e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2010
or
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 1-33615
Concho Resources Inc.
(Exact name of registrant as specified in its charter)
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Delaware
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76-0818600 |
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(State or other jurisdiction
of incorporation or organization)
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(I.R.S. Employer
Identification No.) |
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550 West Texas Avenue, Suite 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
þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer
and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
(Do not check if a smaller reporting company)
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Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
Number
of shares of the registrants common stock outstanding at August
4, 2010: 91,842,832 shares.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Various statements contained in or incorporated by reference into this report that
express a belief, expectation, or intention, or that are not statements of historical fact, are
forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the
Securities Act) and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act).
These forward-looking statements include statements, projections and estimates concerning our
operations, performance, business strategy, oil and natural gas reserves, drilling program capital
expenditures, liquidity and capital resources, the timing and success of specific projects,
outcomes and effects of litigation, claims and disputes, derivative activities and the estimated
purchase price of the acquisition of the assets of Marbob Energy Corporation and affiliates
(Marbob), potential financing, closing timeline and other discussion of the Marbob acquisition.
Forward-looking statements are generally accompanied by words such as estimate, project,
predict, believe, expect, anticipate, potential, could, may, foresee, plan,
goal or other words that convey the uncertainty of future events or outcomes. Forward-looking
statements are not guarantees of performance. We have based these forward-looking statements on our
current expectations and assumptions about future events. These statements are based on certain
assumptions and analyses made by us in light of our experience and our perception of historical
trends, current conditions and expected future developments as well as other factors we believe are
appropriate under the circumstances. Actual results may differ materially from those implied or
expressed by the forward-looking statements. These forward-looking statements speak only as of the
date of this report, or if earlier, as of the date they were made; we disclaim any obligation to
update or revise these statements unless required by securities law, and we caution you not to rely
on them unduly. While our management considers these expectations and assumptions to be reasonable,
they are inherently subject to significant business, economic, competitive, regulatory and other
risks, contingencies and uncertainties relating to, among other matters, the risks discussed in our
Annual Report on Form 10-K for the year ended December 31, 2009, as well as those factors
summarized below:
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sustained or further declines in the prices we receive for our oil and natural
gas; |
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uncertainties about the estimated quantities of oil and natural gas reserves; |
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uncertainty regarding the exercise of preferential purchase rights on assets to
be acquired in the Marbob acquisitions; |
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risks related to the integration of the Marbob assets and employees with our
operations; |
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drilling and operating risks; |
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the adequacy of our capital resources and liquidity including, but not limited
to, access to additional borrowing capacity under our credit facility; |
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the effects of government regulation, permitting and other legal requirements,
including new legislation or regulation of hydraulic fracturing; |
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difficult and adverse conditions in the domestic and global capital and credit
markets; |
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risks related to the concentration of our operations in the Permian Basin of
Southeast New Mexico and West Texas; |
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potential financial losses or earnings reductions from our commodity price risk
management program; |
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shortages of oilfield equipment, services and qualified personnel and increased
costs for such equipment, services and personnel; |
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risks and liabilities associated with acquired properties or businesses,
including the Marbob assets; |
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uncertainties about our ability to successfully execute our business and
financial plans and strategies; |
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uncertainties about our ability to replace reserves and economically develop our
current reserves; |
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general economic and business conditions, either internationally or domestically
or in the jurisdictions in which we operate; |
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competition in the oil and natural gas industry; |
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uncertainty concerning our assumed or possible future results of operations; and |
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our existing indebtedness. |
Reserve engineering is a process of estimating underground accumulations of oil and natural
gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the
quality of available data, the interpretation of such data and price and cost assumptions made by
our reserve engineers. In addition, the results of drilling, testing and production activities may
justify revisions of estimates that were made previously. If significant, such revisions would
change the schedule of any further production and development drilling. Accordingly, reserve
estimates may differ from the quantities of oil and natural gas that are ultimately recovered.
ii
PART I FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements (Unaudited)
iii
Concho Resources Inc.
Consolidated Balance Sheets
Unaudited
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June 30, |
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December 31, |
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(in thousands, except share and per share data) |
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2010 |
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2009 |
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Assets
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Current assets: |
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Cash and cash equivalents |
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$ |
383 |
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$ |
3,234 |
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Accounts receivable, net of allowance for doubtful accounts: |
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Oil and natural gas |
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88,029 |
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69,199 |
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Joint operations and other |
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88,836 |
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100,120 |
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Related parties |
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395 |
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216 |
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Derivative instruments |
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32,409 |
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1,309 |
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Deferred income taxes |
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29,284 |
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Prepaid costs and other |
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10,600 |
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13,896 |
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Total current assets |
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220,652 |
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217,258 |
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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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3,697,653 |
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3,358,004 |
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Accumulated depletion and depreciation |
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(630,255 |
) |
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(517,421 |
) |
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Total oil and natural gas properties, net |
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3,067,398 |
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2,840,583 |
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Other property and equipment, net |
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16,304 |
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15,706 |
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Total property and equipment, net |
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3,083,702 |
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2,856,289 |
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Deferred loan costs, net |
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20,771 |
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20,676 |
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Intangible asset, net operating rights |
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35,748 |
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36,522 |
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Inventory |
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20,258 |
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16,255 |
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Noncurrent derivative instruments |
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62,164 |
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23,614 |
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Other assets |
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958 |
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471 |
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Total assets |
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$ |
3,444,253 |
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$ |
3,171,085 |
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Liabilities and Stockholders Equity
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Current liabilities: |
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Accounts payable: |
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Trade |
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$ |
5,982 |
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$ |
15,443 |
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Related parties |
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852 |
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291 |
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Other current liabilities: |
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Bank overdrafts |
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37,992 |
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3,415 |
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Revenue payable |
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30,172 |
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31,069 |
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Accrued and prepaid drilling costs |
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190,719 |
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164,282 |
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Derivative instruments |
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18,093 |
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62,419 |
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Deferred income taxes |
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3,530 |
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Other current liabilities |
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60,308 |
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60,095 |
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Total current liabilities |
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347,648 |
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337,014 |
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Long-term debt |
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644,023 |
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845,836 |
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Deferred income taxes |
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664,222 |
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603,286 |
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Noncurrent derivative instruments |
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5,678 |
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29,337 |
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Asset retirement obligations and other long-term liabilities |
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20,335 |
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20,184 |
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Commitments and contingencies (Note K) |
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Stockholders equity: |
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Common stock, $0.001 par value; 300,000,000 authorized; 91,851,690 and 85,815,926
shares issued at June 30, 2010 and December 31, 2009, respectively |
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92 |
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86 |
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Additional paid-in capital |
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1,265,179 |
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1,029,392 |
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Retained earnings |
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498,078 |
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306,367 |
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Treasury stock, at cost; 23,667 and 12,380 shares at June 30, 2010 and December 31, 2009,
respectively |
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(1,002 |
) |
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(417 |
) |
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Total stockholders equity |
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1,762,347 |
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1,335,428 |
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Total liabilities and stockholders equity |
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$ |
3,444,253 |
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$ |
3,171,085 |
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The accompanying notes are an integral part of these consolidated financial statements.
1
Concho Resources Inc.
Consolidated Statements of Operations
Unaudited
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Three Months Ended June 30, |
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Six Months Ended June 30, |
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(in thousands, except per share amounts) |
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2010 |
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2009 |
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2010 |
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2009 |
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Operating revenues: |
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Oil sales |
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$ |
174,427 |
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$ |
101,511 |
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$ |
337,152 |
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$ |
166,485 |
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Natural gas sales |
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41,283 |
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25,821 |
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90,558 |
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46,849 |
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Total operating revenues |
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215,710 |
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127,332 |
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427,710 |
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213,334 |
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Operating costs and expenses: |
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Oil and natural gas production |
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40,448 |
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25,817 |
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77,148 |
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50,583 |
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Exploration and abandonments |
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878 |
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1,424 |
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2,173 |
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7,419 |
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Depreciation, depletion and amortization |
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54,101 |
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52,402 |
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107,944 |
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103,150 |
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Accretion of discount on asset retirement obligations |
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372 |
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301 |
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772 |
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579 |
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Impairments of long-lived assets |
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4,692 |
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4,499 |
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7,312 |
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8,555 |
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General and administrative (including non-cash
stock-based compensation of $2,871 and $2,188 for the
three months ended June 30, 2010 and 2009, respectively,
and $5,702 and $4,113 for the six months ended June 30,
2010 and 2009, respectively) |
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17,538 |
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14,172 |
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31,096 |
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25,918 |
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Bad debt expense |
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33 |
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572 |
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(Gain) loss on derivatives not designated as hedges |
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(112,763 |
) |
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81,606 |
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(128,336 |
) |
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86,652 |
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Total operating costs and expenses |
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5,299 |
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180,221 |
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98,681 |
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282,856 |
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Income (loss) from operations |
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210,411 |
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(52,889 |
) |
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329,029 |
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(69,522 |
) |
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Other income (expense): |
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Interest expense |
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(11,192 |
) |
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(6,200 |
) |
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(22,257 |
) |
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(10,570 |
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Other, net |
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(304 |
) |
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180 |
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(377 |
) |
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(148 |
) |
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Total other expense |
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(11,496 |
) |
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(6,020 |
) |
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(22,634 |
) |
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(10,718 |
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Income (loss) before income taxes |
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198,915 |
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(58,909 |
) |
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306,395 |
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(80,240 |
) |
Income tax benefit (expense) |
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(74,744 |
) |
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25,691 |
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(114,684 |
) |
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33,797 |
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Net income (loss) |
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$ |
124,171 |
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$ |
(33,218 |
) |
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$ |
191,711 |
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$ |
(46,443 |
) |
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Basic earnings per share: |
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Net income (loss) per share |
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$ |
1.36 |
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$ |
(0.39 |
) |
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$ |
2.13 |
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$ |
(0.55 |
) |
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Weighted average shares used in basic earnings per share |
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91,044 |
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|
84,799 |
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89,944 |
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|
84,665 |
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Diluted earnings per share: |
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Net income (loss) per share |
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$ |
1.35 |
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$ |
(0.39 |
) |
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$ |
2.10 |
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$ |
(0.55 |
) |
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Weighted average shares used in diluted earnings per share |
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|
92,297 |
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|
|
84,799 |
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|
|
91,220 |
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|
84,665 |
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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, 2009 |
|
|
85,816 |
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|
$ |
86 |
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|
$ |
1,029,392 |
|
|
$ |
306,367 |
|
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|
12 |
|
|
$ |
(417 |
) |
|
$ |
1,335,428 |
|
Net income |
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|
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|
191,711 |
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|
191,711 |
|
Issuance of common stock |
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|
5,348 |
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5 |
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|
219,303 |
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|
219,308 |
|
Stock options exercised |
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|
436 |
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|
1 |
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|
4,079 |
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|
4,080 |
|
Stock-based compensation for restricted stock |
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|
4,114 |
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|
4,114 |
|
Grants of restricted stock |
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|
254 |
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Cancellation of restricted stock |
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(2 |
) |
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Stock-based compensation for stock options |
|
|
|
|
|
|
|
|
|
|
1,588 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,588 |
|
Excess tax benefits related to stock-based compensation |
|
|
|
|
|
|
|
|
|
|
6,703 |
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
6,703 |
|
Purchase of treasury stock |
|
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|
|
|
|
|
|
12 |
|
|
|
(585 |
) |
|
|
(585 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT JUNE 30, 2010 |
|
|
91,852 |
|
|
$ |
92 |
|
|
$ |
1,265,179 |
|
|
$ |
498,078 |
|
|
|
24 |
|
|
$ |
(1,002 |
) |
|
$ |
1,762,347 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
3
Concho Resources Inc.
Consolidated Statements of Cash Flows
Unaudited
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
191,711 |
|
|
$ |
(46,443 |
) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
107,944 |
|
|
|
103,150 |
|
Impairments of long-lived assets |
|
|
7,312 |
|
|
|
8,555 |
|
Accretion of discount on asset retirement obligations |
|
|
772 |
|
|
|
579 |
|
Exploration and abandonments, including dry holes |
|
|
945 |
|
|
|
6,294 |
|
Non-cash compensation expense |
|
|
5,702 |
|
|
|
4,113 |
|
Bad debt expense |
|
|
572 |
|
|
|
|
|
Deferred income taxes |
|
|
100,453 |
|
|
|
(39,799 |
) |
(Gain) loss on sale of assets |
|
|
(169 |
) |
|
|
191 |
|
(Gain) loss on derivatives not designated as hedges |
|
|
(128,336 |
) |
|
|
86,652 |
|
Other non-cash items |
|
|
2,420 |
|
|
|
1,686 |
|
Changes in operating assets and liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(27,831 |
) |
|
|
(18,401 |
) |
Prepaid costs and other |
|
|
105 |
|
|
|
612 |
|
Inventory |
|
|
(3,834 |
) |
|
|
(6,786 |
) |
Accounts payable |
|
|
(8,900 |
) |
|
|
9,415 |
|
Revenue payable |
|
|
(897 |
) |
|
|
8,976 |
|
Other current liabilities |
|
|
(8,439 |
) |
|
|
(562 |
) |
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
239,530 |
|
|
|
118,232 |
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Capital expenditures on oil and natural gas properties |
|
|
(278,002 |
) |
|
|
(223,283 |
) |
Acquisition of oil and natural gas properties |
|
|
(13,362 |
) |
|
|
|
|
Additions to other property and equipment |
|
|
(2,292 |
) |
|
|
(2,014 |
) |
Proceeds from the sale of oil and natural gas properties and other assets |
|
|
790 |
|
|
|
1,004 |
|
Settlements received from (paid on) derivatives not designated as hedges |
|
|
(9,299 |
) |
|
|
61,465 |
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(302,165 |
) |
|
|
(162,828 |
) |
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt |
|
|
360,000 |
|
|
|
211,650 |
|
Payments of long-term debt |
|
|
(562,000 |
) |
|
|
(181,650 |
) |
Net proceeds from issuance of common stock |
|
|
219,308 |
|
|
|
|
|
Exercise of stock options |
|
|
4,080 |
|
|
|
3,931 |
|
Excess tax benefit related to stock-based compensation |
|
|
6,703 |
|
|
|
2,992 |
|
Payments for loan origination costs |
|
|
(2,299 |
) |
|
|
|
|
Purchase of treasury stock |
|
|
(585 |
) |
|
|
(192 |
) |
Bank overdrafts |
|
|
34,577 |
|
|
|
(6,806 |
) |
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
59,784 |
|
|
|
29,925 |
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
|
(2,851 |
) |
|
|
(14,671 |
) |
Cash and cash equivalents at beginning of period |
|
|
3,234 |
|
|
|
17,752 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
383 |
|
|
$ |
3,081 |
|
|
|
|
|
|
|
|
SUPPLEMENTAL CASH FLOWS: |
|
|
|
|
|
|
|
|
Cash paid for interest and fees, net of
$56 and $18 capitalized interest |
|
$ |
21,707 |
|
|
$ |
6,911 |
|
Cash paid for income taxes |
|
$ |
16,715 |
|
|
$ |
4,232 |
|
The accompanying notes are an integral part of these consolidated financial statements.
4
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Note A. Organization and nature of operations
Concho Resources Inc. (the Company or Concho) is a Delaware corporation formed on February
22, 2006. The Companys principal business is the acquisition, development and exploration of oil
and natural gas properties in the Permian Basin region of Southeast 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 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 (U.S. GAAP) 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 is 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, 2009 is derived from audited
consolidated financial statements. In the opinion of management, the accompanying consolidated
financial statements reflect all adjustments necessary to present fairly the Companys financial
position at June 30, 2010, its results of operations for the three and six months ended June 30,
2010 and 2009 and its cash flows for the six months ended June 30, 2010 and 2009. 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, 2009.
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 $20.8 million and $20.7 million, net of accumulated amortization of $10.8 million and $8.6
million, at June 30, 2010 and December 31, 2009, respectively.
5
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Future amortization expense of deferred loan costs at June 30, 2010 is as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
Remaining 2010 |
|
$ |
2,458 |
|
2011 |
|
|
4,973 |
|
2012 |
|
|
5,057 |
|
2013 |
|
|
3,433 |
|
2014 |
|
|
1,132 |
|
Thereafter |
|
|
3,718 |
|
|
|
|
|
Total |
|
$ |
20,771 |
|
|
|
|
|
Intangible assets. The Company has capitalized certain operating rights acquired in 2008. The
gross operating rights, 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. The following table
reflects the gross and net intangible assets at June 30, 2010 and December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Gross intangible operating rights |
|
$ |
38,717 |
|
|
$ |
38,717 |
|
Accumulated amortization |
|
|
(2,969 |
) |
|
|
(2,195 |
) |
|
|
|
|
|
|
|
Net intangible operating rights |
|
$ |
35,748 |
|
|
$ |
36,522 |
|
|
|
|
|
|
|
|
The following table reflects amortization expense for the three and six months ended June 30,
2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
(in thousands) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Amortization expense |
|
$ |
387 |
|
|
$ |
388 |
|
|
$ |
774 |
|
|
$ |
781 |
|
6
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
The following table reflects the estimated aggregate amortization expense for each of the
periods presented below at June 30, 2010:
|
|
|
|
|
(in thousands) |
|
|
|
|
Remaining 2010 |
|
$ |
774 |
|
2011 |
|
|
1,549 |
|
2012 |
|
|
1,549 |
|
2013 |
|
|
1,549 |
|
2014 |
|
|
1,549 |
|
Thereafter |
|
|
28,778 |
|
|
|
|
|
Total |
|
$ |
35,748 |
|
|
|
|
|
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.
The following tables reflect the Companys natural gas imbalance positions at June 30, 2010
and December 31, 2009 as well as amounts reflected in oil and natural gas production expense for
the three and six months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
(dollars in thousands) |
|
2010 |
|
2009 |
|
Natural gas imbalance receivable (included in other assets) |
|
$ |
431 |
|
|
$ |
444 |
|
Undertake position (Mcf) |
|
|
95,736 |
|
|
|
98,584 |
|
|
|
|
|
|
|
|
|
|
Natural gas imbalance liability (included in asset retirement obligations and other
long-term liabilities) |
|
$ |
525 |
|
|
$ |
533 |
|
Overtake position (Mcf) |
|
|
99,438 |
|
|
|
101,278 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
(dollars in thousands) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Value of net overtake (undertake) arising during the period increasing (decreasing)
oil and natural gas production expense |
|
$ |
10 |
|
|
$ |
9 |
|
|
$ |
5 |
|
|
$ |
(40 |
) |
Net overtake (undertake) position arising during the period (Mcf) |
|
|
2,292 |
|
|
|
1,697 |
|
|
|
1,008 |
|
|
|
(10,069 |
) |
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 $3.6 million
7
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
and $2.8 million for the three months ended June 30, 2010 and 2009, respectively, and $6.5 million
and $5.4 million for the six months ended June 30, 2010 and 2009, respectively.
Recent accounting pronouncements.
Various topics. In February 2010, the Financial Accounting Standards Board (the FASB) issued
an update to various topics, which eliminated outdated provisions and inconsistencies in the
Accounting Standards Codification (the Codification), and clarified certain guidance to reflect
the FASBs original intent. The update is effective for the first reporting period, including
interim periods, beginning after issuance of the update, except for the amendments affecting
embedded derivatives and reorganizations. In addition to amending the Codification, the FASB made
corresponding changes to the legacy accounting literature to facilitate historical research. These
changes are included in an appendix to the update. The Company adopted the update effective January
1, 2010, and the adoption did not have a significant impact on the Companys consolidated financial
statements.
Accounting for extractive activities. In April 2010, the FASB issued an amendment to a
paragraph in the accounting standard for oil and natural gas extractive activities accounting. The
standard adds to the Codification the SECs Modernization of Oil and Gas Reporting release. The
Company adopted the update effective April 20, 2010, and the adoption did not have a significant
impact on the Companys consolidated financial statements.
Note C. Exploratory well costs
The Company capitalizes exploratory well costs until a determination is made that the well has
either found proved reserves or that it is impaired. The capitalized exploratory well costs are
presented in unproved properties in the consolidated balance sheets. If the exploratory well is
determined to be impaired, the well costs are charged to expense.
