derivatives not designated as hedges |
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5,046 |
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17,178 |
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Total operating costs and expenses |
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102,635 |
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65,383 |
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Income (loss) from operations |
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(16,633 |
) |
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41,328 |
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Other income (expense): |
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Interest expense |
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(4,370 |
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(5,615 |
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Other, net |
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(328 |
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1,020 |
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Total other expense |
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(4,698 |
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(4,595 |
) |
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Income (loss) before income taxes |
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(21,331 |
) |
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36,733 |
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Income tax (expense) benefit |
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8,106 |
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(14,368 |
) |
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Net income (loss) |
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$ |
(13,225 |
) |
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$ |
22,365 |
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Basic earnings per share: |
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Net income (loss) per share |
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$ |
(0.16 |
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$ |
0.30 |
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Weighted average shares used in basic earnings per share |
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84,529 |
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75,473 |
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Diluted earnings per share: |
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Net income (loss) per share |
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$ |
(0.16 |
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$ |
0.29 |
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Weighted average shares used in diluted earnings per share |
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84,529 |
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76,886 |
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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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(13,225 |
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(13,225 |
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Stock options exercised |
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248 |
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2,005 |
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2,005 |
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Stock-based compensation for restricted stock |
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91 |
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897 |
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897 |
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Cancellation of restricted stock |
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(1 |
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Stock-based compensation for stock options |
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1,028 |
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1,028 |
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Excess tax benefits related to stock-based compensation |
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804 |
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|
804 |
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BALANCE AT MARCH 31, 2009 |
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85,167 |
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$ |
85 |
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$ |
1,013,759 |
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$ |
302,944 |
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3 |
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$ |
(125 |
) |
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$ |
1,316,663 |
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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
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Three Months Ended March 31, |
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(in thousands) |
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2009 |
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2008 |
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CASH FLOWS FROM OPERATING ACTIVITIES: |
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Net income (loss) |
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$ |
(13,225 |
) |
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$ |
22,365 |
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Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
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Depreciation, depletion and amortization |
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50,748 |
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21,284 |
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Impairments of long-lived assets |
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4,056 |
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16 |
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Accretion of discount on asset retirement obligations |
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278 |
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153 |
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Exploration expense, including dry holes |
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5,318 |
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|
848 |
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Non-cash compensation expense |
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1,925 |
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1,299 |
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Deferred income taxes |
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(10,871 |
) |
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14,368 |
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(Gain) loss on sale of assets |
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243 |
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(777 |
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Ineffective portion of cash flow hedges |
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(564 |
) |
Loss on derivatives not designated as hedges |
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5,046 |
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17,178 |
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Dedesignated cash flow hedges reclassified from accumulated other comprehensive
income |
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|
296 |
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Other non-cash items |
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813 |
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334 |
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Changes in operating assets and liabilities, net of acquisitions: |
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Accounts receivable |
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(31,744 |
) |
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(281 |
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Prepaid costs and other |
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1,581 |
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1,849 |
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Inventory |
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(2,371 |
) |
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(152 |
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Accounts payable |
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15,203 |
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(11,619 |
) |
Revenue payable |
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2,273 |
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3,362 |
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Other current liabilities |
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11,339 |
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(154 |
) |
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Net cash provided by operating activities |
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40,612 |
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69,805 |
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CASH FLOWS FROM INVESTING ACTIVITIES: |
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Capital expenditures on oil and natural gas properties |
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(131,559 |
) |
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(51,537 |
) |
Additions to other property and equipment |
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(1,078 |
) |
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(2,803 |
) |
Proceeds from the sale of oil and natural gas properties and other assets |
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1,000 |
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1,034 |
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Settlements received (paid) on derivatives not designated as hedges |
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37,124 |
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(3,987 |
) |
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Net cash used in investing activities |
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(94,513 |
) |
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(57,293 |
) |
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CASH FLOWS FROM FINANCING ACTIVITIES: |
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Proceeds from issuance of long-term debt |
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100,650 |
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Payments of long-term debt |
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(59,900 |
) |
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(26,500 |
) |
Exercise of stock options |
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2,005 |
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1,238 |
|
Excess tax benefit from stock-based compensation |
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|
804 |
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|
593 |
|
Proceeds from repayment of officer and employee notes |
|
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|
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|
333 |
|
Bank overdrafts |
|
|
(5,003 |
) |
|
|
(2,908 |
) |
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
38,556 |
|
|
|
(27,244 |
) |
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
|
(15,345 |
) |
|
|
(14,732 |
) |
Cash and cash equivalents at beginning of period |
|
|
17,752 |
|
|
|
30,424 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
2,407 |
|
|
$ |
15,692 |
|
|
|
|
|
|
|
|
SUPPLEMENTAL CASH FLOWS: |
|
|
|
|
|
|
|
|
Cash paid for interest and fees, net of $15 and $475 capitalized interest |
|
$ |
3,457 |
|
|
$ |
6,301 |
|
Cash paid for income taxes |
|
$ |
1,065 |
|
|
$ |
|
|
The accompanying notes are an integral part of these consolidated financial statements.
4
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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 March 31, 2009, its results of operations and its cash flows for the three months ended
March 31, 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 $14.8 million and $15.7 million, net of accumulated amortization of $4.2 million and $3.3
million, at March 31, 2009 and December 31, 2008, respectively.
5
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
Future amortization expense of deferred loan costs at March 31, 2009 is as follows:
|
|
|
|
|
(in thousands) |
|
Total |
|
|
Remaining 2009 |
|
$ |
2,570 |
|
2010 |
|
|
3,426 |
|
2011 |
|
|
3,426 |
|
2012 |
|
|
3,426 |
|
2013 |
|
|
1,997 |
|
|
|
|
|
Total |
|
$ |
14,845 |
|
|
|
|
|
Intangible assets. The Company has capitalized certain operating rights acquired in an
acquisition, see Note D. The gross operating rights of approximately $38.8 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 months ended
March 31, 2009 was approximately $0.4 million. The following table reflects the estimated
aggregate amortization expense for each of the periods presented below:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Remaining 2009 |
|
$ |
1,163 |
|
2010 |
|
|
1,550 |
|
2011 |
|
|
1,550 |
|
2012 |
|
|
1,550 |
|
2013 |
|
|
1,550 |
|
Thereafter |
|
|
30,361 |
|
|
|
|
|
Total |
|
$ |
37,724 |
|
|
|
|
|
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
March 31, 2009
Unaudited
The following table reflects the Companys natural gas imbalance positions at March 31, 2009
and December 31, 2008 as well as amounts reflected in oil and natural gas production expense for
the three months ended March 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
December 31, |
(dollars in thousands) |
|
2009 |
|
2008 |
|
Natural gas imbalance liability (included in asset
retirement obligations and other long-term liabilities) |
|
$ |
455 |
|
|
$ |
472 |
|
Overtake position (Mcf) |
|
|
81,189 |
|
|
|
85,698 |
|
|
|
|
|
|
|
|
|
|
Natural gas imbalance receivable (included in other assets) |
|
$ |
439 |
|
|
$ |
406 |
|
Undertake position (Mcf) |
|
|
97,578 |
|
|
|
90,321 |
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2009 |
|
2008 |
|
|
|
Value of net undertake arising during the period
(reducing oil and natural gas production expense) |
|
$ |
49 |
|
|
$ |
4 |
|
Net undertake position arising during the period (Mcf) |
|
|
11,766 |
|
|
|
1,014 |
|
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 $2.7 million and $0.2 million for the
three months ended March 31, 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 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 business combinations in 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 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.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities, 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.
7
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
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
Note H.
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, 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. 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 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 the first quarter of 2009, and as such, the adoption of this statement 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, with early adoption permitted for periods ending after March 15, 2009. An entity may
early adopt this FSP only if it also elects to early adopt 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) and FSP SFAS No. 115-2
and SFAS No. 124-2, Recognition and Presentation of Other-Than-Temporary Impairments. The Company
did not elect early adoption. 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. The Company is currently evaluating the potential
impact, if any, of FSP SFAS No. 107-1 on its financial statement disclosures.
In April 2009, the FASB issued 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. |
8
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
|
|
|
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. |
|
|
|
|
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, with early adoption permitted for periods ending after March 15, 2009. An entity early
adopting FSP SFAS No. 157-4 must also early adopt FSP SFAS No. 115-2 and SFAS No. 124-2. The
Company is not affected by FSP SFAS No. 115-2 and SFAS No. 124-2. The Company is currently
evaluating the potential impact, if any, of FSP SFAS No. 157-4 on its 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 also permits the use of new technologies to determine proved reserves if those technologies
have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The
Reserve Ruling will also allow companies to disclose their probable and possible reserves to
investors. 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.
