e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the year ended December 31,
2008
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or
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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
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Commission file
number: 1-33615
Concho Resources Inc.
(Exact name of registrant as
specified in its charter)
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Delaware
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76-0818600
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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550 West Texas Avenue, Suite 100
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
(Registrants telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange On Which Registered
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Common Stock, $0.001 par value
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New York Stock Exchange
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Securities Registered Pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act of
1933. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large
accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller
reporting
company o
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(Do not
check if a smaller reporting company)
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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 þ
Aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the price
at which the common equity was last sold, or the average bid and
asked price of such common equity, as of the last business day
of the registrants most recently completed second fiscal
quarter:
$1,993,092,788
Number of shares of registrants common stock outstanding
as of February 19,
2009: 84,913,298
Documents Incorporated by Reference:
Portions of the registrants definitive proxy statement for
its 2009 Annual Meeting of Stockholders, which will be filed
with the Securities and Exchange Commission within 120 days
of December 31, 2008, are incorporated by reference into
Part III of this report for the year ended
December 31, 2008.
Table of
Contents
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1
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2
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PART I
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6
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12
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31
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33
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34
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34
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34
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PART II
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35
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35
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35
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38
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42
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i
CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This report may contain forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as
amended, (the Securities Act) and Section 21E
of the Securities Exchange Act of 1934, as amended, (the
Exchange Act) that are subject to a number of risks
and uncertainties, many of which are beyond our control. All
statements, other than statements of historical fact included in
this report, regarding our strategy, future operations,
financial position, estimated revenues and losses, projected
costs, prospects, plans and objectives of management are
forward-looking statements. When used in this report, the words
could, believe, anticipate,
intend, estimate, expect,
may, continue, predict,
potential, project and similar
expressions are intended to identify forward-looking statements,
although not all forward-looking statements contain such
identifying words. In particular, the factors discussed below
and elsewhere in this report could affect our actual results and
cause our actual results to differ materially from expectations,
estimates, or assumptions expressed in, forecasted in, or
implied in such forward-looking statements.
Forward-looking statements may include statements about:
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our business and financial strategy;
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the estimated quantities of crude oil and natural gas reserves;
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our use of industry technology;
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our realized crude oil and natural gas prices;
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the timing and amount of the future production of our crude oil
and natural gas;
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the amount, nature and timing of our capital expenditures;
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the drilling of our wells;
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our competition and government regulations;
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the marketing of our crude oil and natural gas;
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our exploitation activities or property acquisitions;
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the costs of exploiting and developing our properties and
conducting other operations;
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general economic and business conditions;
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our cash flow and anticipated liquidity;
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uncertainty regarding our future operating results;
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our plans, objectives, expectations and intentions contained in
this report that are not historical; and
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our ability to integrate acquisitions.
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You should not place undue reliance on these forward-looking
statements. All forward-looking statements speak only as of the
date of this report. We do not undertake any obligation to
release publicly any revisions to any forward-looking statements
to reflect events or circumstances after the date of this report
or to reflect the occurrence of unanticipated events, except as
required by law.
Although we believe that our plans, objectives, expectations and
intentions reflected in or suggested by the forward-looking
statements we make in this report are reasonable, we can give no
assurance that they will be achieved. These cautionary
statements qualify all forward-looking statements attributable
to us or persons acting on our behalf.
1
GLOSSARY
OF TERMS
The following terms are used throughout this report:
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Bbl |
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One stock tank barrel, of 42 U.S. gallons liquid volume, used
herein in reference to crude oil, condensate or natural gas
liquids. |
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Boe |
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One barrel of crude oil equivalent, a standard convention used
to express oil and natural gas volumes on a comparable oil
equivalent basis. Natural gas equivalents are determined under
the relative energy content method by using the ratio of
6.0 Mcf of gas to 1.0 Bbl of oil or condensate. |
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Bcfe |
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One billion cubic feet of natural gas equivalent using the ratio
of one barrel of crude oil, condensate or natural gas liquids to
six Mcf of natural gas. |
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Basin |
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A large natural depression on the earths surface in which
sediments accumulate. |
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Development wells |
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Wells drilled within the proved area of an oil or gas reservoir
to the depth of a stratigraphic horizon known to be productive. |
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Dry hole |
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A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such
production would exceed production expenses, taxes and the
royalty burden. |
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Exploitation |
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A drilling or other project which may target proven or unproven
reserves (such as probable or possible reserves), but which
generally is reasonably expected to have lower risk. |
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Exploratory wells |
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Wells drilled to find and produce oil or gas in an unproved
area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a
known reservoir. |
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Field |
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An area consisting of a single reservoir or multiple reservoirs
all grouped on, or related to, the same individual geological
structural feature or stratigraphic condition. The field name
refers to the surface area, although it may refer to both the
surface and the underground productive formations. |
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Gross wells |
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The number of wells in which a working interest is owned. |
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Horizontal drilling |
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A drilling technique used in certain formations where a well is
drilled vertically to a certain depth and then drilled at a high
angle to vertical (which can be greater than 90 degrees) in
order to stay within a specified interval. |
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Infill wells |
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Wells drilled into the same pool as known producing wells so
that oil or natural gas does not have to travel as far through
the formation. |
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LIBOR |
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London Interbank Offered Rate, which is a market rate of
interest. |
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MBbl |
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One thousand barrels of crude oil, condensate or natural gas
liquids. |
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MBoe |
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One thousand Boe. |
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Mcf |
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One thousand cubic feet of natural gas. |
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MMBbl |