The following table reflects the Companys capitalized exploratory well activity during the
three and six months ended June 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
(in thousands) |
|
June 30, 2010 |
|
|
June 30, 2010 |
|
|
Beginning capitalized exploratory well costs |
|
$ |
24,317 |
|
|
$ |
8,668 |
|
Additions to exploratory well costs pending the determination of proved reserves |
|
|
34,161 |
|
|
|
64,496 |
|
Reclassifications due to determination of proved reserves |
|
|
(25,616 |
) |
|
|
(40,302 |
) |
Exploratory well costs charged to expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending capitalized exploratory well costs |
|
$ |
32,862 |
|
|
$ |
32,862 |
|
|
|
|
|
|
|
|
8
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
The following table provides an aging, at June 30, 2010 and December 31, 2009, of capitalized
exploratory well costs based on the date drilling was completed:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Wells in drilling progress |
|
$ |
7,903 |
|
|
$ |
1,767 |
|
Capitalized exploratory well costs that have been capitalized for a period of one year or less |
|
|
24,959 |
|
|
|
6,901 |
|
Capitalized exploratory well costs that have been capitalized for a period greater than one year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalized exploratory well costs |
|
$ |
32,862 |
|
|
$ |
8,668 |
|
|
|
|
|
|
|
|
At June 30, 2010, the Company had 45 gross exploratory wells waiting on their completion,
including 21 wells in the Texas Permian area, 18 wells in the New Mexico Permian area and 6 wells
in the emerging plays area.
Note D. Business Combinations
Wolfberry acquisitions. In December 2009, together with the acquisition of related additional
interests that closed in 2010, the Company closed two acquisitions (the Wolfberry Acquisitions)
of interests in producing and non-producing assets in the Wolfberry play in the Permian Basin for
approximately $270.7 million. The Wolfberry Acquisitions were primarily funded with borrowings
under the Companys credit facility. See Note J. The Companys 2009 results of operations do not
include any production, revenues or costs from the Wolfberry Acquisitions.
The following table represents the allocation of the total purchase price of the Wolfberry
Acquisitions to the acquired assets and liabilities. The allocation represents the fair values
assigned to each of the assets acquired and liabilities assumed:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Fair value of the Wolfberry Acquisitions net assets: |
|
|
|
|
Proved oil and natural gas properties |
|
$ |
212,987 |
|
Unproved oil and natural gas properties |
|
|
58,222 |
|
|
|
|
|
Total assets acquired |
|
|
271,209 |
|
|
|
|
|
|
Asset retirement obligations |
|
|
(464 |
) |
|
|
|
|
Net purchase price |
|
$ |
270,745 |
|
|
|
|
|
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 productive 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.
9
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
The following table summarizes the Companys asset retirement obligation transactions recorded
during the three and six months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Asset retirement obligations, beginning of period |
|
$ |
20,837 |
|
|
$ |
18,254 |
|
|
$ |
22,754 |
|
|
$ |
16,809 |
|
Liabilities incurred from new wells |
|
|
665 |
|
|
|
102 |
|
|
|
1,111 |
|
|
|
270 |
|
Accretion expense |
|
|
372 |
|
|
|
301 |
|
|
|
772 |
|
|
|
579 |
|
Disposition of wells |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(142 |
) |
Liabilities settled upon plugging and abandoning
wells |
|
|
(112 |
) |
|
|
(343 |
) |
|
|
(297 |
) |
|
|
(353 |
) |
Revision of estimates |
|
|
295 |
|
|
|
(3,928 |
) |
|
|
(2,283 |
) |
|
|
(2,777 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, end of period |
|
$ |
22,057 |
|
|
$ |
14,386 |
|
|
$ |
22,057 |
|
|
$ |
14,386 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note F. Stockholders equity
Equity issuance. On February 1, 2010, the Company issued 5,347,500 shares of its common stock
at $42.75 per share. After deducting underwriting discounts of approximately $9.1 million and
transaction costs, the Company received net proceeds of approximately $219.3 million. The net
proceeds from this offering were used to repay a portion of the borrowings under the Companys
credit facility.
Treasury stock. The restrictions on certain restricted stock awards issued to certain of the
Companys officers, directors and key employees lapsed during the six months ended June 30, 2010.
Immediately upon the lapse of restrictions, these individuals became liable for income taxes on the
value of such shares. In accordance with the Companys 2006 Stock Incentive Plan and the
applicable restricted stock award agreements, some of such persons elected to deliver shares of the
Companys common stock to the Company in exchange for cash used to satisfy such tax liability. In
total, at June 30, 2010 and December 31, 2009, the Company had acquired 23,667 and 12,380 shares,
respectively, that are held as treasury stock in the approximate amounts of $1.0 million and $0.4
million, respectively.
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. Currently, the
Company matches 100 percent of employee contributions, not to exceed 6 percent of the employees
annual salary. The Company contributions to the plans for the three months ended June 30, 2010 and
2009, were approximately $0.4 million and $0.2 million, respectively, and approximately $0.6
million and $0.5 million for the six months ended June 30, 2010 and 2009, respectively.
10
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Stock incentive plan. The Companys 2006 Stock Incentive Plan (together with applicable stock
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 existing awards and awards available under the Plan at June 30,
2010:
|
|
|
|
|
|
|
Number of |
|
|
Common Shares |
|
Approved and authorized awards |
|
|
5,850,000 |
|
Stock option grants, net of forfeitures |
|
|
(3,463,720 |
) |
Restricted stock grants, net of forfeitures |
|
|
(1,057,465 |
) |
|
|
|
|
|
Awards available for future grant |
|
|
1,328,815 |
|
|
|
|
|
|
Restricted stock awards. All restricted shares are treated as issued and outstanding in the
accompanying consolidated balance sheets. Holders of restricted stock are eligible to vote and
receive dividends, if any. If an employee terminates employment prior the restriction lapse date,
the awarded shares that have not vested as of the date of termination of employment are forfeited
and cancelled and are no longer considered issued and outstanding. A summary of the Companys
restricted stock awards activity under the Plan for the six months ended June 30, 2010 is presented
below:
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
Grant Date |
|
|
Restricted |
|
Fair Value |
|
|
Shares |
|
Per Share |
|
Restricted stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009 |
|
|
497,257 |
|
|
|
|
|
Shares granted |
|
|
254,130 |
|
|
$ |
48.57 |
|
Shares cancelled / forteited |
|
|
(1,719 |
) |
|
|
|
|
Lapse of restrictions |
|
|
(65,435 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2010 |
|
|
684,233 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
The following table summarizes information about stock-based compensation for the Companys
restricted stock awards for the three and six months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Grant date fair value for awards during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee grants |
|
$ |
5,751 |
|
|
$ |
4,620 |
|
|
$ |
7,341 |
(a) |
|
$ |
4,620 |
|
Officer and director grants |
|
|
|
|
|
|
|
|
|
|
5,075 |
|
|
|
1,850 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
5,751 |
|
|
$ |
4,620 |
|
|
$ |
12,416 |
|
|
$ |
6,470 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense from restricted stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee grants |
|
$ |
1,140 |
|
|
$ |
830 |
|
|
$ |
2,118 |
|
|
$ |
1,393 |
|
Officer and director grants |
|
|
1,152 |
|
|
|
473 |
|
|
|
1,996 |
|
|
|
807 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
2,292 |
|
|
$ |
1,303 |
|
|
$ |
4,114 |
|
|
$ |
2,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes and other information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit related to restricted stock |
|
$ |
864 |
|
|
$ |
586 |
|
|
$ |
1,553 |
|
|
$ |
927 |
|
Deductions in current taxable income related to
restricted stock |
|
$ |
1,252 |
|
|
$ |
3,989 |
|
|
$ |
2,959 |
|
|
$ |
4,367 |
|
|
|
|
(a) |
|
Includes effects of modifications to certain stock-based awards. |
Stock option awards. A summary of the Companys stock option awards activity under the Plan
for the six months ended June 30, 2010 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Average |
|
|
Number of |
|
Exercise |
|
|
Options |
|
Price |
|
Stock options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009 |
|
|
2,156,503 |
|
|
$ |
14.11 |
|
Options granted |
|
|
|
|
|
$ |
|
|
Options exercised |
|
|
(435,853 |
) |
|
$ |
9.36 |
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2010 |
|
|
1,720,650 |
|
|
$ |
15.31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at end of period |
|
|
1,247,705 |
|
|
$ |
13.26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period |
|
|
835,489 |
|
|
$ |
15.77 |
|
|
|
|
|
|
|
|
|
|
12
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
The following table summarizes information about the Companys vested and exercisable stock
options outstanding at June 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Weighted |
|
|
|
|
|
|
|
|
Number |
|
|
Remaining |
|
|
Average |
|
|
|
|
|
|
|
|
of Stock |
|
|
Contractual |
|
|
Exercise |
|
|
Intrinsic |
|
|
|
|
|
Options |
|
|
Life |
|
|
Price |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
Vested options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price |
|
$8.00 |
|
|
607,782 |
|
|
1.93 years |
|
$ |
8.00 |
|
|
$ |
28,766 |
|
Exercise price |
|
$12.00 |
|
|
95,887 |
|
|
4.46 years |
|
$ |
12.00 |
|
|
|
4,155 |
|
Exercise price |
|
$12.50 - $15.50 |
|
|
257,500 |
|
|
6.22 years |
|
$ |
14.83 |
|
|
|
10,429 |
|
Exercise price |
|
$20.00 - $23.00 |
|
|
236,578 |
|
|
7.80 years |
|
$ |
21.67 |
|
|
|
7,962 |
|
Exercise price |
|
$28.00 - $37.27 |
|
|
49,958 |
|
|
7.97 years |
|
$ |
31.78 |
|
|
|
1,177 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,247,705 |
|
|
4.37 years |
|
$ |
13.26 |
|
|
$ |
52,489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price |
|
$8.00 |
|
|
213,394 |
|
|
2.74 years |
|
$ |
8.00 |
|
|
$ |
10,100 |
|
Exercise price |
|
$12.00 |
|
|
78,059 |
|
|
5.13 years |
|
$ |
12.00 |
|
|
|
3,382 |
|
Exercise price |
|
$12.50 - $15.50 |
|
|
257,500 |
|
|
6.22 years |
|
$ |
14.83 |
|
|
|
10,429 |
|
Exercise price |
|
$20.00 - $23.00 |
|
|
236,578 |
|
|
7.80 years |
|
$ |
21.67 |
|
|
|
7,962 |
|
Exercise price |
|
$28.00 - $37.27 |
|
|
49,958 |
|
|
7.97 years |
|
$ |
31.78 |
|
|
|
1,177 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
835,489 |
|
|
5.78 years |
|
$ |
15.77 |
|
|
$ |
33,050 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
The following table summarizes information about stock-based compensation for stock options
for the three and six months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Grant date fair value for awards during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee grants |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Officer and director grants |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,454 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,454 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense from stock options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee grants |
|
$ |
42 |
|
|
$ |
70 |
|
|
$ |
86 |
|
|
$ |
141 |
|
Officer and director grants |
|
|
537 |
|
|
|
815 |
|
|
|
1,502 |
|
|
|
1,772 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
579 |
|
|
$ |
885 |
|
|
$ |
1,588 |
|
|
$ |
1,913 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes and other information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit related to stock options |
|
$ |
218 |
|
|
$ |
415 |
|
|
$ |
599 |
|
|
$ |
806 |
|
Deductions in current taxable income related to stock options exercised |
|
$ |
8,473 |
|
|
$ |
4,117 |
|
|
|
$18,124 |
|
|
$ |
7,157 |
|
The Company used the simplified method that is accepted by the SEC to calculate the
expected term for stock options granted during the six months ended June 30, 2009, since it did 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.
Future stock-based compensation expense. Future stock-based compensation expense based on the
awards outstanding at June 30, 2010 is summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted |
|
|
Stock |
|
|
|
|
(in thousands) |
|
Stock |
|
|
Options |
|
|
Total |
|
|
Remaining 2010 |
|
$ |
4,862 |
|
|
$ |
1,065 |
|
|
$ |
5,927 |
|
2011 |
|
|
6,239 |
|
|
|
879 |
|
|
|
7,118 |
|
2012 |
|
|
3,524 |
|
|
|
184 |
|
|
|
3,708 |
|
2013 |
|
|
1,237 |
|
|
|
15 |
|
|
|
1,252 |
|
2014 |
|
|
56 |
|
|
|
|
|
|
|
56 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
15,918 |
|
|
$ |
2,143 |
|
|
$ |
18,061 |
|
|
|
|
|
|
|
|
|
|
|
14
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Note H. Disclosures about fair value of financial instruments
The Company uses a valuation framework based upon inputs that market participants use in
pricing an asset or liability, which are classified into two categories: observable inputs and
unobservable inputs. Observable inputs represent market data obtained from independent sources,
whereas unobservable inputs reflect a companys own market assumptions, which are used if
observable inputs are not reasonably available without undue cost and effort. These two types of
inputs are further prioritized into the following fair value input hierarchy:
|
Level 1: |
|
Unadjusted quoted prices in active markets that are accessible at the
measurement date for identical, unrestricted assets or liabilities. The Company considers
active markets to be those in which transactions for the assets or liabilities occur in
sufficient frequency and volume to provide pricing information on an ongoing basis. |
|
|
Level 2: |
|
Quoted prices in markets that are not active, or inputs which are observable,
either directly or indirectly, for substantially the full term of the asset or liability.
This category includes those derivative instruments that the Company values using
observable market data. Substantially all of these inputs are observable in the
marketplace throughout the full term of the derivative instrument, can be derived from
observable data, or supported by observable levels at which transactions are executed in
the marketplace. Level 2 instruments primarily include non-exchange traded derivatives
such as over-the-counter commodity price swaps, basis swaps, investments and interest
rate swaps. The Companys valuation models are primarily industry-standard models that
consider various inputs including: (i) quoted forward prices for commodities, (ii) time
value and (iii) current market and contractual prices for the underlying instruments, as
well as other relevant economic measures. The Company utilizes its counterparties
valuations to assess the reasonableness of its prices and valuation techniques. |
|
|
Level 3: |
|
Measured based on prices or valuation models that require inputs that are both
significant to the fair value measurement and less observable from objective sources
(i.e., supported by little or no market activity). Level 3 instruments primarily include
derivative instruments, such as commodity price collars and floors, as well as
investments. The Companys valuation models are primarily industry-standard models that
consider various inputs including: (i) quoted forward prices for commodities, (ii) time
value, (iii) volatility factors and (iv) current market and contractual prices for the
underlying instruments, as well as other relevant economic measures. Although the
Company utilizes its counterparties valuations to assess the reasonableness of its
prices and valuation techniques, the Company does not have sufficient corroborating
market evidence to support classifying these assets and liabilities as Level 2. |
15
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
The fair value input hierarchy level to which an asset or liability measurement in its
entirety falls is determined based on the lowest level input that is significant to the measurement
in its entirety. The following table presents the Companys assets and liabilities that are
measured at fair value on a recurring basis at June 30, 2010, for each of the fair value hierarchy
levels:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at Reporting Date Using |
|
|
|
|
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Other |
|
|
Significant |
|
|
|
|
|
|
Active Markets for |
|
|
Observable |
|
|
Unobservable |
|
|
Fair Value at |
|
|
|
Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
|
June 30, |
|
(in thousands) |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
2010 |
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
$ |
|
|
|
$ |
122,689 |
|
|
$ |
|
|
|
$ |
122,689 |
|
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
3,808 |
|
|
|
3,808 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
122,689 |
|
|
|
3,808 |
|
|
|
126,497 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
(44,315 |
) |
|
|
|
|
|
|
(44,315 |
) |
Commodity derivative basis swap contracts |
|
|
|
|
|
|
(5,095 |
) |
|
|
|
|
|
|
(5,095 |
) |
Interest rate derivative swap contracts |
|
|
|
|
|
|
(6,285 |
) |
|
|
|
|
|
|
(6,285 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(55,695 |
) |
|
|
|
|
|
|
(55,695 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial assets (liabilities) |
|
$ |
|
|
|
$ |
66,994 |
|
|
$ |
3,808 |
|
|
$ |
70,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth a reconciliation of changes in the fair value of financial
assets (liabilities) classified as Level 3 in the fair value hierarchy:
|
|
|
|
|
(in thousands) |
|
|
|
|
Balance at December 31, 2009 |
|
$ |
(945 |
) |
Realized and unrealized gains, net |
|
|
6,584 |
|
Settlements (receipts), net |
|
|
(1,831 |
) |
|
|
|
|
Balance at June 30, 2010 |
|
$ |
3,808 |
|
|
|
|
|
|
|
|
|
|
Total gains for the period included in earnings attributable to the change in unrealized gains relating to assets
(liabilities) still held at the reporting date |
|
$ |
4,753 |
|
|
|
|
|
16
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following table presents the carrying amounts and fair values of the Companys financial
instruments at June 30, 2010 and December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2010 |
|
December 31, 2009 |
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
(in thousands) |
|
Value |
|
Value |
|
Value |
|
Value |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments |
|
$ |
94,573 |
|
|
$ |
94,573 |
|
|
$ |
24,923 |
|
|
$ |
24,923 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments |
|
$ |
23,771 |
|
|
$ |
23,771 |
|
|
$ |
91,756 |
|
|
$ |
91,756 |
|
Credit facility |
|
$ |
348,000 |
|
|
$ |
332,029 |
|
|
$ |
550,000 |
|
|
$ |
528,849 |
|
8.625% senior notes due 2017 |
|
$ |
296,023 |
|
|
$ |
309,000 |
|
|
$ |
295,836 |
|
|
$ |
315,000 |
|
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.
Credit facility. The fair value of the Companys credit facility is estimated by discounting
the principal and interest payments at the Companys credit adjusted discount rate at the reporting
date.
Senior notes. The fair value of the Companys senior notes is based on quoted market prices.
17
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Derivative instruments. The fair value of the Companys derivative instruments are estimated
by management considering various factors, including closing exchange and over-the-counter
quotations and the time value of the underlying commitments. 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 tables (i) summarize the
valuation of each of the Companys financial instruments by required pricing levels and (ii)
summarize the gross fair value by the appropriate balance sheet classification, even when the
derivative instruments are subject to netting arrangements and qualify for net presentation in the
Companys consolidated balance sheets at June 30, 2010 and December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
Total |
|
|
|
Quoted Prices in |
|
|
Other |
|
|
Significant |
|
|
Carrying Value |
|
|
|
Active Markets for |
|
|
Observable |
|
|
Unobservable |
|
|
at |
|
|
|
Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
|
June 30, |
|
(in thousands) |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
2010 |
|
|
Assets (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
$ |
|
|
|
$ |
50,851 |
|
|
$ |
|
|
|
$ |
50,851 |
|
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
3,808 |
|
|
|
3,808 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,851 |
|
|
|
3,808 |
|
|
|
54,659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
71,838 |
|
|
|
|
|
|
|
71,838 |
|
Interest rate derivative swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
71,838 |
|
|
|
|
|
|
|
71,838 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
(32,772 |
) |
|
|
|
|
|
|
(32,772 |
) |
Commodity derivative basis swap contracts |
|
|
|
|
|
|
(3,485 |
) |
|
|
|
|
|
|
(3,485 |
) |
Interest rate derivative swap contracts |
|
|
|
|
|
|
(4,086 |
) |
|
|
|
|
|
|
(4,086 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(40,343 |
) |
|
|
|
|
|
|
(40,343 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
(11,543 |
) |
|
|
|
|
|
|
(11,543 |
) |
Commodity derivative basis swap contracts |
|
|
|
|
|
|
(1,610 |
) |
|
|
|
|
|
|
(1,610 |
) |
Interest rate derivative swap contracts |
|
|
|
|
|
|
(2,199 |
) |
|
|
|
|
|
|
(2,199 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15,352 |
) |
|
|
|
|
|
|
(15,352 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial assets |
|
$ |
|
|
|
$ |
66,994 |
|
|
$ |
3,808 |
|
|
$ |
70,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Total current financial assets, gross basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
14,316 |
|
(b) Total noncurrent financial assets, gross basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56,486 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
70,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
Total |
|
|
|
Quoted Prices in |
|
|
Other |
|
|
Significant |
|
|
Carrying Value |
|
|
|
Active Markets for |
|
|
Observable |
|
|
Unobservable |
|
|
at |
|
|
|
Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
|
December 31, |
|
(in thousands) |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
2009 |
|
|
Assets (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
$ |
|
|
|
$ |
13,850 |
|
|
$ |
|
|
|
$ |
13,850 |
|
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
134 |
|
|
|
134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,850 |
|
|
|
134 |
|
|
|
13,984 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
35,016 |
|
|
|
|
|
|
|
35,016 |
|
Interest rate derivative swap contracts |
|
|
|
|
|
|
1,369 |
|
|
|
|
|
|
|
1,369 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36,385 |
|
|
|
|
|
|
|
36,385 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
(65,351 |
) |
|
|
|
|
|
|
(65,351 |
) |
Commodity derivative basis swap contracts |
|
|
|
|
|
|
(5,254 |
) |
|
|
|
|
|
|
(5,254 |
) |
Interest rate derivative swap contracts |
|
|
|
|
|
|
(3,870 |
) |
|
|
|
|
|
|
(3,870 |
) |
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
(619 |
) |
|
|
(619 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(74,475 |
) |
|
|
(619 |
) |
|
|
(75,094 |
) |
Noncurrent: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
(38,259 |
) |
|
|
|
|
|
|
(38,259 |
) |
Commodity derivative basis swap contracts |
|
|
|
|
|
|
(3,389 |
) |
|
|
|
|
|
|
(3,389 |
) |
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
(460 |
) |
|
|
(460 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(41,648 |
) |
|
|
(460 |
) |
|
|
(42,108 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial liabilities |
|
$ |
|
|
|
$ |
(65,888 |
) |
|
$ |
(945 |
) |
|
$ |
(66,833 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Total current financial liabilities, gross basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(61,110 |
) |
(b)Total noncurrent financial liabilities, gross basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,723 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(66,833 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The fair value of derivative instruments reported in the Companys consolidated balance
sheets are subject to netting arrangements and qualify for net presentation. The following
table reports the net basis derivative fair values as reported in the consolidated balance
sheets at June 30, 2010 and December 31, 2009: |
19
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Consolidated Balance Sheet Classification: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative contracts: |
|
|
|
|
|
|
|
|
Assets |
|
$ |
32,409 |
|
|
$ |
1,309 |
|
Liabilities |
|
|
(18,093 |
) |
|
|
(62,419 |
) |
|
|
|
|
|
|
|
Net current |
|
$ |
14,316 |
|
|
$ |
(61,110 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent derivative contracts: |
|
|
|
|
|
|
|
|
Assets |
|
$ |
62,164 |
|
|
$ |
23,614 |
|
Liabilities |
|
|
(5,678 |
) |
|
|
(29,337 |
) |
|
|
|
|
|
|
|
Net noncurrent |
|
$ |
56,486 |
|
|
$ |
(5,723 |
) |
|
|
|
|
|
|
|
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 The Company reviews its long-lived assets to be held and
used, including proved oil and natural 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 undiscounted future net cash flows is less than the carrying amount of the
assets. In that 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 natural 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 natural gas reserve quantities, timing of development and production,
expected future commodity prices, capital expenditures and production costs.