9
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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 months ended March 31, 2009:
|
|
|
|
|
|
Three Months Ended |
|
(in thousands) |
March 31, 2009 |
|
|
Beginning capitalized exploratory well costs |
|
$ |
25,553 |
|
Additions to exploratory well costs pending the determination of proved reserves |
|
|
2,537 |
|
Reclassifications due to determination of proved reserves |
|
|
(25,103 |
) |
Exploratory well costs charged to expense |
|
|
(451 |
) |
|
|
|
|
Ending capitalized exploratory well costs |
|
$ |
2,536 |
|
|
|
|
|
The following table provides an aging, at March 31, 2009 and December 31, 2008, of capitalized
exploratory well costs based on the date drilling was completed:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Wells in drilling progress |
|
$ |
|
|
|
$ |
7,765 |
|
Capitalized exploratory well costs that have been capitalized for a period of one year or less |
|
|
2,536 |
|
|
|
17,788 |
|
Capitalized exploratory well costs that have been capitalized for a period greater than one year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalized exploratory well costs |
|
$ |
2,536 |
|
|
$ |
25,553 |
|
|
|
|
|
|
|
|
At March 31, 2009, the Company had five gross exploratory wells waiting on their completion,
including three wells in the Texas Permian area, one well in the New Mexico Permian area and one
well in the Williston Basin of North Dakota.
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 (referred to as Henry or 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 $584.1 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 purchase price of the acquired
Henry Properties net assets is based on the total value of the cash consideration. The initial
purchase
10
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
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) |
|
$ |
86,321 |
|
Proved oil and natural gas properties |
|
|
594,065 |
|
Unproved oil and natural gas properties |
|
|
233,790 |
|
Other long-term assets |
|
|
6,977 |
|
Intangible assets operating rights |
|
|
38,758 |
|
|
|
|
|
Total assets acquired |
|
|
959,911 |
|
|
|
|
|
Current liabilities |
|
|
(113,729 |
) |
Asset retirement obligations and other long-term liabilities |
|
|
(7,529 |
) |
Noncurrent derivative liabilities |
|
|
(39,037 |
) |
Deferred tax liability |
|
|
(215,475 |
) |
|
|
|
|
Total liabilities assumed |
|
|
(375,770 |
) |
|
|
|
|
Net purchase price |
|
$ |
584,141 |
|
|
|
|
|
|
|
|
|
|
Consideration paid for Henry Properties net assets: |
|
|
|
|
Cash consideration paid, net of cash acquired of $19,049 |
|
$ |
578,491 |
|
Acquisition costs (b) |
|
|
5,650 |
|
|
|
|
|
Total purchase price |
|
$ |
584,141 |
|
|
|
|
|
|
|
|
(a) |
|
Includes a deferred tax asset of approximately $9.0 million. |
|
(b) |
|
Estimated acquisition costs include legal and accounting fees, advisory fees and other
acquisition-related costs. |
11
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
The following unaudited pro forma combined condensed financial data for the three months ended
March 31, 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 |
(in thousands, except per share data) |
|
March 31, 2008 |
|
Operating revenues |
|
$ |
154,424 |
|
Net income |
|
$ |
14,542 |
|
Earnings per common share: |
|
|
|
|
Basic |
|
$ |
0.17 |
|
Diluted |
|
$ |
0.17 |
|
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 obligation (ARO) transactions
recorded during the three months ended March 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Asset retirement obligations, beginning of period |
|
$ |
16,809 |
|
|
$ |
9,418 |
|
Liabilities incurred from new wells |
|
|
168 |
|
|
|
34 |
|
Accretion expense |
|
|
278 |
|
|
|
153 |
|
Disposition of wells sold |
|
|
(142 |
) |
|
|
|
|
Liabilities settled upon plugging and abandoning wells |
|
|
(10 |
) |
|
|
|
|
Revision of estimates |
|
|
1,151 |
|
|
|
(810 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, end of period |
|
$ |
18,254 |
|
|
$ |
8,795 |
|
|
|
|
|
|
|
|
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.
12
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
In connection with the Private Placement, the Company entered into a registration rights
agreement with the investors. On October 24, 2008, pursuant to the registration rights agreement,
the Company filed a registration statement to register the shares of common stock issued in the
Private Placement.
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.
Note G. Incentive plans
Defined contribution plan. The Company sponsors a 401(k) defined contribution plan for the
benefit of substantially 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 March 31, 2009 and 2008
were approximately $0.3 million and $0.1 million, 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 March 31, 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 |
|
|
(602,334 |
) |
|
|
|
|
|
Awards available for future grant |
|
|
1,786,181 |
|
|
|
|
|
|
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, the awarded shares are forfeited and cancelled and are no longer considered issued and
outstanding. A summary of the Companys restricted stock awards activity for the three months ended
March 31, 2009 is presented below:
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
Grant Date |
|
|
Restricted |
|
Fair Value |
|
|
Shares |
|
Per Share |
|
Outstanding at December 31, 2008 |
|
|
407,351 |
|
|
|
|
|
Shares granted |
|
|
90,688 |
|
|
$ |
20.40 |
|
Shares cancelled / forfeited |
|
|
(1,163 |
) |
|
|
|
|
Lapse of restrictions |
|
|
(12,500 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at March 31, 2009 |
|
|
484,376 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
A summary of the impact on the consolidated statements of operations for the Companys
restricted stock awards during the three months ended March 31, 2009 and 2008 is presented below:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
(in thousands) |
|
2009 |
|
2008 |
|
Stock-based compensation expense related to restricted stock |
|
$ |
897 |
|
|
$ |
394 |
|
Income tax benefit related to restricted stock |
|
$ |
341 |
|
|
$ |
154 |
|
Deductions in current taxable income related to restricted stock |
|
$ |
378 |
|
|
$ |
|
|
Stock option awards. A summary of the Companys stock option awards activity under the Plan
for the three months ended March 31, 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 |
|
|
(248,356 |
) |
|
$ |
8.08 |
|
|
|
|
|
|
|
|
|
|
Outstanding at March 31, 2009 |
|
|
2,600,769 |
|
|
$ |
13.24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at end of period |
|
|
1,747,913 |
|
|
$ |
9.89 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested and exercisable at end of period |
|
|
922,921 |
|
|
$ |
11.42 |
|
|
|
|
|
|
|
|
|
|
14
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
The following table summarizes information about the Companys vested and exercisable stock
options outstanding at March 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
Remaining |
|
|
Average |
|
|
|
|
|
|
|
|
|
|
Stock |
|
|
Contractual |
|
|
Exercise |
|
|
Intrinsic |
|
|
|
|
|
|
|
Options |
|
|
Life |
|
|
Price |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
Vested options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price |
|
$ |
8.00 |
|
|
|
1,311,633 |
|
|
2.68 years |
|
$ |
8.00 |
|
|
$ |
23,072 |
|
Exercise price |
|
$ |
12.00 |
|
|
|
138,780 |
|
|
4.86 years |
|
$ |
12.00 |
|
|
|
1,886 |
|
Exercise price |
|
$ |
14.68 |
|
|
|
191,250 |
|
|
7.54 years |
|
$ |
14.68 |
|
|
|
2,086 |
|
Exercise price |
|
$ |
21.84 |
|
|
|
106,250 |
|
|
8.91 years |
|
$ |
21.84 |
|
|
|
399 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,747,913 |
|
|
|
|
|
|
$ |
9.89 |
|
|
$ |
27,443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested and exercisable options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price |
|
$ |
8.00 |
|
|
|
522,602 |
|
|
3.34 years |
|
$ |
8.00 |
|
|
$ |
9,193 |
|
Exercise price |
|
$ |
12.00 |
|
|
|
102,819 |
|
|
5.77 years |
|
$ |
12.00 |
|
|
|
1,397 |
|
Exercise price |
|
$ |
14.68 |
|
|
|
191,250 |
|
|
7.54 years |
|
$ |
14.68 |
|
|
|
2,086 |
|
Exercise price |
|
$ |
21.84 |
|
|
|
106,250 |
|
|
8.91 years |
|
$ |
21.84 |
|
|
|
399 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
922,921 |
|
|
|
|
|
|
$ |
11.42 |
|
|
$ |
13,075 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
The following table summarizes information about stock-based compensation for stock options
for the three months ended March 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Grant date fair value for awards during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time vesting options |
|
$ |
|
|
|
$ |
183 |
|
Stock option grants under the Plan |
|
1,454 |
|
|
4,296 |
|
Total |
|
$ |
1,454 |
|
|
$ |
4,479 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense from stock options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time vesting options |
|
$ |
71 |
|
|
$ |
30 |
|
Performance vesting options: |
|
|
|
|
|
|
|
|
Officers |
|
|
71 |
|
|
|
150 |
|
Stock option grants under the Plan |
|
|
886 |
|
|
|
725 |
|
|
|
|
|
|
|
|
Total |
|
$ |
1,028 |
|
|
$ |
905 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes and other information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit related to stock options |
|
$ |
391 |
|
|
$ |
354 |
|
Deductions in current taxable income related to stock options exercised |
|
$ |
3,040 |
|
|
$ |
|
|
In calculating compensation expense for options granted during the three months ended March
31, 2009, the Company has 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 months
ended March 31, 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.