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One million barrels of crude oil, condensate or natural gas
liquids. |
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MMBoe |
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One million Boe. |
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MMBtu |
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One million British thermal units. |
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MMcf |
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One million cubic feet of natural gas. |
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NYMEX |
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The New York Mercantile Exchange. |
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NYSE |
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The New York Stock Exchange. |
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Net acres |
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The percentage of total acres an owner owns out of a particular
number of acres within a specified tract. For example, an owner
who has a 50 percent interest in 100 acres owns
50 net acres. |
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Net revenue interest |
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A working interest owners gross working interest in
production, less the related royalty, overriding royalty,
production payment, and net profits interests. |
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Net wells |
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The total of fractional working interests owned in gross wells. |
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PV-10 |
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When used with respect to oil and natural gas reserves,
PV-10 means
the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production and
future development and abandonment costs, using prices and costs
in effect at the determination date, before income taxes, and
without giving effect to non-property-related expenses except
for specific general and administrative expenses incurred to
operate the properties, discounted to a present value using an
annual discount rate of 10 percent. |
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Primary recovery |
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The period of production in which oil and natural gas is
produced from its reservoir through the wellbore without
enhanced recovery technologies, such as water flooding or gas
injection. |
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Productive wells |
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Wells that produce commercial quantities of hydrocarbons,
exclusive of their capacity to produce at a reasonable rate of
return. |
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Proved developed reserves |
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Has the meaning given to such term in
Rule 4-10(a)(3)
of
Regulation S-X,
which defines proved developed reserves as: |
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Proved developed oil and gas reserves are reserves that can be
expected to be recovered through existing wells with existing
equipment and operating methods. Additional oil and gas expected
to be obtained through the application of fluid injection or
other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as
proved developed reserves only after testing by a pilot project
or after the operation of an installed program has confirmed
through production response that increased recovery will be
achieved. |
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Proved reserves |
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Has the meaning given to such term in
Rule 4-10(a)(2)
of
Regulation S-X,
which defines proved reserves as: |
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Proved oil and gas reserves are the estimated quantities of
crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future
conditions. |
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(i) Reservoirs are considered proved if economic
producibility is supported by either actual production or
conclusive formation test. The area of a reservoir considered
proved includes (a) that portion delineated by drilling and
defined by gas-oil and/or oil-water contacts, if any, and
(b) the immediately adjoining portions not yet drilled, but
which can be reasonably judged as economically productive on the
basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir.
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(ii) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid
injection) are included in the proved classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
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(iii) Estimates of proved reserves do not include the
following: (a) oil that may become available from known
reservoirs but is classified separately as indicated additional
reserves; (b) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt
because of uncertainty as to geology, reservoir characteristics,
or economic factors; (c) crude oil, natural gas, and
natural gas liquids, that may occur in undrilled prospects; and
(d) crude oil, natural gas, and natural gas liquids, that
may be recovered from oil shales, coal, gilsonite and other such
sources.
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Proved undeveloped reserves |
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Has the meaning given to such term in
Rule 4-10(a)(4)
of
Regulation S-X,
which defines proved undeveloped reserves as: |
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Proved undeveloped oil and gas reserves are reserves that are
expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is
required for recompletion. Reserves on undrilled acreage shall
be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved
reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of
production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves
be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual
tests in the area and in the same reservoir. |
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Recompletion |
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The addition of production from another interval or formation in
an existing wellbore. |
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Reservoir |
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A formation beneath the surface of the earth from which
hydrocarbons may be present. Its
make-up is
sufficiently homogenous to differentiate it from other
formations. |
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SEC |
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The United States Securities and Exchange Commission. |
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Secondary recovery |
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The recovery of oil and gas through the injection of liquids or
gases into the reservoir, supplementing its natural energy.
Secondary |
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recovery methods are often applied when production slows due to
depletion of the natural pressure. |
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Seismic survey |
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Also known as a seismograph survey, is a survey of an area by
means of an instrument which records the travel time of the
vibrations of the earth. By recording the time interval between
the source of the shock wave and the reflected or refracted
shock waves from various formations, geophysicists are better
able to define the underground configurations. |
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Spacing |
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The distance between wells producing from the same reservoir.
Spacing is expressed in terms of acres, e.g.,
40-acre
spacing, and is established by regulatory agencies. |
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Standardized measure |
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The present value (discounted at an annual rate of 10%) of
estimated future net revenues to be generated from the
production of proved reserves net of estimated income taxes
associated with such net revenues, as determined in accordance
with Statement of Financial Accounting Standards No. 69
(using prices and costs in effect as of the period end date)
without giving effect to non-property related expenses such as
indirect general and administrative expenses, and debt service
or to depreciation, depletion and amortization. Standardized
measure does not give effect to derivative transactions. |
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Step-out drilling |
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The drilling of a well adjacent to existing production in an
effort to expand the aerial extent of a known producing field. |
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Undeveloped acreage |
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Acreage owned or leased on which wells can be drilled or
completed to a point that would permit the production of
commercial quantities of oil and natural gas regardless of
whether such acreage contains proved reserves. |
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Unit |
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The joining of all or substantially all interests in a reservoir
or field, rather than single tracts, to provide for development
and operation without regard to separate property interests.
Also, the area covered by a unitization agreement. |
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Wellbore |
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The hole drilled by the bit that is equipped for oil or gas
production on a completed well. Also called a well or borehole. |
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Working interest |
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The right granted to the lessee of a property to explore for and
to produce and own oil, gas, or other minerals. The working
interest owners bear the exploration, development, and operating
costs on either a cash, penalty, or carried basis. |
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Workover |
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Operations on a producing well to restore or increase production. |
5
PART I
General
Concho Resources Inc., a Delaware corporation
(Concho, Company, we,
us and our) is an independent oil and
natural gas company engaged in the acquisition, development,
exploitation and exploration of oil and natural gas properties.
Our core operations are focused in the Permian Basin of
Southeastern New Mexico and West Texas. These core operating
areas are complemented by our activities in our emerging plays.
We intend to grow our reserves and production through
development drilling, exploitation and exploration activities on
our multi-year project inventory and through acquisitions that
meet our strategic and financial objectives.