The Company periodically reviews its proved oil and natural gas properties that are sensitive
to oil and natural gas prices for impairment. Due primarily to downward adjustments to the
economically recoverable resource potential associated with declines in commodity prices and well
performance, the Company recognized impairment expense related to its proved oil and natural gas
properties. The following table reports the carrying amounts, estimated fair values and impairment
expense of long-lived assets for the three and six months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying |
|
Estimated |
|
Impairment |
(in thousands) |
|
Amount |
|
Fair Value |
|
Expense |
|
Three Months Ended June 30, 2010 |
|
$ |
7,884 |
|
|
$ |
3,192 |
|
|
$ |
4,692 |
|
Three Months Ended June 30, 2009 |
|
$ |
7,232 |
|
|
$ |
2,733 |
|
|
$ |
4,499 |
|
Six Months Ended June 30, 2010 |
|
$ |
13,776 |
|
|
$ |
6,464 |
|
|
$ |
7,312 |
|
Six Months Ended June 30, 2009 |
|
$ |
14,175 |
|
|
$ |
5,620 |
|
|
$ |
8,555 |
|
20
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Asset Retirement Obligations The Company estimates the fair value of asset retirement
obligations based on discounted cash flow projections using numerous estimates, assumptions and
judgments regarding such factors as the existence of a legal obligation for an asset retirement
obligation; 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 asset retirement obligations.
Measurement information for assets that are measured at fair value on a nonrecurring basis was
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
Quoted Prices in |
|
Other |
|
Significant |
|
|
|
|
Active Markets for |
|
Observable |
|
Unobservable |
|
Total |
|
|
Identical Assets |
|
Inputs |
|
Inputs |
|
Impairment |
(in thousands) |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
Loss |
|
Three Months Ended June 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
3,192 |
|
|
$ |
4,692 |
|
Asset retirement obligations incurred in current period |
|
|
|
|
|
|
|
|
|
|
665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
2,733 |
|
|
$ |
4,499 |
|
Asset retirement obligations incurred in current period |
|
|
|
|
|
|
|
|
|
|
102 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
6,464 |
|
|
$ |
7,312 |
|
Asset retirement obligations incurred in current period |
|
|
|
|
|
|
|
|
|
|
1,111 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
5,620 |
|
|
$ |
8,555 |
|
Asset retirement obligations incurred in current period |
|
|
|
|
|
|
|
|
|
|
270 |
|
|
|
|
|
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 oil and natural gas the Company produces and sells, (ii) support the Companys
capital budget and expenditure plans and (iii) support the economics associated with acquisitions.
Interest rate hedges are used to mitigate the cash flow risk associated with rising interest rates.
The Company does not enter into derivative financial instruments for speculative or trading
purposes. The Company also may enter into physical delivery contracts to effectively provide
commodity price hedges. Because these contracts are not expected to be net cash settled, they are
considered to be normal sales contracts and not derivatives. Therefore, these contracts are not
recorded in the Companys consolidated financial statements.
Currently, the Company does not designate its derivative instruments to qualify for hedge
accounting. Accordingly, the Company reflects changes in the fair value of its derivative
instruments in its statements of operations.
21
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
New commodity derivative contracts in the first half of 2010. During the six months ended
June 30, 2010, the Company entered into additional commodity derivative contracts to hedge a
portion of its estimated future production. The following table summarizes information about these
additional commodity derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
Index |
|
Contract |
|
|
Volume |
|
Price |
|
Period |
|
Oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
670,000 |
|
|
$ |
83.72 |
(a) |
|
|
1/1/10 - 12/31/10 |
|
Price swap |
|
|
195,000 |
|
|
$ |
76.85 |
(a) |
|
|
3/1/10 - 12/31/10 |
|
Price swap |
|
|
1,463,000 |
|
|
$ |
88.63 |
(a) |
|
|
5/1/10 - 12/31/10 |
|
Price swap |
|
|
2,136,000 |
|
|
$ |
88.36 |
(a) |
|
|
1/1/11 - 12/31/11 |
|
Price swap |
|
|
2,268,000 |
|
|
$ |
92.68 |
(a) |
|
|
1/1/12 - 12/31/12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
418,000 |
|
|
$ |
5.99 |
(b) |
|
|
2/1/10 - 12/31/10 |
|
Price swap |
|
|
1,250,000 |
|
|
$ |
5.55 |
(b) |
|
|
3/1/10 - 12/31/10 |
|
Price swap |
|
|
5,076,000 |
|
|
$ |
6.14 |
(b) |
|
|
1/1/11 - 12/31/11 |
|
Price swap |
|
|
300,000 |
|
|
$ |
6.54 |
(b) |
|
|
1/1/12 - 12/31/12 |
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate
monthly average futures price. |
|
(b) |
|
The index prices for the natural gas price swaps are based on the NYMEX-Henry Hub last trading
day futures price. |
22
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Commodity derivative contracts at June 30, 2010. The following table sets forth the
Companys outstanding commodity derivative contracts at June 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
Total |
|
Oil Swaps: (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
|
|
|
|
|
|
|
|
1,817,936 |
|
|
|
1,651,936 |
|
|
|
3,469,872 |
|
Price per Bbl |
|
|
|
|
|
|
|
|
|
$ |
76.78 |
|
|
$ |
76.43 |
|
|
$ |
76.61 |
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
1,378,436 |
|
|
|
1,339,436 |
|
|
|
1,304,436 |
|
|
|
1,272,436 |
|
|
|
5,294,744 |
|
Price per Bbl |
|
$ |
81.55 |
|
|
$ |
81.80 |
|
|
$ |
82.03 |
|
|
$ |
82.26 |
|
|
$ |
81.90 |
|
2012: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
693,000 |
|
|
|
693,000 |
|
|
|
693,000 |
|
|
|
693,000 |
|
|
|
2,772,000 |
|
Price per Bbl |
|
$ |
99.07 |
|
|
$ |
99.07 |
|
|
$ |
99.07 |
|
|
$ |
99.07 |
|
|
$ |
99.07 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
|
|
|
|
2,427,000 |
|
|
|
2,258,000 |
|
|
|
4,685,000 |
|
Price per MMBtu |
|
|
|
|
|
|
|
|
|
$ |
6.03 |
|
|
$ |
6.03 |
|
|
$ |
6.03 |
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
1,569,000 |
|
|
|
3,069,000 |
|
|
|
3,069,000 |
|
|
|
3,069,000 |
|
|
|
10,776,000 |
|
Price per MMBtu |
|
$ |
6.36 |
|
|
$ |
6.62 |
|
|
$ |
6.62 |
|
|
$ |
6.62 |
|
|
$ |
6.58 |
|
2012: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
75,000 |
|
|
|
75,000 |
|
|
|
75,000 |
|
|
|
75,000 |
|
|
|
300,000 |
|
Price per MMBtu |
|
$ |
6.54 |
|
|
$ |
6.54 |
|
|
$ |
6.54 |
|
|
$ |
6.54 |
|
|
$ |
6.54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Collars: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
|
|
|
|
1,500,000 |
|
|
|
1,500,000 |
|
|
|
3,000,000 |
|
Price per MMBtu |
|
|
|
|
|
|
|
|
|
$ |
5.25 - $5.75 |
|
|
$ |
6.00 - $6.80 |
|
|
$ |
5.63 - $6.28 |
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
1,500,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,500,000 |
|
Price per MMBtu |
|
$ |
6.00 - $6.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
6.00 - $6.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Swaps: (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
|
|
|
|
2,100,000 |
|
|
|
2,100,000 |
|
|
|
4,200,000 |
|
Price per MMBtu |
|
|
|
|
|
|
|
|
|
$ |
0.85 |
|
|
$ |
0.85 |
|
|
$ |
0.85 |
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
1,800,000 |
|
|
|
1,800,000 |
|
|
|
1,800,000 |
|
|
|
1,800,000 |
|
|
|
7,200,000 |
|
Price per MMBtu |
|
$ |
0.87 |
|
|
$ |
0.76 |
|
|
$ |
0.76 |
|
|
$ |
0.76 |
|
|
$ |
0.79 |
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate monthly
average futures price. |
|
(b) |
|
The index prices for the natural gas price swaps and collars are based on the NYMEX-Henry Hub
last trading day futures price. |
|
(c) |
|
The basis differential between the El Paso Permian delivery point and NYMEX Henry Hub delivery
point. |
23
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Interest rate derivative contracts. The Company has an interest rate swap which fixes the
LIBOR interest rate on $300 million of the Companys bank debt at 1.90 percent for three years
beginning in May 2009. For this portion of the Companys bank debt, the all-in interest rate will
be calculated by adding the fixed rate of 1.90 percent to a margin that ranges from 2.00 percent to
3.00 percent, depending on the amount of bank debt outstanding.
The following table summarizes the gains and losses reported in earnings related to the
commodity and interest rate derivative instruments for the three and six months ended June 30, 2010
and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Gain (loss) on derivatives not designated as hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash (payments on) receipts from derivatives not designated as hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
(2,852 |
) |
|
$ |
21,828 |
|
|
$ |
(12,985 |
) |
|
$ |
56,412 |
|
Natural gas |
|
|
5,614 |
|
|
|
3,292 |
|
|
|
6,120 |
|
|
|
5,832 |
|
Interest rate derivatives |
|
|
(1,221 |
) |
|
|
(779 |
) |
|
|
(2,434 |
) |
|
|
(779 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market gain (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
119,303 |
|
|
|
(105,062 |
) |
|
|
120,741 |
|
|
|
(144,099 |
) |
Natural gas |
|
|
(6,509 |
) |
|
|
(4,312 |
) |
|
|
20,678 |
|
|
|
(5,018 |
) |
Interest rate derivatives |
|
|
(1,572 |
) |
|
|
3,427 |
|
|
|
(3,784 |
) |
|
|
1,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivatives not designated as hedges |
|
$ |
112,763 |
|
|
$ |
(81,606 |
) |
|
$ |
128,336 |
|
|
$ |
(86,652 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
All of the Companys commodity derivative contracts at June 30, 2010 are expected to settle by
December 31, 2012.
Note J. Debt
The Companys debt consisted of the following at June 30, 2010 and December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Credit facility |
|
$ |
348,000 |
|
|
$ |
550,000 |
|
8.625% unsecured senior notes due 2017 |
|
|
300,000 |
|
|
|
300,000 |
|
Less: unamortized original issue discount |
|
|
(3,977 |
) |
|
|
(4,164 |
) |
Less: current portion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
644,023 |
|
|
$ |
845,836 |
|
|
|
|
|
|
|
|
Credit facility. The Companys credit facility, as amended (the Credit Facility), has a
maturity date of July 31, 2013. At June 30, 2010, the Companys borrowing base was $1.2 billion, it
had letters of credit outstanding under the Credit Facility of approximately $25,000, and its
availability to borrow additional funds was approximately $852.0 million. The next scheduled
borrowing base redetermination will occur in October 2010. 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.
24
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
In July 2010, the Company received an $800 million underwritten commitment from two of its
lenders under the Credit Facility to expand the size of its existing Credit Facility from $1.2
billion to $2.0 billion as part of the financing for an upcoming acquisition. The expanded credit
facility is expected to close simultaneously with such acquisition. See Note Q.
Advances on the Credit Facility bear interest, at the Companys option, based on (i) the prime
rate of JPMorgan Chase Bank (JPM Prime Rate) (3.25 percent at June 30, 2010) or (ii) a Eurodollar
rate (substantially equal to the London Interbank Offered Rate). At June 30, 2010, the interest
rates of Eurodollar rate advances and JPM Prime Rate advances vary, with interest margins ranging
from 200 to 300 basis points and 112.5 to 212.5 basis points, respectively, per annum depending on
the debt balance outstanding. At June 30, 2010, the Company pays commitment fees on the unused
portion of the available borrowing base of 50 basis points per annum.
The Credit Facility also includes a same-day advance facility under which the Company may
borrow funds from the administrative agent. Same-day advances cannot exceed $25 million and the
maturity dates cannot exceed fourteen days. The interest rate on the same-day advance 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 Facility contains various restrictive covenants and
compliance requirements which include (a) maintenance of certain financial ratios, including (i) a
quarterly ratio of total debt to consolidated earnings before interest expense, income taxes,
depletion, depreciation, and amortization, exploration expense and other noncash income and
expenses to be no greater than 4.0 to 1.0, and (ii) a ratio of current assets to current
liabilities, excluding noncash assets and liabilities related to financial derivatives and asset
retirement obligations and including the unfunded amounts under the Credit Facility, to be no less
than 1.0 to 1.0; (b) limits on the incurrence of additional indebtedness and certain types of
liens; (c) restrictions as to mergers, combinations and dispositions of assets; and (d)
restrictions on the payment of cash dividends. At June 30, 2010, the Company was in compliance with
its covenants under the Credit Facility.
8.625% unsecured senior notes. On September 18, 2009, the Company completed its public
offering of $300 million aggregate principal amount of 8.625% senior notes due 2017 (the Senior
Notes). The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by
all of the Companys subsidiaries.
The Senior Notes will mature on October 1, 2017, and interest is payable on the Senior Notes
each April 1 and October 1. The Company received net proceeds of $288.2 million (net of related
estimated offering costs), which were used to repay a portion of the outstanding borrowings under
the Credit Facility.
The Company may redeem some or all of the Senior Notes at any time on or after October 1, 2013
at the redemption prices specified in the indenture governing the Senior Notes. The Company may
also redeem up to 35 percent of the Senior Notes using all or a portion of the net proceeds of
certain public sales of equity interests completed before October 1, 2012 at a redemption price as
specified in the indenture. If the Company sells certain assets or experiences specific kinds of
change of control, each as described in the indenture, each holder of the Senior Notes will have
the right to require the Company to repurchase the Senior Notes at a purchase price described in
the indenture plus accrued and unpaid interest, if any, to the date of repurchase. At June 30,
2010, the Company was in compliance with its covenants in the indenture governing the Senior Notes.
25
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Future interest expense from the original issue discount on the Senior Notes at June 30, 2010
is as follows:
|
|
|
|
|
(in thousands) |
|
|
|
Remaining 2010 |
|
$ |
197 |
|
2011 |
|
|
421 |
|
2012 |
|
|
462 |
|
2013 |
|
|
507 |
|
2014 |
|
|
557 |
|
Thereafter |
|
|
1,833 |
|
|
|
|
|
Total |
|
$ |
3,977 |
|
|
|
|
|
Principal maturities of debt. Principal maturities of debt outstanding at June 30, 2010 are as
follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2010 |
|
$ |
|
|
2011 |
|
|
|
|
2012 |
|
|
|
|
2013 |
|
|
348,000 |
|
2014 and thereafter |
|
|
300,000 |
|
|
|
|
|
Total |
|
$ |
648,000 |
|
|
|
|
|
Interest expense. The following amounts have been incurred and charged to interest expense for
the three and six months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Cash payments for interest |
|
$ |
18,016 |
|
|
$ |
3,457 |
|
|
$ |
21,763 |
|
|
$ |
6,929 |
|
Amortization of original issue discount |
|
|
95 |
|
|
|
|
|
|
|
187 |
|
|
|
|
|
Amortization of deferred loan origination costs |
|
|
1,164 |
|
|
|
857 |
|
|
|
2,204 |
|
|
|
1,713 |
|
Net changes in accruals |
|
|
(8,045 |
) |
|
|
1,889 |
|
|
|
(1,841 |
) |
|
|
1,946 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest costs incurred |
|
|
11,230 |
|
|
|
6,203 |
|
|
|
22,313 |
|
|
|
10,588 |
|
Less: capitalized interest |
|
|
(38 |
) |
|
|
(3 |
) |
|
|
(56 |
) |
|
|
(18 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest expense |
|
$ |
11,192 |
|
|
$ |
6,200 |
|
|
$ |
22,257 |
|
|
$ |
10,570 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Note K. Commitments and contingencies
Severance agreements. The Company has entered into severance and change in control agreements
with all of its officers. The current annual salaries for the Companys officers covered under such
agreements total approximately $2.1 million.
Indemnification. The Company has agreed to indemnify its directors and officers for claims and
damages arising from certain acts or omissions taken in such capacity.
Legal actions. The Company is a party to proceedings and claims incidental to its business.
While many of these matters involve inherent uncertainty, the Company believes that the amount of
the liability, if any, ultimately incurred with respect to any such proceedings or claims will not
have a material adverse effect on the Companys consolidated financial position as a whole or on
its liquidity, capital resources or future results of operations. The Company will continue to
evaluate proceedings and claims involving the Company on a quarter-by-quarter basis and will
establish and adjust any reserves as appropriate to reflect its assessment of the then current
status of the matters.
Acquisition commitments. In connection with the July 2008 acquisition of Henry Petroleum LP
and certain entities and individuals affiliated with Henry Petroleum LP (collectively, the Henry
Entities), the Company agreed to pay certain employees, who were formerly employed by the Henry
Entities, bonuses of approximately $11.0 million in the aggregate at each of the first and second
anniversaries of the closing of the acquisition. Except as described below, these employees must
remain employed with the Company to receive the bonus. A former Henry Entities employee who is
otherwise entitled to a full bonus will receive the full bonus (i) if the Company terminates the
employee without cause, (ii) upon the death or disability of such employee or (iii) upon a change
in control of the Company. If any such employee resigns or is terminated for cause, the employee
will not receive the bonus and, subject to certain conditions, the Company will be required to
reimburse the sellers in the acquisition of the Henry Entities 65 percent of the bonus amount not
paid to the employee. The Company reflects the bonus amounts to be paid to these employees as a
period cost, which is included in the Companys results of operations over the period earned.
Amounts that ultimately are determined to be paid to the sellers are treated as a contingent
purchase price and reflected as an adjustment to the purchase price. During the three months ended
June 30, 2010 and 2009, the Company recognized $2.5 million and $2.8 million, respectively, of this
obligation in its results of operations, and $4.9 million and $5.3 million during the six months
ended June 30, 2010 and 2009, respectively.
