UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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☑
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QUARTERLY REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the quarterly period ended March 31, 2015
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
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For the transition period from
to
Commission file number: 1-33615
Concho Resources Inc.
(Exact name of registrant as specified in its charter)
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Delaware
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76-0818600
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(State or other jurisdiction
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(I.R.S. Employer
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of incorporation or organization)
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Identification No.)
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One Concho Center
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600 West Illinois Avenue
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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)
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(432) 683-7443
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(Registrant’s telephone number, including area code)
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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 ☑
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 ☑ 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.
Large
accelerated filer ☑
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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
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Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes o No ☑
Number of shares of the registrant’s common stock outstanding at May 1,
2015: 120,012,851 shares
TABLE
OF CONTENTS
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PART I – FINANCIAL INFORMATION:
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iii
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Item 1. Consolidated
Financial Statements (Unaudited)
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iii
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Item 2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations
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27
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Item 3. Quantitative
and Qualitative Disclosures About Market Risk
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42
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Item 4. Controls and
Procedures
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44
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PART II – OTHER INFORMATION:
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45
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Item 1. Legal
Proceedings
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45
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Item 1A. Risk
Factors
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45
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Item 2. Unregistered
Sales of Equity Securities and Use of Proceeds
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45
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Item 6. Exhibits
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46
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CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Various
statements and information contained in or incorporated by reference into this
Quarterly Report on Form 10-Q (this “Quarterly 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 potential financing.
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 and
their potential effect on us. 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 any forward-looking
statements. These forward-looking statements speak only as of the date of this
Quarterly Report, or if earlier, as of the date they were made. We disclaim any
obligation to update or revise these statements unless required by 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,
2014, as well as those factors summarized below:
·
declines
in the prices we receive for our oil and natural gas;
·
uncertainties
about the estimated quantities of oil and natural gas reserves;
·
drilling
and operating risks, including risks related to properties where we do not
serve as the operator and risks related to hydraulic fracturing activities;
·
the
adequacy of our capital resources and liquidity including, but not limited to,
access to additional borrowing capacity under our credit facility;
·
the
effects of government regulation, permitting and other legal requirements,
including new legislation or regulation of hydraulic fracturing and the export
of oil and natural gas;
·
environmental
hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids,
toxic gas or other pollution into the environment, including groundwater
contamination;
·
difficult
and adverse conditions in the domestic and global capital and credit markets;
·
risks
related to the concentration of our operations in the Permian Basin of
Southeast New Mexico and West Texas;
·
disruptions
to, capacity constraints in or other limitations on the pipeline systems that
deliver our oil, natural gas liquids and natural gas and other processing and
transportation considerations;
·
shortages
of oilfield equipment, supplies, water, services and qualified personnel and
increased costs for such equipment, supplies, services and personnel;
·
potential
financial losses or earnings reductions from our commodity price management
program;
·
risks
and liabilities associated with acquired properties or businesses;
·
uncertainties
about our ability to successfully execute our business and financial plans and
strategies;
·
uncertainties
about our ability to replace reserves and economically develop our current
reserves;
·
general
economic and business conditions, either internationally or domestically;
·
competition
in the oil and natural gas industry; and
·
uncertainty
concerning our assumed or possible future results of operations.
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.
PART I –
FINANCIAL INFORMATION
Item 1. Consolidated Financial
Statements (Unaudited)
Consolidated
Balance Sheets at March 31, 2015 and December 31, 2014
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1
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Consolidated
Statements of Operations for the Three Months Ended March 31, 2015 and 2014
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2
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Consolidated
Statement of Stockholders’ Equity for the Three Months Ended March
31, 2015
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3
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Consolidated
Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014
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4
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Condensed
Notes to Consolidated Financial Statements
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5
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Concho
Resources Inc.
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Consolidated Balance Sheets
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Unaudited
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March 31,
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December 31,
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(in thousands, except share and per share amounts)
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2015
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2014
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Assets
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Current assets:
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Cash and cash equivalents
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$
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21
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$
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21
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Accounts receivable, net of allowance for doubtful
accounts:
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Oil and natural gas
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219,486
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250,600
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Joint operations and other
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401,425
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409,665
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Derivative instruments
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495,803
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490,351
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Prepaid costs and other
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37,541
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37,759
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Total current assets
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1,154,276
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1,188,396
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Property and equipment:
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Oil and natural gas properties, successful efforts method
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14,609,006
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13,867,831
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Accumulated depletion and depreciation
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(4,053,199)
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(3,790,953)
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Total oil and natural gas properties, net
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10,555,807
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10,076,878
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Other property and equipment, net
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132,778
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129,136
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Total property and equipment, net
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10,688,585
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10,206,014
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Deferred loan costs, net
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65,980
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68,443
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Intangible asset - operating rights, net
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26,789
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27,154
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Inventory
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14,352
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14,435
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Noncurrent derivative instruments
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205,250
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262,349
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Other assets
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51,914
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33,172
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Total assets
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$
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12,207,146
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$
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11,799,963
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Liabilities and Stockholders’ Equity
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Current liabilities:
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Accounts payable - trade
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$
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23,573
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$
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20,380
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Bank overdrafts
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19,002
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92,541
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Revenue payable
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160,993
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238,098
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Accrued and prepaid drilling costs
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665,922
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718,300
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Deferred income taxes
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166,447
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162,566
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Other current liabilities
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188,840
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195,308
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Total current liabilities
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1,224,777
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1,427,193
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Long-term debt
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3,377,147
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3,517,320
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Deferred income taxes
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1,423,273
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1,438,185
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Noncurrent derivative instruments
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168
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-
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Asset retirement obligations and other long-term
liabilities
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139,432
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136,477
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Commitments and contingencies (Note 9)
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Stockholders’ equity:
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Common stock, $0.001 par value; 300,000,000
authorized; 120,304,465 and
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113,264,918 shares issued at March 31, 2015 and December
31, 2014, respectively
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120
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113
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Additional paid-in capital
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3,784,605
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3,027,412
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Retained earnings
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2,287,253
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2,279,741
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Treasury stock, at cost; 289,069 and 260,124 shares at
March 31, 2015 and
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December 31, 2014, respectively
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(29,629)
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(26,478)
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Total stockholders’ equity
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6,042,349
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5,280,788
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Total liabilities and stockholders’ equity
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$
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12,207,146
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$
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11,799,963
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The accompanying notes are an integral
part of these consolidated financial statements.
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Concho Resources Inc.
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Consolidated Statements of Operations
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Unaudited
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Three Months Ended
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March 31,
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(in thousands, except per share amounts)
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2015
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2014
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Operating revenues:
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Oil sales
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$
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349,584
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$
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539,857
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Natural gas sales
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63,938
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121,102
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Total operating revenues
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413,522
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|
660,959
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Operating costs and expenses:
|
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Oil and natural gas production
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125,535
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126,924
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Exploration and abandonments
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5,755
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25,375
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Depreciation, depletion and amortization
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267,205
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221,392
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Accretion of discount on asset retirement obligations
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|
|
1,994
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|
|
1,671
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General and administrative (including non-cash stock-based
compensation of $15,495 and
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|
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|
|
|
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$11,432 for the three months ended March 31, 2015 and
2014, respectively)
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|
58,801
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|
|
47,750
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(Gain) loss on derivatives not designated as hedges
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(115,340)
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35,615
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Total operating costs and expenses
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|
343,950
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|
458,727
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Income from operations
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69,572
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202,232
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Other income (expense):
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Interest expense
|
|
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(53,569)
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|
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(56,135)
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Other, net
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|
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(4,341)
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|
|
541
|
|
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Total other expense
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|
|
(57,910)
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|
|
(55,594)
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Income before income taxes
|
|
|
11,662
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|
|
146,638
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Income tax expense
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|
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(4,150)
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(55,331)
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Net income
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|
$
|
7,512
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|
$
|
91,307
|
Earnings per share:
|
|
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|
|
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|
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Basic net income
|
|
$
|
0.07
|
|
$
|
0.87
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Diluted net income
|
|
$
|
0.06
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|
$
|
0.87
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|
|
|
|
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The accompanying notes are an integral
part of these consolidated financial statements.
|
Concho
Resources Inc.
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Consolidated Statement of Stockholders’
Equity
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Unaudited
|
|
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|
|
|
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Additional
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Total
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|
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Common Stock Issued
|
|
|
Paid-in
|
|
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Retained
|
|
Treasury Stock
|
|
Stockholders’
|
(in thousands)
|
|
Shares
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Amount
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Capital
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Earnings
|
|
Shares
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Amount
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|
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Equity
|
BALANCE AT DECEMBER 31, 2014
|
|
113,265
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|
$
|
113
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|
$
|
3,027,412
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|
$
|
2,279,741
|
|
260
|
|
$
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(26,478)
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|
$
|
5,280,788
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|
Net income
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|
-
|
|
|
-
|
|
|
-
|
|
|
7,512
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|
-
|
|
|
-
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|
|
7,512
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Issuance of common stock
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|
6,900
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|
|
7
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|
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741,177
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|
|
-
|
|
-
|
|
|
-
|
|
|
741,184
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|
Stock options exercised
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|
4
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|
|
-
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|
|
57
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|
|
-
|
|
-
|
|
|
-
|
|
|
57
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|
Grants of restricted stock
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|
140
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|
|
-
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
Cancellation of restricted stock
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|
(5)
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|
|
-
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
Stock-based compensation
|
|
-
|
|
|
-
|
|
|
15,495
|
|
|
-
|
|
-
|
|
|
-
|
|
|
15,495
|
|
Excess tax benefits related to stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation
|
|
-
|
|
|
-
|
|
|
464
|
|
|
-
|
|
-
|
|
|
-
|
|
|
464
|
|
Purchase of treasury stock
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
29
|
|
|
(3,151)
|
|
|
(3,151)
|
BALANCE AT MARCH 31, 2015
|
|
120,304
|
|
$
|
120
|
|
$
|
3,784,605
|
|
$
|
2,287,253
|
|
289
|
|
$
|
(29,629)
|
|
$
|
6,042,349
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral
part of these consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
Concho
Resources Inc.
|
Consolidated Statements of Cash Flows
|
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
(in thousands)
|
|
2015
|
|
2014
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
Net income
|
|
$
|
7,512
|
|
$
|
91,307
|
|
Adjustments to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
267,205
|
|
|
221,392
|
|
|
Accretion of discount on asset retirement obligations
|
|
|
1,994
|
|
|
1,671
|
|
|
Exploration and abandonments, including dry holes
|
|
|
2,700
|
|
|
23,759
|
|
|
Non-cash stock-based compensation expense
|
|
|
15,495
|
|
|
11,432
|
|
|
Deferred income taxes
|
|
|
(11,031)
|
|
|
41,954
|
|
|
(Gain) loss on disposition of assets, net
|
|
|
39
|
|
|
(146)
|
|
|
(Gain) loss on derivatives not designated as hedges
|
|
|
(115,340)
|
|
|
35,615
|
|
|
Other non-cash items
|
|
|
2,612
|
|
|
2,710
|
|
Changes in operating assets and liabilities, net of acquisitions and
dispositions:
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
35,731
|
|
|
(10,139)
|
|
|
|
Prepaid costs and other
|
|
|
649
|
|
|
21
|
|
|
|
Inventory
|
|
|
3
|
|
|
1,126
|
|
|
|
Accounts payable
|
|
|
3,119
|
|
|
20,087
|
|
|
|
Revenue payable
|
|
|
(77,105)
|
|
|
21,675
|
|
|
|
Other current liabilities
|
|
|
(7,334)
|
|
|
13,516
|
|
|
|
|
Net cash provided by operating activities
|
|
|
126,249
|
|
|
475,980
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Capital expenditures on oil and natural gas properties
|
|
|
(790,773)
|
|
|
(554,266)
|
|
Additions to property, equipment and other assets
|
|
|
(8,147)
|
|
|
(5,617)
|
|
Proceeds from the disposition of assets
|
|
|
-
|
|
|
24
|
|
Contribution to equity method investment
|
|
|
(20,000)
|
|
|
-
|
|
Settlements received from (paid on) derivatives not designated as
hedges
|
|
|
167,156
|
|
|
(14,837)
|
|
|
|
|
Net cash used in investing activities
|
|
|
(651,764)
|
|
|
(574,696)
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
Proceeds from issuance of debt
|
|
|
739,000
|
|
|
593,400
|
|
Payments of debt
|
|
|
(878,500)
|
|
|
(548,750)
|
|
Exercise of stock options
|
|
|
57
|
|
|
1,254
|
|
Excess tax benefit from stock-based compensation
|
|
|
464
|
|
|
2,993
|
|
Net proceeds from issuance of common stock
|
|
|
741,184
|
|
|
-
|
|
Purchase of treasury stock
|
|
|
(3,151)
|
|
|
(3,748)
|
|
Increase (decrease) in bank overdrafts
|
|
|
(73,539)
|
|
|
53,567
|
|
|
|
|
Net cash provided by financing activities
|
|
|
525,515
|
|
|
98,716
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
-
|
|
|
-
|
Cash and cash equivalents at beginning of period
|
|
|
21
|
|
|
21
|
Cash and cash equivalents at end of period
|
|
$
|
21
|
|
$
|
21
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Note 1. Organization and nature of operations
Concho Resources Inc. (the “Company”) is a Delaware
corporation formed on February 22, 2006. The Company’s principal business
is the acquisition, development and exploration of oil and natural gas
properties primarily located in the Permian Basin region of Southeast New
Mexico and West Texas.