16
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
Future stock-based compensation expense. Future stock-based compensation expense at March 31,
2009 is summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted |
|
|
Stock |
|
|
|
|
(in thousands) |
|
Stock |
|
|
Options |
|
|
Total |
|
|
Remaining 2009 |
|
$ |
2,568 |
|
|
$ |
2,309 |
|
|
$ |
4,877 |
|
2010 |
|
|
1,895 |
|
|
|
1,694 |
|
|
|
3,589 |
|
2011 |
|
|
699 |
|
|
|
706 |
|
|
|
1,405 |
|
2012 |
|
|
143 |
|
|
|
166 |
|
|
|
309 |
|
2013 |
|
|
14 |
|
|
|
14 |
|
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
5,319 |
|
|
$ |
4,889 |
|
|
$ |
10,208 |
|
|
|
|
|
|
|
|
|
|
|
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 our
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 our counterparties
valuations to assess the reasonableness of our prices and valuation techniques. |
|
|
|
|
|
|
|
Level 3: |
|
Measured based on prices or valuation models that require inputs that are both
significant to the fair value measurement and less observable from objective sources
(i.e., supported by little or no market activity). Level 3 instruments primarily include
derivative instruments, such as 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 our 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. |
17
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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 and term note. The carrying amount of borrowings outstanding under the
Companys credit facility approximate
fair value because the instruments bear interest at variable market rates.
18
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Derivative instruments. The fair value of the 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 master netting
arrangements and qualify for net presentation in the consolidated balance sheets at March 31, 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 |
|
|
March 31, |
|
(in thousands) |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
2009 |
|
|
Assets (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:(a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap
contracts |
|
$ |
|
|
|
$ |
56,316 |
|
|
$ |
|
|
|
$ |
56,316 |
|
Commodity derivative basis swap
contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivative swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price collar
contracts |
|
|
|
|
|
|
|
|
|
|
36,870 |
|
|
|
36,870 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56,316 |
|
|
|
36,870 |
|
|
|
93,186 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent:(b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap
contracts |
|
|
|
|
|
|
58,773 |
|
|
|
|
|
|
|
58,773 |
|
Commodity derivative basis swap
contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivative swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price collar
contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
58,773 |
|
|
|
|
|
|
|
58,773 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:(a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap
contracts |
|
|
|
|
|
|
(4,281 |
) |
|
|
|
|
|
|
(4,281 |
) |
Commodity derivative basis swap
contracts |
|
|
|
|
|
|
(1,007 |
) |
|
|
|
|
|
|
(1,007 |
) |
Interest rate derivative swap contracts |
|
|
|
|
|
|
(3,072 |
) |
|
|
|
|
|
|
(3,072 |
) |
Commodity derivative price collar
contracts |
|
|
|
|
|
|
|
|
|
|
(1,429 |
) |
|
|
(1,429 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,360 |
) |
|
|
(1,429 |
) |
|
|
(9,789 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent:(b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap
contracts |
|
|
|
|
|
|
(9,198 |
) |
|
|
|
|
|
|
(9,198 |
) |
Commodity derivative basis swap
contracts |
|
|
|
|
|
|
(569 |
) |
|
|
|
|
|
|
(569 |
) |
Interest rate derivative swap contracts |
|
|
|
|
|
|
(437 |
) |
|
|
|
|
|
|
(437 |
) |
Commodity derivative price collar
contracts |
|
|
|
|
|
|
|
|
|
|
(1,697 |
) |
|
|
(1,697 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10,204 |
) |
|
|
(1,697 |
) |
|
|
(11,901 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial assets (liabilities) |
|
$ |
|
|
|
$ |
96,525 |
|
|
$ |
33,744 |
|
|
$ |
130,269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Total current financial assets
(liabilities), gross basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
83,397 |
|
(b) Total noncurrent financial
assets (liabilities), gross basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46,872 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial assets
(liabilities) |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
130,269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
|
|
|
(1) |
|
The fair value of derivative instruments reported in the consolidated balance sheets
are subject to master 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 March 31, 2009 and December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Consolidated Balance Sheet Classification: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
$ |
86,082 |
|
|
$ |
113,149 |
|
Liabilities |
|
|
(2,685 |
) |
|
|
(1,866 |
) |
|
|
|
|
|
|
|
Net current |
|
$ |
83,397 |
|
|
$ |
111,283 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent derivative contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
$ |
48,649 |
|
|
$ |
61,157 |
|
Liabilities |
|
|
(1,777 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net noncurrent |
|
$ |
46,872 |
|
|
$ |
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 January 1, 2009 |
|
$ |
49,562 |
|
Realized and unrealized gains |
|
|
(1,056 |
) |
Purchases, issuances, and settlements |
|
|
(14,762 |
) |
|
|
|
|
Balance at March 31, 2009 |
|
$ |
33,744 |
|
|
|
|
|
|
|
|
|
|
Total losses for the period included in earnings attributable to the change in unrealized losses relating to assets
still held at the reporting date |
|
$ |
(15,818 |
) |
|
|
|
|
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.
21
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
As a result of a significant decline in the assumptions at March 31, 2009, the Company
reviewed its proved oil and gas properties that are sensitive to oil and natural gas prices for
impairment. The Company recognized impairment expense of $4.1 million for the three months ended
March 31, 2009, related to its proved oil and gas properties. The impaired assets, which had a
total carrying amount of $6.9 million, were reduced to their estimated fair value of $2.8 million.
Asset Retirement Obligations The Company estimates the fair values 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 March 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
2,887 |
|
|
$ |
(4,056 |
) |
Asset retirement obligations incurred in current period |
|
|
|
|
|
|
|
|
|
|
168 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(16 |
) |
Asset retirement obligations incurred in current period |
|
|
|
|
|
|
|
|
|
|
34 |
|
|
|
|
|
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 financial statements.
Currently, the Company does not designate its derivative instruments to qualify for hedge
accounting. Accordingly, the Company reflects the changes in the fair value of its derivative
instruments in the 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.
22
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
New commodity derivatives contracts in 2009. During the three months ended March 31, 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 |
|
Daily |
|
Index |
|
Contract |
|
|
Volume |
|
Volume |
|
Price |
|
Period |
|
Oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
540,000 |
|
|
|
2,935 |
|
|
$51.62 (a) |
|
7/1/09 - 12/31/09 |
Price swap |
|
|
1,608,000 |
|
|
|
4,405 |
|
|
$55.83 (a) |
|
1/1/10 - 12/31/10 |
Price collar |
|
|
600,000 |
|
|
|
6,522 |
|
|
$45.00 - $49.00 (a) (e) |
|
3/1/09 - 5/31/09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
3,000,000 |
|
|
|
16,393 |
|
|
$4.31 (b) |
|
4/1/09 - 9/30/09 |
Price collar |
|
|
9,000,000 |
|
|
|
16,453 |
|
|
$5.42 -
$6.12 (c) (e) |
|
10/1/09 - 3/31/11 |
Basis swap |
|
|
7,500,000 |
|
|
|
16,484 |
|
|
$0.90 (d) |
|
1/1/10 - 3/31/11 |
|
|
|
(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 price for the natural gas price swap is based on the NYMEX-Henry Hub last trading
day futures price. |
|
(c) |
|
The index price for the natural gas price collar is 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. |
On May 5, 2009, the Company entered into an oil price swap to hedge an additional portion of
its estimated oil production for 2011 at a price of $70.15 per Bbl.