Daywork commitments. The Company periodically enters into contractual arrangements under which
the Company is committed to expend funds to drill wells in the future, including agreements to
secure drilling rig services, which require the Company to make future minimum payments to the rig
operators. The Company records drilling commitments in the periods in which well capital is
incurred or rig services are provided. The following table summarizes the Companys future drilling
commitments at June 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due By Period |
|
|
|
|
|
|
|
Less than |
|
|
1 - 3 |
|
|
3 - 5 |
|
|
More than |
|
(in thousands) |
|
Total |
|
|
1 year |
|
|
years |
|
|
years |
|
|
5 years |
|
|
Daywork drilling contracts with related parties (a) |
|
$ |
1,000 |
|
|
$ |
1,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Daywork drilling contracts assumed in the Henry Entities acquisition (b) |
|
|
313 |
|
|
|
313 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual drilling commitments |
|
$ |
1,313 |
|
|
$ |
1,313 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Consists of daywork drilling contracts with Silver Oak Drilling, LLC, an affiliate
of Chase Oil Corporation, a stockholder of the Company. |
|
(b) |
|
A major oil and natural gas company which owns an interest in the wells being
drilled and the Company are parties to these contracts. Only the Companys 25 percent share of the
contract obligation has been reflected above. |
27
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Operating leases. The Company leases vehicles, equipment and office facilities under
non-cancellable operating leases. Lease payments associated with these operating leases for the
three months ended June 30, 2010 and 2009 were approximately $0.5 million and $0.6 million,
respectively, and approximately $1.1 million and $1.3 million for the six months ended June 30,
2010 and 2009, respectively. Future minimum lease commitments under non-cancellable operating
leases at June 30, 2010 are as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Remaining 2010 |
|
$ |
1,165 |
|
2011 |
|
|
1,885 |
|
2012 |
|
|
1,452 |
|
2013 |
|
|
1,324 |
|
2014 and thereafter |
|
|
3,982 |
|
|
|
|
|
Total |
|
$ |
9,808 |
|
|
|
|
|
Note L. Income taxes
The Company uses an asset and liability approach for financial accounting and reporting for
income taxes. The Companys objectives of accounting for income taxes are to recognize (i) the
amount of taxes payable or refundable for the current year and (ii) deferred tax liabilities and
assets for the future tax consequences of events that have been recognized in its financial
statements or tax returns. The Company and its subsidiaries file a federal corporate income tax
return on a consolidated basis. The tax returns and the amount of taxable income or loss are
subject to examination by federal and state taxing authorities.
The Company continually assesses both positive and negative evidence to determine whether it
is more likely than not that deferred tax assets can be realized prior to their expiration.
Management monitors Company-specific, oil and natural gas industry and worldwide economic factors
and assesses the likelihood that the Companys net operating loss carryforwards (NOLs) and other
deferred tax attributes in the United States, state, and local tax jurisdictions will be utilized
prior to their expiration. At June 30, 2010, the Company had no valuation allowances related to its
deferred tax assets.
At June 30, 2010, the Company did not have any significant uncertain tax positions requiring
recognition in the financial statements. The tax years 2004 through 2009 remain subject to
examination by the major tax jurisdictions.
28
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Income tax provision. The Companys income tax provision (benefit) and amounts separately
allocated were attributable to the following items for the three and six months ended June 30, 2010
and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Tax expense (benefit) related to income (loss) from operations |
|
$ |
74,744 |
|
|
$ |
(25,691 |
) |
|
$ |
114,684 |
|
|
$ |
(33,797 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in stockholders equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess tax benefits related to stock-based compensation |
|
|
(3,205 |
) |
|
|
(2,188 |
) |
|
|
(6,703 |
) |
|
|
(2,992 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
71,539 |
|
|
$ |
(27,879 |
) |
|
$ |
107,981 |
|
|
$ |
(36,789 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys income tax provision (benefit) attributable to income (loss) from operations
consisted of the following for the three and six months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
$ |
1,628 |
|
|
$ |
2,856 |
|
|
$ |
12,506 |
|
|
$ |
5,294 |
|
U.S. state and local |
|
|
492 |
|
|
|
381 |
|
|
|
1,725 |
|
|
|
708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,120 |
|
|
|
3,237 |
|
|
|
14,231 |
|
|
|
6,002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
|
64,911 |
|
|
|
(25,518 |
) |
|
|
89,592 |
|
|
|
(35,103 |
) |
U.S. state and local |
|
|
7,713 |
|
|
|
(3,410 |
) |
|
|
10,861 |
|
|
|
(4,696 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72,624 |
|
|
|
(28,928 |
) |
|
|
100,453 |
|
|
|
(39,799 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
74,744 |
|
|
$ |
(25,691 |
) |
|
$ |
114,684 |
|
|
$ |
(33,797 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
29
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
The Companys provision for income taxes differed from the U.S. federal statutory rate of 35
percent primarily due to state income taxes and non-deductible expenses. 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 |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Income (loss) at U.S. federal statutory rate |
|
$ |
69,620 |
|
|
$ |
(20,618 |
) |
|
$ |
107,238 |
|
|
$ |
(28,084 |
) |
State income taxes (net of federal tax effect) |
|
|
5,333 |
|
|
|
(1,969 |
) |
|
|
8,181 |
|
|
|
(2,592 |
) |
Statutory depletion |
|
|
45 |
|
|
|
|
|
|
|
(178 |
) |
|
|
|
|
Nondeductible expense & other |
|
|
(254 |
) |
|
|
(3,104 |
) |
|
|
(557 |
) |
|
|
(3,121 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) |
|
$ |
74,744 |
|
|
$ |
(25,691 |
) |
|
$ |
114,684 |
|
|
$ |
(33,797 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate |
|
|
37.6 |
% |
|
|
43.6 |
% |
|
|
37.4 |
% |
|
|
42.1 |
% |
Note M. Related parties
The following tables summarize charges incurred with and payments made to the Companys
related parties and reported in the consolidated statements of operations, as well as outstanding
payables and receivables included in the consolidated balance sheets for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
(in thousands) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Charges incurred with Chase Oil and affiliates (a) |
|
$ |
422 |
|
|
$ |
6,541 |
|
|
$ |
15,507 |
|
|
$ |
13,269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working interests owned by employees: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues distributed to employees |
|
$ |
93 |
|
|
$ |
32 |
|
|
$ |
171 |
|
|
$ |
62 |
|
Joint interest payments received from employees |
|
$ |
345 |
|
|
$ |
245 |
|
|
$ |
575 |
|
|
$ |
884 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Overriding royalty interests paid to Chase Oil affiliates (c) |
|
$ |
517 |
|
|
$ |
258 |
|
|
$ |
1,046 |
|
|
$ |
499 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty interests paid to a director of the Company (d) |
|
$ |
38 |
|
|
$ |
30 |
|
|
$ |
79 |
|
|
$ |
56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts paid under consulting agreement with Steven L. Beal (e) |
|
$ |
67 |
|
|
$ |
|
|
|
$ |
130 |
|
|
$ |
|
|
30
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
(in thousands) |
|
2010 |
|
2009 |
|
|
|
Amounts included in accounts receivable related parties: |
|
|
|
|
|
|
|
|
Chase Oil and affiliates (a) |
|
$ |
197 |
|
|
$ |
87 |
|
Working interests owned by employees (b) |
|
$ |
198 |
|
|
$ |
129 |
|
|
|
|
|
|
|
|
|
|
Amounts included in accounts payable related parties: |
|
|
|
|
|
|
|
|
Chase Oil and affiliates (a) |
|
$ |
512 |
|
|
$ |
9 |
|
Working interests owned by employees (b) |
|
$ |
9 |
|
|
$ |
15 |
|
Overriding royalty interests of Chase Oil affiliates (c) |
|
$ |
319 |
|
|
$ |
255 |
|
Royalty interests of a director of the Company (d) |
|
$ |
12 |
|
|
$ |
12 |
|
|
|
|
(a) |
|
The Company incurred charges for services rendered in the ordinary course of business from
Chase Oil Corporation (Chase Oil), a stockholder of the Company, and its affiliates
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 tables above summarize the charges incurred as well as outstanding
payables and receivables. |
|
(b) |
|
The Company purchased oil and natural gas properties from third parties in which employees of
the Company owned a working interest. The tables above summarize the Companys activities with
these employees. |
|
(c) |
|
Certain persons affiliated with Chase Oil own overriding royalty interests in certain of the
Companys properties. The tables above summarize the amounts paid attributable to such
interests and amounts due at period end. |
|
(d) |
|
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 owns a 3.5 percent
partnership interest. The tables above summarize the amounts paid attributable to such
interest and amounts due at period end. |
|
(e) |
|
On June 30, 2009, Steven L. Beal, the Companys then President and Chief Operating Officer,
retired from such positions. On June 9, 2009, the Company entered into a consulting agreement
(the Consulting Agreement) with Mr. Beal, under which Mr. Beal began serving as a consultant
to the Company on July 1, 2009. Either the Company or Mr. Beal may terminate the consulting
relationship at any time by giving ninety days written notice to the other party; however, the
Company may terminate the relationship immediately for cause. During the term of the
consulting relationship, Mr. Beal will receive a consulting fee of $20,000 per month and a
monthly reimbursement for his medical and dental coverage costs. If Mr. Beal dies during the
term of the Consulting Agreement, his estate will receive a $60,000 lump sum payment. As part
of the consulting agreement, certain of Mr. Beals stock-based awards were modified to permit
vesting and exercise under the original terms of the stock-based awards as if Mr. Beal were
still an employee of the Company while he is performing consulting services for the Company.
The tables above summarize the Companys activities pursuant to the consulting agreement with
this director. |
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, 2010, the Company owned 97.5 percent of the system and Chase Oil and its affiliates
owned 2.5 percent.
Purchase of residence. During the second quarter of 2010, the Company purchased the Houston,
Texas residence of Darin G. Holderness, the Companys Vice President, Chief Financial Officer and
Treasurer. To effectuate the purchase, the Company
31
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
engaged a third-party relocation company, who executed the purchase
for $920,000 and will subsequently sell Mr.
Holderness residence. The third-party relocation company appraised the fair value of Mr.
Holderness residence at $920,000.
Note N. Net income (loss) per share
Basic net income (loss) per share is computed by dividing net income (loss) by the weighted
average number of common shares treated as outstanding for the period.
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 capital options,
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 for the three and six months
ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
(in thousands) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
91,044 |
|
|
|
84,799 |
|
|
|
89,944 |
|
|
|
84,665 |
|
Dilutive capital options |
|
|
437 |
|
|
|
|
|
|
|
498 |
|
|
|
|
|
Dilutive common stock options |
|
|
432 |
|
|
|
|
|
|
|
418 |
|
|
|
|
|
Dilutive restricted stock |
|
|
384 |
|
|
|
|
|
|
|
360 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
92,297 |
|
|
|
84,799 |
|
|
|
91,220 |
|
|
|
84,665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Because the Company reported a net loss for the three and six months ended June 30, 2009, a
total of 2,403,336 stock options and 492,810 restricted shares, outstanding at June 30, 2009, were
not included in the diluted loss per share computations. The inclusion of these equity instruments
would have been anti-dilutive, therefore, the weighted average common shares reported for basic and diluted net loss per
share were the same.
32
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Note O. Other current liabilities
The following table provides the components of the Companys other current liabilities at June
30, 2010 and December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Other current liabilities: |
|
|
|
|
|
|
|
|
Accrued production costs |
|
$ |
30,164 |
|
|
$ |
24,128 |
|
Payroll related matters |
|
|
14,370 |
|
|
|
14,490 |
|
Accrued interest |
|
|
8,215 |
|
|
|
10,055 |
|
Asset retirement obligations |
|
|
2,429 |
|
|
|
3,262 |
|
Other |
|
|
5,130 |
|
|
|
8,160 |
|
|
|
|
|
|
|
|
Other current liabilities |
|
$ |
60,308 |
|
|
$ |
60,095 |
|
|
|
|
|
|
|
|
Note P. Subsidiary guarantors
All of the Companys wholly-owned subsidiaries have fully and unconditionally guaranteed the
Senior Notes of the Company (see Note J). In accordance with practices accepted by the SEC, the
Company has prepared Condensed Consolidating Financial Statements in order to quantify the assets,
results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following
Condensed Consolidating Balance Sheets at June 30, 2010 and December 31, 2009, and Condensed
Consolidating Statements of Operations for the three and six months ended June 30, 2010 and 2009
and Condensed Consolidating Statements of Cash Flows for the six months ended June 30, 2010 and
2009, present financial information for Concho Resources Inc. as the parent on a stand-alone basis
(carrying any investments in subsidiaries under the equity method), financial information for the
subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries
under the equity method), and the consolidation and elimination entries necessary to arrive at the
information for the Company on a consolidated basis. All current and deferred income taxes are
recorded on Concho Resources Inc. as the subsidiaries are flow-through entities for income tax
purposes. The subsidiary guarantors are not restricted from making distributions to the Company.
33
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Condensed Consolidating Balance Sheet
June 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable related parties |
|
$ |
3,872,138 |
|
|
$ |
776,975 |
|
|
$ |
(4,648,718 |
) |
|
$ |
395 |
|
Other current assets |
|
|
37,121 |
|
|
|
183,136 |
|
|
|
|
|
|
|
220,257 |
|
Total oil and natural gas properties, net |
|
|
|
|
|
|
3,067,398 |
|
|
|
|
|
|
|
3,067,398 |
|
Total property and equipment, net |
|
|
|
|
|
|
16,304 |
|
|
|
|
|
|
|
16,304 |
|
Investment in subsidiaries |
|
|
1,079,751 |
|
|
|
|
|
|
|
(1,079,751 |
) |
|
|
|
|
Total other long-term assets |
|
|
82,935 |
|
|
|
56,964 |
|
|
|
|
|
|
|
139,899 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
5,071,945 |
|
|
$ |
4,100,777 |
|
|
$ |
(5,728,469 |
) |
|
$ |
3,444,253 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable related parties |
|
$ |
1,968,956 |
|
|
$ |
2,680,614 |
|
|
$ |
(4,648,718 |
) |
|
$ |
852 |
|
Other current liabilities |
|
|
27,943 |
|
|
|
318,853 |
|
|
|
|
|
|
|
346,796 |
|
Other long-term liabilities |
|
|
668,676 |
|
|
|
21,559 |
|
|
|
|
|
|
|
690,235 |
|
Long-term debt |
|
|
644,023 |
|
|
|
|
|
|
|
|
|
|
|
644,023 |
|
Equity |
|
|
1,762,347 |
|
|
|
1,079,751 |
|
|
|
(1,079,751 |
) |
|
|
1,762,347 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity |
|
$ |
5,071,945 |
|
|
$ |
4,100,777 |
|
|
$ |
(5,728,469 |
) |
|
$ |
3,444,253 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Balance Sheet
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable related parties |
|
$ |
2,715,307 |
|
|
$ |
1,738,382 |
|
|
$ |
(4,453,473 |
) |
|
$ |
216 |
|
Other current assets |
|
|
33,561 |
|
|
|
183,481 |
|
|
|
|
|
|
|
217,042 |
|
Total oil and natural gas properties, net |
|
|
|
|
|
|
2,840,583 |
|
|
|
|
|
|
|
2,840,583 |
|
Total property and equipment, net |
|
|
|
|
|
|
15,706 |
|
|
|
|
|
|
|
15,706 |
|
Investment in subsidiaries |
|
|
876,154 |
|
|
|
|
|
|
|
(876,154 |
) |
|
|
|
|
Total other long-term assets |
|
|
44,291 |
|
|
|
53,247 |
|
|
|
|
|
|
|
97,538 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
3,669,313 |
|
|
$ |
4,831,399 |
|
|
$ |
(5,329,627 |
) |
|
$ |
3,171,085 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable related parties |
|
$ |
790,251 |
|
|
$ |
3,663,513 |
|
|
$ |
(4,453,473 |
) |
|
$ |
291 |
|
Other current liabilities |
|
|
68,706 |
|
|
|
268,017 |
|
|
|
|
|
|
|
336,723 |
|
Other long-term liabilities |
|
|
629,092 |
|
|
|
23,715 |
|
|
|
|
|
|
|
652,807 |
|
Long-term debt |
|
|
845,836 |
|
|
|
|
|
|
|
|
|
|
|
845,836 |
|
Equity |
|
|
1,335,428 |
|
|
|
876,154 |
|
|
|
(876,154 |
) |
|
|
1,335,428 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity |
|
$ |
3,669,313 |
|
|
$ |
4,831,399 |
|
|
$ |
(5,329,627 |
) |
|
$ |
3,171,085 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Condensed Consolidating Statement of Operations
Three Months Ended June 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
Total operating revenues |
|
$ |
|
|
|
$ |
215,710 |
|
|
$ |
|
|
|
$ |
215,710 |
|
Total operating costs and expenses |
|
|
109,112 |
|
|
|
(114,411 |
) |
|
|
|
|
|
|
(5,299 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
109,112 |
|
|
|
101,299 |
|
|
|
|
|
|
|
210,411 |
|
Interest expense |
|
|
(11,192 |
) |
|
|
|
|
|
|
|
|
|
|
(11,192 |
) |
Other, net |
|
|
100,995 |
|
|
|
(304 |
) |
|
|
(100,995 |
) |
|
|
(304 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
198,915 |
|
|
|
100,995 |
|
|
|
(100,995 |
) |
|
|
198,915 |
|
Income tax expense |
|
|
(74,744 |
) |
|
|
|
|
|
|
|
|
|
|
(74,744 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
124,171 |
|
|
$ |
100,995 |
|
|
$ |
(100,995 |
) |
|
$ |
124,171 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Operations
Three Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
Total operating revenues |
|
$ |
|
|
|
$ |
127,332 |
|
|
$ |
|
|
|
$ |
127,332 |
|
Total operating costs and expenses |
|
|
(81,629 |
) |
|
|
(98,592 |
) |
|
|
|
|
|
|
(180,221 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
|
(81,629 |
) |
|
|
28,740 |
|
|
|
|
|
|
|
(52,889 |
) |
Interest expense |
|
|
(6,200 |
) |
|
|
|
|
|
|
|
|
|
|
(6,200 |
) |
Other, net |
|
|
28,920 |
|
|
|
180 |
|
|
|
(28,920 |
) |
|
|
180 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
(58,909 |
) |
|
|
28,920 |
|
|
|
(28,920 |
) |
|
|
(58,909 |
) |
Income tax benefit |
|
|
25,691 |
|
|
|
|
|
|
|
|
|
|
|
25,691 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(33,218 |
) |
|
$ |
28,920 |
|
|
$ |
(28,920 |
) |
|
$ |
(33,218 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
35
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Condensed Consolidating Statement of Operations
Six Months Ended June 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
Total operating revenues |
|
$ |
|
|
|
$ |
427,710 |
|
|
$ |
|
|
|
$ |
427,710 |
|
Total operating costs and expenses |
|
|
125,055 |
|
|
|
(223,736 |
) |
|
|
|
|
|
|
(98,681 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
125,055 |
|
|
|
203,974 |
|
|
|
|
|
|
|
329,029 |
|
Interest expense |
|
|
(22,257 |
) |
|
|
|
|
|
|
|
|
|
|
(22,257 |
) |
Other, net |
|
|
203,597 |
|
|
|
(377 |
) |
|
|
(203,597 |
) |
|
|
(377 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
306,395 |
|
|
|
203,597 |
|
|
|
(203,597 |
) |
|
|
306,395 |
|
Income tax expense |
|
|
(114,684 |
) |
|
|
|
|
|
|
|
|
|
|
(114,684 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
191,711 |
|
|
$ |
203,597 |
|
|
$ |
(203,597 |
) |
|
$ |
191,711 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Operations
Six Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
Total operating revenues |
|
$ |
|
|
|
$ |
213,334 |
|
|
$ |
|
|
|
$ |
213,334 |
|
Total operating costs and expenses |
|
|
(86,846 |
) |
|
|
(196,010 |
) |
|
|
|
|
|
|
(282,856 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
|
(86,846 |
) |
|
|
17,324 |
|
|
|
|
|
|
|
(69,522 |
) |
Interest expense |
|
|
(10,570 |
) |
|
|
|
|
|
|
|
|
|
|
(10,570 |
) |
Other, net |
|
|
17,176 |
|
|
|
(148 |
) |
|
|
(17,176 |
) |
|
|
(148 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
(80,240 |
) |
|
|
17,176 |
|
|
|
(17,176 |
) |
|
|
(80,240 |
) |
Income tax benefit |
|
|
33,797 |
|
|
|
|
|
|
|
|
|
|
|
33,797 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(46,443 |
) |
|
$ |
17,176 |
|
|
$ |
(17,176 |
) |
|
$ |
(46,443 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
36
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
Net cash flows (used in) provided by operating activities |
|
$ |
(17,206 |
) |
|
$ |
256,736 |
|
|
$ |
|
|
|
$ |
239,530 |
|
Net cash flows used in investing activities |
|
|
(8,024 |
) |
|
|
(294,141 |
) |
|
|
|
|
|
|
(302,165 |
) |
Net cash flows provided by financing activities |
|
|
25,207 |
|
|
|
34,577 |
|
|
|
|
|
|
|
59,784 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
|
(23 |
) |
|
|
(2,828 |
) |
|
|
|
|
|
|
(2,851 |
) |
Cash and cash equivalents at beginning of period |
|
|
48 |
|
|
|
3,186 |
|
|
|
|
|
|
|
3,234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
25 |
|
|
$ |
358 |
|
|
$ |
|
|
|
$ |
383 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
Net cash flows provided by (used in) operating activities |
|
$ |
(98,145 |
) |
|
$ |
216,377 |
|
|
$ |
|
|
|
$ |
118,232 |
|
Net cash flows provided by (used in) investing activities |
|
|
61,465 |
|
|
|
(224,293 |
) |
|
|
|
|
|
|
(162,828 |
) |
Net cash flows provided by (used in) financing activities |
|
|
36,731 |
|
|
|
(6,806 |
) |
|
|
|
|
|
|
29,925 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
51 |
|
|
|
(14,722 |
) |
|
|
|
|
|
|
(14,671 |
) |
Cash and cash equivalents at beginning of period |
|
|
|
|
|
|
17,752 |
|
|
|
|
|
|
|
17,752 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
51 |
|
|
$ |
3,030 |
|
|
$ |
|
|
|
$ |
3,081 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Note Q. Subsequent events
Marbob Acquisition.