Note 2. Summary
of significant accounting policies
Principles
of consolidation. The
consolidated financial statements of the Company include the accounts of the
Company and its 100 percent owned subsidiaries. The Company consolidates the
financial statements of these entities. All material intercompany balances and
transactions have been eliminated.
Use of
estimates in the preparation of financial statements. Preparation of financial statements in conformity
with generally accepted accounting principles in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, the disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting periods. Actual results could differ
from these estimates. Depletion of oil and natural gas properties 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, the asset
retirement obligations, fair value of derivative financial instruments, the fair
value of business combinations, fair value of stock-based compensation and
income taxes.
Interim
financial statements. The
accompanying consolidated financial statements of the Company have not been
audited by the Company’s independent registered public accounting firm, except
that the consolidated balance sheet at December 31, 2014 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 Company’s consolidated financial statements.
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 in or omitted from
these consolidated financial statements. Accordingly, these condensed consolidated
financial statements should be read in conjunction with the audited
consolidated financial statements and notes included in the Company’s Annual
Report on Form 10-K for the year ended December 31, 2014.
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 $66.0 million and $68.4 million, net of accumulated
amortization of $62.1 million and $59.7 million, at March 31, 2015 and December
31, 2014, respectively.
Equity
method investment. The Company
owns a 50 percent member interest in a midstream joint venture, Alpha Crude
Connector, LLC (“ACC”), to construct a crude oil gathering and transportation
system in the northern Delaware Basin. The Company accounts for its investment
in ACC under the equity method of accounting for investments in unconsolidated
affiliates. The Company’s net investment in ACC is $49.3 million at March 31,
2015 and is included in other assets in the Company’s consolidated balance
sheet. The equity loss for the three months ended March 31, 2015 is
approximately $0.8 million and is included in other expense in the Company’s
consolidated statement of operations. During the three months ended March 31,
2015, the Company recorded $0.6 million of capitalized interest on its investment
in ACC.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Revenue recognition. Oil and natural gas revenues are recorded at the time of physical
transfer of such products to the purchaser, which for the Company is primarily
at the wellhead. The Company follows the sales method of accounting for oil and
natural gas sales, recognizing revenues based on the Company’s actual proceeds
from the oil and natural gas sold to purchasers.
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 $6.4 million and $5.1 million for the three months ended
March 31, 2015 and 2014, respectively.
Recent
accounting pronouncements. In
April 2015, the Financial Accounting Standards Board (the “FASB”) issued ASU
No. 2015-03, “Interest–Imputation of Interest (Subtopic 835-30),” that
requires debt issuance costs related to a recognized debt liability be
presented as a direct deduction from the carrying amount of that debt
liability. The Company currently presents debt issuance costs on the balance
sheet as an asset. The new standard does not impact current recognition or
measurement guidance for debt issuance costs.
An entity is required to apply ASU
2015-03 for fiscal years beginning after December 15, 2015, and interim periods
within those fiscal years. Early adoption of the new standard is permitted. The
Company is evaluating the impact that this new guidance will have on its
balance sheet presentation of debt issuance costs.
In May 2014, the FASB issued ASU
No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” that
outlines a new, single comprehensive model for entities to use in accounting
for revenue arising from contracts with customers and supersedes most current
revenue recognition guidance, including industry-specific guidance. This new
revenue recognition model provides a five-step analysis in determining when and
how revenue is recognized. The new model will require revenue recognition to
depict the transfer of promised goods or services to customers in an amount
that reflects the consideration a company expects to receive in exchange for
those goods or services.
An entity is required to apply ASU
2014-09 for annual reporting periods beginning after December 15, 2016, and
interim periods within those annual periods. An entity can apply ASU 2014-09
using either a full retrospective method, meaning the standard is applied to
all of the periods presented, or a modified retrospective method, meaning the
cumulative effect of initially applying the standard is recognized in the most
current period presented in the financial statements. The Company is evaluating
the impact that this new guidance will have on its consolidated financial
statements.
Note 3. 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. After an exploratory well has been completed and found oil and
natural gas reserves, a determination may be pending as to whether the oil and
natural reserves can be classified as proved. In those circumstances, the
Company continues to capitalize the well or project costs pending the
determination of proved status if (i) the well has found a sufficient quantity
of reserves to justify its completion as a producing well and (ii) the Company
is making sufficient progress assessing the reserves and the economic and
operating viability of the project. The capitalized exploratory
well costs are carried in unproved oil and natural gas properties. See Note 16
for the proved and unproved components of oil and natural gas properties. If
the exploratory well is determined to be impaired, the well costs are charged
to exploration and abandonments expense in the consolidated statements of
operations.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
The following table reflects the Company’s net capitalized
exploratory well activity during the three months ended March 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
(in thousands)
|
|
|
March 31, 2015
|
|
|
|
|
|
|
|
|
Beginning capitalized exploratory well costs
|
|
|
|
|
$
|
241,657
|
|
Additions to exploratory well costs pending the determination of
proved reserves
|
|
|
|
|
|
171,806
|
|
Reclassifications due to determination of proved reserves
|
|
|
|
|
|
(167,768)
|
|
Exploratory well costs charged to expense
|
|
|
|
|
|
(559)
|
Ending capitalized exploratory well costs
|
|
|
|
|
$
|
245,136
|
|
|
|
|
|
|
|
|
The following table provides an aging at March 31, 2015 and
December 31, 2014 of capitalized exploratory well costs based on the date
drilling was completed:
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
(dollars in thousands)
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
Capitalized exploratory well costs that have been
capitalized for a period of one year or less
|
|
$
|
234,983
|
|
$
|
232,346
|
Capitalized exploratory well costs that have been
capitalized for a period greater than one year
|
|
|
10,153
|
|
|
9,311
|
|
Total capitalized exploratory well costs
|
|
$
|
245,136
|
|
$
|
241,657
|
Number of projects with exploratory well costs that have
been capitalized for a period greater
|
|
|
|
|
|
|
|
than one year
|
|
|
5
|
|
|
7
|
|
|
|
|
|
|
|
|
Delaware Basin project. At March 31,
2015, the Company had approximately $4.5 million of
suspended well costs greater than one year recorded for a well that was
initially drilled to monitor nearby wells but is now undergoing tests to
determine commercial production capability.
Projects operated by others. At March 31, 2015, the Company had approximately $5.7 million of suspended
well costs greater than one year recorded for four wells that are operated by
others and waiting on completion.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Note 4. Asset retirement obligations
The
Company's asset retirement obligations primarily relate to the future plugging
and abandonment of wells and facilities. The following table summarizes the
Company's asset retirement obligation activity during the three months ended March 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
(in thousands)
|
|
|
March 31, 2015
|
|
|
|
|
|
|
|
|
Asset retirement obligations, beginning of period
|
|
|
|
|
$
|
119,881
|
|
Liabilities incurred from new wells
|
|
|
|
|
|
1,779
|
|
Accretion expense
|
|
|
|
|
|
1,994
|
|
Liabilities settled upon plugging and abandoning wells
|
|
|
|
|
|
(1,078)
|
|
Revision of estimates
|
|
|
|
|
|
(196)
|
Asset retirement obligations, end of period
|
|
|
|
|
$
|
122,380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 5.
Stock incentive plan
The Company’s 2006 Stock Incentive Plan, as amended and
restated, provides for granting stock options, restricted stock awards and
performance awards to directors, officers and employees of the Company.
A summary of
the Company’s activity for the three months ended March 31, 2015 is presented
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted
|
|
Stock
|
|
Performance
|
|
|
|
|
Stock
|
|
Options
|
|
Units
|
|
Outstanding at December 31, 2014
|
|
|
1,091,309
|
|
|
47,713
|
|
|
250,314
|
|
|
Awards granted (a)
|
|
|
139,556
|
|
|
-
|
|
|
176,330
|
|
|
Options exercised
|
|
|
-
|
|
|
(4,812)
|
|
|
-
|
|
|
Awards cancelled / forfeited
|
|
|
(4,821)
|
|
|
-
|
|
|
-
|
|
|
Lapse of restrictions
|
|
|
(109,630)
|
|
|
-
|
|
|
-
|
|
Outstanding at March 31, 2015
|
|
1,116,414
|
|
42,901
|
|
426,644
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Weighted average grant date fair value per share
|
|
$
|
101.58
|
|
$
|
-
|
|
$
|
156.86
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
The following table reflects the future stock-based
compensation expense to be recorded for all the stock-based compensation awards
that were outstanding at March 31, 2015:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
Remaining 2015
|
|
$
|
42,195
|
2016
|
|
|
38,043
|
2017
|
|
|
18,300
|
2018
|
|
|
1,887
|
2019
|
|
|
71
|
Thereafter
|
|
|
-
|
|
Total
|
|
$
|
100,496
|
|
|
|
|
|
Note 6. Disclosures
about fair value measurements
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 company’s 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,
collars and floors, investments and interest rate swaps. The Company’s
valuation models are primarily industry-standard models that consider various
inputs including: (i) quoted forward prices for commodities,
(ii) time value, (iii) current market and contractual prices for the
underlying instruments and (iv) volatility factors, as well as other relevant
economic measures.
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). The Company’s 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.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Financial Assets and Liabilities Measured at Fair Value
The
following table presents the carrying amounts and fair values of the Company’s
financial instruments at March 31, 2015 and December 31, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2015
|
|
December 31, 2014
|
|
|
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
Fair
|
(in thousands)
|
|
Value
|
|
Value
|
|
Value
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
$
|
701,053
|
|
$
|
701,053
|
|
$
|
752,700
|
|
$
|
752,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
$
|
168
|
|
$
|
168
|
|
$
|
-
|
|
$
|
-
|
|
|
Credit facility
|
|
$
|
-
|
|
$
|
-
|
|
$
|
139,500
|
|
$
|
131,068
|
|
|
7.0% senior notes due 2021
|
|
$
|
600,000
|
|
$
|
628,500
|
|
$
|
600,000
|
|
$
|
625,500
|
|
|
6.5% senior notes due 2022
|
|
$
|
600,000
|
|
$
|
630,000
|
|
$
|
600,000
|
|
$
|
628,500
|
|
|
5.5% senior notes due 2022
|
|
$
|
600,000
|
|
$
|
603,000
|
|
$
|
600,000
|
|
$
|
598,500
|
|
|
5.5% senior notes due 2023
|
|
$
|
1,577,147
|
|
$
|
1,592,761
|
|
$
|
1,577,820
|
|
$
|
1,573,875
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Company’s credit facility is estimated by discounting the
principal and interest payments at the Company’s credit-adjusted discount rate
at the reporting date, which utilizes inputs that are Level 2 measurements in
the fair value hierarchy.
Senior notes. The
fair values of the Company’s senior notes are based on quoted market prices. The
debt securities are not actively traded and, therefore, are classified as
Level 2 in the fair value hierarchy.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Derivative instruments. The fair value of the Company’s derivative
instruments is 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 Company’s 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 summarize (i) the valuation of each of the Company’s financial
instruments by required fair value hierarchy levels and (ii) 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 Company’s consolidated balance sheets at March 31, 2015 and
December 31, 2014. The Company nets the fair value of derivative instruments by
counterparty in the Company’s consolidated balance sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2015
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Quoted Prices
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Fair Value
|
|
|
|
|
|
in Active
|
|
|
Significant
|
|
|
|
|
|
|
|
|
Amounts
|
|
|
Presented
|
|
|
|
|
|
Markets for
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
Offset in the
|
|
|
in the
|
|
|
|
|
|
Identical
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
|
Consolidated
|
|
|
Consolidated
|
|
|
|
|
|
Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Total
|
|
|
Balance
|
|
|
Balance
|
(in thousands)
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Fair Value
|
|
|
Sheet
|
|
|
Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
-
|
|
$
|
527,500
|
|
$
|
-
|
|
$
|
527,500
|
|
$
|
(31,697)
|
|
$
|
495,803
|
|
|
Noncurrent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
207,937
|
|
|
-
|
|
|
207,937
|
|
|
(2,687)
|
|
|
205,250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
(31,697)
|
|
|
-
|
|
|
(31,697)
|
|
|
31,697
|
|
|
-
|
|
|
Noncurrent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
(2,855)
|
|
|
-
|
|
|
(2,855)
|
|
|
2,687
|
|
|
(168)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative instruments
|
|
$
|
-
|
|
$
|
700,885
|
|
$
|
-
|
|
$
|
700,885
|
|
$
|
-
|
|
$
|
700,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Quoted Prices
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Fair Value
|
|
|
|
|
|
in Active
|
|
|
Significant
|
|
|
|
|
|
|
|
|
Amounts
|
|
|
Presented
|
|
|
|
|
|
Markets for
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
Offset in the
|
|
|
in the
|
|
|
|
|
|
Identical
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
|
Consolidated
|
|
|
Consolidated
|
|
|
|
|
|
Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Total
|
|
|
Balance
|
|
|
Balance
|
(in thousands)
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Fair Value
|
|
|
Sheet
|
|
|
Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
-
|
|
$
|
501,717
|
|
$
|
-
|
|
$
|
501,717
|
|
$
|
(11,366)
|
|
$
|
490,351
|
|
|
Noncurrent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
262,349
|
|
|
-
|
|
|
262,349
|
|
|
-
|
|
|
262,349
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
(11,366)
|
|
|
-
|
|
|
(11,366)
|
|
|
11,366
|
|
|
-
|
|
|
Noncurrent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative instruments
|
|
$
|
-
|
|
$
|
752,700
|
|
$
|
-
|
|
$
|
752,700
|
|
$
|
-
|
|
$
|
752,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concentrations
of credit risk. At March 31, 2015,
the Company’s primary concentration of credit risks are the risk of collecting
accounts receivable and the risk of counterparties’ failure to perform under
derivative obligations.