We were formed in February 2006 as a result of the combination
of Concho Equity Holdings Corp. and a portion of the oil and
natural gas properties and related assets owned by Chase Oil
Corporation (Chase Oil) and certain of its
affiliates. Concho Equity Holdings Corp. was formed in April
2004 and represented the third of three Permian Basin-focused
companies that have been formed since 1997 by certain members of
our current management team (the prior two companies were sold
to large domestic independent oil and gas companies).
Henry
Entities Acquisition
On July 31, 2008, we closed our acquisition of Henry
Petroleum LP and certain entities affiliated with Henry
Petroleum LP (which we refer to collectively as the Henry
Entities), together with certain additional non-operated
interests in oil and gas properties from persons affiliated with
the Henry Entities. In August 2008 and September 2008, we
acquired additional non-operated interests in oil and gas
properties from persons affiliated with the Henry Entities. We
paid approximately $584.1 million in net cash for the
acquisition of the Henry Entities and the related acquisition of
the along-side interests, which was funded with
(i) borrowings under our credit facility and (ii) net
proceeds of approximately $242.4 million from our private
placement of 8,302,894 shares of our common stock. The oil
and gas assets acquired in the acquisition of the Henry Entities
and the along-side interests (which we refer to as the
Henry Properties) contained approximately
30.1 MMBoe of net proved reserves at the acquisition date.
Chase Oil
Transaction
On February 24, 2006, we entered into a combination
agreement in which we agreed to purchase oil and gas properties
owned by Chase Oil, Caza Energy LLC and other related working
interest owners (which we refer to collectively as the
Chase Group) and combine them with substantially all
of the outstanding equity interests of Concho Equity Holdings
Corp. to form our company. The initial closing of the
transactions contemplated by the combination agreement occurred
on February 27, 2006, and the members of the Chase Group
that sold their working interests to us then received
34,683,315 shares of our common stock and approximately
$400 million in cash. The oil and gas properties
contributed to us by the Chase Group are referred to as the
Chase Group Properties.
Business
and Properties
Our core operations are focused in the Permian Basin of
Southeastern New Mexico and West Texas. The Permian Basin is one
of the most prolific producing oil and gas regions in the United
States. It underlies an area of Southeastern New Mexico and West
Texas approximately 250 miles wide and 300 miles long.
Commercial accumulations of hydrocarbons occur in multiple
stratigraphic horizons, at depths ranging from approximately
1,000 feet to over 25,000 feet. This basin is
characterized by long life, shallow decline reserves. At
December 31, 2008, 97.9 percent of our total estimated
net proved reserves were located in our core operating areas and
consisted of approximately 62.9 percent crude oil and
37.1 percent natural gas. We refer to our core operating
areas as (i) New Mexico Permian and (ii) Texas
Permian. The Permian Basin is characterized by an extensive
production history, mature infrastructure, long reserve life,
multiple producing horizons, enhanced recovery potential and a
large number of operators. Producing horizons in our core
properties include (i) the Yeso in the New Mexico Permian,
which is located at depths ranging from 3,800 feet to
7,500 feet and (ii) the Wolfberry in the Texas
Permian, the term applied to the combined Wolfcamp and Spraberry
horizons, which is located at depths ranging from
7,000 feet to
6
10,500 feet. We have assembled a multi-year inventory of
development drilling and exploitation projects, including
projects to further evaluate the aerial extent of the Yeso
formation and the Wolfberry play, that we believe will allow us
to grow proved reserves and production. We also have significant
acreage positions in active emerging plays in the Lower Abo
horizontal play in Southeastern New Mexico and the Bakken/Three
Forks play in North Dakota. We view an emerging play as an area
where we can acquire large undeveloped acreage positions and
apply horizontal drilling, advanced fracture stimulation
and/or
enhanced recovery technologies to achieve economic and
repeatable production results.
In 2008, we drilled or participated in the drilling of
243 gross (157.2 net) wells, 86.8 percent of which
were completed as producers, 0.4 percent of which were dry
holes and 12.8 percent of which were awaiting completion at
December 31, 2008. In addition, in 2008, we recompleted or
participated in the recompletion of 242 gross (198.6 net)
wells, 90.9 percent of which were productive,
2.1 percent of which were unsuccessful and 7 percent
were still in progress at December 31, 2008. We increased
our total estimated net proved reserves by approximately
53.4 MMBoe, taking into account the effects of negative
price revisions (10.1 MMBoe) and acquisitions. We produced
approximately 7.1 MMBoe of oil and natural gas during 2008.
In addition, we increased our average net daily production from
15.6 MBoe during the first quarter of 2008 to
25.2 MBoe during the fourth quarter of 2008, including the
impact of the acquisition of the Henry Properties.
Drilling
Activities
The following table sets forth information with respect to wells
drilled and completed during the periods indicated. The
information should not be considered indicative of future
performance, nor should a correlation be assumed between the
number of productive wells drilled, quantities of reserves found
or economic value.