On July 19, 2010, the Company entered into an asset purchase agreement to acquire
substantially all of the oil and natural gas leases, interests, properties and related
assets owned by Marbob Energy Corporation and certain affiliated entities (collectively, Marbob)
for aggregate consideration of approximately $1.65 billion, subject to purchase price adjustments,
which include downward purchase price adjustments based on the exercise of third parties of contractual
preferential rights to purchase certain interests in properties to be acquired from Marbob
(the Marbob Acquisition). Upon closing, the consideration is expected to consist of (i) cash
consideration in the aggregate amount of $1.45 billion, (ii) the issuance by the Company to Marbob
of an 8 percent unsecured promissory note due 2018 in the aggregate principal amount of $150 million
and (iii) the issuance to Marbob of approximately 1.1 million shares of the Companys common stock
(representing a negotiated value of $50 million). The Marbob Acquisition is expected to close on or
before November 30, 2010.
The Company intends to finance the $1.45 billion cash portion of the Marbob Acquisition with a combination of
equity and debt. On July 19, 2010, the Company entered into a common stock purchase agreement with third-party
investors to sell approximately 6.6 million shares of the Companys common stock in a private placement for
aggregate cash consideration of approximately $300 million. The Company anticipates that this private placement
will close simultaneously with the Marbob Acquisition. In addition, the Company has received an $800 million
underwritten commitment from two of its lenders under its Credit Facility to expand the size of its existing Credit
Facility from $1.2 billion to $2.0 billion as part of the financing for the Marbob Acquisition, which the Company
expects will provide the credit capacity to fund the remaining cash portion of the purchase price. The expanded
credit facility is expected to close simultaneously with the Marbob Acquisition.
Marbob preferential rights.
Certain of the Marbob interests in properties contain contractual preferential rights
to purchase by third parties if Marbob were to sell them. Marbob has informed the Company of the receipt by
Marbob of a notice from BP America Production Company (BP) electing to exercise its contractual preferential
purchase right under certain operating agreements to purchase interests in certain of Marbobs properties as a result
of the Marbob Acquisition. The approximate value of the interests in properties associated with this election is $400
million, which, if closed between Marbob and BP, would reduce the purchase price of the Marbob Acquisition.
In addition, Marbob has contractual preferential rights under certain operating agreements to purchase certain
interests in properties if third parties were to sell those interests in properties. On July 20, 2010, BP
announced it was selling all its assets in the Permian Basin to a subsidiary of Apache Corporation (Apache).
Marbob and BP own common interests in certain common properties subject to a contractual preferential right to
purchase. BP and Apache have contested Marbobs ability to exercise its contractual preferential rights in this
situation. As a result, Marbob and the Company have filed suit against BP and Apache seeking declaratory judgment
and injunctive relief to protect Marbobs contractual right to have the option to purchase these interests in properties.
The Company is unable to predict at this time if the court will grant Marbob and the Company the relief sought in
connection with the suit.
38
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
New commodity derivative contracts. In July 2010, the Company entered into the following oil
price swaps to protect the Companys cash flows in anticipation of the Marbob Acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
Index |
|
Contract |
|
|
Volume |
|
Price (a) |
|
Period |
|
Oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
1,578,000 |
|
|
$ |
80.80 |
|
|
|
1/1/11 - 12/31/11 |
|
Price swap |
|
|
1,305,000 |
|
|
$ |
81.39 |
|
|
|
1/1/12 - 12/31/12 |
|
Price swap |
|
|
261,000 |
|
|
$ |
82.50 |
|
|
|
7/1/12 - 12/31/12 |
|
Price swap |
|
|
1,380,000 |
|
|
$ |
82.58 |
|
|
|
1/1/13 - 12/31/13 |
|
Price swap |
|
|
1,248,000 |
|
|
$ |
83.94 |
|
|
|
1/1/14 - 12/31/14 |
|
Price swap |
|
|
600,000 |
|
|
$ |
84.50 |
|
|
|
1/1/15 - 6/30/15 |
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate
monthly average futures price. |
39
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
June 30, 2010
Unaudited
Note R. Supplementary information
Capitalized costs
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Oil and natural gas properties: |
|
|
|
|
|
|
|
|
Proved |
|
$ |
3,465,443 |
|
|
$ |
3,139,424 |
|
Unproved |
|
|
232,210 |
|
|
|
218,580 |
|
Less: accumulated depletion |
|
|
(630,255 |
) |
|
|
(517,421 |
) |
|
|
|
|
|
|
|
Net capitalized costs for oil and natural gas properties |
|
$ |
3,067,398 |
|
|
$ |
2,840,583 |
|
|
|
|
|
|
|
|
Costs incurred for oil and natural gas producing activities (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
3,897 |
|
|
$ |
(68 |
) |
|
$ |
13,739 |
|
|
$ |
(1,008 |
) |
Unproved |
|
|
15,673 |
|
|
|
3,361 |
|
|
|
21,029 |
|
|
|
4,582 |
|
Exploration |
|
|
36,434 |
|
|
|
61,131 |
|
|
|
61,933 |
|
|
|
84,940 |
|
Development |
|
|
134,206 |
|
|
|
31,450 |
|
|
|
245,912 |
|
|
|
115,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred for oil and natural gas properties |
|
$ |
190,210 |
|
|
$ |
95,874 |
|
|
$ |
342,613 |
|
|
$ |
203,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The costs incurred for oil and natural gas producing activities includes the following
amounts of asset retirement obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Proved property acquisition costs |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Exploration costs |
|
|
184 |
|
|
|
52 |
|
|
|
252 |
|
|
|
220 |
|
Development costs |
|
|
776 |
|
|
|
(3,878 |
) |
|
|
(1,424 |
) |
|
|
(2,727 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
960 |
|
|
$ |
(3,826 |
) |
|
$ |
(1,172 |
) |
|
$ |
(2,507 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
40
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 and Managements Discussion and Analysis of
Financial Condition and Results of Operations included in our Annual Report on Form 10-K for the
year ended December 31, 2009.
During the fourth quarter of 2009, we closed the Wolfberry Acquisitions as discussed below. As
a result of the acquisitions, many comparisons between periods will be difficult or impossible.
Certain statements in our discussion below are forward-looking statements. These
forward-looking statements involve risks and uncertainties. We caution that a number of factors
could cause actual results to differ materially from these implied or expressed by the
forward-looking statements. Please see Cautionary Statement Regarding Forward-Looking Statements.
Overview
We are an independent oil and natural gas company engaged in the acquisition, development and
exploration of producing oil and natural gas properties. Our core operations are primarily focused
in the Permian Basin of Southeast New Mexico and West Texas. We have also acquired significant
acreage positions in and are actively involved in drilling or participating in drilling of emerging
plays located in the Permian Basin of Southeast New Mexico and the Williston Basin of North Dakota,
where we are applying horizontal drilling, advanced fracture stimulation and enhanced recovery
technologies. Crude oil comprised 67 percent of our 211.5 million barrels of oil equivalent
(MMBoe) of estimated net proved reserves at December 31, 2009, and 68 percent of our 6.7 MMBoe of
production for the six months ended June 30, 2010. We seek to operate the wells in which we own an
interest, and we operated wells that accounted for 95.3 percent of our proved developed producing
PV-10 and 66.4 percent of our 3,960 gross wells at December 31, 2009. 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
Our results of operations are heavily influenced by commodity prices. Factors that may impact
future commodity prices, including the price of oil and natural gas, include:
|
|
|
developments generally impacting the Middle East, including Iraq and Iran; |
|
|
|
|
the extent to which members of the Organization of Petroleum Exporting Countries and
other oil exporting nations are able to continue to manage oil supply through export
quotas; |
|
|
|
|
the current drilling moratorium in the Gulf of Mexico; |
|
|
|
|
the overall global demand for oil; and |
|
|
|
|
overall North American natural gas supply and demand fundamentals, including: |
|
§ |
|
the impact of any decline in 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 hedge a portion of our commodity price risk to mitigate the
impact of price volatility on our business. See Note I of the Condensed Notes to Consolidated
Financial Statements included in Item 1. Consolidated Financial Statements (Unaudited) for
additional information regarding our commodity hedge positions at June 30, 2010.
41
Oil and natural gas prices have been subject to significant fluctuations during the past
several years. In general, oil prices were substantially higher during the comparable periods of
2010 measured against 2009, while natural gas prices were moderately higher. The following table
sets forth the average NYMEX oil and natural gas prices for the three and six months ended June 30,
2010 and 2009, as well as the high and low NYMEX prices for the same periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Average NYMEX prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) |
|
$ |
78.12 |
|
|
$ |
59.83 |
|
|
$ |
78.36 |
|
|
$ |
51.61 |
|
Natural gas (MMBtu) |
|
$ |
4.35 |
|
|
$ |
3.80 |
|
|
$ |
4.69 |
|
|
$ |
4.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High / Low NYMEX prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
86.84 |
|
|
$ |
72.68 |
|
|
$ |
86.84 |
|
|
$ |
72.68 |
|
Low |
|
$ |
68.01 |
|
|
$ |
45.88 |
|
|
$ |
68.01 |
|
|
$ |
33.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMBtu): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
5.19 |
|
|
$ |
4.45 |
|
|
$ |
6.01 |
|
|
$ |
6.07 |
|
Low |
|
$ |
3.91 |
|
|
$ |
3.25 |
|
|
$ |
3.84 |
|
|
$ |
3.25 |
|
Further,
the NYMEX oil price and NYMEX natural gas price reached highs and
lows of $82.55 and
$71.98 per Bbl and $4.92 and $4.31 per MMBtu, respectively, during the period from July 1, 2010
to August 4, 2010. At August 4, 2010, the NYMEX oil price and NYMEX natural gas price were
$82.47 per Bbl and $4.74 per MMBtu, respectively.
Recent Events
Marbob Acquisition.
On July 19, 2010, we entered into an asset purchase agreement to acquire substantially all
of the oil and natural gas leases, interests, properties and related assets owned by Marbob Energy Corporation and
certain affiliated entities (collectively, Marbob) for aggregate consideration of approximately
$1.65 billion, subject to purchase price adjustments, which include downward purchase price adjustments based on
the exercise of third parties of contractual preferential rights to purchase certain interests in properties to be acquired
from Marbob (the Marbob Acquisition). Upon closing, the consideration is expected to consist of
(i) cash consideration in the aggregate amount of $1.45 billion, (ii) the issuance by us to Marbob of an 8 percent
unsecured promissory note due 2018 in the aggregate principal amount of $150 million and (iii) the issuance to
Marbob of approximately 1.1 million shares of our common stock (representing a negotiated value of $50 million).
The Marbob Acquisition is expected to close on or before November 30, 2010.
We intend to finance the $1.45 billion cash portion of the Marbob Acquisition with a combination of equity and
debt. On July 19, 2010, we entered into a common stock purchase agreement with third-party investors to sell
approximately 6.6 million shares of our common stock in a private placement for aggregate cash consideration of
approximately $300 million. We anticipate that this private placement will close simultaneously with the Marbob
Acquisition. In addition, we have received an $800 million underwritten commitment from two of our lenders under
our Credit Facility to expand the size of our existing credit facility from $1.2 billion to $2.0 billion as part of the
financing for the Marbob Acquisition, which we expect will provide the credit capacity to fund the remaining cash
portion of the purchase price. The expanded credit facility is expected to close simultaneously with the Marbob
Acquisition.
Marbob preferential rights.
Certain of the Marbob interests in properties contain contractual preferential rights
to purchase by third parties if Marbob were to sell them. Marbob has informed us of the receipt by Marbob of
a notice from BP America Production Company (BP) electing to exercise its contractual preferential
purchase right under certain operating agreements to purchase interests in certain of Marbobs properties as a
result of the Marbob Acquisition. The approximate value of the interests in properties associated with this election is
$400 million, which, if closed between Marbob and BP, would reduce the purchase price of the Marbob
Acquisition.
In addition, Marbob has contractual preferential rights under certain operating agreements to purchase certain
interests in properties if third parties were to attempt to sell those interests in properties. On July 20, 2010, BP
announced it was selling all its assets in the Permian Basin to a subsidiary of Apache Corporation
(Apache). Marbob and BP own common interests in certain common properties subject to a
contractual preferential right to purchase. BP and Apache have contested Marbobs ability to exercise its
contractual preferential rights in this situation. As a result,
42
Marbob and we have filed suit against BP and Apache
seeking declaratory judgment and injunctive relief to protect Marbobs contractual right to have the option to
purchase these interests in properties. We are unable to predict at this time if the court will grant Marbob and us the
relief sought in connection with the suit.
Credit facility. In April 2010, we increased our borrowing base under our credit facility to
$1.2 billion, an increase of $244.1 million. We had $852.0 million of availability under our credit
facility at June 30, 2010. As part of the Marbob Acquisition, we have received an $800 million
underwritten commitment from two of our lenders in our credit facility to further expand the size
of our existing credit facility from $1.2 billion to $2.0 billion as part of the financing for the
acquisition. We believe that the increased size of the credit facility will provide us the credit
capacity to fund the Marbob Acquisition and maintain an adequate level of liquidity.
Equity issuance. On February 1, 2010, we issued approximately 5.3 million shares of our common
stock at $42.75 per share in a public offering. After deducting underwriting discounts of
approximately $9.1 million and transaction costs, we received net proceeds of approximately $219.3
million. The net proceeds from this offering were used to repay a portion of the borrowings under
our credit facility.
Wolfberry acquisitions. In December 2009, together with the acquisition of related additional
interests that closed in 2010, we closed two acquisitions of interests in producing and
non-producing assets in the Wolfberry play of the Permian Basin for approximately $270.7 million in
cash (the Wolfberry Acquisitions). The Wolfberry Acquisitions were primarily funded with
borrowings under our credit facility. As of December 31, 2009, these acquisitions included
estimated total proved reserves of 19.9 MMBoe, of which 69 percent were oil and 25 percent were
proved developed. Our 2009 results of operations do not include any production, revenues or costs
from the Wolfberry Acquisitions.
2010 capital budget. In December 2009, we announced our 2010 capital budget of approximately $625 million,
which we expected could be funded substantially within our cash flow. In August 2010, we announced the increase
of our 2010 capital budget to $700 million. Based on current commodity prices and our expectations, we believe our
2010 revised capital budget will exceed our 2010 cash flow, excluding the effects of the Marbob Acquisition. As our
size and financial flexibility have grown, we have a longer-term view on spending substantially within our cash
flow, and our spending during any specific period may exceed our cash flow for that period. However, our capital
budget is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the
current levels or substantial increases in our drilling and completion costs, we may reduce our capital spending
program to be substantially within our cash flow.
Our capital budget does not include acquisitions (other than the customary purchase of
leasehold acreage). Our 2010 capital budget does not include capital we may spend on the Marbob
assets once we close the acquisition. The following is a summary of our 2010 capital budget:
|
|
|
|
|
|
|
|
|
|
|
Original |
|
|
Revised |
|
|
|
2010 |
|
|
2010 |
|
(in millions) |
|
Budget |
|
|
Budget |
|
|
Drilling and recompletion opportunities in our core operating area |
|
$ |
502 |
|
|
$ |
538 |
|
Projects operated by third parties |
|
|
8 |
|
|
|
10 |
|
Emerging plays, acquisition of leasehold acreage and other property interests, and geological and geophysical |
|
|
82 |
|
|
|
117 |
|
Facilities capital in our core operating areas |
|
|
33 |
|
|
|
35 |
|
|
|
|
|
|
|
|
Total 2010 capital budget |
|
$ |
625 |
|
|
$ |
700 |
|
|
|
|
|
|
|
|
During the six months ended June 30, 2010, our cost incurred was approximately $330.0 million
(excluding non leasehold acquisitions of approximately $13.7 million and asset retirement
obligations). Originally our capital budget was front end loaded, and we expected to outspend our
cash flow in the first half of 2010. We outspent our cash flow during the six months ended June 30,
2010 by approximately $60 million, including acquisitions.
Derivative Financial Instruments
Derivative financial instrument exposure. At June 30, 2010, the fair value of our financial
derivatives was a net asset of $70.8 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.
Under 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
43
instruments. We currently have no reason to believe that our counterparties to these commodity
derivative contracts are not financially viable. Our credit facility does not allow us to offset
amounts we may owe a lender against amounts we may be owed related to our financial instruments
with such party.
New commodity derivative contracts. During the six months ended June 30, 2010, we entered into
additional commodity derivative contracts to hedge a portion of our estimated future production.
The following table summarizes information about these additional commodity derivative contracts
for the six months ended June 30, 2010. When aggregating multiple contracts, the weighted average
contract price is disclosed.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
Index |
|
Contract |
|
|
Volume |
|
Price |
|
Period |
|
Oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
670,000 |
|
|
$ |
83.72 |
(a) |
|
|
1/1/10 - 12/31/10 |
|
Price swap |
|
|
195,000 |
|
|
$ |
76.85 |
(a) |
|
|
3/1/10 - 12/31/10 |
|
Price swap |
|
|
1,463,000 |
|
|
$ |
88.63 |
(a) |
|
|
5/1/10 - 12/31/10 |
|
Price swap |
|
|
2,136,000 |
|
|
$ |
88.36 |
(a) |
|
|
1/1/11 - 12/31/11 |
|
Price swap |
|
|
2,268,000 |
|
|
$ |
92.68 |
(a) |
|
|
1/1/12 - 12/31/12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
418,000 |
|
|
$ |
5.99 |
(b) |
|
|
2/1/10 - 12/31/10 |
|
Price swap |
|
|
1,250,000 |
|
|
$ |
5.55 |
(b) |
|
|
3/1/10 - 12/31/10 |
|
Price swap |
|
|
5,076,000 |
|
|
$ |
6.14 |
(b) |
|
|
1/1/11 - 12/31/11 |
|
Price swap |
|
|
300,000 |
|
|
$ |
6.54 |
(b) |
|
|
1/1/12 - 12/31/12 |
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate monthly
average futures price. |
|
(b) |
|
The index prices for the natural gas price swaps are based on the NYMEX-Henry Hub last trading
day futures price. |
In July 2010, we entered into the following oil price swaps to protect our cash flows in
anticipation of the Marbob Acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
Index |
|
Contract |
|
|
Volume |
|
Price (a) |
|
Period |
|
Oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
1,578,000 |
|
|
$ |
80.80 |
|
|
|
1/1/11 - 12/31/11 |
|
Price swap |
|
|
1,305,000 |
|
|
$ |
81.39 |
|
|
|
1/1/12 - 12/31/12 |
|
Price swap |
|
|
261,000 |
|
|
$ |
82.50 |
|
|
|
7/1/12 - 12/31/12 |
|
Price swap |
|
|
1,380,000 |
|
|
$ |
82.58 |
|
|
|
1/1/13 - 12/31/13 |
|
Price swap |
|
|
1,248,000 |
|
|
$ |
83.94 |
|
|
|
1/1/14 - 12/31/14 |
|
Price swap |
|
|
600,000 |
|
|
$ |
84.50 |
|
|
|
1/1/15 - 6/30/15 |
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate monthly
average futures price. |
44
Results of Operations
The following table sets forth summary information concerning our production results, average
sales prices and operating costs and expenses for the three and six months ended June 30, 2010 and
2009. The actual historical data in this table excludes results from the Wolfberry Acquisitions for
periods prior to January 1, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Production and operating data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
|
2,337 |
|
|
|
1,831 |
|
|
|
4,507 |
|
|
|
3,518 |
|
Natural gas (MMcf) |
|
|
6,692 |
|
|
|
5,414 |
|
|
|
12,933 |
|
|
|
10,369 |
|
Total (MBoe) |
|
|
3,452 |
|
|
|
2,733 |
|
|
|
6,663 |
|
|
|
5,246 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) |
|
|
25,681 |
|
|
|
20,121 |
|
|
|
24,901 |
|
|
|
19,436 |
|
Natural gas (Mcf) |
|
|
73,538 |
|
|
|
59,495 |
|
|
|
71,453 |
|
|
|
57,287 |
|
Total (Boe) |
|
|
37,938 |
|
|
|
30,037 |
|
|
|
36,809 |
|
|
|
28,984 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl) |
|
$ |
74.64 |
|
|
$ |
55.44 |
|
|
$ |
74.81 |
|
|
$ |
47.32 |
|
Oil, with derivatives (Bbl) (a) |
|
$ |
73.42 |
|
|
$ |
67.36 |
|
|
$ |
71.93 |
|
|
$ |
63.36 |
|
Natural gas, without derivatives (Mcf) |
|
$ |
6.17 |
|
|
$ |
4.77 |
|
|
$ |
7.00 |
|
|
$ |
4.52 |
|
Natural gas, with derivatives (Mcf) (a) |
|
$ |
7.01 |
|
|
$ |
5.38 |
|
|
$ |
7.48 |
|
|
$ |
5.08 |
|
Total, without derivatives (Boe) |
|
$ |
62.49 |
|
|
$ |
46.59 |
|
|
$ |
64.19 |
|
|
$ |
40.67 |
|
Total, with derivatives (Boe) (a) |
|
$ |
63.29 |
|
|
$ |
55.78 |
|
|
$ |
63.16 |
|
|
$ |
52.53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses and workover costs |
|
$ |
6.71 |
|
|
$ |
5.75 |
|
|
$ |
6.29 |
|
|
$ |
6.24 |
|
Oil and natural gas taxes |
|
$ |
5.01 |
|
|
$ |
3.69 |
|
|
$ |
5.29 |
|
|
$ |
3.40 |
|
Depreciation, depletion and amortization |
|
$ |
15.67 |
|
|
$ |
19.17 |
|
|
$ |
16.20 |
|
|
$ |
19.66 |
|
General and administrative |
|
$ |
5.08 |
|
|
$ |
5.19 |
|
|
$ |
4.67 |
|
|
$ |
4.94 |
|
|
|
|
(a) |
|
Includes the effect of the cash settlements received from (paid on) commodity
derivatives not designated as hedges and reported in operating costs and expenses.