The Company has entered into International Swap Dealers
Association Master Agreements (“ISDA Agreements”) with each of its derivative
counterparties. The terms of the ISDA Agreements provide the Company and the
counterparties with rights of set off upon the occurrence of defined acts of
default by either the Company or a counterparty to a derivative, whereby the
party not in default may set off all derivative liabilities owed to the
defaulting party against all derivative asset receivables from the defaulting
party. See Note 7 for additional information regarding the Company's derivative
activities.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
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 Company’s 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, for instance when there are declines in commodity prices or well
performance. 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 this circumstance, the Company recognizes an impairment loss for the
amount by which the carrying amount of the asset exceeds the estimated fair
value of the asset. The Company reviews its oil and natural gas properties by
depletion base or by individual well for those wells not constituting part of a
depletion 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 of the properties would be recognized at that time.
It
is reasonably possible that the estimate of undiscounted future net cash flows
may change in the future resulting in the need to impair carrying values. The
primary factors that may affect estimates of future cash flows are
(i) commodity futures prices, (ii) increases or decreases in
production and capital costs, (iii) future reserve adjustments, both positive
and negative, to proved reserves and appropriate risk-adjusted probable and
possible reserves and (iv) results of future drilling activities.
Additionally, based on the factors above as of March 31,
2015, the Company determined that undiscounted future cash flows attributable
to certain depletion groups indicated that their carrying amounts were expected
to be recovered; however, they may be at risk for impairment if management’s
estimates of future cash flows further decline.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Note 7. Derivative financial instruments
The Company uses derivative financial instruments to manage
its exposure to commodity price fluctuations. Commodity derivative instruments
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
Company’s capital budget and expenditure plans and (iii) support the economics
associated with acquisitions. The Company does not enter into derivative
financial instruments for speculative or trading purposes. The Company may also
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 Company’s consolidated financial
statements.
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 as
they occur.
The following
table summarizes the gains (losses) reported in earnings related to the
commodity derivative instruments for the three months ended March 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
March 31,
|
|
(in thousands)
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as hedges:
|
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
110,280
|
|
$
|
(24,220)
|
|
|
Natural gas derivatives
|
|
|
5,060
|
|
|
(11,395)
|
|
|
|
Total
|
|
$
|
115,340
|
|
$
|
(35,615)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table
represents the Company's cash receipts from (payments on) derivatives for the
three months ended March 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
March 31,
|
|
(in thousands)
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
Cash receipts from (payments on) derivatives not
designated as hedges:
|
|
|
|
|
|
Oil derivatives
|
|
$
|
160,186
|
|
$
|
(9,769)
|
|
|
Natural gas derivatives
|
|
|
6,970
|
|
|
(5,068)
|
|
|
|
Total
|
|
$
|
167,156
|
|
$
|
(14,837)
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Commodity derivative
contracts at March 31, 2015. The following table sets forth the
Company’s outstanding derivative contracts at March 31, 2015. When
aggregating multiple contracts, the weighted average contract price is
disclosed. All of the Company’s derivative contracts at March 31, 2015 are expected to settle by June 30, 2017.
|
|
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
|
|
|
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Total
|
Oil Swaps: (a)
|
|
|
|
|
|
|
|
|
|
|
|
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
4,579,000
|
|
4,314,000
|
|
4,109,000
|
|
13,002,000
|
|
|
Price per Bbl
|
|
|
$
|
83.05
|
$
|
82.83
|
$
|
82.47
|
$
|
82.79
|
|
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
3,398,000
|
|
3,248,000
|
|
3,138,000
|
|
2,715,000
|
|
12,499,000
|
|
|
Price per Bbl
|
$
|
88.87
|
$
|
89.24
|
$
|
88.77
|
$
|
63.48
|
$
|
83.43
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
84,000
|
|
84,000
|
|
-
|
|
-
|
|
168,000
|
|
|
Price per Bbl
|
$
|
87.00
|
$
|
87.00
|
$
|
-
|
$
|
-
|
$
|
87.00
|
Oil Basis Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
4,200,500
|
|
4,002,000
|
|
3,772,000
|
|
11,974,500
|
|
|
Price per Bbl
|
|
|
$
|
(3.32)
|
$
|
(3.30)
|
$
|
(3.24)
|
$
|
(3.29)
|
|
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
2,639,000
|
|
2,639,000
|
|
2,668,000
|
|
2,668,000
|
|
10,614,000
|
|
|
Price per Bbl
|
$
|
(2.31)
|
$
|
(2.31)
|
$
|
(2.31)
|
$
|
(2.31)
|
$
|
(2.31)
|
Natural Gas Swaps: (c)
|
|
|
|
|
|
|
|
|
|
|
|
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
|
5,915,000
|
|
5,980,000
|
|
5,980,000
|
|
17,875,000
|
|
|
Price per MMBtu
|
|
|
$
|
4.16
|
$
|
4.16
|
$
|
4.16
|
$
|
4.16
|
Natural Gas Basis Swaps: (d)
|
|
|
|
|
|
|
|
|
|
|
|
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
|
1,365,000
|
|
1,380,000
|
|
1,380,000
|
|
4,125,000
|
|
|
Price per MMBtu
|
|
|
$
|
(0.13)
|
|
(0.13)
|
$
|
(0.13)
|
$
|
(0.13)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) The index prices for the oil price swaps are based on
the New York Mercantile Exchange (“NYMEX”) – West Texas Intermediate
|
|
(“WTI”) monthly average futures price.
|
(b) The basis differential price is between Midland – WTI
and Cushing – WTI.
|
(c) The index prices for the natural gas price swaps are
based on the NYMEX – Henry Hub last trading day futures price.
|
(d) The basis differential price is between the El Paso
Permian delivery point and NYMEX – Henry Hub delivery point.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative counterparties. The Company uses credit and other
financial criteria to evaluate the credit worthiness of counterparties to its
derivative instruments. The Company believes that all of its derivative
counterparties are currently acceptable credit risks. Other than provided by
the Company’s revolving credit facility, the Company is not required to provide
credit support or collateral to any counterparties under its derivative
contracts, nor are they required to provide credit support to the Company.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
At March 31, 2015, the Company had a net asset position of
$700.9 million as a result of outstanding derivative contracts
which are reflected in the accompanying consolidated balance sheets. The
Company assessed this balance for concentration risk and noted balances of
approximately $113.4 million, $85.3 million, $81.3 million and $73.7 million
with J.P. Morgan Chase Bank,
Wells Fargo Bank, N.A., Barclays Bank PLC and Citibank, N.A., respectively.
Note 8. Debt
The Company’s
debt consisted of the following at March 31, 2015 and December 31, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
(in thousands)
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
Credit facility
|
|
$
|
-
|
|
$
|
139,500
|
7.0% unsecured senior notes due 2021
|
|
|
600,000
|
|
|
600,000
|
6.5% unsecured senior notes due 2022
|
|
|
600,000
|
|
|
600,000
|
5.5% unsecured senior notes due 2022
|
|
|
600,000
|
|
|
600,000
|
5.5% unsecured senior notes due 2023
|
|
|
1,550,000
|
|
|
1,550,000
|
Unamortized original issue premium, net
|
|
|
27,147
|
|
|
27,820
|
|
Less: current portion
|
|
|
-
|
|
|
-
|
|
|
Total long-term debt
|
|
$
|
3,377,147
|
|
$
|
3,517,320
|
|
|
|
|
|
|
|
|
|
Credit
facility. The
Company’s credit facility, as amended and restated, has a maturity date of May
9, 2019. In April 2015, the Company amended its credit agreement, which removed
the current ratio financial covenant and reaffirmed its borrowing base of $3.25 billion.
At March 31, 2015, commitments
from the Company’s bank group totaled $2.5 billion.
Senior notes.
Interest on the Company’s senior notes is paid in arrears semi-annually. The
senior notes are fully and unconditionally guaranteed on a senior unsecured
basis by all subsidiaries of the Company, subject to customary release
provisions as described in Note 14.
At March 31, 2015, the Company was in compliance with the covenants under
all of its debt instruments.
Principal
maturities of long-term debt. Principal maturities of long-term debt outstanding at March
31, 2015 were as follows:
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
Remaining 2015
|
|
$
|
|
-
|
2016
|
|
|
|
-
|
2017
|
|
|
|
-
|
2018
|
|
|
|
-
|
2019
|
|
|
|
-
|
2020
|
|
|
|
-
|
Thereafter
|
|
|
|
3,350,000
|
|
Total
|
$
|
|
3,350,000
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Interest expense.
The following amounts have been incurred and charged to interest expense for
the three
months ended March 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
(in thousands)
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments for interest
|
|
$
|
46,007
|
|
$
|
44,320
|
Amortization of original issue premium
|
|
|
(673)
|
|
|
(637)
|
Amortization of deferred loan origination costs
|
|
|
2,463
|
|
|
3,347
|
Net changes in accruals
|
|
|
6,982
|
|
|
9,105
|
|
Interest costs incurred
|
|
|
54,779
|
|
|
56,135
|
Less: capitalized interest
|
|
|
(1,210)
|
|
|
-
|
|
Total interest expense
|
|
$
|
53,569
|
|
$
|
56,135
|
|
|
|
|
|
|
|
|
|
|
|
Note 9. 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 Company’s officers covered under
such agreements total approximately $7.9 million.
Indemnifications.
The Company has agreed to indemnify its
directors and officers with respect to claims and damages arising from certain
acts or omissions taken in such capacity.
Legal actions.
The Company is a party to proceedings and
claims incidental to its business. While many of these matters involve inherent
uncertainty, the Company believes that the amount of the liability, if any,
ultimately incurred with respect to any such proceedings or claims will not
have a material adverse effect on the Company’s 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 regular basis and will establish and adjust any
reserves as appropriate to reflect its assessment of the then current status of
the matters.
Severance tax, royalty and joint interest
audits. The Company is subject to routine severance, royalty and joint
interest audits from regulatory bodies and non-operators and makes accruals as
necessary for estimated exposure when deemed probable and estimable. Additionally, the Company is subject
to various possible contingencies that arise primarily from interpretations
affecting the oil and natural gas industry. Such contingencies include
differing interpretations as to the prices at which oil and natural gas sales
may be made, the prices at which royalty owners may be paid for production from
their leases, allowable costs under joint interest arrangements and other matters. At
March 31, 2015
and December 31, 2014, the Company
had $12.5 million and $12.3 million accrued for estimated exposure,
respectively. Although the
Company believes that it has estimated its exposure with respect to the various
laws and regulations, administrative rulings and interpretations thereof,
adjustments could be required as new interpretations and regulations are
issued.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Commitments. The Company periodically enters into contractual
arrangements under which the Company is committed to expend funds. These
contractual arrangements relate to purchase agreements the Company has entered
into including daywork drilling contracts, water commitment agreements,
throughput volume delivery commitments and power commitments. The following table summarizes the
Company’s commitments at March 31, 2015:
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
Remaining 2015
|
|
$
|
42,201
|
2016
|
|
|
36,609
|
2017
|
|
|
17,210
|
2018
|
|
|
21,182
|
2019
|
|
|
10,040
|
2020
|
|
|
3,550
|
Thereafter
|
|
|
28,530
|
|
Total
|
$
|
159,322
|
|
|
|
|
|
Operating
leases. The Company leases
vehicles, equipment and office facilities under non-cancellable operating
leases. Lease payments associated with these operating leases for the three months ended March 31, 2015 and 2014
were approximately $1.9 million and $1.7 million, respectively.
Future
minimum lease commitments under non-cancellable operating leases at March 31, 2015 were as
follows:
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
Remaining 2015
|
|
$
|
5,460
|
2016
|
|
|
5,889
|
2017
|
|
|
5,861
|
2018
|
|
|
5,040
|
2019
|
|
|
4,227
|
2020
|
|
|
4,259
|
Thereafter
|
|
|
4,687
|
|
Total
|
$
|
35,423
|
|
|
|
|
|
Note 10.