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Years Ended December 31,
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2008
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2007
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2006
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Development wells
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Productive
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118.0
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76.8
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60.0
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38.5
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93.0
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57.8
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Dry
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7.0
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2.4
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Exploratory wells
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Productive
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93.0
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63.2
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55.0
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48.0
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37.0
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25.4
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Dry
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1.0
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1.0
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2.0
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1.2
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3.0
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0.8
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Total wells
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Productive
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211.0
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140.0
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115.0
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86.5
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130.0
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83.2
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Dry
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1.0
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1.0
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|
|
|
2.0
|
|
|
|
1.2
|
|
|
|
10.0
|
|
|
|
3.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
212.0
|
|
|
|
141.0
|
|
|
|
117.0
|
|
|
|
87.7
|
|
|
|
140.0
|
|
|
|
86.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth information about our wells for
which drilling was in progress or are pending completion at
December 31, 2008, which are not included in the above
table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling In-progress
|
|
Pending Completion
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Development wells
|
|
|
7.0
|
|
|
|
5.4
|
|
|
|
17.0
|
|
|
|
10.2
|
|
Exploratory wells
|
|
|
4.0
|
|
|
|
1.7
|
|
|
|
14.0
|
|
|
|
6.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
11.0
|
|
|
|
7.1
|
|
|
|
31.0
|
|
|
|
16.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
Our
Production, Prices and Expenses
The following table sets forth summary information concerning
our production results, average sales prices and operating costs
and expenses for the years ended December 31, 2008, 2007
and 2006. The actual historical data in this table excludes
production from the (i) Chase Group Properties for periods
prior to February 27, 2006 and (ii) Henry Properties
for periods prior to August 1, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2008
|
|
2007
|
|
2006
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
4,586
|
|
|
|
3,014
|
|
|
|
2,295
|
|
Natural gas (MMcf)
|
|
|
14,968
|
|
|
|
12,064
|
|
|
|
9,507
|
|
Total (MBoe)
|
|
|
7,081
|
|
|
|
5,025
|
|
|
|
3,880
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
12,530
|
|
|
|
8,258
|
|
|
|
6,288
|
|
Natural gas (Mcf)
|
|
|
40,896
|
|
|
|
33,052
|
|
|
|
26,047
|
|
Total (Boe)
|
|
|
19,347
|
|
|
|
13,767
|
|
|
|
10,630
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without hedges (Bbl)
|
|
$
|
91.92
|
|
|
$
|
68.58
|
|
|
$
|
60.47
|
|
Oil, with hedges (Bbl)
|
|
$
|
85.25
|
|
|
$
|
64.90
|
|
|
$
|
57.42
|
|
Natural gas, without hedges (Mcf)
|
|
$
|
9.59
|
|
|
$
|
8.08
|
|
|
$
|
6.87
|
|
Natural gas, with hedges (Mcf)
|
|
$
|
9.54
|
|
|
$
|
8.18
|
|
|
$
|
7.00
|
|
Total, without hedges (Boe)
|
|
$
|
79.80
|
|
|
$
|
60.54
|
|
|
$
|
52.62
|
|
Total, with hedges (Boe)
|
|
$
|
75.38
|
|
|
$
|
58.56
|
|
|
$
|
51.12
|
|
Operating costs and expenses per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
$
|
6.70
|
|
|
$
|
5.96
|
|
|
$
|
5.69
|
|
Oil and gas production taxes
|
|
$
|
6.18
|
|
|
$
|
4.84
|
|
|
$
|
4.06
|
|
General and administrative
|
|
$
|
5.76
|
|
|
$
|
5.01
|
|
|
$
|
5.60
|
|
Depreciation, depletion and amortization
|
|
$
|
17.50
|
|
|
$
|
15.28
|
|
|
$
|
15.65
|
|
Summary
of Core Operating Areas and Emerging Plays
The following is a summary of information regarding our core
operating areas and emerging plays that are further described
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
|
|
|
|
|
|
|
2008 Average
|
|
|
Number of
|
|
|
|
|
|
|
Proved Reserves
|
|
|
Daily Sales
|
|
|
Net
|
|
|
Percent of
|
|
|
|
at December 31, 2008
|
|
|
Volumes
|
|
|
Producing
|
|
|
PV-10
|
|
|
|
MBoe
|
|
|
PV-10
|
|
|
(Boe)
|
|
|
Wells
|
|
|
Operated by Us
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
Core Operating Areas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Mexico Permian
|
|
|
95,055
|
|
|
$
|
1,242.8
|
|
|
|
14,664
|
|
|
|
1,020.5
|
|
|
|
94.6
|
%
|
Texas Permian
|
|
|
39,392
|
|
|
|
378.0
|
|
|
|
4,008
|
|
|
|
395.5
|
|
|
|
93.4
|
%
|
Emerging plays and other
|
|
|
2,828
|
|
|
|
42.4
|
|
|
|
675
|
|
|
|
13.7
|
|
|
|
47.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
137,275
|
|
|
$
|
1,663.2
|
|
|
|
19,347
|
|
|
|
1,429.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Core
Operating Areas
Our core operating areas are located in the Permian Basin region
of Southeastern New Mexico and West Texas, the largest onshore
oil and gas basin in the United States. We refer to our core
operating areas as the (i) New Mexico Permian and
(ii) Texas Permian. At December 31, 2008, our core
operating areas had estimated net proved reserves
8
of 134.4 MMBoe, which accounted for 97.9 percent of
our total estimated net proved reserves and 97.4 percent of
our PV-10.
At December 31, 2008, we owned interests in
3,403 gross wells in our core operating areas, of which we
operated 2,294 (gross). At December 31, 2008, in our core
operating areas, we had identified 3,465 drilling locations,
with proved undeveloped reserves attributed to 811 of such
locations, and 2,118 recompletion opportunities, with proved
reserves attributed to 916 of such opportunities.
New Mexico Permian. We acquired the
majority of our properties in this area from the Chase Group.
This area represents our most significant concentration of
assets and, at December 31, 2008, our estimated proved
reserves of 95.1 MMBoe in this area accounted for
69.2 percent of our total net proved reserves and
75.1 percent of our
PV-10.
During 2008, our average net daily production from this area was
approximately 14.7 MBoe per day, representing
75.6 percent of our total production for that time period.
Within this area we target two distinct producing areas, which
we refer to as the shelf properties and the basinal properties.
The shelf properties generally produce from the Yeso (Paddock
and Blinebry intervals), San Andres and Grayburg
formations, with producing depths generally ranging from
900 feet to 7,500 feet. The basinal properties
generally produce from the Strawn, Atoka and Morrow formations,
with producing depths generally ranging from 7,500 feet to
15,000 feet.