The following table reflects the amounts of cash settlements received from (paid on)
commodity derivatives not designated as hedges that were included in computing
average prices with derivatives and reconciles to the amount in gain (loss) on
derivatives not designated as hedges as reported in the consolidated statements of
operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Gain (loss) on derivatives not designated as hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash (payments on) receipts from oil derivatives |
|
$ |
(2,852 |
) |
|
$ |
21,828 |
|
|
$ |
(12,985 |
) |
|
$ |
56,412 |
|
Cash receipts from natural gas derivatives |
|
|
5,614 |
|
|
|
3,292 |
|
|
|
6,120 |
|
|
|
5,832 |
|
Cash payments on interest rate derivatives |
|
|
(1,221 |
) |
|
|
(779 |
) |
|
|
(2,434 |
) |
|
|
(779 |
) |
Unrealized mark-to-market gain (loss) on commodity and interest rate
derivatives |
|
|
111,222 |
|
|
|
(105,947 |
) |
|
|
137,635 |
|
|
|
(148,117 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as hedges |
|
$ |
112,763 |
|
|
$ |
(81,606 |
) |
|
$ |
128,336 |
|
|
$ |
(86,652 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
45
The following table presents selected financial and operating information for the fields which
represented greater than 15 percent of our total proved reserves at December 31, 2009 and 2008,
respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
West |
|
Grayburg |
|
Grayburg |
|
West |
|
Grayburg |
|
Grayburg |
|
|
Wolfberry |
|
Jackson |
|
Jackson |
|
Wolfberry |
|
Jackson |
|
Jackson |
|
Production and operating data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
|
357 |
|
|
|
388 |
|
|
|
324 |
|
|
|
687 |
|
|
|
797 |
|
|
|
648 |
|
Natural gas (MMcf) |
|
|
993 |
|
|
|
1,135 |
|
|
|
962 |
|
|
|
1,978 |
|
|
|
2,282 |
|
|
|
1,904 |
|
Total (MBoe) |
|
|
523 |
|
|
|
577 |
|
|
|
484 |
|
|
|
1,017 |
|
|
|
1,177 |
|
|
|
965 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl) |
|
$ |
77.09 |
|
|
$ |
74.38 |
|
|
$ |
56.56 |
|
|
$ |
76.93 |
|
|
$ |
74.89 |
|
|
$ |
46.71 |
|
Natural gas, without derivatives (Mcf) |
|
$ |
6.41 |
|
|
$ |
6.67 |
|
|
$ |
4.74 |
|
|
$ |
7.39 |
|
|
$ |
7.39 |
|
|
$ |
4.65 |
|
Total, without derivatives (Boe) |
|
$ |
64.86 |
|
|
$ |
63.12 |
|
|
$ |
47.24 |
|
|
$ |
66.36 |
|
|
$ |
65.02 |
|
|
$ |
40.52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses including workovers |
|
$ |
4.16 |
|
|
$ |
6.75 |
|
|
$ |
6.40 |
|
|
$ |
4.41 |
|
|
$ |
6.19 |
|
|
$ |
6.38 |
|
Oil and natural gas taxes |
|
$ |
4.29 |
|
|
$ |
5.47 |
|
|
$ |
4.02 |
|
|
$ |
4.41 |
|
|
$ |
5.61 |
|
|
$ |
3.49 |
|
46
Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009
Oil and natural gas revenues. Revenue from oil and natural gas operations was $215.7 million
for the three months ended June 30, 2010, an increase of $88.4 million (69 percent) from $127.3
million for the three months ended June 30, 2009. This increase was primarily due to substantial
increases in realized oil and natural gas prices and increased production (i) as a result of the
Wolfberry Acquisitions and (ii) due to successful drilling efforts during 2009 and 2010.
Specifically the:
|
|
|
average realized oil price (excluding the effects of derivative activities) was
$74.64 per Bbl during the three months ended June 30, 2010, an increase of 35 percent
from $55.44 per Bbl during the three months ended June 30, 2009; |
|
|
|
|
total oil production was 2,337 MBbl for the three months ended June 30, 2010, an
increase of 506 MBbl (28 percent) from 1,831 MBbl for the three months ended June 30,
2009; |
|
|
|
|
average realized natural gas price (excluding the effects of derivative activities)
was $6.17 per Mcf during the three months ended June 30, 2010, an increase of 29 percent
from $4.77 per Mcf during the three months ended June 30, 2009; and |
|
|
|
|
total natural gas production was 6,692 MMcf for the three months ended June 30, 2010,
an increase of 1,278 MMcf (24 percent) from 5,414 MMcf for the three months ended June
30, 2009. |
Production expenses. The following table provides the components of our total oil and natural
gas production costs for the three months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Lease operating expenses |
|
$ |
20,339 |
|
|
$ |
5.89 |
|
|
$ |
15,726 |
|
|
$ |
5.75 |
|
Taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem |
|
|
2,237 |
|
|
|
0.65 |
|
|
|
989 |
|
|
|
0.36 |
|
Production |
|
|
15,055 |
|
|
|
4.36 |
|
|
|
9,090 |
|
|
|
3.33 |
|
Workover costs |
|
|
2,817 |
|
|
|
0.82 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas production expenses |
|
$ |
40,448 |
|
|
$ |
11.72 |
|
|
$ |
25,817 |
|
|
$ |
9.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, in general, we have some control over lease
operating expenses and workover costs on properties we operate, but production and ad valorem taxes
are directly related to commodity price changes.
Lease operating expenses were $20.3 million ($5.89 per Boe) for the three months ended June
30, 2010, an increase of $4.6 million (29 percent) from $15.7 million ($5.75 per Boe) for the three
months ended June 30, 2009. The increase in lease operating expenses was primarily due to (i) our
wells successfully drilled and completed in 2009 and 2010 and (ii) additional interests acquired in
the Wolfberry Acquisitions in December 2009. The increase in lease operating expenses per Boe was in
part due to incurrence of some non-routine costs during the three months ended June 30, 2010,
offset in part by additional production from our wells successfully drilled and completed in 2009
and 2010 where we are receiving benefits from economies of scale.
Ad valorem taxes have increased primarily as a result of increased valuations of our Texas
properties, and the increase in our number of wells primarily associated with the Wolfberry
Acquisitions and 2009 and 2010 drilling activity.
Production taxes per unit of production were $4.36 per Boe during the three months ended June
30, 2010, an increase of 31 percent from $3.33 per Boe during the three months ended June 30, 2009.
The increase was directly related to the increase in commodity prices and our increase in oil and
natural gas revenues related to increased volumes. Over the same period, our per Boe prices
(excluding the effects of derivatives) increased 34 percent.
47
Workover expenses were approximately $2.8 million for the three months ended June 30,
2010, which were primarily related to increased workovers in the New Mexico Permian area due to
work performed to restore production.
Exploration and abandonments expense. The following table provides a breakdown of our
exploration and abandonments expense for the three months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Geological and geophysical |
|
$ |
560 |
|
|
$ |
448 |
|
Exploratory dry holes |
|
|
|
|
|
|
445 |
|
Leasehold abandonments and other |
|
|
318 |
|
|
|
531 |
|
|
|
|
|
|
|
|
Total exploration and abandonments |
|
$ |
878 |
|
|
$ |
1,424 |
|
|
|
|
|
|
|
|
Our geological and geophysical expense, which primarily consists of the costs of acquiring and
processing seismic data, geophysical data and core analysis, was $0.6 million and $0.4 million for
the three months ended June 30, 2010 and 2009, respectively.
During the three months ended June 30, 2009, we wrote-off two unsuccessful exploratory wells
in our Texas Permian area.
For the three months ended June 30, 2010, we recorded $0.3 million of leasehold abandonments,
which were primarily related to non-core prospects in our Texas Permian area. For the three months
ended June 30, 2009, we recorded approximately $0.5 million of leasehold abandonments, which
related primarily to the write-off of a non-core prospect in our New Mexico Permian area.
Depreciation, depletion and amortization expense. The following table provides components of
our depreciation, depletion and amortization expense for the three months ended June 30, 2010 and
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Depletion of proved oil and natural gas properties |
|
$ |
53,001 |
|
|
$ |
15.35 |
|
|
$ |
51,218 |
|
|
$ |
18.74 |
|
Depreciation of other property and equipment |
|
|
713 |
|
|
|
0.21 |
|
|
|
796 |
|
|
|
0.29 |
|
Amortization of intangible asset operating rights |
|
|
387 |
|
|
|
0.11 |
|
|
|
388 |
|
|
|
0.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depletion, depreciation and amortization |
|
$ |
54,101 |
|
|
$ |
15.67 |
|
|
$ |
52,402 |
|
|
$ |
19.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period end |
|
$ |
72.23 |
|
|
|
|
|
|
$ |
66.25 |
|
|
|
|
|
Natural gas price used to estimate proved natural gas
reserves at period end |
|
$ |
4.10 |
|
|
|
|
|
|
$ |
3.72 |
|
|
|
|
|
Depletion of proved oil and natural gas properties was $53.0 million ($15.35 per Boe) for the
three months ended June 30, 2010, an increase of $1.8 million from $51.2 million ($18.74 per Boe)
for the three months ended June 30, 2009. The increase in depletion expense was primarily due to
capitalized costs associated with new wells that were successfully drilled and completed in 2009
and 2010 and the Wolfberry Acquisitions, and was offset in part by the increase in the oil and
natural gas prices between the periods utilized to determine proved reserves. The decrease in
depletion expense per Boe was primarily due to (i) the increase in the oil and natural gas prices
between the periods utilized to determine proved reserves, (ii) the increase in proved reserves
from the successful 2009 and 2010 drilling of unproved properties and (iii) the increase in total
proved reserves due to the new SEC rules related to disclosures of oil and natural gas reserves.
On December 31, 2009, we adopted the new SEC rules related to disclosures of oil and natural
gas reserves. As a result of these new SEC rules, we recorded an additional 13.6 MMBoe of proved
reserves in 2009. We included the additional proved reserves in our depletion computation in the
fourth quarter of 2009 and first two quarters of 2010. Our second quarter of 2010 depletion expense
rate
48
was $15.35 per Boe, which is lower than past quarters in part due to these additional proved
reserves. In the future, making comparisons to prior periods as it relates to our depletion rate
may be difficult as a result of these new SEC rules.
The amortization of the intangible asset is a result of the value assigned to the operating
rights that we acquired in the July 2008 acquisition of Henry Petroleum LP and certain entities and
individuals affiliated with Henry Petroleum LP (collectively the Henry Entities). The intangible
asset is currently being amortized over an estimated life of approximately 25 years.
Impairment of long-lived assets. We periodically review our long-lived assets to be held and
used, including proved oil and natural gas properties accounted for under the successful efforts
method of accounting. Due primarily to downward adjustments to the economically recoverable proved
reserves associated with declines in well performance, we recognized a non-cash charge against
earnings of $4.7 million during the three months ended June 30, 2010, which was primarily
attributable to natural gas related properties in our New Mexico Permian area. For the three months
ended June 30, 2009, we recognized a non-cash charge against earnings of $4.5 million, which was
primarily attributable to natural gas related, non-core properties, in our New Mexico Permian area.
General and administrative expenses. The following table provides components of our general
and administrative expenses for the three months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
General and administrative expenses recurring |
|
$ |
15,875 |
|
|
$ |
4.60 |
|
|
$ |
12,025 |
|
|
$ |
4.40 |
|
Non-recurring bonus paid to Henry Entities
employees, see Note K |
|
|
2,470 |
|
|
|
0.72 |
|
|
|
2,750 |
|
|
|
1.01 |
|
Non-cash stock-based compensation stock options |
|
|
579 |
|
|
|
0.17 |
|
|
|
885 |
|
|
|
0.32 |
|
Non-cash stock-based compensation restricted stock |
|
|
2,292 |
|
|
|
0.66 |
|
|
|
1,303 |
|
|
|
0.48 |
|
Less: Third-party operating fee reimbursements |
|
|
(3,678 |
) |
|
|
(1.07 |
) |
|
|
(2,791 |
) |
|
|
(1.02 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses |
|
$ |
17,538 |
|
|
$ |
5.08 |
|
|
$ |
14,172 |
|
|
$ |
5.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were $17.5 million ($5.08 per Boe) for the three months
ended June 30, 2010, an increase of $3.3 million (24 percent) from $14.2 million ($5.19 per Boe)
for the three months ended June 30, 2009. The increase in general and administrative expenses was
primarily due to (i) an increase in non-cash stock-based compensation for stock-based compensation
awards and (ii) an increase in the number of employees and related personnel expenses to handle our
increased activities, partially offset by an increase in third-party operating fee reimbursements.
The decrease in total general and administrative expenses per Boe was primarily due to increased
production associated with (i) additional production from our wells successfully drilled and
completed in 2009 and 2010 and (ii) additional production from our Wolfberry Acquisitions for which
we added no administrative personnel.
In connection with the Henry Entities acquisition in July 2008, we agreed to pay certain of
the Henry Entities former employees a predetermined bonus amount, in addition to the compensation
we pay these employees, at each of the first and second anniversaries of the closing of the
acquisition. Since these employees will earn this bonus over the two years following the
acquisition and it is outside of our control, we are reflecting the cost in our general and
administrative costs as non-recurring. 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 $3.7 million and $2.8 million during the three
months ended June 30, 2010 and 2009, respectively. This reimbursement is reflected as a reduction
of general and administrative expenses in the consolidated statements of operations.
49
(Gain) loss on derivatives not designated as hedges. The following table sets forth the cash
settlements and the non-cash mark-to-market adjustment for the derivative contracts not designated
as hedges for the three months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Cash payments (receipts): |
|
|
|
|
|
|
|
|
Commodity derivatives oil |
|
$ |
2,852 |
|
|
$ |
(21,828 |
) |
Commodity derivatives natural gas |
|
|
(5,614 |
) |
|
|
(3,292 |
) |
Financial derivatives interest |
|
|
1,221 |
|
|
|
779 |
|
Mark-to-market (gain) loss: |
|
|
|
|
|
|
|
|
Commodity derivatives oil |
|
|
(119,303 |
) |
|
|
105,062 |
|
Commodity derivatives natural gas |
|
|
6,509 |
|
|
|
4,312 |
|
Financial derivatives interest |
|
|
1,572 |
|
|
|
(3,427 |
) |
|
|
|
|
|
|
|
(Gain) loss on derivatives not designated as hedges |
|
$ |
(112,763 |
) |
|
$ |
81,606 |
|
|
|
|
|
|
|
|
Interest expense. The following table sets forth interest expense, weighted average interest
rates and weighted average debt balances for the three months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
June 30, |
|
|
2010 |
|
2009 |
|
Interest expense (in thousands) |
|
$ |
11,192 |
|
|
$ |
6,200 |
|
|
|
|
|
|
|
|
|
|
Weighted average interest rate |
|
|
5.4 |
% |
|
|
2.9 |
% |
|
|
|
|
|
|
|
|
|
Weighted average debt balance (in millions) |
|
$ |
663.4 |
|
|
$ |
680.0 |
|
The increase in interest expense of approximately $5.0 million was due to interest costs on our
8.625 percent unsecured senior notes that were issued in September 2009. The decrease in the
weighted average debt balance during the three months ended June 30, 2010 was due to partial
repayment on our credit facility in February 2010 with the net proceeds of our equity offering. The
increase in the weighted average interest rate was primarily due to the interest rate on our
unsecured senior notes coupled with an increase in market interest rates, which increases the rate
on borrowings under our credit facility.
Income tax provisions. We recorded income tax expense of $74.7 million and an income tax
benefit of $25.7 million for the three months ended June 30, 2010 and 2009, respectively. The
effective income tax rate for the three months ended June 30, 2010 and 2009 was 37.6 percent and
43.6 percent, respectively.
50
Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009
Oil and natural gas revenues. Revenue from oil and natural gas operations was $427.7
million for the six months ended June 30, 2010, an increase of $214.4 million (101 percent) from
$213.3 million for the six months ended June 30, 2009. This increase was primarily due to
substantial increases in realized oil and natural gas prices and increased production (i) as a
result of the Wolfberry Acquisitions and (ii) due to successful drilling efforts during 2009 and
2010. Specifically the:
|
|
|
average realized oil price (excluding the effects of derivative activities) was
$74.81 per Bbl during the six months ended June 30, 2010, an increase of 58 percent from
$47.32 per Bbl during the six months ended June 30, 2009; |
|
|
|
|
total oil production was 4,507 MBbl for the six months ended June 30, 2010, an
increase of 989 MBbl (28 percent) from 3,518 MBbl for the six months ended June 30,
2009; |
|
|
|
|
average realized natural gas price (excluding the effects of derivative activities)
was $7.00 per Mcf during the six months ended June 30, 2010, an increase of 55 percent
from $4.52 per Mcf during the six months ended June 30, 2009; and |
|
|
|
|
total natural gas production was 12,933 MMcf for the six months ended June 30, 2010,
an increase of 2,564 MMcf (25 percent) from 10,369 MMcf for the six months ended June
30, 2009. |
Production expenses. The following table provides the components of our total oil and natural
gas production costs for the six months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Lease operating expenses |
|
$ |
38,715 |
|
|
$ |
5.81 |
|
|
$ |
32,294 |
|
|
$ |
6.16 |
|
Taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem |
|
|
5,192 |
|
|
|
0.78 |
|
|
|
2,491 |
|
|
|
0.47 |
|
Production |
|
|
30,053 |
|
|
|
4.51 |
|
|
|
15,365 |
|
|
|
2.93 |
|
Workover costs |
|
|
3,188 |
|
|
|
0.48 |
|
|
|
433 |
|
|
|
0.08 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas production expenses |
|
$ |
77,148 |
|
|
$ |
11.58 |
|
|
$ |
50,583 |
|
|
$ |
9.64 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, in general, we have some control over lease
operating expenses and workover costs on properties we operate, but production and ad valorem taxes
are directly related to commodity price changes.
Lease operating expenses were $38.7 million ($5.81 per Boe) for the six months ended June 30,
2010, an increase of $6.4 million (20 percent) from $32.3 million ($6.16 per Boe) for the six
months ended June 30, 2009. The increase in lease operating expenses was primarily due to (i) our
wells successfully drilled and completed in 2009 and 2010 and (ii) additional interests acquired in
the Wolfberry Acquisitions in December 2009. The decrease in lease operating expenses per Boe was
primarily due to additional production from our wells successfully drilled and completed in 2009
and 2010 where we are receiving benefits from economies of scale, offset in part by the incurrence
of some non-routine costs during the six months ended June 30, 2010.