Income taxes
The effective income tax rates were 35.6 percent
and 37.7 percent for the three months ended March 31, 2015 and 2014,
respectively. Total income tax expense for the three months ended March 31, 2015
and 2014 differed from amounts computed by applying the U.S. federal statutory
tax rates to pre-tax income due primarily to state taxes and the impact of
permanent differences between book and taxable income.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Note 11. Related
party transactions
The
following table summarizes charges incurred with and payments made to related
parties and reported in the Company’s consolidated statements of operations for
the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
(in thousands)
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
Amounts paid to a partnership in which a director has an ownership
interest (a)
|
|
$
|
1,694
|
|
$
|
2,802
|
|
|
|
|
|
|
|
|
|
|
|
Amounts paid to a director and certain officers of the Company (b)
|
|
$
|
523
|
|
$
|
97
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Amounts include royalties on
certain properties and lease bonus payments paid to a partnership in which a
director of the Company is the general partner and owns a 3.5 percent
partnership interest.
(b) Amounts include revenue interests,
overriding royalty interests, and net profits interests in properties owned by
the Company made to a director and certain officers (or affiliated entities).
Amounts also include payments for an acreage acquisition and lease bonuses to
an affiliated entity of an officer.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Note 12. Net income per share
The Company uses the two-class method of calculating net
income per share because certain of the Company’s unvested share-based awards
qualify as participating securities.
The following
table reconciles the Company’s income from operations and income attributable
to common stockholders to the basic and diluted earnings used to determine the
Company’s income per share amounts for the three months ended March 31,
2015 and 2014, respectively, under the
two-class method:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
(in thousands, except per share amounts)
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
Income as reported
|
$
|
7,512
|
|
$
|
91,307
|
Participating basic earnings
|
|
(74)
|
|
|
(1,068)
|
|
Basic income attributable to common stockholders
|
|
7,438
|
|
|
90,239
|
Reallocation of participating earnings
|
|
-
|
|
|
4
|
|
Diluted income attributable to common stockholders
|
$
|
7,438
|
|
$
|
90,243
|
|
|
|
|
|
|
|
|
Income per common share:
|
|
|
|
|
|
|
Basic
|
$
|
0.07
|
|
$
|
0.87
|
|
Diluted
|
$
|
0.06
|
|
$
|
0.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table is a
reconciliation of the basic weighted average common shares outstanding to
diluted weighted average common shares outstanding for the three months ended March 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in thousands)
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
Basic
|
|
114,047
|
|
103,949
|
|
|
Dilutive common stock options
|
|
25
|
|
123
|
|
|
Dilutive performance units
|
|
411
|
|
234
|
|
Diluted
|
|
114,483
|
|
104,306
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
unit awards. The number of shares
of common stock that will ultimately be issued for performance units will be
determined by a combination of (i) comparing the Company's total shareholder
return relative to the total shareholder return of a predetermined group of
peer companies at the end of the performance period and (ii) the Company’s
absolute total shareholder return at the end of the performance period. The
performance period is 36 months. The actual payout of shares will be between
zero and 300 percent of the performance units granted depending on the
Company's performance at the end of the performance period.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Note 13. Stockholders’
equity
Public common stock offering. In March 2015, the Company issued 6.9 million
shares of its common stock in a secondary public offering at $107.49 per share
and received net proceeds of approximately $741.2 million.
Note 14. Subsidiary
guarantors
All of the Company’s 100 percent owned
subsidiaries have fully and unconditionally guaranteed the Company’s senior
notes. The indentures
governing the Company’s senior notes provide that the guarantees of its
subsidiary guarantors will be released
in certain customary circumstances, including (i) in connection with any
sale, exchange or other disposition, whether by merger, consolidation or
otherwise, of the capital stock of that guarantor to a person that is not the
Company or a restricted subsidiary of the Company, such that, after giving
effect to such transaction, such guarantor would no longer constitute a
subsidiary of the Company, (ii) in connection with any sale, exchange or other
disposition (other than a lease) of all or substantially all of the assets of
that guarantor to a person that is not the Company or a restricted subsidiary
of the Company, (iii) upon the merger of a guarantor into the Company or any
other guarantor or the liquidation or dissolution of a guarantor, (iv) if the
Company designates any restricted subsidiary that is a guarantor to be an
unrestricted subsidiary in accordance with the indenture, (v) upon legal
defeasance or satisfaction and discharge of the indenture and (vi) upon written
notice of such release or discharge by the Company to the trustee following the
release or discharge of all guarantees by such guarantor of any indebtedness
that resulted in the creation of such guarantee, except a discharge or release
by or as a result of payment under such guarantee.
See Note 8 for a summary of
the Company’s senior notes. In accordance with practices accepted by the United
States Securities and Exchange Commission, 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 March 31, 2015 and
December 31, 2014,
condensed consolidating statements of operations for the three months ended
March 31, 2015 and
2014 and
condensed consolidating statements of cash flows for the three months ended
March 31, 2015 and
2014, 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 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.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Condensed
Consolidating Balance Sheet
|
March 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in thousands)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable - related parties
|
|
$
|
7,405,404
|
|
$
|
1,186,344
|
|
$
|
(8,591,748)
|
|
$
|
-
|
Other current assets
|
|
|
561,539
|
|
|
592,737
|
|
|
-
|
|
|
1,154,276
|
Oil and natural gas properties, net
|
|
|
-
|
|
|
10,555,807
|
|
|
-
|
|
|
10,555,807
|
Property and equipment, net
|
|
|
-
|
|
|
132,778
|
|
|
-
|
|
|
132,778
|
Investment in subsidiaries
|
|
|
4,035,672
|
|
|
-
|
|
|
(4,035,672)
|
|
|
-
|
Other long-term assets
|
|
|
271,232
|
|
|
93,053
|
|
|
-
|
|
|
364,285
|
|
Total assets
|
|
$
|
12,273,847
|
|
$
|
12,560,719
|
|
$
|
(12,627,420)
|
|
$
|
12,207,146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable - related parties
|
|
$
|
1,186,344
|
|
$
|
7,405,404
|
|
$
|
(8,591,748)
|
|
$
|
-
|
Other current liabilities
|
|
|
244,566
|
|
|
980,211
|
|
|
-
|
|
|
1,224,777
|
Long-term debt
|
|
|
3,377,147
|
|
|
-
|
|
|
-
|
|
|
3,377,147
|
Other long-term liabilities
|
|
|
1,423,441
|
|
|
139,432
|
|
|
-
|
|
|
1,562,873
|
Equity
|
|
|
6,042,349
|
|
|
4,035,672
|
|
|
(4,035,672)
|
|
|
6,042,349
|
|
Total liabilities and equity
|
|
$
|
12,273,847
|
|
$
|
12,560,719
|
|
$
|
(12,627,420)
|
|
$
|
12,207,146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Balance Sheet
|
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in thousands)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable - related parties
|
|
$
|
6,670,744
|
|
$
|
1,201,950
|
|
$
|
(7,872,694)
|
|
$
|
-
|
Other current assets
|
|
|
569,545
|
|
|
618,851
|
|
|
-
|
|
|
1,188,396
|
Oil and natural gas properties, net
|
|
|
-
|
|
|
10,076,878
|
|
|
-
|
|
|
10,076,878
|
Property and equipment, net
|
|
|
-
|
|
|
129,136
|
|
|
-
|
|
|
129,136
|
Investment in subsidiaries
|
|
|
4,085,045
|
|
|
-
|
|
|
(4,085,045)
|
|
|
-
|
Other long-term assets
|
|
|
330,792
|
|
|
74,761
|
|
|
-
|
|
|
405,553
|
|
Total assets
|
|
$
|
11,656,126
|
|
$
|
12,101,576
|
|
$
|
(11,957,739)
|
|
$
|
11,799,963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable - related parties
|
|
$
|
1,201,950
|
|
$
|
6,670,744
|
|
$
|
(7,872,694)
|
|
$
|
-
|
Other current liabilities
|
|
|
217,884
|
|
|
1,209,309
|
|
|
-
|
|
|
1,427,193
|
Long-term debt
|
|
|
3,517,320
|
|
|
-
|
|
|
-
|
|
|
3,517,320
|
Other long-term liabilities
|
|
|
1,438,184
|
|
|
136,478
|
|
|
-
|
|
|
1,574,662
|
Equity
|
|
|
5,280,788
|
|
|
4,085,045
|
|
|
(4,085,045)
|
|
|
5,280,788
|
|
Total liabilities and equity
|
|
$
|
11,656,126
|
|
$
|
12,101,576
|
|
$
|
(11,957,739)
|
|
$
|
11,799,963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Condensed
Consolidating Statement of Operations
|
Three Months Ended March 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in thousands)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
-
|
|
$
|
413,522
|
|
$
|
-
|
|
$
|
413,522
|
Total operating costs and expenses
|
|
|
114,604
|
|
|
(458,554)
|
|
|
-
|
|
|
(343,950)
|
|
Income (loss) from operations
|
|
|
114,604
|
|
|
(45,032)
|
|
|
-
|
|
|
69,572
|
Interest expense
|
|
|
(53,569)
|
|
|
-
|
|
|
-
|
|
|
(53,569)
|
Other, net
|
|
|
(49,373)
|
|
|
(4,341)
|
|
|
49,373
|
|
|
(4,341)
|
|
Income (loss) before income taxes
|
|
|
11,662
|
|
|
(49,373)
|
|
|
49,373
|
|
|
11,662
|
Income tax expense
|
|
|
(4,150)
|
|
|
-
|
|
|
-
|
|
|
(4,150)
|
|
Net income (loss)
|
|
$
|
7,512
|
|
$
|
(49,373)
|
|
$
|
49,373
|
|
$
|
7,512
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Operations
|
Three Months Ended March 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in thousands)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
-
|
|
$
|
660,959
|
|
$
|
-
|
|
$
|
660,959
|
Total operating costs and expenses
|
|
|
(36,153)
|
|
|
(422,574)
|
|
|
-
|
|
|
(458,727)
|
|
Income (loss) from operations
|
|
|
(36,153)
|
|
|
238,385
|
|
|
-
|
|
|
202,232
|
Interest expense
|
|
|
(56,135)
|
|
|
-
|
|
|
-
|
|
|
(56,135)
|
Other, net
|
|
|
238,926
|
|
|
541
|
|
|
(238,926)
|
|
|
541
|
|
Income before income taxes
|
|
|
146,638
|
|
|
238,926
|
|
|
(238,926)
|
|
|
146,638
|
Income tax expense
|
|
|
(55,331)
|
|
|
-
|
|
|
-
|
|
|
(55,331)
|
|
Net income
|
|
$
|
91,307
|
|
$
|
238,926
|
|
$
|
(238,926)
|
|
$
|
91,307
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Condensed
Consolidating Statement of Cash Flows
|
Three Months Ended March 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in thousands)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows provided by (used in) operating activities
|
|
$
|
(766,210)
|
|
$
|
892,459
|
|
$
|
-
|
|
$
|
126,249
|
Net cash flows provided by (used in) investing activities
|
|
|
167,156
|
|
|
(818,920)
|
|
|
-
|
|
|
(651,764)
|
Net cash flows provided by (used in) financing activities
|
|
|
599,054
|
|
|
(73,539)
|
|
|
-
|
|
|
525,515
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Cash and cash equivalents at beginning of period
|
|
|
-
|
|
|
21
|
|
|
-
|
|
|
21
|
|
Cash and cash equivalents at end of period
|
|
$
|
-
|
|
$
|
21
|
|
$
|
-
|
|
$
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Cash Flows
|
Three Months Ended March 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in thousands)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows provided by (used in) operating activities
|
|
$
|
(30,312)
|
|
$
|
506,292
|
|
$
|
-
|
|
$
|
475,980
|
Net cash flows used in investing activities
|
|
|
(14,837)
|
|
|
(559,859)
|
|
|
-
|
|
|
(574,696)
|
Net cash flows provided by financing activities
|
|
|
45,149
|
|
|
53,567
|
|
|
-
|
|
|
98,716
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Cash and cash equivalents at beginning of period
|
|
|
-
|
|
|
21
|
|
|
-
|
|
|
21
|
|
Cash and cash equivalents at end of period
|
|
$
|
-
|
|
$
|
21
|
|
$
|
-
|
|
$
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Note 15. Subsequent
events
New
commodity derivative contracts. After March 31, 2015, the Company entered into
the following oil price swaps and oil basis swaps to hedge additional amounts
of the Company’s estimated future production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
|
|
|
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Swaps: (a)
|
|
|
|
|
|
|
|
|
|
|
|
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
535,000
|
|
1,405,000
|
|
795,000
|
|
2,735,000
|
|
|
Price per Bbl
|
|
|
$
|
59.83
|
$
|
59.87
|
$
|
60.05
|
$
|
59.91
|
|
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
640,000
|
|
460,000
|
|
330,000
|
|
330,000
|
|
1,760,000
|
|
|
Price per Bbl
|
$
|
64.80
|
$
|
64.88
|
$
|
64.98
|
$
|
64.98
|
$
|
64.89
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
1,890,000
|
|
1,890,000
|
|
-
|
|
-
|
|
3,780,000
|
|
|
Price per Bbl
|
$
|
64.62
|
$
|
64.62
|
$
|
-
|
$
|
-
|
$
|
64.62
|
Oil Basis Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
150,000
|
|
460,000
|
|
460,000
|
|
1,070,000
|
|
|
Price per Bbl
|
|
|
$
|
(0.98)
|
$
|
(0.98)
|
$
|
(0.98)
|
$
|
(0.98)
|
|
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
637,000
|
|
637,000
|
|
276,000
|
|
-
|
|
1,550,000
|
|
|
Price per Bbl
|
$
|
(1.68)
|
$
|
(1.68)
|
$
|
(1.70)
|
$
|
-
|
$
|
(1.68)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
The index prices for the oil price swaps are based on the NYMEX – WTI
monthly average futures price.
|
(b)
|
The basis differential price is between Midland – WTI and Cushing –
WTI.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2015
Unaudited
Note 16. Supplementary
information
Capitalized
costs
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
December 31,
|
(in thousands)
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
13,530,022
|
|
$
|
12,795,970
|
|
Unproved
|
|
|
1,078,984
|
|
|
1,071,861
|
|
Less: accumulated depletion
|
|
|
(4,053,199)
|
|
|
(3,790,953)
|
|
|
Net capitalized costs for oil and natural gas properties
|
|
$
|
10,555,807
|
|
$
|
10,076,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
incurred for oil and natural gas producing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in thousands)
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
-
|
|
$
|
20,490
|
|
Unproved
|
|
|
16,013
|
|
|
24,688
|
Exploration
|
|
|
429,169
|
|
|
324,497
|
Development
|
|
|
301,744
|
|
|
211,679
|
|
Total costs incurred for oil and natural gas properties
|
|
$
|
746,926
|
|
$
|
581,354
|
|
|
|
|
|
|
|
|
|
Item 2. Management’s Discussion and
Analysis of Financial Condition and Results of Operations
The following discussion is intended to assist
you in understanding our business and results of operations together with our
present financial condition. This section should be read in conjunction with
our historical consolidated financial statements and notes.