23
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
Commodity derivative contracts at March 31, 2009. The following table sets forth the Companys
outstanding commodity derivative contracts at March 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
Total |
|
Oil Swaps: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
|
|
|
|
452,673 |
|
|
|
725,473 |
|
|
|
725,473 |
|
|
|
1,903,619 |
|
Price per Bbl (a) (f) |
|
|
|
|
|
$ |
87.17 |
|
|
$ |
73.91 |
|
|
$ |
73.91 |
|
|
$ |
77.06 |
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
562,436 |
|
|
|
562,436 |
|
|
|
562,436 |
|
|
|
562,436 |
|
|
|
2,249,744 |
|
Price per Bbl (a) |
|
$ |
66.50 |
|
|
$ |
66.50 |
|
|
$ |
66.50 |
|
|
$ |
66.50 |
|
|
$ |
66.50 |
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
139,436 |
|
|
|
139,436 |
|
|
|
139,436 |
|
|
|
139,436 |
|
|
|
557,744 |
|
Price per Bbl (a) (f) |
|
$ |
104.91 |
|
|
$ |
104.91 |
|
|
$ |
104.91 |
|
|
$ |
104.91 |
|
|
$ |
104.91 |
|
2012: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
126,000 |
|
|
|
126,000 |
|
|
|
126,000 |
|
|
|
126,000 |
|
|
|
504,000 |
|
Price per Bbl (a) |
|
$ |
127.80 |
|
|
$ |
127.80 |
|
|
$ |
127.80 |
|
|
$ |
127.80 |
|
|
$ |
127.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Collars: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
|
|
|
|
592,000 |
|
|
|
192,000 |
|
|
|
192,000 |
|
|
|
976,000 |
|
Price per Bbl (a) |
|
|
|
|
|
$ |
69.32 - $76.76 |
(f) |
|
$ |
120.00 - $134.60 |
|
|
$ |
120.00 - $134.60 |
|
|
$ |
89.26 - $99.52 |
(f) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
455,000 |
|
|
|
460,000 |
|
|
|
460,000 |
|
|
|
1,375,000 |
|
Price per MMBtu (b) |
|
|
|
|
|
$ |
8.44 |
|
|
$ |
8.44 |
|
|
$ |
8.44 |
|
|
$ |
8.44 |
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
1,500,000 |
|
|
|
1,500,000 |
|
|
|
|
|
|
|
3,000,000 |
|
Price per MMBtu (c) |
|
|
|
|
|
$ |
4.31 |
|
|
$ |
4.31 |
|
|
|
|
|
|
$ |
4.31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Collars: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,500,000 |
|
|
|
1,500,000 |
|
Price per MMBtu (d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
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 (d) |
|
$ |
5.00 - $5.81 |
|
|
$ |
5.25 - $5.75 |
|
|
$ |
5.25 - $5.75 |
|
|
$ |
6.00 - $6.80 |
|
|
$ |
5.38 - $6.03 |
(f) |
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
1,500,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,500,000 |
|
Price per MMBtu (d) |
|
$ |
6.00 - $6.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
6.00 - $6.80 |
|
24
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
Total |
|
Natural Gas Basis Swaps: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
1,501,500 |
|
|
|
1,518,000 |
|
|
|
1,518,000 |
|
|
|
4,537,500 |
|
Price per MMBtu (e) (f) |
|
|
|
|
|
$ |
1.08 |
|
|
$ |
1.08 |
|
|
$ |
1.08 |
|
|
$ |
1.08 |
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
1,500,000 |
|
|
|
1,500,000 |
|
|
|
1,500,000 |
|
|
|
1,500,000 |
|
|
|
6,000,000 |
|
Price per MMBtu (e) |
|
$ |
0.90 |
|
|
$ |
0.90 |
|
|
$ |
0.90 |
|
|
$ |
0.90 |
|
|
$ |
0.90 |
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
1,500,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,500,000 |
|
Price per MMBtu (e) |
|
$ |
0.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
0.90 |
|
|
|
|
(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 price for the natural gas price swap is based on the NYMEX-Henry Hub last trading
day futures price. |
|
(d) |
|
The index price for the natural gas price collar is based on the NYMEX-Henry Hub last trading
day futures price. |
|
(e) |
|
The basis differential between the El Paso Permian delivery point and NYMEX Henry Hub delivery
point. |
|
(f) |
|
Prices represent weighted average prices. |
Interest rate derivative contracts at March 31, 2009. The Company has an interest rate swap
which fixes the LIBOR interest rate on the Companys bank debt at 1.90 percent for three years
beginning in May of 2009 on $300 million of the Companys bank debt. 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.
25
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 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):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Decrease in oil and natural gas revenue from derivative activity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments on cash flow hedges in oil sales |
|
$ |
|
|
|
$ |
(7,206 |
) |
Cash receipts from cash flow hedges in natural gas sales |
|
|
|
|
|
|
1 |
|
Dedesignated cash flow hedges reclassified from AOCI in natural gas sales |
|
|
|
|
|
|
(296 |
) |
|
|
|
|
|
|
|
Total decrease in oil and natural gas revenue from derivative activity |
|
$ |
|
|
|
$ |
(7,501 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on derivatives not designated as hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market loss: |
|
|
|
|
|
|
|
|
Commodity derivatives |
|
$ |
(39,743 |
) |
|
$ |
(13,191 |
) |
Interest rate derivatives |
|
|
(2,427 |
) |
|
|
|
|
Cash (payments) receipts on derivatives not designated as hedges: |
|
|
|
|
|
|
|
|
Commodity derivatives |
|
|
37,124 |
|
|
|
(3,987 |
) |
Interest rate derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total loss on derivatives not designated as hedges |
|
$ |
(5,046 |
) |
|
$ |
(17,178 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain from ineffective portion of cash flow hedges |
|
$ |
|
|
|
$ |
564 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges: |
|
|
|
|
|
|
|
|
Mark-to-market loss of cash flow hedges |
|
$ |
|
|
|
$ |
(6,606 |
) |
Reclassification adjustment of losses to earnings |
|
|
|
|
|
|
7,205 |
|
Net AOCI upon dedesignation at June 30, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change, before income taxes |
|
|
|
|
|
|
599 |
|
Income tax effect |
|
|
|
|
|
|
(233 |
) |
|
|
|
|
|
|
|
Net change, net of income taxes |
|
$ |
|
|
|
$ |
366 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dedesignated cash flow hedges: |
|
|
|
|
|
|
|
|
Net AOCI upon dedesignation at June 30, 2007 |
|
$ |
|
|
|
$ |
|
|
Reclassification adjustment of losses to earnings |
|
|
|
|
|
|
296 |
|
Income tax effect |
|
|
|
|
|
|
(116 |
) |
|
|
|
|
|
|
|
Net change, net of income taxes |
|
$ |
|
|
|
$ |
180 |
|
|
|
|
|
|
|
|
26
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
Note J. Debt
The Companys debt consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Credit facility |
|
$ |
670,750 |
|
|
$ |
630,000 |
|
Less: current portion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
670,750 |
|
|
$ |
630,000 |
|
|
|
|
|
|
|
|
Credit facility. The Companys credit facility, as amended, is subject to scheduled
semiannual redeterminations, and has a maturity date of July 31, 2013 (the Credit Facility). At
March 31, 2009, the Company had letters of credit outstanding under the Credit Facility of
approximately $275,000 and its availability to borrow additional funds was $289.0 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 March 31, 2009) or (ii) a
Eurodollar rate (substantially equal to the London Interbank Offered Rate). At March 31, 2009, the
interest rates of Eurodollar rate advances and JPM Prime Rate advances vary, with interest margins
ranging from 125 to 275 basis points and zero to 125 basis points, respectively, per annum
depending on the debt balance outstanding. At March 31, 2009, the Company pays commitment fees on
the unused portion of the available borrowing base ranging from 25 to 50 basis points per annum.
As part of the Companys April 2009 borrowing base review, the Company agreed to modify the
pricing grid on the Credit Facility, effective in April 2009. The interest rates of Eurodollar
rate advances and JPM Prime Rate advances will have interest rate 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. The Company will pay 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 on a daily basis 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) maintenance of a quarterly ratio of total debt to consolidated earnings before interest
expense, income taxes, depletion, depreciation, and amortization, exploration expense and other
noncash income and expenses to be no greater than 4.0 to 1.0, and (ii) maintenance of a ratio of
current assets to current liabilities, excluding noncash assets and liabilities related to
financial derivatives and asset retirement obligations 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 and sales or transfer of
assets; and (d) a restriction on the payment of cash dividends. At March 31, 2009, the Company was
in compliance with its debt covenants.