Ad valorem taxes have increased primarily as a result of increased valuations of our Texas
properties and the increase in our number of wells primarily associated with the Wolfberry
Acquisitions and 2009 and 2010 drilling activity.
Production taxes per unit of production were $4.51 per Boe during the six months ended June
30, 2010, an increase of 54 percent from $2.93 per Boe during the six months ended June 30, 2009.
The increase was directly related to the increase in commodity prices and our increase in oil and
natural gas revenues related to increased volumes. Over the same period, our per Boe prices
(excluding the effects of derivatives) increased 58 percent.
51
Workover expenses were approximately $3.2 million and $0.4 million for the six months ended
June 30, 2010 and 2009, respectively. The 2010 amounts related primarily to increased workovers in
our New Mexico Permian area due to work performed to restore production, whereas the 2009 amounts
related primarily to workovers in our Texas Permian area.
Exploration and abandonments expense. The following table provides a breakdown of our
exploration and abandonments expense for the six months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Geological and geophysical |
|
$ |
1,228 |
|
|
$ |
1,125 |
|
Exploratory dry holes |
|
|
218 |
|
|
|
1,866 |
|
Leasehold abandonments and other |
|
|
727 |
|
|
|
4,428 |
|
|
|
|
|
|
|
|
Total exploration and abandonments |
|
$ |
2,173 |
|
|
$ |
7,419 |
|
|
|
|
|
|
|
|
Our geological and geophysical expense, which primarily consists of the costs of acquiring and
processing seismic data, geophysical data and core analysis, was approximately $1.2 million and
$1.1 million for the six months ended June 30, 2010 and 2009, respectively.
During the six months ended June 30, 2009, we wrote-off an unsuccessful exploratory well in
our Arkansas emerging play and two unsuccessful exploratory wells in our Texas Permian area.
For the six months ended June 30, 2010, we recorded $0.7 million of leasehold abandonments,
which were primarily related to non-core prospects in our Texas Permian area. For the six months
ended June 30, 2009, we recorded approximately $4.4 million of leasehold abandonments, which
related primarily to the write-off of four non-core prospects in our New Mexico Permian area and
three non-core prospects in our Texas Permian area.
Depreciation, depletion and amortization expense. The following table provides components of
our depreciation, depletion and amortization expense for the six months ended June 30, 2010 and
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Depletion of proved oil and natural gas properties |
|
$ |
105,768 |
|
|
$ |
15.87 |
|
|
$ |
100,995 |
|
|
$ |
19.25 |
|
Depreciation of other property and equipment |
|
|
1,402 |
|
|
|
0.21 |
|
|
|
1,374 |
|
|
|
0.26 |
|
Amortization of intangible asset operating rights |
|
|
774 |
|
|
|
0.12 |
|
|
|
781 |
|
|
|
0.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depletion, depreciation and amortization |
|
$ |
107,944 |
|
|
$ |
16.20 |
|
|
$ |
103,150 |
|
|
$ |
19.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period end |
|
$ |
72.23 |
|
|
|
|
|
|
$ |
66.25 |
|
|
|
|
|
Natural gas price used to estimate proved natural gas
reserves at period end |
|
$ |
4.10 |
|
|
|
|
|
|
$ |
3.72 |
|
|
|
|
|
Depletion of proved oil and natural gas properties was $105.8 million ($15.87 per Boe) for the
six months ended June 30, 2010, an increase of $4.8 million from $101.0 million ($19.25 per Boe)
for the six months ended June 30, 2009. The increase in depletion expense was primarily due to
capitalized costs associated with new wells that were successfully drilled and completed in 2009
and 2010 and the Wolfberry Acquisitions, and was offset in part by the increase in the oil and
natural gas prices between the periods utilized to determine proved reserves. The decrease in
depletion expense per Boe was primarily due to (i) the increase in the oil and natural gas prices
between the periods utilized to determine proved reserves, (ii) the increase in proved reserves
from the successful 2009 and 2010 drilling of unproved properties and (iii) the increase in total
proved reserves due to the new SEC rules related to disclosures of oil and natural gas reserves.
52
On December 31, 2009, we adopted the new SEC rules related to disclosures of oil and natural
gas reserves. As a result of these new SEC rules, we recorded an additional 13.6 MMBoe of proved
reserves in 2009. We included the additional proved reserves in our depletion computation in the
fourth quarter of 2009 and first two quarters of 2010. Our depletion expense rate for the six
months ended June 30, 2010, was $15.87 per Boe, which is lower than the same period last year in
part due to these additional proved reserves. In the future, making comparisons to prior periods as
it relates to our depletion rate may be difficult as a result of these new SEC rules.
The amortization of the intangible asset is a result of the value assigned to the operating
rights that we acquired in the July 2008 acquisition of Henry Petroleum LP and certain entities and
individuals affiliated with the Henry Entities. The intangible asset is currently being amortized
over an estimated life of approximately 25 years.
Impairment of long-lived assets. We periodically review our long-lived assets to be held and
used, including proved oil and natural gas properties accounted for under the successful efforts
method of accounting. Due primarily to downward adjustments to the economically recoverable proved
reserves associated with declines in well performance, we recognized a non-cash charge against
earnings of $7.3 million during the six months ended June 30, 2010, which was primarily
attributable to natural gas related properties in our New Mexico Permian area. For the six months
ended June 30, 2009, we recognized a non-cash charge against earnings of $8.6 million, which was
primarily attributable to non-core, natural gas related properties in our New Mexico Permian area.
General and administrative expenses. The following table provides components of our general
and administrative expenses for the six months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
General and administrative expenses recurring |
|
$ |
26,996 |
|
|
$ |
4.05 |
|
|
$ |
21,939 |
|
|
$ |
4.18 |
|
Non-recurring bonus paid to Henry Entities
employees, see Note K |
|
|
4,938 |
|
|
|
0.74 |
|
|
|
5,311 |
|
|
|
1.01 |
|
Non-cash stock-based compensation stock options |
|
|
1,588 |
|
|
|
0.24 |
|
|
|
1,913 |
|
|
|
0.37 |
|
Non-cash stock-based compensation restricted stock |
|
|
4,114 |
|
|
|
0.62 |
|
|
|
2,200 |
|
|
|
0.42 |
|
Less: Third-party operating fee reimbursements |
|
|
(6,540 |
) |
|
|
(0.98 |
) |
|
|
(5,445 |
) |
|
|
(1.04 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses |
|
$ |
31,096 |
|
|
$ |
4.67 |
|
|
$ |
25,918 |
|
|
$ |
4.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were $31.1 million ($4.67 per Boe) for the six months
ended June 30, 2010, an increase of $5.2 million (20 percent) from $25.9 million ($4.94 per Boe)
for the six months ended June 30, 2009. The increase in general and administrative expenses was
primarily due to (i) an increase in non-cash stock-based compensation for stock-based compensation
awards and (ii) an increase in the number of employees and related personnel expenses to handle our
increased activities, partially offset by an increase in third-party operating fee reimbursements.
The decrease in total general and administrative expenses per Boe was primarily due to increased
production associated with (i) additional production from our wells successfully drilled and
completed in 2009 and 2010 and (ii) additional production from our Wolfberry Acquisitions for which
we added no administrative personnel.
In connection with the Henry Entities acquisition in July 2008, we agreed to pay certain of
the Henry Entities former employees a predetermined bonus amount, in addition to the compensation
we pay these employees, at each of the first and second anniversaries of the closing of the
acquisition. Since these employees will earn this bonus over the two years following the
acquisition and it is outside of our control, we are reflecting the cost in our general and
administrative costs as non-recurring. 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 $6.5 million and $5.4 million during the six months
ended June 30, 2010 and 2009, respectively. This reimbursement is reflected as a reduction of
general and administrative expenses in the consolidated statements of operations.
53
(Gain) loss on derivatives not designated as hedges. The following table sets forth the cash
settlements and the non-cash mark-to-market adjustment for the derivative contracts not designated
as hedges for the six months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Cash payments (receipts): |
|
|
|
|
|
|
|
|
Commodity derivatives oil |
|
$ |
12,985 |
|
|
$ |
(56,412 |
) |
Commodity derivatives natural gas |
|
|
(6,120 |
) |
|
|
(5,832 |
) |
Financial derivatives interest |
|
|
2,434 |
|
|
|
779 |
|
Mark-to-market (gain) loss: |
|
|
|
|
|
|
|
|
Commodity derivatives oil |
|
|
(120,741 |
) |
|
|
144,099 |
|
Commodity derivatives natural gas |
|
|
(20,678 |
) |
|
|
5,018 |
|
Financial derivatives interest |
|
|
3,784 |
|
|
|
(1,000 |
) |
|
|
|
|
|
|
|
(Gain) loss on derivatives not designated as hedges |
|
$ |
(128,336 |
) |
|
$ |
86,652 |
|
|
|
|
|
|
|
|
Interest expense. The following table sets forth interest expense, weighted average interest
rates and weighted average debt balances for the six months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
June 30, |
|
|
2010 |
|
2009 |
|
Interest expense (in thousands) |
|
$ |
22,257 |
|
|
$ |
10,570 |
|
|
|
|
|
|
|
|
|
|
Weighted average interest rate |
|
|
5.3 |
% |
|
|
2.5 |
% |
|
|
|
|
|
|
|
|
|
Weighted average debt balance (in millions) |
|
$ |
687.1 |
|
|
$ |
668.0 |
|
The increase in interest expense of approximately $11.7 million is due to interest costs on
our 8.625 percent unsecured senior notes that were issued in September 2009. The increase in the
weighted average debt balance during the six months ended June 30, 2010 is due to our borrowings
under our credit facility to finance the Wolfberry Acquisitions, offset by a partial repayment on
our credit facility in February 2010 with the net proceeds of our equity offering. The increase in
the weighted average interest rate is primarily due to the interest rate on our unsecured senior
notes coupled with an increase in market interest rates, which increases the rate on borrowings
under our credit facility.
Income tax provisions. We recorded income tax expense of $114.7 million and an income tax
benefit of $33.8 million for the six months ended June 30, 2010 and 2009, respectively. The
effective income tax rate for the six months ended June 30, 2010 and 2009 was 37.4 percent and 42.1
percent, respectively.
54
Capital Commitments, Capital Resources and Liquidity
Capital commitments. Our primary needs for cash are development, exploration and acquisition
of oil and natural gas assets, payment of contractual obligations and working capital obligations.
Funding for these cash needs may be provided by any combination of internally-generated cash flow,
financing under our credit facility, proceeds from the disposition of assets or alternative
financing sources, as discussed in Capital resources below.
Oil and natural gas properties. Our costs incurred on oil and natural gas properties,
excluding acquisitions and asset retirement obligations, during the six months ended June 30, 2010
and 2009 totaled $309.0 million and $202.7 million, respectively, as compared to the comparable
amount in cash flows used by investing activities of $278.0 million and $223.3 million for the
respective periods. The primary reason for the differences in the costs incurred and cash flow
expenditures is the timing of payments. These expenditures in 2010 were primarily funded by cash
flow from operations (including effects of cash settlements received from (paid on) derivatives not
designated as hedges).
In December 2009, we announced our 2010 capital budget of approximately $625 million, which we expected
could be funded substantially within our cash flow. In August 2010, we announced the increase of our 2010 capital
budget to $700 million. Based on current commodity prices and our expectations, we believe our 2010 revised
capital budget will exceed our 2010 cash flow, excluding the effects of the Marbob Acquisition. Originally our capital
budget was front end loaded, and we expected to outspend our cash flow in the first half of 2010. We outspent our cash
flow during the six months ended June 30, 2010 by approximately $60 million, including acquisitions. As our size and
financial flexibility has grown, we have a longer-term view on spending substantially within our cash flow, and our
spending during any specific period may exceed our cash flow for that period. However, our capital budget is
largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels
or substantial increases in our drilling and completion costs, we may reduce our capital spending program to be
substantially within our cash flow. Our capital budget does not include acquisitions (other than the customary
purchase of leasehold acreage). Our 2010 capital budget does not include capital we may spend on the Marbob
assets once we close the acquisition.
On July 19, 2010, we entered into an asset purchase agreement to acquire substantially all of the oil and natural
gas leases, interests, properties and related assets owned by Marbob for aggregate consideration of approximately
$1.65 billion, subject to purchase price adjustments, which include downward purchase price adjustments based on
the exercise of third parties of contractual preferential rights to purchase certain interests in properties to be acquired
from Marbob. Upon closing, the consideration consists of (i) cash consideration in the aggregate amount of
$1.45 billion, (ii) the issuance by us to Marbob of an 8 percent unsecured promissory note due 2018 in the aggregate
principal amount of $150 million and (iii) the issuance to Marbob of approximately 1.1 million shares of our
common stock. As previously discussed, Marbob has informed us of the receipt by Marbob of a notice from BP
electing to exercise its contractual preferential right under certain operating agreements to purchase certain Marbob
interests in properties as a result of the announcement of the Marbob Acquisition which have an approximate
allocated value of $400 million. The result of this would reduce the purchase price associated with the Marbob
Acquisition. The Marbob Acquisition is expected to close on or before November 30, 2010. Though no assurances
can be given, we are targeting an anticipated closing date of October 1, 2010. Assuming the acquisition closes on
October 1, 2010 and no contractual preferential rights to purchase interests in properties have been exercised, we
estimate we would spend approximately $70 million on drilling and related expenditures during the fourth quarter of
2010 that is not currently reflected in our revised 2010 capital budget.
Other than the purchase of leasehold acreage, our revised 2010 capital budget is exclusive of
acquisitions (including the Marbob Acquisition). 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
development, high-potential exploration and control of operations that will allow us to apply our
operating expertise.
Although we cannot provide any assurance, we generally attempt to fund our non-acquisition
expenditures with our available cash and cash flow, as adjusted from time to time; however, we may
also use our credit facility, or other alternative financing sources, to fund such expenditures.
The actual amount and timing of our expenditures may differ materially from our estimates as a
result of, among other things, actual drilling results, the timing of expenditures by third parties
on projects that we do not operate, the availability of drilling rigs and other services and
equipment, regulatory, technological and competitive developments and market conditions. In
addition, under certain circumstances we would consider increasing or reallocating our revised 2010
capital budget.
Acquisitions.
Our expenditures for acquisitions of proved and unproved
properties (which include leasehold acquisitions) during the
three months ended June 30, 2010 and 2009 totaled approximately $19.6 million and $3.3 million,
respectively, and approximately $34.8 million and $3.6 million during the six months ended June 30,
2010 and 2009, respectively. The proved acquisitions during the six months ended June 30, 2010,
primarily relate to additional interests that we closed in 2010 on the Wolfberry Acquisitions and
the acquisition of other Wolfberry assets.
55
Contractual obligations. Our contractual obligations include long-term debt, cash interest
expense on debt, operating lease obligations, drilling commitments, employment agreements with
executive officers, contractual bonus payments, derivative liabilities
and other obligations. Since December 31, 2009, the material changes in our contractual
obligations included a $202 million decrease in outstanding
long-term borrowings, a $38.8 million
decrease in cash interest expense on debt and our net commodity derivative is now in an asset
position. See Note J of Condensed Notes to Consolidated Financial Statements included in Item 1.
Consolidated Financial Statements (Unaudited) for additional information regarding our long-term
debt and Item 3. Quantitative and Qualitative Disclosures About Market Risk for information
regarding the interest on our long-term debt and information on changes in the fair value of our
open derivative obligations during the six months ended June 30, 2010.
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 (including the cash settlements received from (paid on) derivatives not
designated as hedges presented in our investing activities) and financing provided by our credit
facility. We believe that funds from our cash flows may not be adequate to meet both our short-term
working capital requirements and our revised 2010 capital expenditure plans (excluding the effects
from the Marbob Acquisition). We believe we have adequate availability under our credit facility to
fund cash flow deficits, though we may reduce our capital spending program to remain substantially
within our cash flow.
Cash flow from operating activities. Our net cash provided by operating activities was $239.5
million and $118.2 million for the six months ended June 30, 2010 and 2009, respectively. The
increase in operating cash flows during the six months ended June 30, 2010 over the same period in
2009 was principally due to increases in average realized oil and natural gas prices coupled with
increased production.
Cash flow used in investing activities. During the six months ended June 30, 2010 and 2009, we
invested $291.4 million and $223.3 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 higher during the six months ended June 30, 2010 over 2009, due to the Wolfberry
Acquisitions and an increase in our capital expenditures on oil and natural gas properties, offset
by settlements paid on derivatives not designated as hedges during the six months ended June 30,
2010 as compared to receipts on derivatives not designated as hedges in the comparable period in
2009.
Cash flow from financing activities. Net cash provided by financing activities was $59.8
million and $29.9 million for the six months ended June 30, 2010 and 2009, respectively. During the
six months ended June 30, 2010, we reduced our outstanding balance on our credit facility by $202
million primarily using proceeds from the issuance of common stock. During the six months ended
June 30, 2009, we had net borrowings of $30.0 million under our credit facility.
Our credit facility, as amended, has a maturity date of July 31, 2013. At June 30, 2010, we
had letters of credit outstanding under the credit facility of approximately $25,000, and our
availability to borrow additional funds was approximately $852.0 million based on the borrowing
base of $1.2 billion. The next scheduled borrowing base redetermination is in October 2010. 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.
We have received an $800 million underwritten commitment from two of our lenders under our
credit facility to expand the size of our existing credit facility from $1.2 billion to $2.0
billion as part of the financing for the Marbob Acquisition, which we expect will provide the
credit capacity to fund the remaining cash portion of the purchase price. The expanded credit
facility is expected to close simultaneously with the Marbob Acquisition.
Advances on the credit facility bear interest, at our option, based on (i) the prime rate of
JPMorgan Chase Bank (JPM Prime Rate) (3.25 percent at June 30, 2010) or (ii) a Eurodollar rate
(substantially equal to the London Interbank Offered Rate). At June 30, 2010, the interest rates
of Eurodollar rate advances and JPM Prime Rate advances vary, with interest margins ranging from
200 to 300 basis points and 112.5 to 212.5 basis points, respectively, per annum depending on the
debt balance outstanding. At June 30, 2010, we paid 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
56
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.
On February 1, 2010, we issued approximately 5.3 million shares of our common stock at $42.75
per share in a public offering. After deducting underwriting discounts of approximately $9.1
million and transaction costs, we received net proceeds of approximately $219.3 million. The net
proceeds from this offering were used to repay a portion of the borrowing under our credit
facility.
Financial markets. The current state of the financial markets remains uncertain; however, we
have recently seen improvements in the stock market, and the credit markets appear to have
stabilized. There have been financial institutions that have (i) failed and been forced into
government receivership, (ii) received government bail-outs, (iii) declared bankruptcy, (iv) been
forced to seek additional capital and liquidity to maintain viability or (v) merged. The United
States and world economies have experienced and continue to experience volatility, which continues
to impact the financial markets.
At June 30, 2010, we had $852.0 million of available borrowing capacity. Our credit facility
is backed by a syndicate of 20 banks. Even in light of the volatility in the financial markets, we
believe that the lenders under our credit facility have the ability to fund additional borrowings
we may need for our business.
We pay floating rate interest under our credit facility, and we are unable to predict,
especially in light of the uncertainty in the financial markets, whether we will incur increased
interest costs due to rising interest rates. We have used interest rate derivatives to mitigate
the cost of rising interest rates, and we may enter into additional interest rate derivatives in
the future. Additionally, we may issue additional fixed rate debt in the future to increase
available borrowing capacity under our credit facility or to reduce our exposure to the volatility
of interest rates.
In the current financial markets, there is no assurance that we could refinance our credit
facility with comparable terms, particularly the five-year term of our credit facility. Because our
credit facility matures in July 2013, we do not expect to seek refinancing of our credit facility
any earlier than 2011.
To the extent we need additional funds beyond those available under our credit facility to
operate our business or make acquisitions, we would have to pursue other financing sources. These
sources could include issuance of (i) fixed and floating rate debt, (ii) convertible securities,
(iii) preferred stock, (iv) common stock or (v) other securities. We may also sell assets.
However, in light of the current financial market conditions there are no assurances that we could
obtain additional funding, or if available, at what cost and terms.
Liquidity. Our principal sources of short-term liquidity are cash on hand and available
borrowing capacity under our credit facility. At June 30, 2010, we had $0.4 million of cash on
hand.
At June 30, 2010, we had $852.0 million of available borrowing capacity. Our borrowing base is redetermined
semi-annually, with the next redetermination occurring in October 2010. 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. 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 or
the volatility in commodity prices and the state of the financial markets, there is no assurance that our borrowing
base will not be reduced.