During 2008, we drilled or participated in the drilling of 142
(123.9 net) wells in this area, of which 132 (114.4 net) were
completed as producers, none were unsuccessful and 10 (9.5 net)
were awaiting completion at December 31, 2008. During 2008,
we (i) continued our development of the Blinebry interval
of the Yeso formation, the top of which is located approximately
400 feet below the top of the Paddock interval of the Yeso
formation, (ii) began our evaluation of drilling on
10 acre spacing in the Blinebry interval and
(iii) continued our evaluation of the use of larger
fracture stimulation procedures in the completion of certain
wells. In addition, we continued our pilot waterflood commenced
in September 2007 injecting water into the Paddock interval.
At December 31, 2008, we had 153,425 gross (71,423
net) acres in this area. At December 31, 2008, on our
properties in this area, we had identified 1,685 drilling
locations, with proved undeveloped reserves attributed to 355 of
such locations, and 1,908 recompletion opportunities, with
proved reserves attributed to 720 of such opportunities. Of the
drilling locations we identified 993 locations intended to
evaluate both the Blinebry and the Paddock intervals, while 17
locations are intended to evaluate only the Blinebry interval,
with proved undeveloped reserves attributed to 176 of such total
drilling locations.
Texas Permian. We acquired the majority
of our properties in this area in the Henry Properties
acquisition. At December 31, 2008, our estimated proved
reserves of 39.4 MMBoe in this area accounted for
28.7 percent of our total net proved reserves and
22.3 percent of our
PV-10.
During 2008, our average net daily production from this area was
approximately 4.0 MBoe per day, representing
20.7 percent of our total production for that time period.
The primary objective in the Texas Permian area is the Wolfberry
in the Midland Basin. Wolfberry is the term applied to the
combined Spraberry and Wolfcamp target interval which is
typically encountered at depths of 7,000 to 10,500 feet.
The Wolfberry is comprised of a sequence of basinal, interbedded
shales and carbonates. We also operate properties on the Central
Basin Platform where the Grayburg, San Andres and Clearfork
objectives are shallower, typically encountered at depths of
4,500 to 7,500 feet. The reservoirs in these formations are
largely carbonates, limestones and dolomites.
At December 31, 2008, we had 241,508 gross (69,727
net) acres in this area. In addition, at December 31, 2008,
we had identified 1,780 drilling locations, with proved
undeveloped reserves attributed to 456 of such locations, and
210 recompletion opportunities, with proved reserves attributed
to 196 of such opportunities.
During 2008, we drilled or participated in the drilling of 69
(24.9 net) wells in this area, of which 54 (20.1 net) were
completed as producers, none were unsuccessful and 15 (4.8 net)
wells were awaiting completion at December 31, 2008. In
addition, during 2008, we commenced the recompletion of
26 wells, 25 of which were producing at December 31,
2008 and 1 of which was unsuccessful.
9
Emerging
Plays
At December 31, 2008, we were actively involved in drilling
or participating in drilling activities in two emerging plays,
in which we held 68,337 gross (32,861 net) acres and
2.3 MMBoe of proved reserves.
Lower Abo horizontal play. The Lower
Abo horizontal play is an oil play along the northwestern rim of
the Delaware Basin in Lea, Eddy and Chaves Counties, New Mexico.
This play is found at vertical depths ranging from
6,500 feet to 9,000 feet and is being exploited
utilizing horizontal drilling techniques.
At December 31, 2008, we held interests in
25,535 gross (21,638 net) acres in this play. In 2008, we
drilled or participated in the drilling of 11 wells in this
play with 8 wells producing, 1 waiting on completion and
2 wells drilling at December 31, 2008. At
December 31, 2008, we had 2.1 MMBoe of proved reserves
in the play.
Bakken/Three Forks play. The
Bakken/Three Forks play is in the Williston Basin in North
Dakota, primarily in Mountrail and McKenzie Counties. This
Mississippian/Devonian age horizon consists of siltstones
encased within and below a highly organic oil-rich shale
package. This horizon is found at vertical depths ranging from
9,000 feet to 11,000 feet and is being exploited
utilizing horizontal drilling techniques.
At December 31, 2008, we held interests in
42,802 gross (11,223 net) acres in this play. In 2008, we
participated in the drilling of 17 wells in this play with
14 wells producing, 2 waiting on completion and 1 well
drilling at December 31, 2008. At December 31, 2008,
we had 0.2 MMBoe of proved reserves in the play.
Other emerging plays. We also own
interests in the following other emerging plays:
|
|
|
|
|
Central Basin Platform of West Texas, where we drilled one
unsuccessful Woodford shale exploratory well in 2008;
|
|
|
|
Western Delaware Basin of West Texas, where we drilled four
exploratory wells prior to 2008, targeting the Bone Springs,
Atoka, Barnett and Woodford shales, of which three were
unsuccessful and one was successful; and
|
|
|
|
Arkoma Basin in Arkansas, where, in 2008, we participated in the
drilling of three exploratory wells targeting both the Hale and
the Fayetteville shale, all of which were in various stages of
completion and evaluation at December 31, 2008.
|
Because of the current commodity price environment, the minimal
success from drilling in these three other emerging plays and
other activity in or around these three other emerging plays, we
are currently not actively pursuing further exploration
activities on these three other emerging plays. We are
evaluating our alternatives related to these three other
emerging plays.
Marketing
Arrangements
General. We market our crude oil and
natural gas in accordance with standard energy practices
utilizing certain of our employees and external consultants, in
each case in consultation with our chief financial officer and
our production engineers. The marketing effort is coordinated
with our operations group as it relates to the planning and
preparation of future drilling programs so that available
markets can be assessed and secured. This planning also involves
the coordination of procuring the physical facilities necessary
to connect new producing wells as efficiently as possible upon
their completion. When possible, we negotiate with our
purchasers on multiple well drilling programs in an attempt to
improve our economics on such wells due to the commitment of
potentially increased production volumes. Our current drilling
plans consist substantially of multiple well programs.