27
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
Principal maturities of debt. Principal maturities of debt outstanding at March 31, 2009 are
as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Remaining 2009 |
|
$ |
|
|
2010 |
|
|
|
|
2011 |
|
|
|
|
2012 |
|
|
|
|
2013 |
|
|
670,750 |
|
|
|
|
|
Total |
|
$ |
670,750 |
|
|
|
|
|
Interest expense. The following amounts have been incurred and charged to interest expense
for the three months ended March 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Cash payments for interest |
|
$ |
3,472 |
|
|
$ |
6,776 |
|
Amortization of original issue discount |
|
|
|
|
|
|
25 |
|
Amortization of deferred loan origination costs |
|
|
856 |
|
|
|
312 |
|
Write-off of deferred loan origination costs and original issue discount |
|
|
|
|
|
|
|
|
Net changes in accruals |
|
|
57 |
|
|
|
(1,023 |
) |
|
|
|
|
|
|
|
Interest costs incurred |
|
|
4,385 |
|
|
|
6,090 |
|
Less: capitalized interest |
|
|
(15 |
) |
|
|
(475 |
) |
|
|
|
|
|
|
|
Total interest expense |
|
$ |
4,370 |
|
|
$ |
5,615 |
|
|
|
|
|
|
|
|
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 $2.4 million.
Indemnifications. The Company has agreed to indemnify its directors and officers, employees
and agents with respect to claims and damages arising from 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 such proceedings and 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 annual results of operations. The Company will continue
to evaluate litigation 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 of 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 of the Henry Entities, 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 such employee resigns or is terminated for cause, the employee will
not receive the bonus and the Company will be required to
28
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
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 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 months ended March 31, 2009, the Company
recognized $2.6 million 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 March 31, 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 |
|
$ |
1,482 |
|
|
$ |
1,482 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Daywork drilling contracts with related parties (a) |
|
|
6,100 |
|
|
|
6,100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Daywork drilling contracts assumed in the Henry Properties
acquisition (b) |
|
|
2,179 |
|
|
|
1,817 |
|
|
|
362 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual drilling commitments |
|
$ |
9,761 |
|
|
$ |
9,399 |
|
|
$ |
362 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 March 31, 2009 and 2008 were approximately $671,000 and $164,000, respectively.
Future minimum lease commitments under non-cancellable operating leases at March 31, 2009 are as
follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Remaining 2009 |
|
$ |
975 |
|
2010 |
|
|
978 |
|
2011 |
|
|
994 |
|
2012 |
|
|
981 |
|
2013 |
|
|
572 |
|
|
|
|
|
Total |
|
$ |
4,500 |
|
|
|
|
|
Note L. Income taxes
The Company accounts for income taxes in accordance with the provisions of SFAS No. 109,
Accounting for Income Taxes. The Company and its subsidiaries file federal corporate income tax
returns on a consolidated basis. The tax returns and the amount of taxable income or loss are
subject to examination by United States federal and state taxing authorities. In determining the
interim period income tax provision, the Company utilizes an estimated annual effective tax rate.
The Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty
in Income Taxes, (FIN No. 48) an interpretation of FASB Statement No. 109, Accounting for Income
Taxes, on January 1, 2007. At the time of adoption and at
29
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
March 31, 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.
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 months ended March 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Income (loss) from operations |
|
$ |
(8,106 |
) |
|
$ |
14,368 |
|
|
|
|
|
|
|
|
|
|
Changes in stockholders equity: |
|
|
|
|
|
|
|
|
Net deferred hedge losses |
|
|
|
|
|
|
(2,582 |
) |
Net settlement losses included in earnings |
|
|
|
|
|
|
2,932 |
|
Tax benefits related to stock-based compensation |
|
|
(804 |
) |
|
|
(593 |
) |
|
|
|
|
|
|
|
|
|
$ |
(8,910 |
) |
|
$ |
14,125 |
|
|
|
|
|
|
|
|
The Companys income tax provision (benefit) attributable to income (loss) from operations
consisted of the following for the three months ended March 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Current: |
|
|
|
|
|
|
|
|
U.S. federal |
|
$ |
2,438 |
|
|
$ |
|
|
U.S. state and local |
|
|
327 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,765 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred: |
|
|
|
|
|
|
|
|
U.S. federal |
|
|
(9,585 |
) |
|
|
12,054 |
|
U.S. state and local |
|
|
(1,286 |
) |
|
|
2,314 |
|
|
|
|
|
|
|
|
|
|
|
(10,871 |
) |
|
|
14,368 |
|
|
|
|
|
|
|
|
|
|
$ |
(8,106 |
) |
|
$ |
14,368 |
|
|
|
|
|
|
|
|
30
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
The reconciliation between the tax expense computed by multiplying pretax income by the
U.S. federal statutory rate and the reported amounts of income tax expense is as follows:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Income (loss) at U.S. federal statutory rate |
|
$ |
(7,466 |
) |
|
$ |
12,857 |
|
State income taxes (net of federal tax effect) |
|
|
(623 |
) |
|
|
1,504 |
|
Nondeductible expense & other |
|
|
(17 |
) |
|
|
7 |
|
|
|
|
|
|
|
|
Expense (benefit) for income taxes |
|
$ |
(8,106 |
) |
|
$ |
14,368 |
|
|
|
|
|
|
|
|
Note M. Related parties
Chase Group transactions. The Company incurred charges from Mack Energy Corporation (MEC),
an affiliate of Chase Oil Corporation (Chase Oil) of approximately $0.3 million and $1.5 million
for the three months ended March 31, 2009 and 2008, respectively, for services rendered in the
ordinary course of business.
The
Company had $139,000 in outstanding receivables due from MEC at March 31, 2009 and no
outstanding receivables due from MEC at December 31, 2008. The Company had $5,000 in outstanding invoices payable to MEC at March 31, 2009 and no
outstanding invoices payable 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 $6.4 million
and $15.1 million for the three months ended March 31, 2009 and 2008, respectively.
The Company had outstanding amounts payable to the other related party vendors identified
above of approximately $781,000 and $21,000 at March 31, 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 $241,000 and $784,000 for the three months ended March 31, 2009 and
2008, respectively. The Company owed these owners royalty payments of approximately $80,000 and
$146,000 at March 31, 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 who also owns a 3.5% partnership
interest. The Company paid this partnership approximately $26,000 and $83,000 for the three months
ended March 31, 2009 and 2008, respectively. The Company owed this partnership royalty payments of
approximately $7,000 and $13,000 at March 31, 2009 and December 31, 2008.
31
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
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 months ended March 31, 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 employees owned a working interest. The Company
distributed revenues to these employees totaling approximately $30,000 and received joint interest
payments from these employees of approximately $639,000 for the three months ended March 31, 2009.
At March 31, 2009 and December 31, 2008, the Company was owed by these employees approximately
$121,000 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.
The following table is a reconciliation of the basic weighted average common shares
outstanding to diluted weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
(in thousands) |
|
2009 |
|
2008 |
|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
84,529 |
|
|
|
75,473 |
|
Dilutive capital options |
|
|
|
|
|
|
23 |
|
Dilutive common stock options |
|
|
|
|
|
|
1,156 |
|
Dilutive restricted stock |
|
|
|
|
|
|
234 |
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
84,529 |
|
|
|
76,886 |
|
|
|
|
|
|
|
|
|
|
For the three months ended March 31, 2009, the computation of diluted net loss per share was
antidilutive; therefore, the amounts reported for basic and diluted net loss per share were the
same. For the three months ended March 31, 2009, 484,376 shares of restricted stock and 2,600,769
stock options were not included in the computation of diluted loss per share, as inclusion of these
items would be antidilutive.
For the three months ended March 31, 2008, the effects of all potentially dilutive securities,
including capital options, stock options and restricted stock were included in the computation of
diluted earnings per share because there were no antidilutive effects.