As is customary in similar acquisitions, there may be adjustments payable to the seller to the purchase price for
items such as (i) costs incurred after a specified date through the closing date, (ii) contractual preferential rights of
third parties to purchase some of the assets involved in the transaction and (iii) other adjustments agreed to in the
asset purchase agreement.
57
In addition, Marbob has contractual preferential rights under certain operating agreements to purchase certain
interests in properties if third parties were to sell those interests in properties. BP announced it was selling
all its assets in the Permian Basin to Apache. Marbob and BP own common interests in certain common properties
subject to a contractual preferential right to purchase. BP and Apache have contested Marbobs ability to exercise its
contractual preferential rights in this situation. As a result, Marbob and we have filed suit against BP and Apache
seeking declaratory judgment and injunctive relief to protect Marbobs contractual right to have the option to
purchase these interests in properties. We are unable to predict at this time if the court will grant Marbob and us the
relief sought in connection with the suit.
Currently, we have identified interests in properties in the Marbob Acquisition that we believe are subject to
contractual preferential rights to purchase by third parties. If all
the contractual preferential rights were exercised (including the
approximately $400 million associated with BP),
we estimate the purchase price would be reduced by approximately $500 million.
As part of the Marbob Acquisition, we agreed to reimburse Marbob for drilling and completion costs, net of any
revenues, incurred on specified properties from July 1, 2010 through the closing date. Though no assurances can be
given, we are targeting an anticipated closing date of October 1, 2010. Assuming the Marbob Acquisition closes on
October 1, 2010, we estimate we will be required to fund an additional $50 million of purchase price, which we
believe we would fund under our credit facility.
We intend to finance the $1.45 billion cash portion of the Marbob Acquisition with a combination of equity and
debt. On July 19, 2010, we entered into a common stock purchase agreement with third-party investors to sell
approximately 6.6 million shares of our common stock in a private placement for aggregate cash consideration of
approximately $300 million. We anticipate that the private placement will close simultaneously with the Marbob
Acquisition. We received an $800 million underwritten commitment from two of our lenders under the credit
facility to expand the size of our existing credit facility from $1.2 billion to $2.0 billion as part of the financing for
the Marbob Acquisition, which we expect will provide the credit capacity to fund the remaining cash portion of the
purchase price. The expanded facility is expected to close simultaneously with the Marbob Acquisition. Assuming
the transaction had closed on June 30, 2010 and no contractual preferential rights to purchase interests in properties
had been exercised, we estimate we would have had approximately $400 million in availability under our
expanded credit facility.
Book capitalization and current ratio. Our book capitalization at June 30, 2010 was $2.4
billion, consisting of debt of $644.0 million and stockholders equity of $1.8 billion. Our debt to
book capitalization was 27 percent and 39 percent at June 30, 2010 and December 31, 2009,
respectively. Our ratio of current assets to current liabilities was 0.63 to 1.0 at June 30, 2010
as compared to 0.64 to 1.0 at December 31, 2009.
Inflation and changes in prices. Our revenues, the value of our assets, and our ability to
obtain bank financing or additional capital on attractive terms have been and will continue to be
affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are
subject to significant fluctuations that are beyond our ability to control or predict. During the
six months ended June 30, 2010, we received an average of $74.81 per barrel of oil and $7.00 per
Mcf of natural gas before consideration of commodity derivative contracts compared to $47.32 per
barrel of oil and $4.52 per Mcf of natural gas in the six months ended June 30, 2009. 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 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 have upward pressure during 2010 as a result of the recent improvements in oil prices from 2009.
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 six months ended June 30, 2010. See our disclosure of critical accounting policies in the
consolidated financial statements included in our Annual Report on Form 10-K for the year ended
December 31, 2009, filed with the SEC on February 26, 2010.
Recent Accounting Pronouncements
Various topics. In February 2010, the FASB issued an update to various topics, which
eliminated outdated provisions and inconsistencies in the Accounting Standards Codification (the
Codification), and clarified certain guidance to reflect the FASBs original intent. The update
is effective for the first reporting period, including interim periods, beginning after issuance of
the update,
58
except for the amendments affecting embedded derivatives and reorganizations. In
addition to amending the Codification, the FASB made corresponding changes to the legacy accounting
literature to facilitate historical research. These changes are included in an appendix to the
update. We adopted the update effective January 1, 2010, and the adoption did not have a
significant impact on our consolidated financial statements.
Accounting for extractive activities. In April 2010, the FASB issued an amendment to a
paragraph in the accounting standard for oil and natural gas extractive activities accounting. The
standard adds to the Codification the SECs Modernization of Oil and Gas Reporting release. We
adopted the update effective April 20, 2010, and the adoption did not have a significant impact on
our consolidated financial statements.
59
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, 2009.
We are exposed to a variety of market risks including credit risk, commodity price risk and
interest rate risk. We address these risks through a program of risk management which includes the
use of derivative instruments. The following quantitative and qualitative information is provided
about financial instruments to which we are a party at June 30, 2010, 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 and to a
lesser extent our derivative counterparties. 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 could further
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
specified period of time. Our commodity price risk management activities could have the effect of
reducing net income and the value of our common stock. An average increase in the commodity price
of $10.00 per barrel of oil and $1.00 per MMBtu for natural gas from the commodity prices at
June 30, 2010, would have created a net unrealized loss of approximately $121.8 million on our
commodity price risk management contracts held at June 30, 2010.
At June 30, 2010, we had (i) oil price swaps that settle on a monthly basis covering future
oil production from July 1, 2010 through December 31, 2012 and (ii) a natural gas price swap,
natural gas price collars and natural gas basis swaps covering future natural gas production from
July 1, 2010 to December 31, 2012; see Note I of the Condensed Notes to Consolidated Financial
Statements included in Item 1. Consolidated Financial Statements (Unaudited) for additional
information on our commodity derivative contracts. The average NYMEX oil futures price and average
NYMEX natural gas futures price for the six months ended June 30, 2010, was $78.36 per Bbl and
$4.69 per MMBtu, respectively. At August 4, 2010, the NYMEX oil price and NYMEX natural
gas price were $82.47 per Bbl and $4.74 per MMBtu, respectively. A decrease in oil and
natural gas prices would increase the fair value asset of our commodity derivative contracts from
their recorded balance at June 30, 2010. 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 our fair value asset would be recorded in earnings as an
unrealized gain. However, an increase in the average NYMEX oil and
natural gas prices above
those at June 30, 2010, would result in a decrease in our fair value asset and be recorded as an
unrealized loss 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 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.
At June 30, 2010, we had interest rate swaps on $300 million of notional principal that fixed
the LIBOR interest rate (not including the interest rate margins discussed above) at 1.90 percent
for the three years beginning in May 2009. An average decrease
60
in future interest rates of 25
basis points from the future rate at June 30, 2010, would have increased our net unrealized
liability on our interest rate risk management contracts by approximately $1.4 million.
We had total indebtedness of $348.0 million outstanding under our credit facility at June 30,
2010. The impact of a 1 percent increase in interest rates on this amount of debt would result in
increased annual interest expense of approximately $3.5 million.
The fair value of our derivative instruments is determined based on our valuation models. We
did not change our valuation method during 2010. During 2010, we were party to commodity and
interest rate derivative instruments; see Note I of the Condensed Notes to Consolidated Financial
Statements included in Item 1. Consolidated Financial Statements (Unaudited) for additional
information regarding our derivative instruments. The following table reconciles the changes that
occurred in the fair values of our derivative instruments during the six months ended June 30,
2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Instruments Net Assets (Liabilities) (a) |
|
(in thousands) |
|
Commodities |
|
|
Interest Rate |
|
|
Total |
|
|
Fair value of contracts outstanding at December 31, 2009 |
|
$ |
(64,332 |
) |
|
$ |
(2,501 |
) |
|
$ |
(66,833 |
) |
Changes in fair values (b) |
|
|
134,554 |
|
|
|
(6,218 |
) |
|
|
128,336 |
|
Contract maturities |
|
|
6,865 |
|
|
|
2,434 |
|
|
|
9,299 |
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts outstanding at June 30, 2010 |
|
$ |
77,087 |
|
|
$ |
(6,285 |
) |
|
$ |
70,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the
Exchange Act, we have evaluated, under the supervision and with the participation of our
management, including our principal executive officer and principal financial officer, the
effectiveness of the design and operation of our disclosure controls and procedures (as defined in
Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this
report. Our disclosure controls and procedures are designed to provide reasonable assurance that
the information required to be disclosed by us in reports that we file under the Exchange Act is
accumulated and communicated to our management, including our principal executive officer and
principal financial officer, as appropriate, to allow timely decisions regarding required
disclosure and is recorded, processed, summarized and reported within the time periods specified in
the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and
principal financial officer have concluded that our disclosure controls and procedures were
effective at June 30, 2010 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting. There have been no changes in our
internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act)
that occurred during our last fiscal quarter that have materially affected or are reasonably likely
to materially affect our internal controls over financial reporting.
61
PART II OTHER INFORMATION
Item 1. Legal Proceedings
We are party to the legal proceedings that are described in Note K of the Condensed Notes
to Consolidated Financial Statements included in Item 1. Consolidated Financial Statements
(Unaudited). We are party to certain proceedings and claims incidental to our business. While many
of these other matters involve inherent uncertainty, we believe that the liability, if any,
ultimately incurred with respect to such other 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, 2009, 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, 2009.
Our estimates of proved reserves have been prepared under new SEC rules which went into effect
for fiscal years ending on or after December 31, 2009, which may make comparisons to prior periods
difficult and could limit our ability to book additional proved undeveloped reserves in the future.
Our Annual Report on Form 10-K for the year ended December 31, 2009 presents estimates of our
proved reserves as of December 31, 2009, which have been prepared and presented under new SEC
rules. These new rules are effective for fiscal years ending on or after December 31, 2009, and
require SEC reporting companies to prepare their reserves estimates using revised reserve
definitions and revised pricing based on a 12-month unweighted average of the
first-day-of-the-month pricing. The previous rules required that reserve estimates be calculated
using last-day-of-the-year pricing. The pricing that was used for estimates of our reserves as of
December 31, 2009 was based on an unweighted average twelve month West Texas Intermediate posted
price of $57.65 per Bbl for oil and a Henry Hub spot natural gas price of $3.87 per MMBtu for
natural gas. As a result of this change in pricing methodology, direct comparisons of our
previously-reported reserves amounts may be more difficult.
Another impact of the new SEC rules is a general requirement that, subject to limited
exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be
drilled within five years of the date of booking. This new rule has limited and may continue to
limit our potential to book additional proved undeveloped reserves as we pursue our drilling
program, particularly as we develop our significant acreage in West Texas and Southeast New Mexico.
Moreover, we may be required to write down our proved undeveloped reserves if we do not drill on
those reserves within the required five-year timeframe.
Accordingly, while the estimates of our proved reserves and related PV-10 and Standardized
Measure at December 31, 2009 included in our Annual Report on Form 10-K for the year ended December
31, 2009 were prepared based on what we and our independent reserve engineers believe to be
reasonable interpretations of the new SEC rules, those estimates could differ materially from any
estimates we might prepare applying future interpretive guidance from the SEC.
The recent adoption of derivatives legislation by the United States Congress could have an
adverse effect on our ability to use derivative instruments to reduce the effect of commodity
price, interest rate and other risks associated with our business.
The United States Congress recently adopted comprehensive financial reform legislation that
establishes federal oversight and regulation of the over-the-counter derivatives market and
entities, including us, that participate in that market. The new legislation was signed into law
by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the
CFTC) and the SEC to promulgate rules and regulations implementing the new legislation within 360
days from the date of enactment. The CFTC has also proposed regulations to set position limits for
certain futures and option contracts in the major energy markets, although it is not possible at
this time to predict whether or when the CFTC will adopt those rules or include comparable
provisions in its rulemaking under the new legislation. The financial reform legislation may also
require us to comply with margin requirements and with certain clearing and trade-execution
requirements in connection with our derivative activities, although the application of those
provisions to us is uncertain at this time. The financial reform legislation may also require the
counterparties to our derivative instruments to spin off some of their derivatives activities to a
separate entity, which may not be as creditworthy as the current counterparty. The new legislation
and any new regulations could significantly increase the cost of derivative contracts (including
62
through requirements to post collateral which could adversely affect our available liquidity),
materially alter the terms of derivative contracts, reduce the availability of derivatives to
protect against risks we encounter, reduce our ability to monetize or restructure our existing
derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce
our use of derivatives as a
result of the legislation and regulations, our results of operations may become more volatile
and our cash flows may be less predictable, which could adversely affect our ability to plan for
and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the
volatility of oil and natural gas prices, which some legislators attributed to speculative trading
in derivatives and commodity instruments related to oil and natural gas. Our revenues could
therefore be adversely affected if a consequence of the legislation and regulations is to lower
commodity prices. Any of these consequences could have a material adverse effect on us, our
financial condition and our results of operations.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total number |
|
Maximum |
|
|
|
|
|
|
|
|
|
|
of shares |
|
number of |
|
|
|
|
|
|
|
|
|
|
purchased as |
|
shares that |
|
|
Total number |
|
|
|
|
|
part of publicly |
|
may yet be |
|
|
of shares |
|
Average price |
|
announced |
|
purchased |
Period |
|
withheld (1) |
|
per share |
|
plans |
|
under the plan |
|
April 1, 2010 - April 30, 2010 |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
May 1, 2010 - May 31, 2010 |
|
|
1,603 |
|
|
$ |
46.79 |
|
|
|
|
|
|
|
|
|
June 1, 2010 - June 30, 2010 |
|
|
5,005 |
|
|
$ |
58.17 |
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents shares that were withheld by us to satisfy tax withholding obligations of certain of our officers, directors and key
employees that arose upon the lapse of restrictions on restricted stock. |
Item 5. Other Information
We are filing a revised report from Cawley, Gillespie & Associates, Inc. (Cawley), our
independent petroleum engineers, included in Exhibit 23.2 to this Quarterly Report on Form 10-Q,
which is a letter dated January 25, 2010 regarding proved reserves. The Cawley report filed as
Exhibit 23.4 to our Annual Report on Form 10-K contained the following language, which has been
deleted in the Cawley report filed as Exhibit 23.2 to this Quarterly Report on Form 10-Q: This
letter was prepared for the exclusive use of Concho Resources Inc. Third parties should not rely on
it without the written consent of the above and Cawley, Gillespie & Associates, Inc. Other than
this change, there has been no other change to the Cawley report filed as Exhibit 23.2 to this
Quarterly Report on Form 10-Q.
We are also filing an updated consent of Cawley, Gillespie & Associates, Inc. as Exhibit 23.1,
to this Quarterly Report on Form 10-Q.
63
Item 6. Exhibits
|
|
|
Exhibit |
|
|
Number |
|
Exhibit |
2.1 *
|
|
Asset Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc., Marbob Energy
Corporation, Pitch Energy Corporation, Costaplenty Energy Corporation and John R. Gray, LLC (filed as Exhibit 2.1 to the Companys Current Report on Form 8-K on July 20, 2010, and
incorporated herein by reference). |
|
|
|
3.1
|
|
Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Companys Current Report on
Form 8-K on August 8, 2007, and incorporated herein by reference). |
|
|
|
3.2
|
|
Amended and Restated Bylaws of Concho Resources Inc., as amended March 25, 2008 (filed as Exhibit
3.1 to the Companys Current Report on Form 8-K on March 26, 2008, and incorporated herein by
reference). |
|
|
|
4.1
|
|
Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Companys Current Report on Form
S-1/A on July 5, 2007, and incorporated herein by reference). |
|
|
|
10.1
|
|
Second Amendment to Amended and Restated Credit Agreement, dated April 26, 2010, by and among
Concho Resources Inc., JP Morgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1
to the Companys Current Report on Form 8-K on April 29, 2010, and incorporated herein by
reference). |
|
|
|
10.2
|
|
Third Amendment to Amended and Restated Credit Agreement and Limited Waiver, dated June 16, 2010,
among Concho Resources Inc. and the lenders party thereto and JPMorgan Chase Bank, N.A., as
Administrative Agent (filed as Exhibit 10.1 to the Companys Current Report on Form 8-K on June
18, 2010, and incorporated herein by reference). |
|
|
|
10.3
|
|
Common Stock Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc. and the
purchasers named therein (filed as Exhibit 10.1 to the Companys Current Report on Form 8-K on
July 20, 2010, and incorporated herein by reference). |
|
|
|
23.1 (a)
|
|
Consent of Cawley, Gillespie & Associates, Inc. |
|
|
|
23.2 (a)
|
|
Cawley, Gillespie & Associates, Inc. Reserve Report. |
|
|
|
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. |
|
|
|
101.INS (a)
|
|
XBRL Instance Document. |
|
|
|
101.SCH (a)
|
|
XBRL Schema Document. |
|
|
|
101.CAL (a)
|
|
XBRL Calculation Linkbase Document. |
|
|
|
101.DEF (a)
|
|
XBRL Definition Linkbase Document. |
|
|
|
101.LAB (a)
|
|
XBRL Labels Linkbase Document. |
|
|
|
101.PRE (a)
|
|
XBRL Presentation Linkbase Document. |
|
|
|
(a) |
|
Filed herewith. |
|
(b) |
|
Furnished herewith. |
|
* |
|
The schedules to this agreement have been omitted from this filing pursuant
to Item 601(b)(2) of Regulation S-K. The Company will furnish copies of such
schedules to the Securities and Exchange Commission upon request. |
64
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
CONCHO RESOURCES INC.
|
|
Date: August 6, 2010 |
By |
/s/ Timothy A. Leach
|
|
|
|
Timothy A. Leach |
|
|
|
Director, Chairman of the Board of Directors, Chief Executive
Officer and President (Principal Executive Officer) |
|
|
|
|
|
|
By |
/s/ Darin G. Holderness
|
|
|
|
Darin G. Holderness |
|
|
|
Vice President, Chief Financial Officer and Treasurer
(Principal Financial and Accounting Officer) |
|
|
65
EXHIBIT INDEX
|
|
|
Exhibit |
|
|
Number |
|
Exhibit |
2.1 *
|
|
Asset Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc., Marbob Energy
Corporation, Pitch Energy Corporation, Costaplenty Energy Corporation and John R. Gray, LLC (filed as Exhibit 2.1 to the Companys Current Report on Form 8-K on July 20, 2010, and
incorporated herein by reference). |
|
|
|
3.1
|
|
Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Companys Current Report on
Form 8-K on August 8, 2007, and incorporated herein by reference). |
|
|
|
3.2
|
|
Amended and Restated Bylaws of Concho Resources Inc., as amended March 25, 2008 (filed as Exhibit
3.1 to the Companys Current Report on Form 8-K on March 26, 2008, and incorporated herein by
reference). |
|
|
|
4.1
|
|
Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Companys Current Report on Form
S-1/A on July 5, 2007, and incorporated herein by reference). |
|
|
|
10.1
|
|
Second Amendment to Amended and Restated Credit Agreement, dated April 26, 2010, by and among
Concho Resources Inc., JP Morgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1
to the Companys Current Report on Form 8-K on April 29, 2010, and incorporated herein by
reference). |
|
|
|
10.2
|
|
Third Amendment to Amended and Restated Credit Agreement and Limited Waiver, dated June 16, 2010,
among Concho Resources Inc. and the lenders party thereto and JPMorgan Chase Bank, N.A., as
Administrative Agent (filed as Exhibit 10.1 to the Companys Current Report on Form 8-K on June
18, 2010, and incorporated herein by reference). |
|
|
|
10.3
|
|
Common Stock Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc. and the
purchasers named therein (filed as Exhibit 10.1 to the Companys Current Report on Form 8-K on
July 20, 2010, and incorporated herein by reference). |
|
|
|
23.1 (a)
|
|
Consent of Cawley, Gillespie & Associates, Inc. |
|
|
|
23.2 (a)
|
|
Cawley, Gillespie & Associates, Inc. Reserve Report. |
|
|
|
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. |
|
|
|
101.INS (a)
|
|
XBRL Instance Document. |
|
|
|
101.SCH (a)
|
|
XBRL Schema Document. |
|
|
|
101.CAL (a)
|
|
XBRL Calculation Linkbase Document. |
|
|
|
101.DEF (a)
|
|
XBRL Definition Linkbase Document. |
|
|
|
101.LAB (a)
|
|
XBRL Labels Linkbase Document. |
|
|
|
101.PRE (a)
|
|
XBRL Presentation Linkbase Document. |
|
|
|
(a) |
|
Filed herewith. |
|
(b) |
|
Furnished herewith. |
|
* |
|
The schedules to this agreement have been omitted from this filing pursuant
to Item 601(b)(2) of Regulation S-K. The Company will furnish copies of such
schedules to the Securities and Exchange Commission upon request. |