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 those 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 operating
areas are located in the Permian Basin of Southeast New Mexico and West
Texas. We refer to our three core operating areas as the (i) New Mexico Shelf,
where we primarily target the Yeso formation with horizontal and vertical
development, (ii) Delaware Basin, where we use horizontal drilling to target
the Bone Spring formation (including the Avalon shale and the Bone Spring sands)
and the Wolfcamp shale formation and (iii) Texas Permian in the Midland Basin,
where we target the Wolfcamp and Spraberry formations with horizontal and
vertical development. Oil
comprised 58.1 percent of our 637.2 MMBoe of estimated proved reserves at
December 31, 2014 and 67.8 percent of our 11.9 MMBoe of production for the
three months ended March 31, 2015. We
seek to operate the wells in which we own an interest, and we operated wells
that accounted for 92.3 percent of our proved developed producing PV-10 and
79.5 percent of our approximately 7,208 gross wells at December 31, 2014. 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.
Financial
and Operating Performance
Our financial
and operating performance for the three months ended March 31, 2015, as
compared to the three months ended March 31, 2014, included the following
highlights:
·
Net income was $7.5 million ($0.06 per diluted share) for the first three months of
2015, as compared to net income of $91.3 million
($0.87 per diluted share) during the three
months ended March 31, 2014. The decrease in net income was primarily due to:
• $247.4
million decrease in oil and natural gas revenues as a result of a
52 percent decrease in commodity price realizations per Boe (excluding the effects of derivative activities), which
completely offset a 30 percent
increase in production;
• $45.8
million increase in depreciation, depletion and amortization expense, primarily
due to increased production associated with new wells
that were successfully drilled and completed in 2014 and 2015; and
• $11.1
million increase in general and administrative expense due to an increase in the number of employees and related
personnel expenses to manage our increased activities related to our increased
drilling and exploration activities;
partially
offset by:
• $115.3 million gain on derivatives not designated as
hedges for the three months ended March 31, 2015, as compared to a $35.6 million loss on derivatives not designated as
hedges during the three months ended March 31, 2014;
• $51.1
million decrease in income tax expense due to the decrease in income before
income taxes resulting in a 35.6 percent effective tax rate; and
• $19.6
million decrease in exploration and abandonment expense due primarily to more exploratory dry hole costs in 2014 as
compared to 2015.
·
Average daily sales volumes increased by 30 percent to 132,187 Boe per day during the first three months of
2015, as compared to 101,623 Boe per day during the first three months of 2014.
The increase is primarily attributable to our
successful drilling and completion efforts during 2014 and 2015.
·
Net cash provided by operating activities decreased by
approximately $349.8 million to $126.2 million for
the first three months of 2015, as compared to $476.0 million
in the first three months of 2014, primarily due to (i) a decrease in oil and
natural gas revenues, (ii) negative variances in working capital changes and
(iii) an increase in cash general and administrative expense.
·
Long-term debt decreased by approximately $140.2 million during
the first three months of 2015, primarily due to utilizing a portion of the net
proceeds from our March 2015 equity offering.
Commodity Prices
Our
results of operations are heavily influenced by commodity prices. Commodity
prices may fluctuate widely in response to (i) relatively minor changes in the
supply of and demand for oil, natural gas and natural gas liquids, (ii) market
uncertainty and (iii) a variety of additional factors that are beyond our
control. Factors that may impact future commodity prices, including the price
of oil, natural gas and natural gas liquids, include:
·
continuing economic uncertainty
worldwide;
·
political and economic developments in
oil and natural gas producing regions, including Africa, South America and the
Middle East;
·
the extent to which members of the
Organization of Petroleum Exporting Countries and other oil exporting nations
are able to continue to manage oil prices and production controls;
·
technological advances affecting energy
consumption and energy supply;
·
the effect of energy conservation efforts;
·
the price and availability of
alternative fuels;
·
domestic and foreign governmental
regulations, including limits on the United States’ ability to export crude
oil, and taxation;
·
the level of global inventories;
·
the proximity, capacity, cost and availability
of pipelines and other transportation facilities, as well as the availability
of commodity processing and gathering and refining capacity;
·
risks related to the concentration of
our operations in the Permian Basin of Southeast New Mexico and West Texas and
the level of commodity inventory in the Permian Basin;
·
the quality of the oil we produce;
·
the overall global demand for oil
natural gas and natural gas liquids;
·
the domestic and foreign supply of oil,
natural gas and natural gas liquids; and
·
overall North American oil and natural
gas supply and demand fundamentals, including:
•
the United States economy impact,
•
weather conditions, and
•
the potential for liquefied natural gas
deliveries to and exports from the United States.
Although
we cannot predict the occurrence of events that may affect future commodity
prices or the degree to which these prices will be affected, the prices for any
commodity that we produce will generally approximate current market prices in
the geographic region of the production. From time to time, we expect that we
may economically hedge a portion of our
commodity
price risk to mitigate the impact of price volatility on our business. See Notes
7 and 15 of the Condensed Notes to Consolidated Financial Statements included
in “Item 1. Consolidated Financial Statements (Unaudited)” for additional
information regarding our commodity derivative positions at March 31, 2015 and
additional derivative contracts entered into subsequent to March 31, 2015,
respectively.
Oil and natural gas prices have been subject to
significant fluctuations during the past several years. In general, average oil
and natural gas prices were significantly lower during the comparable periods of
2015 measured against 2014. The following table sets forth the average New York
Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three months
ended March 31, 2015 and 2014, as well as the high and low NYMEX
prices for the same periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
|
|
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
Average NYMEX prices:
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
$
|
48.80
|
|
$
|
98.60
|
|
Natural gas (MMBtu)
|
|
$
|
2.82
|
|
$
|
4.72
|
|
|
|
|
|
|
|
|
|
High and Low NYMEX prices:
|
|
|
|
|
|
|
|
Oil (Bbl):
|
|
|
|
|
|
|
|
|
High
|
|
$
|
53.53
|
|
$
|
104.92
|
|
|
Low
|
|
$
|
43.46
|
|
$
|
91.66
|
|
Natural gas (MMBtu):
|
|
|
|
|
|
|
|
|
High
|
|
$
|
3.23
|
|
$
|
6.15
|
|
|
Low
|
|
$
|
2.58
|
|
$
|
4.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Further, the NYMEX oil price and NYMEX natural
gas price reached highs and lows of $59.63 and $49.14 per Bbl and $2.78 and
$2.49 per MMBtu, respectively, during the period from March 31, 2015
to May 1, 2015. At May 1, 2015, the NYMEX oil price and NYMEX natural gas price
were $59.15 per Bbl and $2.78 per MMBtu, respectively.
Historically, approximately 45 to 65 percent of
our total natural gas revenues have been derived from the value of the natural
gas liquids contained in our natural gas, with the remaining portion coming
from the value of the dry natural gas residue. In the past, our liquids-rich
natural gas stream and the related value of the natural gas liquids included in
our natural gas revenues resulted in our realized natural gas price (excluding
the effects of derivatives) being greater than the related NYMEX natural gas
price. However, during the three months ended March 31, 2015, our realized
natural gas price (excluding the effects of derivatives) fell below the related
NYMEX natural gas price as a result of the average Mont Belvieu price for a
blended barrel of natural gas liquids decreasing to $19.30 per Bbl, as compared
to $40.87 per Bbl during the three months ended March 31, 2014.
Recent Events
Common stock offering. In March 2015, we issued in a secondary public offering
approximately 6.9 million shares of our common stock at $107.49 per share, and
we received net proceeds of approximately $741.2 million. We used a portion of
the net proceeds from this offering to repay all outstanding borrowings under
our credit facility and the remainder for general corporate purposes.
Derivative Financial Instruments
Derivative financial instrument exposure. At March 31, 2015, the fair value of our financial derivatives was a net asset of $700.9 million. All of our counterparties to these financial
derivatives are parties or affiliates of parties 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
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 or its affiliates.
New commodity derivative contracts. After March 31, 2015, we entered into the
following oil price swaps and oil basis swaps to hedge additional amounts of
our estimated future production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
|
|
|
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Swaps: (a)
|
|
|
|
|
|
|
|
|
|
|
|
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
535,000
|
|
1,405,000
|
|
795,000
|
|
2,735,000
|
|
|
Price per Bbl
|
|
|
$
|
59.83
|
$
|
59.87
|
$
|
60.05
|
$
|
59.91
|
|
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
640,000
|
|
460,000
|
|
330,000
|
|
330,000
|
|
1,760,000
|
|
|
Price per Bbl
|
$
|
64.80
|
$
|
64.88
|
$
|
64.98
|
$
|
64.98
|
$
|
64.89
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
1,890,000
|
|
1,890,000
|
|
-
|
|
-
|
|
3,780,000
|
|
|
Price per Bbl
|
$
|
64.62
|
$
|
64.62
|
$
|
-
|
$
|
-
|
$
|
64.62
|
Oil Basis Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
150,000
|
|
460,000
|
|
460,000
|
|
1,070,000
|
|
|
Price per Bbl
|
|
|
$
|
(0.98)
|
$
|
(0.98)
|
$
|
(0.98)
|
$
|
(0.98)
|
|
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
637,000
|
|
637,000
|
|
276,000
|
|
-
|
|
1,550,000
|
|
|
Price per Bbl
|
$
|
(1.68)
|
$
|
(1.68)
|
$
|
(1.70)
|
$
|
-
|
$
|
(1.68)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
The index prices for the oil price swaps are based on the NYMEX – WTI
monthly average futures price.
|
(b)
|
The basis differential price is between Midland – WTI and Cushing –
WTI.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results
of Operations
The following table sets forth summary
information concerning our production and operating data for the three months
ended March 31, 2015 and 2014. Because of normal production
declines, increased or decreased drilling activities, fluctuations in commodity
prices and the effects of acquisitions or divestitures, the historical
information presented below should not be interpreted as being indicative of
future results.
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
|
|
|
|
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
Production and operating data:
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
8,066
|
|
|
5,846
|
|
|
Natural gas (MMcf)
|
|
|
22,985
|
|
|
19,800
|
|
|
Total (MBoe)
|
|
|
11,897
|
|
|
9,146
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
89,622
|
|
|
64,956
|
|
|
Natural gas (Mcf)
|
|
|
255,389
|
|
|
220,000
|
|
|
Total (Boe)
|
|
|
132,187
|
|
|
101,623
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices:
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl)
|
|
$
|
43.34
|
|
$
|
92.35
|
|
|
Oil, with derivatives (Bbl) (a)
|
|
$
|
63.20
|
|
$
|
90.68
|
|
|
Natural gas, without derivatives (Mcf)
|
|
$
|
2.78
|
|
$
|
6.12
|
|
|
Natural gas, with derivatives (Mcf) (a)
|
|
$
|
3.08
|
|
$
|
5.86
|
|
|
Total, without derivatives (Boe)
|
|
$
|
34.76
|
|
$
|
72.27
|
|
|
Total, with derivatives (Boe) (a)
|
|
$
|
48.81
|
|
$
|
70.65
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses per Boe:
|
|
|
|
|
|
|
|
|
Lease operating expenses and workover costs
|
|
$
|
7.64
|
|
$
|
8.07
|
|
|
Oil and natural gas taxes
|
|
$
|
2.91
|
|
$
|
5.80
|
|
|
Depreciation, depletion and amortization
|
|
$
|
22.46
|
|
$
|
24.21
|
|
|
General and administrative
|
|
$
|
4.95
|
|
$
|
5.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes the
effect of cash receipts from (payments on) derivatives not designated as
hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
|
|
(in thousands)
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash receipts from (payments on) derivatives not
designated as hedges:
|
|
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
160,186
|
|
$
|
(9,769)
|
|
|
|
Natural gas derivatives
|
|
|
6,970
|
|
|
(5,068)
|
|
|
|
|
Total
|
|
$
|
167,156
|
|
$
|
(14,837)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The presentation
of average prices with derivatives is a non-GAAP measure as a result of
including the cash receipts from (payments on) commodity derivatives that are
presented in our statements of cash flows. This presentation of average
prices with derivatives is a means by which to reflect the actual cash
performance of our commodity derivatives for the respective periods and
presents oil and natural gas prices with derivatives in a manner consistent
with the presentation generally used by the investment community.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014
Oil and natural gas
revenues. Revenue from oil and natural gas operations was $413.5 million for the three months ended March 31, 2015, a
decrease of
$247.5 million (37 percent) from $661.0 million for the three months ended March 31, 2014.