32
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
Note O. Other current liabilities
The following table provides the components of the Companys other current liabilities at
March 31, 2009 and December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Other current liabilities: |
|
|
|
|
|
|
|
|
Accrued production costs |
|
$ |
20,455 |
|
|
$ |
15,489 |
|
Payroll related matters |
|
|
12,625 |
|
|
|
11,290 |
|
Accrued interest |
|
|
410 |
|
|
|
353 |
|
Asset retirement obligations |
|
|
2,853 |
|
|
|
2,611 |
|
Other |
|
|
|
|
|
|
8,314 |
|
|
|
|
|
|
|
|
Other current liabilities |
|
$ |
36,343 |
|
|
$ |
38,057 |
|
|
|
|
|
|
|
|
33
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited
Note P. Supplementary information
Capitalized costs
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Oil and natural gas properties: |
|
|
|
|
|
|
|
|
Proved |
|
$ |
2,453,517 |
|
|
$ |
2,316,330 |
|
Unproved |
|
|
337,518 |
|
|
|
377,244 |
|
Less: accumulated depletion |
|
|
(357,585 |
) |
|
|
(306,990 |
) |
|
|
|
|
|
|
|
Net capitalized costs for oil and natural gas properties |
|
$ |
2,433,450 |
|
|
$ |
2,386,584 |
|
|
|
|
|
|
|
|
|
Costs incurred for oil and natural gas producing activities (a) |
|
|
|
Three Months Ended March 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Property acquisition costs:(b) |
|
|
|
|
|
|
|
|
Proved |
|
$ |
(940 |
) |
|
$ |
105 |
|
Unproved |
|
|
1,221 |
|
|
|
762 |
|
Exploration |
|
|
23,809 |
|
|
|
29,565 |
|
Development |
|
|
83,779 |
|
|
|
24,877 |
|
|
|
|
|
|
|
|
Total costs incurred for oil and natural gas properties |
|
$ |
107,869 |
|
|
$ |
55,309 |
|
|
|
|
|
|
|
|
|
|
(a) The costs incurred for oil and natural gas producing activities includes the following
amounts of asset retirement obligations: |
|
|
|
Three Months Ended March 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Proved property acquisition costs |
|
$ |
|
|
|
$ |
|
|
Exploration costs |
|
|
168 |
|
|
|
26 |
|
Development costs |
|
|
999 |
|
|
|
(802 |
) |
|
|
|
|
|
|
|
Total |
|
$ |
1,167 |
|
|
$ |
(776 |
) |
|
|
|
|
|
|
|
|
|
|
(b) |
|
During the three months ended March 31, 2009, the Company adjusted the purchase price
allocation related to the acquisition of the Henry Properties. This adjustment reduced the
proved acquisition costs by $940,000 and increased the unproved acquisition costs by $591,000. |
34
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, the Company 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 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, specifically Iraq and Iran; |
|
|
|
|
the extent to which members of the Organization of Petroleum Exporting Countries
(OPEC) 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 March 31, 2009.
Oil prices in 2008 were high and particularly volatile compared to historical prices. The
NYMEX oil price per Bbl averaged $43.30 and $97.74 for the three months ended March 31, 2009 and
2008, respectively. In addition, natural gas prices have been subject to significant fluctuations
during the past several years. The NYMEX natural gas price per MMBtu averaged $4.49 and $8.73 for
the three months ended March 31, 2009 and 2008, respectively. Further demonstrating the continuing
volatility, the NYMEX oil price and NYMEX natural gas price reached lows of $45.88 per Bbl and
$3.25 per MMBtu, respectively, during the period from April 1, 2009 to May 4, 2009. At May 4,
2009, the NYMEX oil price and NYMEX natural gas price were $54.47 per Bbl and $3.73 per MMBtu,
respectively.
35
Henry Entities acquisition
On July 31, 2008, we closed the acquisition of Henry Petroleum LP and certain entities
affiliated with Henry Petroleum LP (referred to as Henry or 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 $584.1 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 a capital budget for 2009 of up to
approximately $500 million, predicated on funding it substantially within our cash flow. The
following is a summary of our 2009 capital budget:
|
|
|
|
|
|
|
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 light of a drop in commodity prices, we took the following actions in January 2009:
|
|
|
reduced our operated drilling rig
count in the Wolfberry play from eight to five; |
|
|
|
|
deferred our deepening program on our Southeastern New Mexico shelf properties;
and |
|
|
|
|
deferred certain drilling activity in the Lower Abo horizontal play. |
The annualized effect of these changes in operating activity would reduce our 2009 capital
spending to approximately $300 million, assuming our current estimate of 2009 capital costs. We
will continue to monitor our capital expenditures 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 quarter of 2009, we incurred approximately $107.1 million of capital
expenditures (excluding the effects of asset retirement obligations and adjustment to the
acquisition of the Henry Properties). These costs were in excess of our cash flows (including
effects of derivative cash receipts) during the first quarter of 2009. We expected to outspend our
cash flow in the first quarter of 2009, but we expect that our capital spending for 2009 will be
substantially within our cash flow. Currently, we believe that our 2009 capital spending will be
approximately $300 million based on current capital costs and
estimated cash flows.
Recent events
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, at the request of the administrative agent, us 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 (a) increase 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) increase 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) increase the unused commitment fee rate from a range of 0.25% to 0.50% to a flat rate of
0.50%.
36
Short-term interruptions in production. During the first quarter of 2008, we experienced
short-term interruptions in our production on the New Mexico shelf properties due to operational
problems with a natural gas processing plant. There were a total of ten days of curtailment during
the first quarter, and approximately 17 MBoe of our production was curtailed during this period.
Derivative financial instrument exposure. At March 31, 2009, the fair value of our financial
derivatives was a net asset of $130.3 million. All of our counterparties to these financial
derivatives are party 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.
Most of our commodity derivative instruments are currently in a net asset position to us. 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 financial
instruments with such party.
New commodity derivative contracts. During the three months ended March 31, 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 |
|
Daily |
|
Index |
|
Contract |
|
|
Volume |
|
Volume |
|
Price |
|
Period |
|
Oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
540,000 |
|
|
|
2,935 |
|
|
$51.62 (a) |
|
7/1/09 - 12/31/09 |
Price swap |
|
|
1,608,000 |
|
|
|
4,405 |
|
|
$55.83 (a) |
|
1/1/10 - 12/31/10 |
Price collar |
|
|
600,000 |
|
|
|
6,522 |
|
|
$45.00 - $49.00 (a) (e) |
|
3/1/09 - 5/31/09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
3,000,000 |
|
|
|
16,393 |
|
|
$4.31 (b) |
|
4/1/09 - 9/30/09 |
Price collar |
|
|
9,000,000 |
|
|
|
16,453 |
|
|
$5.42 -
$6.12 (c) (e) |
|
10/1/09 - 3/31/11 |
Basis swap |
|
|
7,500,000 |
|
|
|
16,484 |
|
|
$0.90 (d) |
|
1/1/10 - 3/31/11 |
|
|
|
(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 price for the natural gas price swap is based on the NYMEX-Henry Hub last trading
day futures price. |
|
(c) |
|
The index price for the natural gas price collar is 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. |
37
Results of Operations
The following table presents selected operating information for the three months ended March
31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2009 |
|
2008 |
|
Net production volumes: |
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
|
1,687 |
|
|
|
887 |
|
Natural gas (MMcf) |
|
|
4,955 |
|
|
|
3,105 |
|
Total (MBoe) |
|
|
2,513 |
|
|
|
1,405 |
|
|
|
|
|
|
|
|
|
|
Average daily production volumes: |
|
|
|
|
|
|
|
|
Oil (Bbl) |
|
|
18,744 |
|
|
|
9,747 |
|
Natural gas (Mcf) |
|
|
55,056 |
|
|
|
34,121 |
|
Total (Boe) |
|
|
27,922 |
|
|
|
15,440 |
|
|
|
|
|
|
|
|
|
|
Average prices: |
|
|
|
|
|
|
|
|
Oil, without hedges (Bbl) |
|
$ |
38.51 |
|
|
$ |
93.60 |
|
Oil, with hedges (Bbl) |
|
$ |
38.51 |
|
|
$ |
85.48 |
|
Natural gas, without hedges (Mcf) |
|
$ |
4.24 |
|
|
$ |
10.04 |
|
Natural gas, with hedges (Mcf) |
|
$ |
4.24 |
|
|
$ |
9.95 |
|
Total, without hedges (Boe) |
|
$ |
34.22 |
|
|
$ |
81.29 |
|
Total, with hedges (Boe) |
|
$ |
34.22 |
|
|
$ |
75.95 |
|
38
Three months ended March 31, 2009, compared to three months ended March 31, 2008
Oil and natural gas revenues. Revenue from oil and natural gas operations was $86.0 million
for the three months ended March 31, 2009, a decrease of $20.7 million (19 percent) from $106.7
million for the three months ended March 31, 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 Entities 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 $38.51 per
Bbl during the three months ended March 31, 2009, a decrease of 55 percent from $85.48
per Bbl during the three months ended March 31, 2008; |
|
|
|
|
total oil production was 1,687 MBbl for the three months ended March 31, 2009, an
increase of 800 MBbl (90 percent) from 887 MBbl for the three months ended March 31,
2008; |
|
|
|
|
average realized natural gas price (after giving effect to hedging activities) was
$4.24 per Mcf during the three months ended March 31, 2009, a decrease of 57 percent
from $9.95 per Mcf during the three months ended March 31, 2008; |
|
|
|
|
total natural gas production was 4,955 MMcf for the three months ended March 31,
2009, an increase of 1,850 MMcf (60 percent) from 3,105 MMcf for the three months ended
March 31, 2008; |
|
|
|
|
average realized barrel of oil equivalent price (after giving effect to hedging
activities) was $34.22 per Boe during the three months ended March 31, 2009, a decrease
of 55 percent from $75.95 per Boe during the three months ended March 31, 2008; and |
|
|
|
|
total production was 2,513 MBoe for the three months ended March 31, 2009, an
increase of 1,108 MBoe (79 percent) from 1,405 MBoe for the three months ended March 31,
2008. |
See discussion in Recent events about our 2008 production interruptions.