Crude Oil. We do not refine or process
the crude oil we produce. A significant portion of our crude oil
is connected directly to pipelines via gathering facilities in
the respective field locations throughout Southeastern New
Mexico, while a significant portion of our production in West
Texas is transported by truck. The oil is then delivered either
to hub facilities located in Midland, Texas or Cushing, Oklahoma
or to third party refineries located in Southeastern New Mexico
and the Panhandle and Gulf Coast area of Texas, with the
majority of our crude oil going to a refinery in Southeastern
New Mexico. This oil is also transported to the hub facilities
and refineries mentioned above. We sell the majority of the oil
we produce under short-term contracts using market sensitive
pricing. The majority of our contracts are based on a
Platts formula which is calculated based on an
intermediate posting
10
deemed 40 degrees (typically as published by major crude oil
purchasers at the Cushing, Oklahoma delivery point) for each
calendar month plus the average of the Platts P-Plus WTI
price as published monthly in the Platts Oilgram Price
Report. This price is then adjusted for differentials based upon
delivery location and oil quality.
Natural Gas. We consider all gas
gathering and delivery infrastructure in the areas of our
production and evaluate market options to obtain the best price
reasonably available under the circumstances. We sell the
majority of our gas under individually negotiated gas purchase
contracts using market sensitive pricing. The majority of our
gas is subject to term agreements that extend at least three
years from the date of the subject contract.
The majority of the gas we sell is casinghead gas sold at the
lease under a percentage of proceeds processing contract. The
purchaser gathers our casinghead gas in the field where produced
and transports it via pipeline to a gas processing plant where
the liquid products are extracted. The remaining gas product is
residue gas, or dry gas. Under our percentage of proceeds
contract, we receive a percentage of the value for the extracted
liquids and the residue gas. Each of the liquid products has its
own individual market and is therefore priced separately.
The remaining portion of our gas is dry gas, which is gathered
at the wellhead and delivered into the purchasers residue
or mainline transportation system. In many cases, the gas
gathering and transportation is performed by a third party
gathering company which transports the production from the
production location to the purchasers mainline. The
majority of our dry gas and residue gas is subject to term
agreements that extend at least three years from the date of the
subject contract.
Our
Principal Customers
We sell our oil and natural gas production principally to
marketers and other purchasers that have access to pipeline
facilities. In areas where there is no practical access to
pipelines, oil is transported to storage facilities by trucks
owned or otherwise arranged by the marketers or purchasers. Our
marketing of oil and natural gas can be affected by factors
beyond our control, the effects of which cannot be accurately
predicted.
For 2008, revenues from oil and natural gas sales to Navajo
Refining Company, L.P. and DCP Midstream, LP accounted for
approximately 59 percent and approximately 18 percent,
respectively, of our total operating revenues. While the loss of
either of these purchasers may result in a temporary
interruption in sales of, or a lower price for, our production,
we believe that the loss of either of these purchasers would not
have a material adverse effect on our operations, as there are
alternative purchasers in our producing regions.
Competition
The oil and natural gas industry in the regions in which we
operate is highly competitive. We encounter strong competition
from numerous parties, ranging generally from small independent
producers to major integrated oil companies. We primarily
encounter significant competition in acquiring properties,
contracting for drilling and workover equipment and securing
trained personnel. Many of these competitors have financial and
technical resources and staffs substantially larger than ours.
As a result, our competitors may be able to pay more for
desirable properties, or to evaluate, bid for and purchase a
greater number of properties or prospects than our financial or
personnel resources will permit.
We are also affected by competition for drilling rigs and the
availability of related equipment. The oil and natural gas
industry periodically experiences shortages of drilling and
workover rigs, equipment, pipe, materials and personnel, which
can delay developmental drilling, workover and exploitation
activities and caused significant price increases. The recent
shortage of personnel has also made it difficult to attract and
retain personnel with experience in the oil and gas industry and
has caused us to increase our general and administrative budget.
We are unable to predict the timing or duration of any such
shortages.
Competition is also strong for attractive oil and natural gas
producing properties, undeveloped leases and drilling rights.
Although we regularly evaluate acquisition opportunities and
submit bids as part of our growth strategy, we do not have any
current agreements, understandings or arrangements with respect
to any material acquisition.
11
Applicable
Laws and Regulations
Regulation
of the Oil and Natural Gas Industry
Regulation of transportation of
oil. Sales of crude oil, condensate and
natural gas liquids are not currently regulated and are made at
negotiated prices. Nevertheless, Congress could reenact price
controls in the future.
Our sales of crude oil are affected by the availability, terms
and cost of transportation. The transportation of oil in common
carrier pipelines is also subject to rate regulation. The
Federal Energy Regulatory Commission, or the FERC,
regulates interstate oil pipeline transportation rates under the
Interstate Commerce Act. In general, interstate oil pipeline
rates must be cost-based, although settlement rates agreed to by
all shippers are permitted and market-based rates may be
permitted in certain circumstances. Effective January 1,
1995, the FERC implemented regulations establishing an indexing
system that permits a pipeline, subject to limited challenges,
to annually increase or decrease its transportation rates due to
inflationary changes in costs using a FERC approved index. On
March 21, 2006, FERC issued a decision setting the index
for the period July 1, 2006 through July 2011 at the
Producer Price Index for Finished Goods (PPI-FG) plus
1.3 percent. The basis for intrastate oil pipeline
regulation, and the degree of regulatory oversight and scrutiny
given to intrastate oil pipeline rates, varies from state to
state. Insofar as effective interstate and intrastate rates are
equally applicable to all comparable shippers, we believe that
the regulation of oil transportation rates will not affect our
operations in any way that is of material difference from those
of our competitors.
Further, interstate and intrastate common carrier oil pipelines
must provide service on a non-discriminatory basis at posted
tariff rates. When oil pipelines operate at full capacity,
access is governed by prorationing provisions set forth in the
pipelines published tariffs. Accordingly, we believe that
access to oil pipeline transportation services generally will be
available to us to the same extent as to our competitors.