This decrease was primarily due to the decrease in realized oil and natural gas
prices, partially offset by increased production due to our successful
drilling efforts during 2014 and 2015. Specific factors affecting oil and
natural gas revenues include the following:
·
total oil production was 8,066 MBbl for the
three months ended March 31, 2015, an increase of 2,220 MBbl (38 percent) from 5,846 MBbl for the
three months ended March 31, 2014;
·
average realized oil price (excluding the effects of derivative
activities) was
$43.34 per Bbl during the three months ended March 31, 2015, a
decrease of 53 percent from $92.35 per Bbl
during the three months ended March 31, 2014. For the three
months ended March 31, 2015 and 2014, we realized approximately 89.9 percent
and 93.7 percent, respectively, of the average NYMEX oil prices for the
respective periods. The basis differential between the location of Midland,
Texas and Cushing, Oklahoma (NYMEX pricing location) for our oil has a direct
effect on our realized oil price. For the three months ended March 31, 2015 and
2014, the market basis differential between WTI-Midland and WTI-Cushing was a
price reduction of $1.98 per
Bbl and $3.50 per
Bbl, respectively;
·
total natural gas production was 22,985 MMcf for the three months ended March 31, 2015, an
increase of 3,185 MMcf (16 percent) from 19,800 MMcf for the
three months ended March 31, 2014; and
·
average realized natural gas price (excluding the effects of
derivative activities) was $2.78 per Mcf during the
three months ended March 31, 2015, a decrease of 55 percent from $6.12 per Mcf during
the three months ended March 31, 2014. For the three months ended March 31,
2015 and 2014, we realized approximately 99.3 percent and 129.7 percent,
respectively, of the average NYMEX natural gas prices for the respective
periods. Historically, approximately 45 to 65 percent of our total natural gas
revenues have been derived from the value of the natural gas liquids contained
in our natural gas, with the remaining portion coming from the value of the dry
natural gas residue. In the past, our liquids-rich natural gas stream and the
related value of the natural gas liquids included in our natural gas revenues
resulted in our realized natural gas price (excluding the effects of
derivatives) being greater than the related NYMEX natural gas price. However,
during the three months ended March 31, 2015, our realized natural gas price
(excluding the effects of derivatives) fell below the related NYMEX natural gas
price as a result of the average Mont Belvieu price for a blended barrel of
natural gas liquids decreasing to $19.30 per Bbl, as compared to $40.87 per Bbl
during the three months ended March 31, 2014.
Production expenses. The following table provides the
components of our total oil and natural gas production costs for the three
months ended March 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
83,658
|
|
$
|
7.03
|
|
$
|
70,193
|
|
$
|
7.67
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem
|
|
|
5,255
|
|
|
0.44
|
|
|
5,691
|
|
|
0.62
|
|
Production
|
|
|
29,411
|
|
|
2.47
|
|
|
47,422
|
|
|
5.18
|
Workover costs
|
|
|
7,211
|
|
|
0.61
|
|
|
3,618
|
|
|
0.40
|
|
|
Total oil and natural gas production expenses
|
|
$
|
125,535
|
|
$
|
10.55
|
|
$
|
126,924
|
|
$
|
13.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, we have
some control over lease operating expenses and workover costs on properties we
operate, but production and ad valorem taxes are related to commodity prices.
Lease operating expenses were $83.7 million ($7.03
per Boe) for the three months ended March 31,
2015, which was an increase of
$13.5 million (19 percent) from $70.2 million ($7.67 per Boe) for the three
months ended March 31, 2014. The increase in lease operating expenses was
primarily due to increased production
associated with our wells successfully drilled and completed in 2014 and 2015. The decrease in lease operating expenses per
Boe was primarily due to increased production
associated with our wells successfully drilled and completed in 2014 and 2015
and a decrease in routine well
maintenance and repairs.
Production taxes per unit of production were $2.47
per Boe during the three months ended March
31, 2015, a decrease of 52 percent
from $5.18 per Boe during the three months ended March 31, 2014. The decrease
was directly related to the decrease in oil and natural gas prices. Over the
same period, our per Boe prices (excluding the effects of derivatives)
decreased 52 percent.
Workover expenses were approximately
$7.2 million and $3.6 million for the three months ended March 31, 2015
and 2014, respectively. The 2015 and 2014 expenses related primarily to routine
workovers performed to increase or restore production.
Exploration
and abandonments expense.
The following table provides a breakdown of our exploration and abandonments
expense for the three months ended March 31,
2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
(in thousands)
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
Geological and geophysical
|
|
$
|
1,432
|
|
$
|
1,616
|
Exploratory dry hole costs
|
|
|
781
|
|
|
19,772
|
Leasehold abandonments
|
|
|
1,919
|
|
|
3,945
|
Other
|
|
|
1,623
|
|
|
42
|
|
Total exploration and abandonments
|
|
$
|
5,755
|
|
$
|
25,375
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our geological and geophysical expense for the
periods presented above primarily consists of the costs of acquiring and
processing geophysical data and core analysis.
Our exploratory dry hole costs during the three
months ended March 31, 2015 were primarily related to expensing an unsuccessful well, which we did not operate,
that was located in our New Mexico Shelf area. Our
exploratory dry hole costs during the three months ended March 31, 2014
were primarily related to (i) partial expensing of unsuccessful horizontal
laterals on two wells in the Delaware Basin, (ii) expensing two unsuccessful wells
drilled while testing the outer limits of our Delaware Basin acreage and (iii) an
unsuccessful horizontal lateral in the New Mexico Shelf area.
For the three months ended March 31, 2015 and 2014, we recorded approximately $1.9 million and
$3.9 million of leasehold abandonments, respectively.
Depreciation, depletion and amortization
expense. The
following table provides components of our depreciation, depletion and
amortization expense for the three months ended March 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2015
|
|
2014
|
|
|
|
|
|
Per
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
262,280
|
|
$
|
22.05
|
|
$
|
216,807
|
|
$
|
23.71
|
Depreciation of other property and equipment
|
|
|
4,560
|
|
|
0.38
|
|
|
4,220
|
|
|
0.46
|
Amortization of intangible assets - operating rights
|
|
|
365
|
|
|
0.03
|
|
|
365
|
|
|
0.04
|
|
Total depletion, depreciation and amortization
|
|
$
|
267,205
|
|
$
|
22.46
|
|
$
|
221,392
|
|
$
|
24.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period
end
|
|
$
|
79.21
|
|
|
|
|
$
|
94.92
|
|
|
|
Natural gas price used to estimate proved natural gas
reserves at period end
|
|
$
|
3.88
|
|
|
|
|
$
|
3.99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas
properties was $262.3 million ($22.05 per Boe) for the three months ended March
31, 2015, an increase of $45.5 million (21 percent) from $216.8 million
($23.71 per Boe) for the three months ended March 31, 2014. The increase in
depletion expense was primarily due to increased production associated with new
wells that were successfully drilled and completed in 2014 and 2015. The decrease
in depletion expense per Boe period over period was primarily due to a reduction in the net book value of our oil
and natural gas properties due to a non-cash impairment charge of approximately
$431.7 million recorded in the fourth quarter of 2014 and increased reserves
supported by one or more reliable technologies, partially offset by lower
commodity prices.
The increase in depreciation expense was
primarily associated with additional other property and equipment related to
buildings and other items as a result of our increased number of employees.
General and administrative expenses. The following table provides components of our general and
administrative expenses for the three months ended March 31, 2015
and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2015
|
|
2014
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
$
|
49,670
|
|
$
|
4.18
|
|
$
|
41,466
|
|
$
|
4.53
|
Non-cash stock-based compensation
|
|
|
15,495
|
|
|
1.30
|
|
|
11,432
|
|
|
1.25
|
Less: Third-party operating fee reimbursements
|
|
|
(6,364)
|
|
|
(0.53)
|
|
|
(5,148)
|
|
|
(0.56)
|
|
Total general and administrative expenses
|
|
$
|
58,801
|
|
$
|
4.95
|
|
$
|
47,750
|
|
$
|
5.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were
approximately $58.8 million ($4.95 per Boe) for the three months ended March 31, 2015,
an increase of $11.0 million (23 percent) from $47.8 million ($5.22 per Boe)
for the three months ended March 31, 2014. The increase in general and administrative
expenses and non-cash stock-based compensation was primarily due to an increase
in the number of employees and related personnel expenses in order to manage
our increased activities directly related to our increased drilling and
exploration activities. The
decrease in total general and administrative expenses per Boe was primarily due
to increased production from our wells successfully drilled and completed in
2014 and 2015, partially offset by an increase in the number of employees and
related personnel expenses in order to manage our increased activities, coupled
with increasing salaries in 2014 due to the highly competitive labor market.
As the operator of certain oil and natural gas properties
in which we own an interest, we earn overhead reimbursements during the
drilling and production phases of the property. We
earned reimbursements of $6.4 million and $5.1 million during the three months
ended March 31, 2015 and 2014, respectively. This reimbursement is
reflected as a reduction of general and administrative expenses in the
consolidated statements of operations. The increase in third-party operating fee
reimbursements was primarily due to increased reimbursements attributable to
more wells operated as a result of continued drilling activity period over
period.
Gain (loss) on derivatives not designated as
hedges. The following table sets forth the gain (loss)
on derivatives not designated as hedges for the three months ended March 31, 2015
and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
March 31,
|
|
(in thousands)
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as hedges:
|
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
110,280
|
|
$
|
(24,220)
|
|
|
Natural gas derivatives
|
|
|
5,060
|
|
|
(11,395)
|
|
|
|
Total
|
|
$
|
115,340
|
|
$
|
(35,615)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table
represents our cash receipts from (payments on) derivatives for the three
months ended March 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
March 31,
|
|
(in thousands)
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
Cash receipts from (payments on) derivatives not
designated as hedges:
|
|
|
|
|
|
Oil derivatives
|
|
$
|
160,186
|
|
$
|
(9,769)
|
|
|
Natural gas derivatives
|
|
|
6,970
|
|
|
(5,068)
|
|
|
|
Total
|
|
$
|
167,156
|
|
$
|
(14,837)
|
|
|
|
|
|
|
|
|
|
|
|
Our earnings are affected by the changes in
value of our derivatives portfolio between periods and the related cash
settlements of those derivatives, which could be significant. To the extent the
future commodity price outlook declines between measurement periods, we will
have mark-to-market gains, while to the extent future commodity price outlook
increases between measurement periods, we will have mark-to-market losses.
Interest expense. The following table sets forth interest expense, weighted average
interest rates and weighted average debt balances for the three months ended March 31, 2015
and 2014:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
(dollars in thousands)
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
Interest expense
|
|
$
|
53,569
|
|
$
|
56,135
|
Capitalized interest
|
|
|
1,210
|
|
|
-
|
|
Interest expense, excluding impact of capitalized interest
|
|
$
|
54,779
|
|
$
|
56,135
|
|
|
|
|
|
|
|
Weighted average interest rate - credit facility
|
|
|
2.4%
|
|
|
2.2%
|
Weighted average interest rate - senior notes
|
|
|
5.9%
|
|
|
5.9%
|
|
Total weighted average interest rate
|
|
|
5.7%
|
|
|
5.7%
|
|
|
|
|
|
|
|
|
Weighted average credit facility balance
|
|
$
|
252,528
|
|
$
|
284,306
|
Weighted average senior notes balance
|
|
|
3,350,000
|
|
|
3,350,000
|
|
Total weighted average debt balance
|
|
$
|
3,602,528
|
|
$
|
3,634,306
|
|
|
|
|
|
|
|
|
The decrease in the weighted average debt balance
for the three months ended March 31, 2015 as compared to the corresponding period in
2014 was due to the repayment of
our credit facility using a portion of the proceeds from our March
2015 and May 2014 equity offerings. The decrease
in interest expense was due to an overall decrease in the weighted average debt
balance.
Income tax provisions. We recorded an income tax expense
of $4.2 million and $55.3 million for the three months ended March 31, 2015
and 2014, respectively. The effective income tax rates for the three months
ended March 31, 2015 and 2014 were 35.6 percent and 37.7 percent,
respectively.