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 March 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
Oil Hedges |
|
Natural Gas Hedges |
|
|
Three Months Ended |
|
Three Months Ended |
|
|
March 31, 2008 |
|
March 31, 2008 |
|
|
|
Hedging revenue increase (decrease) (in thousands) |
|
$ |
(7,206 |
) |
|
$ |
(296 |
) |
Hedged volumes (Bbls and MMBtus, respectively) |
|
|
236,600 |
|
|
|
1,228,500 |
|
Hedged revenue increase (decrease) per hedged volume |
|
$ |
(30.46 |
) |
|
$ |
(0.24 |
) |
39
Production expenses. The following tables provide the components of our total oil and natural
gas production costs for the three months ended March 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
2008 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Lease operating expenses |
|
$ |
16,568 |
|
|
$ |
6.59 |
|
|
$ |
6,942 |
|
|
$ |
4.94 |
|
Taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem |
|
|
1,502 |
|
|
|
0.60 |
|
|
|
488 |
|
|
|
0.35 |
|
Production |
|
|
6,275 |
|
|
|
2.50 |
|
|
|
9,078 |
|
|
|
6.46 |
|
Workover costs |
|
|
421 |
|
|
|
0.17 |
|
|
|
387 |
|
|
|
0.28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas production expenses |
|
$ |
24,766 |
|
|
$ |
9.86 |
|
|
$ |
16,895 |
|
|
$ |
12.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, in general, we have 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 $16.6 million ($6.59 per Boe) for the three months ended March
31, 2009, an increase of $9.7 million (141 percent) from $6.9 million ($4.94 per Boe) for the three
months ended March 31, 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, (ii)
our wells successfully drilled and completed in 2008 and 2009 and (iii) general inflation of field
service and supply costs associated with rising commodity prices.
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 $2.50 per Boe during the three months ended March
31, 2009, a decrease of 61 percent from $6.46 per Boe during the three months ended March 31, 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 58 percent.
Workover expenses were approximately $0.4 million for the three months ended March 31, 2009
and 2008. 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 three months ended March 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
(in thousands) |
|
2009 |
|
|
2008 |
|
|
Geological and geophysical |
|
$ |
677 |
|
|
$ |
1,893 |
|
Exploratory dry holes |
|
|
1,421 |
|
|
|
18 |
|
Leasehold abandonments and other |
|
|
3,897 |
|
|
|
830 |
|
|
|
|
|
|
|
|
Total exploration and abandonments |
|
$ |
5,995 |
|
|
$ |
2,741 |
|
|
|
|
|
|
|
|
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 March
31, 2009 was $0.7 million, a decrease of $1.2 million from $1.9 million for the three months ended
March 31, 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.
40
During the three months ended March 31, 2009, we wrote-off an unsuccessful exploratory well in
our Arkansas emerging play.
For the three months ended March 31, 2009, we recorded approximately $3.9 million of leasehold
abandonments, which relates primarily to the write-off of one prospect in New Mexico and two
prospects in Texas. For the three months ended March 31, 2008, we recorded $0.8 million of
leasehold abandonments, which were primarily related to prospects in Chaves and Eddy Counties, New
Mexico and Andrews County, Texas.
Depreciation, depletion and amortization expense. The following table provides components of
our depreciation, depletion and amortization expense for the three months ended March 31, 2009 and
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Depletion of proved oil and natural gas properties |
|
$ |
49,777 |
|
|
$ |
19.81 |
|
|
|
$20,926 |
|
|
$ |
14.89 |
|
Depreciation of other property and equipment |
|
|
578 |
|
|
|
0.23 |
|
|
|
358 |
|
|
|
0.25 |
|
Amortization of intangible asset operating rights |
|
|
393 |
|
|
|
0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depletion, depreciation and amortization |
|
$ |
50,748 |
|
|
$ |
20.20 |
|
|
|
$21,284 |
|
|
$ |
15.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil price used to estimate proved oil reserves at period end |
|
$ |
44.63 |
|
|
|
|
|
|
$ |
98.00 |
|
|
|
|
|
Natural gas price used to estimate proved gas reserves at period end |
|
$ |
3.63 |
|
|
|
|
|
|
$ |
9.37 |
|
|
|
|
|
Depletion of proved oil and natural gas properties was $49.8 million ($19.81 per Boe) for the
three months ended March 31, 2009, an increase of $28.9 million from $20.9 million ($14.89 per Boe)
for the three months ended March 31, 2008. The increase in depletion expense 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. As a result of this review of the recoverability of the carrying value of our
assets during the three months ended March 31, 2009, we recognized a non-cash charge against
earnings of $4.1 million, which was primarily attributable to leases in Eddy Counties, New Mexico.
For the three months ended March 31, 2008, we recognized a non-cash charge against earnings of
$0.02 million, which was primarily attributable to a lease located in Kent County, Texas.
41
General and administrative expenses. The following table provides components of our general
and administrative expenses for the three months ended March 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
General and administrative expenses recurring |
|
$ |
9,914 |
|
|
$ |
3.95 |
|
|
$ |
6,620 |
|
|
$ |
4.71 |
|
Non-recurring bonus paid to former Henry Entities employees |
|
|
2,561 |
|
|
|
1.02 |
|
|
|
|
|
|
|
|
|
Non-cash stock-based compensation stock options |
|
|
1,028 |
|
|
|
0.41 |
|
|
|
905 |
|
|
|
0.64 |
|
Non-cash stock-based compensation restricted stock |
|
|
897 |
|
|
|
0.36 |
|
|
|
394 |
|
|
|
0.28 |
|
Less: Third-party operating fee reimbursements |
|
|
(2,654 |
) |
|
|
(1.06 |
) |
|
|
(239 |
) |
|
|
(0.16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses |
|
$ |
11,746 |
|
|
$ |
4.68 |
|
|
$ |
7,680 |
|
|
$ |
5.47 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were $11.7 million ($4.68 per Boe) for the three months
ended March 31, 2009, an increase of $4.0 million (52 percent) from $7.7 million ($5.47 per Boe)
for the three months ended March 31, 2008. The increase in general
and administrative expenses during the three months ended March 31, 2009 over 2008 was
primarily due to (i) the non-recurring bonus paid to 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 the Henry
Entities former 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 $2.7 million and $0.2 million during the three
months ended March 31, 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.
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.
For the three months ended March 31, 2009, the related cash receipts for settlements for
derivative contracts not designated as hedges was approximately $37.1 million. The non-cash
mark-to-market adjustment for the derivative contracts not designated as hedges was a loss of $42.2
million. This is compared to cash payments for settlements of $4.0 million and non-cash
mark-to-market losses of $13.2 million for the three months ended March 31, 2008.
Interest expense. Interest expense was $4.4 million for the three months ended March 31,
2009, a decrease of $1.2 million from $5.6 million for the three months ended March 31, 2008. The
weighted average interest rate for the three months ended March 31, 2009 and 2008 was 2.0% and
6.7%, respectively. The weighted average debt balance during the three months ended March 31, 2009
and 2008 was approximately $655.9 million and $324.5 million, respectively.
The increase in weighted average debt balance during the three months ended March 31, 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
42
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 $8.1 million and income tax
expense of $14.4 million for the three months ended March 31, 2009 and 2008, respectively. The
effective income tax rate for the three months ended March 31, 2009 and 2008 was 38.0 percent and
39.1 percent, respectively. We estimated a higher effective state income rate in 2008 than in 2009,
which is primarily due to our estimate of income among the various states in which we own assets.
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,
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 March 31,
2009 and 2008 totaled $106.4 million and $55.2 million, respectively. These expenditures were
primarily funded by cash flow from operations.
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 light of the recent drop in commodity prices we took the following actions in January
2009:
|
|
|
reduced our operated drilling rig count in the Wolfberry play from eight to five; |
|
|
|
|
deferred our deepening program on our Southeastern New Mexico shelf properties; and |
|
|
|
|
deferred certain drilling activity in the Lower Abo horizontal play. |
The annualized effect of these changes in operating activity would reduce the Companys 2009
capital spending to approximately $300 million, assuming the Companys current estimate of 2009
capital costs and estimated cashflows. We will monitor our capital expenditures in relation to our
cash flow on a quarterly basis and will adjust our activity and capital spending level based on
changes in commodity prices and the cost of goods and services.