Regulation of transportation and sale of natural
gas. Historically, the transportation and
sale for resale of natural gas in interstate commerce have been
regulated pursuant to the Natural Gas Act of 1938, the Natural
Gas Policy Act of 1978 and regulations issued under those acts
by the FERC. In the past, the federal government has regulated
the prices at which natural gas could be sold. While sales by
producers of natural gas can currently be made at uncontrolled
market prices, Congress could reenact price controls in the
future, and market participants are prohibited from engaging in
market manipulation. Deregulation of wellhead natural gas sales
began with the enactment of the Natural Gas Policy Act. In 1989,
Congress enacted the Natural Gas Wellhead Decontrol Act which
removed all Natural Gas Act and Natural Gas Policy Act price and
non-price controls affecting wellhead sales of natural gas
effective January 1, 1993.
The FERC regulates interstate natural gas transportation rates
and service conditions, which affects the marketing of natural
gas that we produce, as well as the revenues we receive for
sales of our natural gas. Since 1985, the FERC has endeavored to
make natural gas transportation more accessible to natural gas
buyers and sellers on an open and non-discriminatory basis. The
FERC has stated that open access policies are necessary to
improve the competitive structure of the interstate natural gas
pipeline industry and to create a regulatory framework that will
put natural gas sellers into more direct contractual relations
with natural gas buyers by, among other things, unbundling the
sale of natural gas from the sale of transportation and storage
services. Beginning in 1992, the FERC issued Order No. 636
and a series of related orders to implement its open access
policies. As a result of the Order No. 636 program, the
marketing and pricing of natural gas have been significantly
altered. The interstate pipelines traditional role as
wholesalers of natural gas has been eliminated and replaced by a
structure under which pipelines provide transportation and
storage service on an open access basis to others who buy and
sell natural gas. Although these orders do not directly regulate
natural gas producers, they are intended to foster increased
competition within all phases of the natural gas industry.
In 2000, the FERC issued Order No. 637 and subsequent
orders, which imposed a number of additional reforms designed to
enhance competition in natural gas markets. Among other things,
Order No. 637 effected changes in FERC regulations relating
to scheduling procedures, capacity segmentation, penalties,
rights of first refusal and information reporting. Most
pipelines tariff filings to implement the requirements of
Order No. 637 have been accepted by the FERC and placed
into effect.
12
In August, 2005, Congress enacted the Energy Policy Act of 2005
(EPAct 2005). Among other matters, EPAct 2005 amends
the Natural Gas Act to make it unlawful for any
entity, including otherwise non-jurisdictional producers
such as us, to use any deceptive or manipulative device or
contrivance in connection with the purchase or sale of natural
gas or the purchase or sale of transportation services subject
to regulation by the FERC, in contravention of rules prescribed
by the FERC. The FERCs rules implementing this provision
make it unlawful, in connection with the purchase or sale of
natural gas subject to the jurisdiction of the FERC, or the
purchase or sale of transportation services subject to the
jurisdiction of the FERC, for any entity, directly or
indirectly, to use or employ any device, scheme or artifice to
defraud; to make any untrue statement of material fact or omit
to make any such statement necessary to make the statements made
not misleading; or to engage in any act or practice that
operates as a fraud or deceit upon any person. EPAct 2005 also
gives the FERC authority to impose civil penalties for
violations of the Natural Gas Act up to $1 million per day
per violation. The new anti-manipulation rule does not apply to
activities that relate only to intrastate or other
non-jurisdictional sales, gathering or production, but does
apply to activities of otherwise non-jurisdictional entities to
the extent the activities are conducted in connection
with gas sales, purchases or transportation subject to
FERC jurisdiction, which now includes the annual reporting
requirements under Order 704. EPAct 2005 therefore reflects a
significant expansion of the FERCs enforcement authority.
We do not anticipate we will be affected any differently than
other producers of natural gas.
In December 2007, the FERC issued rules (Order 704)
requiring that any market participant, including a producer such
as Concho, that engages in wholesale sales or purchases of
natural gas that equal or exceed 2.2 million MMBtus during
a calendar year to annually report, starting May 1, 2009,
such sales and purchases to the FERC. These rules are intended
to increase the transparency of the wholesale natural gas
markets and to assist the FERC in monitoring such markets and in
detecting market manipulation. We do not anticipate that we will
be affected by these rules any differently than other producers
of natural gas.
We cannot accurately predict whether the FERCs actions
will achieve the goal of increasing competition in markets in
which our natural gas is sold. Additional proposals and
proceedings that might affect the natural gas industry are
pending before the FERC and the courts. The natural gas industry
historically has been very heavily regulated. Therefore, we
cannot provide any assurance that the less stringent regulatory
approach recently established by the FERC will continue.
However, we do not believe that any action taken will affect us
in a way that materially differs from the way it affects other
natural gas producers.
Gathering service, which occurs upstream of jurisdictional
transmission services, is regulated by the states onshore and in
state waters. Although its policy is still in flux, the FERC has
reclassified certain jurisdictional transmission facilities as
non-jurisdictional gathering facilities, which has the tendency
to increase our costs of getting gas to point of sale locations.