Capital Commitments, Capital Resources and Liquidity
Capital commitments. Our primary needs for cash are development, exploration and acquisition
of oil and natural gas assets, midstream joint venture and other capital
commitments, 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 or 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
three months ended March 31, 2015
and 2014 totaled $729.4 million and $534.7 million, respectively. The
increase in costs incurred was primarily due to additional completion activity.
The primary reason for the differences in the costs incurred and cash flow
expenditures was the timing of payments. The 2015 expenditures were funded in
part from borrowings under our credit facility.
2015 capital budget. In January 2015, we announced our updated 2015 capital budget of
approximately $2.0 billion, of which approximately 90 percent of our capital
budget for drilling and completion costs will be dedicated to horizontal
drilling opportunities. Our 2015 capital program is expected to continue
focusing on drilling in the Delaware Basin. The capital spend related to our
annual budget is weighted towards our first quarter of 2015. The 2015 capital
budget, based on our current expectations of commodity prices and cost, will
exceed our expected cash flow. We expect our cash flow and borrowings under our
credit facility will be sufficient to fund our budgeted capital expenditure
needs during 2015. However, if we experience sustained commodity prices lower
than our forecasted pricing without sufficient costs reductions, we may adjust
our capital budget to preserve our financial strength.
During the remainder of 2015, we plan to use our credit
facility to fund such expenditures in excess of our cash flows. 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 costs of
drilling rigs and other services and equipment, regulatory, technological and
competitive developments and market conditions. In addition, under certain
circumstances, we may consider increasing, decreasing or reallocating our
capital spending plans.
Other than the customary purchase of leasehold acreage, our
capital budgets are exclusive of acquisitions. We do not have a specific
acquisition budget, since the timing and size of acquisitions are difficult to
forecast. We evaluate opportunities to purchase or sell oil and natural gas
properties in the marketplace and could participate as a buyer or seller of
properties at various times. We seek to acquire oil and natural gas properties
that provide opportunities for the addition of reserves and production through
a combination of development, high-potential exploration and control of
operations that will allow us to apply our operating expertise.
Acquisitions. The
following table reflects our expenditures for
acquisitions of proved and unproved properties for the three months ended March 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in thousands)
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
-
|
|
$
|
20,490
|
|
Unproved (a)
|
|
|
16,013
|
|
|
24,688
|
|
|
Total property acquisition costs
|
|
$
|
16,013
|
|
$
|
45,178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Included in the unproved property acquisition costs above are budgeted
leasehold acreage acquisitions of $16.0 million and $10.0 million for the
three months ended March 31, 2015 and 2014, respectively.
|
|
|
|
|
|
|
|
|
|
|
Contractual obligations. Our contractual obligations include long-term
debt, cash interest expense on debt, operating lease obligations, purchase
obligations, employment agreements with executive officers, derivative
liabilities, investment contributions related to Alpha Crude Connecter, LLC
(“ACC”) and other obligations. Since December 31, 2014, the material
changes in our contractual obligations included a $140.2 million decrease in
outstanding long-term debt and a $54.3 million decrease in cash interest
expense on debt. We also plan to contribute approximately $45.0 million of
additional funds to ACC over the remainder of 2015. See Note 8 of the Condensed
Notes to Consolidated Financial Statements included in “Item 1. Consolidated
Financial Statements (Unaudited)” for additional information regarding our
long-term debt and “Item 3. Quantitative and Qualitative Disclosures About
Market Risk” for information regarding the interest on our long-term debt and
information on changes in the fair value of our open derivative obligations
during the three months ended March 31,
2015.
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), borrowings under our credit facility and proceeds from bond and
equity offerings. We believe our 2015 expected capital expenditures will exceed our 2015 cash
flow, and we have funded, and expect to continue to fund, the difference with
cash on hand and borrowings under our credit facility. We believe that we have
adequate availability under our credit facility to fund any cash flow deficits.
The following table summarizes our changes in
cash and cash equivalents for the three months ended March 31, 2015
and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in thousands)
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
126,249
|
|
$
|
475,980
|
Net cash used in investing activities
|
|
|
(651,764)
|
|
|
(574,696)
|
Net cash provided by financing activities
|
|
|
525,515
|
|
|
98,716
|
|
Net increase (decrease) in cash and cash equivalents
|
|
$
|
-
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operating activities. The decrease in operating cash flows during the three months ended March
31, 2015 as compared to the same period in
2014 was primarily due to (i) a decrease in
oil and natural gas revenues of approximately $247.4 million, (ii)
approximately $91.2 million of negative variances in operating assets and
liabilities and (iii) a cash increase in general and administrative expense of
approximately $7.0 million.
Our net cash provided by operating activities included a
reduction of approximately $44.9 million and
an increase of approximately $46.3 million for
the three months ended March 31, 2015 and 2014,
respectively, associated with changes in working capital items. Changes in
working capital items adjust for the timing of receipts and payments of actual
cash.
Cash flow used in investing activities. During the three months ended March 31, 2015
and 2014, we invested approximately $790.8 million and $554.3 million,
respectively, for capital expenditures on oil and natural gas properties. Also,
cash flows used in investing activities increased during the three months ended
March 31, 2015 as compared to 2014 related to (i) contributions to our equity
method investment of approximately $20.0 million during the three months ended
March 31, 2015 and (ii) $8.1 million of investment in other property and
equipment during the three months ended March 31, 2015 compared to $5.6 million
during the comparative period of 2014, partially offset by 2015 settlements
received on derivatives not designated as hedges of approximately $167.2
million during the three months ended March 31, 2015 compared to payments of
approximately $14.8 million during the three months ended March 31, 2014.
Cash flow from financing activities. Net cash provided by
financing activities was approximately $525.5 million and $98.7 million for the
three months ended March 31, 2015 and 2014, respectively.
In March 2015, we issued 6.9
million shares of our common stock in a secondary public offering at
$107.49 per share and received net proceeds of approximately
$741.2 million. We used a portion of the net proceeds from this offering
to repay all outstanding borrowings under our credit facility and the remainder
for general corporate purposes.
At March 31,
2015, we had unused commitments of
approximately $2.5 billion based on bank commitments of $2.5 billion. The maturity
date of the credit facility is May 9, 2019.
Advances on our amended and restated credit
facility bear interest, at our option, based on (i) the prime rate of JPMorgan
Chase Bank (“JPM Prime Rate”) or (ii) a Eurodollar rate (substantially equal to
the London Interbank Offered Rate). The amended and restated credit facility’s
interest rates of Eurodollar rate advances and JPM Prime Rate advances varied,
with interest margins ranging from 125 to 225 basis points and 25 to 125 basis
points, respectively, per annum depending on the utilization of the borrowing
base. We pay commitment fees on the unused portion of the available commitment
ranging from 30.0 to 37.5 basis points per annum, depending on utilization of
the borrowing base. Subject to certain restrictions, with respect to our public
debt ratings, the collateral securing the facility may be released.
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. Over the last three years, we have
demonstrated our use of the capital markets by issuing common stock and senior
unsecured debt. There are no assurances that we can access the capital markets
to obtain additional funding, if needed, and at cost and terms that are
favorable to us. We may also sell assets and issue securities in
exchange for oil and natural gas assets or interests in oil and natural gas
companies. Additional securities may be of a class senior to common stock with
respect to such matters as dividends and liquidation rights and may also have
other rights and preferences as determined from time to time by our board of
directors. Utilization of some of these financing sources may require approval
from the lenders under our credit facility.
Liquidity. Our
principal sources of liquidity are cash on hand and available borrowing
capacity under our credit facility. At March
31, 2015, we had $21,000 of cash on hand.
At March 31,
2015, commitments from our bank group totaled $2.5
billion. In April 2015, we amended our credit agreement, which removed the
current ratio financial covenant and reaffirmed our borrowing base of
$3.25 billion. There is no assurance that our borrowing base will not be
reduced, which could affect our liquidity. Upon a redetermination, our borrowing base could
be substantially reduced.
Debt ratings. We receive debt credit ratings from Standard & Poor’s
Ratings Group, Inc. (“S&P”) and Moody’s Investors Service, Inc.
(“Moody’s”), which are subject to regular reviews. S&P’s corporate rating
for us is “BB+” with a stable outlook. Moody’s corporate rating for us is “Ba2”
with a positive outlook. S&P and Moody’s consider many factors in
determining our ratings including: production growth opportunities, liquidity,
debt levels and asset and reserve mix. A reduction in our debt ratings could
negatively affect our ability to obtain additional financing or the interest
rate, fees and other terms associated with such additional financing.
Book capitalization and current ratio. Our book capitalization at March 31, 2015 was $9.4 billion, consisting of debt of $3.4 billion and stockholders’ equity of $6.0 billion. Our debt to book capitalization was 36 percent and 40 percent at
March 31, 2015
and December 31, 2014, respectively. Our ratio of current assets to current
liabilities was 0.94 to 1.0 at March 31, 2015 as compared
to 0.83 to 1.0 at December 31, 2014.
Inflation and changes in prices. Our revenues, the value of our assets, and our ability to
obtain bank financing or additional capital on attractive terms have been and
will continue to be affected by changes in commodity prices and the costs to
produce our reserves. Commodity prices are subject to significant fluctuations
that are beyond our ability to control or predict. During the three months
ended March 31, 2015, we received an average of $43.34
per Bbl of oil and $2.78 per Mcf of
natural gas before consideration of commodity derivative contracts compared to
$92.35 per Bbl of oil and $6.12 per Mcf of natural gas in the three months ended March 31, 2014. Although
certain of our costs are affected by general inflation, inflation does not
normally have a significant effect on our business.
Critical
Accounting Policies, Practices and Estimates
Our historical consolidated financial statements and related
condensed notes to consolidated financial statements contain information that
is pertinent to our management’s 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 management’s opinion, the more significant reporting
areas impacted by management’s judgments and estimates are 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, valuation of stock-based compensation, valuation of business
combinations, valuation of financial derivative instruments and income taxes.
Management’s judgments and estimates in these areas are based on information
available from both internal and external sources, including engineers,
geologists and historical experience in similar matters. Actual results could
differ from the estimates as additional information becomes known.
There have been no material changes in our critical
accounting policies and procedures during the three months ended March 31,
2015. See our disclosure of critical accounting policies in “Item 8. Financial
Statements and Supplementary Data” of our Annual Report on Form 10-K for the
year ended December 31, 2014, filed with the United States Securities and
Exchange Commission (the “SEC”) on February 26, 2015.
Recent accounting pronouncements. In April 2015, the FASB issued ASU No. 2015-03, “Interest–Imputation
of Interest (Subtopic 835-30),” that requires debt issuance costs related to a
recognized debt liability be presented as a direct deduction from the carrying
amount of that debt liability. We currently present debt issuance costs on the
balance sheet as an asset. The new standard does not impact current recognition
or measurement guidance for debt issuance costs.
An entity is required to apply ASU 2015-03 for fiscal years
beginning after December 15, 2015, and interim periods within those fiscal
years. Early adoption of the new standard is permitted. We are evaluating the
impact that this new guidance will have on our balance sheet presentation of
debt issuance costs.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue
from Contracts with Customers (Topic 606),” that outlines a new, single
comprehensive model for entities to use in accounting for revenue arising from
contracts with customers and supersedes most current revenue recognition
guidance, including industry-specific guidance. This new revenue recognition
model provides a five-step analysis in determining when and how revenue is
recognized. The new model will require revenue recognition to depict the
transfer of promised goods or services to customers in an amount that reflects
the consideration a company expects to receive in exchange for those goods or
services.
An entity is required to apply ASU 2014-09 for annual
reporting periods beginning after December 15, 2016, and interim periods within
those annual periods. An entity can apply ASU 2014-09 using either a full
retrospective method, meaning the standard is applied to all of the periods
presented, or a modified retrospective method, meaning the cumulative effect of
initially applying the standard is recognized in the most current period
presented in the financial statements. We are evaluating the impact that this
new guidance will have on our consolidated financial statements.
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,
2014.
We are exposed to
a variety of market risks including credit risk, commodity price risk and
interest rate risk. We address these risks through a program of risk management
which includes the use of derivative instruments. The following quantitative
and qualitative information is provided about financial instruments to which we
are a party at March 31, 2015, 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 counterparty’s creditworthiness. Although we have not
generally required our counterparties to provide collateral to support their
obligation to us, we may, if circumstances dictate, require collateral in the
future. In this manner, we reduce credit risk.
We have entered into International Swap Dealers Association
Master Agreements (“ISDA Agreements”) with each of our derivative
counterparties. The terms of the ISDA Agreements provide us and the
counterparties with rights of set off upon the occurrence of defined acts of
default by either us or a counterparty to a derivative, whereby the party not
in default may set off all derivative liabilities owed to the defaulting party
against all derivative asset receivables from the defaulting party. See Note 7 of the Condensed Notes to Consolidated Financial
Statements included in “Item 1. Consolidated Financial Statements
(Unaudited)” for additional information regarding our derivative activities.