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 our 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 to fund such expenditures. The actual amount and
timing of our expenditures may differ materially from our estimates as a result of, among other
things, actual drilling results, the timing of expenditures by third parties on projects that we do
not operate, the availability of drilling rigs and other services and equipment, and regulatory,
technological and competitive developments. In addition, under certain circumstances we would
consider increasing or reallocating our 2009 capital budget.
Acquisitions. Our expenditures for acquisitions of proved and unproved properties during the
three months ended March 31, 2009 and 2008 totaled $1.8 million and $0.9 million, 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 $40.8
million increase in outstanding long-term borrowings, a $42.2 million decrease in our net commodity
derivative obligations, and a $19.0 million decrease in our drilling commitments. See Note K 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.
43
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 months ended March 31, 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 $40.6
million and $69.8 million for the three months ended March 31, 2009 and 2008, respectively. The
decrease in operating cash flows during the three months ended March 31, 2009 over 2008 was
principally due to (i) decreases in average realized oil and natural gas prices, (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 three months ended March 31, 2009 and 2008,
we invested $131.6 million and $51.5 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 March 31, 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 financing activities was $38.6
million and $27.2 million for the three months ended March 31, 2009 and 2008, respectively. During
the three months ended March 31, 2009, we had net borrowings of $40.8 million under our credit
facility. During the three months ended March 31, 2008, we reduced our outstanding balance by $26.0
million on our credit facilities utilizing cash from operations.
Our credit facility, as amended, is subject to scheduled semiannual redeterminations, and has
a maturity date of July 31, 2013 (the Credit Facility). At March 31, 2009, we had letters of
credit outstanding under the Credit Facility of approximately $275,000 and
our availability to borrow additional funds was $289.0 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.
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 March 31, 2009) or (ii) a Eurodollar rate
(substantially equal to the London Interbank Offered Rate). At March 31, 2009, the interest rates
of Eurodollar rate advances and JPM Prime Rate advances vary, with interest margins ranging from
125 to 275 basis points and zero to 125 basis points, respectively, per annum depending on the debt
balance outstanding. At March 31, 2009, we pay commitment fees on the unused portion of the
available borrowing base ranging from 25 to 50 basis points per annum.
As part of our April 2009 borrowing base review, we agreed to modify the pricing grid on the
Credit Facility, effective in April 2009. The interest rates of Eurodollar rate advances and JPM
Prime Rate advances will have interest rate 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. We will
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 March 31, 2009, we had $289.0 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.
44
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.
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) additional common stock or (v) other securities. We may also sell
assets. However, in light of the current financial markets 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 March 31, 2009, we had $2.4 million of cash on
hand.
At March 31, 2009, the borrowing base under our credit facility was $960 million, which
provides us with $289.0 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 March 31, 2009 was $1,987.4
million, consisting of debt of $670.8 million and stockholders equity of $1,316.7 million. Our
debt to book capitalization was 34 percent and 32 percent at March 31, 2009 and December 31, 2008,
respectively. Our ratio of current assets to current liabilities was 1.01 to 1.00 at March 31,
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, 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 March 31, 2009, we received an average of $38.51 per barrel of oil and $4.24 per Mcf
of natural gas before consideration of commodity derivative contracts compared to $93.60 per barrel
of oil and $10.05 per Mcf of natural gas in the three months ended March 31, 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
moderate during 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 March 31, 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.
45
Recent Accounting Pronouncements and Developments
Recent accounting pronouncements. In December 2007, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting Standards (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
business combinations in 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 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, 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 included in Note H 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 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, 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. 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 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 the first quarter of 2009, and as such, the adoption of this statement did not have a
significant impact.
46
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, with early adoption permitted for periods ending after March 15, 2009. An entity may
early adopt this FSP only if it also elects to early adopt 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) and FSP SFAS No. 115-2
and SFAS No. 124-2, Recognition and Presentation of Other-Than-Temporary Impairments. We did not
elect early adoption. 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. We are currently evaluating
the potential impact, if any, of FSP SFAS No. 107-1 on our financial statement disclosures.
In April 2009, the FASB issued 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. |
|
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|
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. |
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|
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. |
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|
|
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, with early adoption permitted for periods ending after March 15,
2009. An entity early adopting FSP SFAS No. 157-4 must also early adopt FSP SFAS No. 115-2 and
SFAS No. 124-2. We are not affected by FSP SFAS No. 115-2 and SFAS No. 124-2. We are currently
evaluating the potential impact, if any, of FSP SFAS No. 157-4 on our 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 also permits the use of new technologies to determine proved reserves if those technologies
have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The
Reserve Ruling will also allow companies to disclose their probable and possible reserves to
investors. 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.
47
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 March 31, 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
our revenues, net income and the value of our common stock. At March 31, 2009, the net unrealized
asset on our commodity price risk management contracts was $133.8 million. An average increase in
the commodity price of $5.00 per barrel of oil and $1.00 per Mcf for natural gas from the commodity
prices at March 31, 2009, would have resulted in a decrease in the net unrealized asset on our
commodity price risk management contracts, as reflected on our consolidated balance sheet at March
31, 2009, of approximately $29.2 million.
At March 31, 2009, we had (i) a oil price collar and oil price swaps that settle on a monthly
basis covering future oil production from April 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 April 1, 2009 to March 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 March 31,
2009, was $43.18 per Bbl and $4.49 per MMBtu, respectively. At May 4, 2009, the NYMEX oil futures
price and NYMEX natural gas futures price was $54.47 per Bbl and $3.73 per MMBtu, respectively. A
decrease in oil and natural gas prices, should one continue during 2009, would increase the fair
value asset of our commodity derivative contracts from their recorded balance at March 31, 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 March 31, 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.
48
At March 31, 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 March 31, 2009, would have resulted in a decrease in the
net unrealized
asset on our interest rate risk management contracts, as reflected on our consolidated balance
sheet at March 31, 2009, of approximately $2.1 million.
We had total indebtedness of $670.8 million outstanding under our credit facility at March 31,
2009. The impact of a 1 percent increase in interest rates on this amount of debt, assuming the
interest rate swaps were outstanding, would result in increased annual interest expense of
approximately $6.7 million and a corresponding decrease in net income before income tax.
The fair value of our derivative instruments is determined based on counterparties estimates
and 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 three months
ended March 31, 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) |
|
|
(2,620 |
) |
|
|
(2,426 |
) |
|
|
(5,046 |
) |
Contract maturities |
|
|
(37,125 |
) |
|
|
|
|
|
|
(37,125 |
) |
|
|
|
|
|
|
|
|
|
|
Fair value of contracts outstanding at March 31, 2009 |
|
$ |
133,778 |
|
|
$ |
(3,509 |
) |
|
$ |
130,269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
49
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.
50
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 factor 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 drilling and
development may be eliminated as a result of future legislation.
On February 26, 2009, the White House released President Obamas budget proposal for the
fiscal year 2010. Among the changes contained in the budget proposal is the elimination of certain
key United States federal income tax preferences currently available to oil and gas exploration and
production companies. These changes include, but are not limited to (i) the elimination of the
immediate expensing of intangible drilling costs and (ii) the repeal of the percentage depletion
allowance for oil and gas properties.
On April 23, 2009, the Oil Industry Tax Break Repeal Act of 2009 was introduced in the Senate
and includes many of the proposals outlined in the Presidents budget proposal. It is unclear
whether any such changes will actually be enacted or how soon any such changes could become
effective. The passage of any legislation as a result of the budget proposal, the senate bill or
any other similar change in United States federal income tax law could represent an extremely
significant reduction in the tax benefits that have historically applied to certain investments in
oil and gas properties, which would adversely affect our financial condition and results of
operations.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 6. Exhibits
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|
Exhibit |
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|
Number |
|
Exhibit |
10.1
|
|
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.) |
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10.2 (a)
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Form of Restricted Stock Agreement (for executive officers). |
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31.1 (a) |
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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. |
51
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: May 8, 2009 |
By /s/ Timothy A. Leach |
|
|
Timothy A. Leach |
|
|
Director, Chairman of the Board of Directors and
Chief Executive Officer (Principal Executive Officer) |
|
|
|
|
|
|
|
|
|
|
|
By /s/ Darin G. Holderness
|
|
|
Darin G. Holderness |
|
|
Vice President, Chief Financial Officer and Treasurer
(Principal Financial and Accounting Officer) |
|
52
EXHIBIT INDEX
|
|
|
Exhibit |
|
|
Number |
|
Exhibit |
10.1
|
|
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.) |
|
|
|
10.2 (a)
|
|
Form of Restricted Stock Agreement (for executive officers). |
|
|
|
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. |