Commodity price risk. We are exposed to market risk as the prices of our
commodities are subject to fluctuations resulting from changes in supply and
demand. To reduce our exposure to changes in the prices of our commodities, we
have entered into, and may in the future enter into, additional commodity price
risk management arrangements for a portion of our oil and natural gas
production. The agreements that we have entered into generally have the effect
of providing us with a fixed price for a portion of our expected future oil and
natural gas production over a fixed period of time. Our commodity price risk
management arrangements are recorded at fair value and thus changes to the
future commodity prices will have an impact on net income. The following table
sets forth the hypothetical impact on the fair value of the commodity price
risk management arrangements from an average increase and decrease in the
commodity price of $10.00 per Bbl of oil and $1.00 per MMBtu of natural gas
from the commodity prices at March 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase of
|
|
|
Decrease of
|
|
|
|
|
|
|
|
|
$10 per Bbl and
|
|
|
$10 per Bbl and
|
(in thousands)
|
|
$1 per MMBtu
|
|
|
$1 per MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss):
|
|
|
|
|
|
|
Oil derivatives
|
$
|
(255,561)
|
|
$
|
255,561
|
|
Natural gas derivatives
|
|
(16,357)
|
|
|
16,357
|
|
|
Total
|
$
|
(271,918)
|
|
$
|
271,918
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At March 31, 2015, we had (i)
oil price swaps that settle on a monthly basis covering future oil production
from April 1, 2015 through June 30, 2017 and (ii) oil basis swaps covering our
Midland to Cushing basis differential from April 1, 2015 to December 31, 2016. See Note 7 of the
Condensed Notes to Consolidated Financial Statements included in “Item 1.
Consolidated Financial Statements (Unaudited)” for additional information on
our commodity derivative instruments. The average NYMEX oil price for the three months
ended March 31, 2015 was $48.80 per Bbl. At May 1, 2015, the NYMEX oil price was $59.15 per Bbl.
At March 31, 2015, we had (i) natural gas price swaps that settle on a
monthly basis covering future natural gas production from April 1, 2015 to
December 31, 2015 and (ii) natural gas basis swaps covering our basis
differential between the El Paso Permian delivery point and the NYMEX-Henry Hub
delivery point from April 1, 2015 to December 31, 2015. See Note 7 of the
Condensed Notes to Consolidated Financial Statements included in “Item 1.
Consolidated Financial Statements (Unaudited)” for additional information on
our commodity derivative instruments. The average NYMEX natural gas price for
the three months
ended March 31, 2015
was $2.82 per MMBtu. At May 1, 2015, the
NYMEX natural gas price was $2.78 per MMBtu.
A decrease in the average forward NYMEX oil and natural gas
prices below those at March 31, 2015, would increase the fair value asset of our commodity
derivative contracts from their recorded balance at March 31, 2015. Changes in
the recorded fair value of the undesignated commodity derivative contracts are
marked to market through earnings as gains or losses. The potential
increase in our fair value asset would be recorded in earnings as a
gain. However, an increase in the average forward NYMEX oil and natural gas
prices above those at March 31, 2015 would decrease the fair value asset of our commodity
derivative contracts from their recorded balance at March 31, 2015. The
potential decrease in our fair value asset would be recorded in earnings as a
loss. 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.
The fair value of our derivative instruments is determined
based on our valuation models. We did not change our valuation method during
the three months ended March 31, 2015 for our
derivative instruments. See Note 7 of the Condensed Notes to Consolidated Financial
Statements included in “Item 1. Consolidated Financial Statements (Unaudited)”
for additional information regarding our derivative instruments. The following
table reconciles the changes that occurred in the fair values of our derivative
instruments during the three months ended March
31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivative
|
|
|
|
|
|
|
|
|
Instruments
|
(in thousands)
|
Net Assets (Liabilities) (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts outstanding at December 31, 2014
|
|
$
|
752,701
|
|
|
Changes in fair values (b)
|
|
|
115,340
|
|
|
Contract maturities
|
|
|
(167,156)
|
|
Fair value of contracts outstanding at March 31, 2015
|
|
$
|
700,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 may, in the future, enter into 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 borrowing base.
We had no indebtedness outstanding under our credit
facility at March 31, 2015.
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 March 31, 2015 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.
PART II – OTHER INFORMATION
Item 1.
Legal Proceedings
We are a party to 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. We will continue to evaluate
proceedings and claims involving us on a regular basis and will establish and
adjust any reserves as appropriate to reflect our assessment of the then
current status of the matters.
Item 1A.
Risk Factors
In addition to the other information set forth in this
Quarterly Report on Form 10-Q, you should carefully consider the risks
discussed in our Annual Report on Form 10-K for the year ended December 31,
2014, under the headings “Item 1. Business — Competition,” “— Marketing Arrangements”
and “— Applicable Laws and Regulations,” “Item 1A. Risk Factors,” “Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of
Operations” and “Item 7A. Quantitative and Qualitative Disclosure About Market
Risk,” which risks could materially affect our business, financial condition or
future results. There have been no material changes in our risk factors from
those described in our Annual Report on Form 10-K for the year ended December
31, 2014. The risks described in our Annual Report on Form 10-K for the year
ended December 31, 2014 are not the only risks we face. Additional risks and
uncertainties not currently known to us or that we currently deem to be
immaterial also may materially adversely affect our business, financial condition
or future results.
Item 2. Unregistered
Sales of Equity Securities and Use of Proceeds
Period
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Total number of shares withheld (a)
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Average price per share
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Total number of shares purchased as part of publicly
announced plans
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Maximum number of shares that may yet be purchased under
the plan
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January 1, 2015 - January 31, 2015
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14,451
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$
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100.18
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-
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February 1, 2015 - February 28, 2015
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14,494
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$
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117.51
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-
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March 1, 2015 - March 31, 2015
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-
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$
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-
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-
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(a)
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Represents shares that were
withheld by us to satisfy tax withholding obligations of certain of our
officers and key employees that arose upon the lapse of restrictions on
restricted stock.
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Item 6. Exhibits
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Exhibit
Number
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Exhibit
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3.1
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Restated Certificate of Incorporation (filed as Exhibit 3.1 to
the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated
herein by reference).
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3.2
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Second Amended and Restated Bylaws of Concho Resources Inc., as
amended November 7, 2012 (filed as Exhibit 3.1 to the Company’s Current
Report on Form 8-K on November 8, 2012, and incorporated herein by reference).
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4.1
10.1
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Specimen Common Stock Certificate (filed as Exhibit 4.1 to the
Company’s Annual Report on Form 10-K on February 22, 2013, and
incorporated herein by reference).
First Amendment to Second Amended and Restated Credit Agreement,
dated as of April 8, 2015, among Concho Resources Inc., the lenders party
thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as
Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 9, 2015,
and incorporated herein by reference).
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31.1 (a)
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Certification of Chief Executive Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
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31.2 (a)
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Certification of Chief Financial Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
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32.1 (b)
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Certification of Chief Executive Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
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32.2 (b)
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Certification of Chief Financial Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
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101.INS (a)
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XBRL Instance Document.
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101.SCH (a)
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XBRL Schema Document.
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101.CAL (a)
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XBRL Calculation Linkbase Document.
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101.DEF (a)
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XBRL
Definition Linkbase Document.
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101.LAB (a)
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XBRL
Labels Linkbase Document.
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101.PRE (a)
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XBRL
Presentation Linkbase Document.
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(a)
Filed herewith.
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.
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Date:
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May 5, 2015
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By
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/s/ Timothy A.
Leach
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Timothy A. Leach
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Director, Chairman of the Board of Directors, Chief Executive
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Officer and President
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(Principal Executive Officer)
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By
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/s/ Darin G. Holderness
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Darin G. Holderness
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Senior Vice President and Chief Financial Officer
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(Principal Financial Officer)
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By
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/s/ Brenda R. Schroer
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Brenda R. Schroer
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Vice President and Chief Accounting Officer
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(Principal Accounting Officer)
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EXHIBIT INDEX
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Exhibit
Number
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Exhibit
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3.1
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Restated Certificate of Incorporation (filed as Exhibit 3.1 to
the Company’s Current Report on Form 8-K on August 8, 2007, and
incorporated herein by reference).
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3.2
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Second Amended and Restated Bylaws of Concho Resources Inc., as
amended November 7, 2012 (filed as Exhibit 3.1 to the Company’s Current
Report on Form 8-K on November 8, 2012, and incorporated herein by reference).
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4.1
10.1
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Specimen Common Stock Certificate (filed as Exhibit 4.1 to the
Company’s Annual Report on Form 10-K on February 22, 2013, and
incorporated herein by reference).
First Amendment to Second Amended and Restated Credit Agreement,
dated as of April 8, 2015, among Concho Resources Inc., the lenders party
thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as
Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 9, 2015,
and incorporated herein by reference).
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31.1 (a)
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Certification of Chief Executive Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
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31.2 (a)
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Certification of Chief Financial Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
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32.1 (b)
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Certification of Chief Executive Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
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32.2 (b)
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Certification of Chief Financial Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
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101.INS (a)
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XBRL Instance Document.
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101.SCH (a)
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XBRL Schema Document.
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101.CAL (a)
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XBRL Calculation Linkbase Document.
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101.DEF (a)
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XBRL
Definition Linkbase Document.
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101.LAB (a)
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XBRL
Labels Linkbase Document.
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101.PRE (a)
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XBRL
Presentation Linkbase Document.
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(a)
Filed herewith.
EXHIBIT
31.1
CERTIFICATIONS
I,
Timothy A. Leach, certify that:
1. I
have reviewed this quarterly report of Concho Resources Inc. (the
“registrant”);
2. Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and
for, the periods presented in this report;
4. The
registrant’s other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant
and have:
(a) Designed
such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b) Designed
such internal control over financial reporting, or caused such internal control
over financial reporting to be designed under our supervision, to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
(c) Evaluated
the effectiveness of the registrant’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of the end of the period covered by this
report based on such evaluation; and
(d) Disclosed
in this report any change in the registrant’s internal control over financial
reporting that occurred during the registrant’s most recent fiscal quarter (the
registrant’s fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5. The
registrant’s other certifying officer and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
(a)
All
significant deficiencies and material weaknesses in the design or operation of internal
control over financial reporting which are reasonably likely to adversely
affect the registrant’s ability to record, process, summarize and report
financial information; and
(b)
Any
fraud, whether or not material, that involves management or other employees who
have a significant role in the registrant’s internal control over financial
reporting.
Date:
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May 5, 2015
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/s/ Timothy A.
Leach
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Timothy A. Leach
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Director, Chairman of the Board of Directors, Chief Executive
Officer
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and President
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(Principal Executive Officer)
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EXHIBIT
31.2
CERTIFICATIONS
I,
Darin G. Holderness, certify that:
1. I
have reviewed this quarterly report of Concho Resources Inc. (the
“registrant”);
2. Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and
for, the periods presented in this report;
4. The
registrant’s other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant
and have:
(a) Designed
such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b) Designed
such internal control over financial reporting, or caused such internal control
over financial reporting to be designed under our supervision, to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
(c) Evaluated
the effectiveness of the registrant’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of the end of the period covered by this
report based on such evaluation; and
(d) Disclosed
in this report any change in the registrant’s internal control over financial
reporting that occurred during the registrant’s most recent fiscal quarter (the
registrant’s fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5. The
registrant’s other certifying officer and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
(a) All
significant deficiencies and material weaknesses in the design or operation of internal
control over financial reporting which are reasonably likely to adversely
affect the registrant’s ability to record, process, summarize and report
financial information; and
(b) Any
fraud, whether or not material, that involves management or other employees who
have a significant role in the registrant’s internal control over financial
reporting.
Date:
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May 5, 2015
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/s/ Darin G. Holderness
|
|
|
|
|
|
|
|
Darin G. Holderness
|
|
|
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Senior Vice President and Chief Financial Officer
|
|
|
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(Principal Financial Officer)
|
EXHIBIT
32.1
Certification of Chief Executive Officer
of Concho Resources Inc.
(Pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002)
In
connection with the quarterly report of Concho Resources Inc. (the “Company”),
as filed with the Securities and Exchange Commission on the date hereof (the
“Report”), Timothy A. Leach, Chief Executive Officer of the Company, hereby
certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002, that, to his knowledge:
(1) the
Report fully complies with the requirements of Section 13(a) or 15(d) of
the Securities Exchange Act of 1934, as amended; and
(2) the
information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of the Company.
Date:
|
May 5, 2015
|
|
/s/ Timothy A.
Leach
|
|
|
|
|
|
|
|
Timothy A. Leach
|
|
|
|
Director, Chairman of the Board of Directors, Chief Executive
Officer
|
|
|
|
and President
|
|
|
|
(Principal Executive Officer)
|
EXHIBIT
32.2
Certification of Chief Financial Officer
of Concho Resources Inc.
(Pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002)
In
connection with the quarterly report of Concho Resources Inc. (the “Company”),
as filed with the Securities and Exchange Commission on the date hereof (the
“Report”), Darin G. Holderness, Chief Financial Officer of the Company, hereby
certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:
(1) the
Report fully complies with the requirements of Section 13(a) or 15(d) of
the Securities Exchange Act of 1934, as amended; and
(2) the
information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of the Company.
Date:
|
May 5, 2015
|
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/s/ Darin G. Holderness
|
|
|
|
|
|
|
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Darin G. Holderness
|
|
|
|
Senior Vice President and Chief Financial Officer
|
|
|
|
(Principal Financial Officer)
|
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