Intrastate natural gas transportation is also subject to
regulation by state regulatory agencies. The basis for
intrastate regulation of natural gas transportation and the
degree of regulatory oversight and scrutiny given to intrastate
natural gas pipeline rates and services varies from state to
state. During the 2007 legislative session, the Texas State
Legislature passed H.B. 3273 (Competition Bill) and
H.B. 1920 (LUG Bill). The Competition Bill gives the
Railroad Commission of Texas (RRC) the ability to
use either a cost-of-service method or a market-based method for
setting rates for natural gas gathering and intrastate
transportation pipelines in formal rate proceedings. It also
gives the RRC specific authority to enforce its statutory duty
to prevent discrimination in natural gas gathering and
transportation, to enforce the requirement that parties
participate in an informal complaint process and to punish
purchasers, transporters, and gatherers for taking
discriminatory actions against shippers and sellers. The
Competition Bill also provides producers with the unilateral
option to determine whether or not confidentiality provisions
are included in a contract to which a producer is a party for
the sale, transportation, or gathering of natural gas. The LUG
Bill modifies the informal complaint process at the RRC with
procedures unique to lost and unaccounted for gas issues. It
extends the types of information that can be requested, provides
producers with an annual audit right, and provides the RRC with
the authority to make determinations and issue orders in
specific situations. Both the Competition Bill and the LUG Bill
became effective September 1, 2007. Insofar as such
regulation within a particular state will generally affect all
intrastate natural gas shippers within the state on a comparable
basis, we believe that the regulation of similarly situated
intrastate natural gas transportation in any states in which we
operate and ship natural gas on an intrastate basis will not
affect our operations in any way that is of material difference
from those of our competitors. Like the regulation of interstate
transportation rates, the
13
regulation of intrastate transportation rates affects the
marketing of natural gas that we produce, as well as the
revenues we receive for sales of our natural gas.
Regulation of production. The
production of oil and natural gas is subject to regulation under
a wide range of local, state and federal statutes, rules, orders
and regulations. Federal, state and local statutes and
regulations require permits for drilling operations, drilling
bonds and reports concerning operations. All of the states in
which we own and operate properties have regulations governing
conservation matters, including provisions for the unitization
or pooling of oil and natural gas properties, the establishment
of maximum allowable rates of production from oil and natural
gas wells, the regulation of well spacing, and the plugging and
abandonment of wells. The effect of these regulations is to
limit the amount of oil and natural gas that we can produce from
our wells and to limit the number of wells or the locations at
which we can drill, although we can apply for exceptions to such
regulations or to have reductions in well spacing. Moreover,
each state generally imposes a production or severance tax with
respect to the production and sale of oil, natural gas and
natural gas liquids within its jurisdiction. The failure to
comply with these rules and regulations can result in
substantial penalties. Our competitors in the oil and natural
gas industry are subject to the same regulatory requirements and
restrictions that affect our operations.
Environmental,
Health and Safety Matters
General. Our operations are subject to
stringent and complex federal, state and local laws and
regulations governing environmental protection as well as the
discharge of materials into the environment. These laws and
regulations may, among other things:
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require the acquisition of various permits before drilling
commences;
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restrict the types, quantities and concentration of various
substances that can be released into the environment in
connection with oil and natural gas drilling and production, and
saltwater disposal activities;
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limit or prohibit drilling activities on certain lands lying
within wilderness, wetlands and other protected areas; and
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require remedial measures to mitigate pollution from former and
ongoing operations, such as requirements to close pits and plug
abandoned wells.
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These laws, rules and regulations may also restrict the rate of
oil and natural gas production below the rate that would
otherwise be possible. The regulatory burden on the oil and gas
industry increases the cost of doing business in the industry
and consequently affects profitability. Additionally, Congress
and federal and state agencies frequently revise environmental
laws and regulations, and any changes that result in more
stringent and costly waste handling, disposal and cleanup
requirements for the oil and gas industry could have a
significant impact on our operating costs.
The following is a summary of some of the existing laws, rules
and regulations to which our business is subject.
Waste handling. The Resource
Conservation and Recovery Act, or RCRA, and
comparable state statutes, regulate the generation,
transportation, treatment, storage, disposal and cleanup of
hazardous and non-hazardous wastes. Under the auspices of the
federal Environmental Protection Agency, or EPA, the
individual states administer some or all of the provisions of
RCRA, sometimes in conjunction with their own, more stringent
requirements. Drilling fluids, produced waters, and most of the
other wastes associated with the exploration, development, and
production of crude oil or natural gas are currently regulated
under RCRAs non-hazardous waste provisions. However, it is
possible that certain oil and natural gas exploration and
production wastes now classified as non-hazardous could be
classified as hazardous wastes in the future. Any such change
could result in an increase in our costs to manage and dispose
of wastes, which could have a material adverse effect on our
results of operations and financial position.
Comprehensive Environmental Response, Compensation and
Liability Act. The Comprehensive
Environmental Response, Compensation and Liability Act, or
CERCLA, also known as the Superfund law, imposes
joint and several liability, without regard to fault or legality
of conduct, on classes of persons who are considered to be
responsible for the release of a hazardous substance into the
environment. These persons include the owner or operator of the
site where the release occurred, and anyone who disposed or
arranged for the disposal of a hazardous
14
substance released at the site. Under CERCLA, such persons may
be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released
into the environment, for damages to natural resources and for
the costs of certain health studies. In addition, it is not
uncommon for neighboring landowners and other third-parties to
file claims for personal injury and property damage allegedly
caused by the hazardous substances released into the environment.
We currently own, lease, or operate numerous properties that
have been used for oil and natural gas exploration and
production for many years. Although we believe that we have
utilized operating and waste disposal practices that were
standard in the industry at the time, hazardous substances,
wastes, or hydrocarbons may have been released on or under the
properties owned or leased by us, or on or under other
locations, including off-site locations, where such substances
have been taken for disposal. In addition, some of our
properties have been operated by third parties or by previous
owners or operators whose treatment and disposal of hazardous
substances, wastes, or hydrocarbons was not under our control.
These properties and the substances disposed or released on them
may be subject to CERCLA, RCRA, and analogous state laws. Under
such laws, we could be required to remove previously disposed
substances and wastes, remediate contaminated property, or
perform remedial plugging or pit closure operations to prevent
future contamination.
Water discharges. The Federal Water
Pollution Control Act, or the Clean Water Act, and
analogous state laws, impose restrictions and strict controls
with respect to the discharge of pollutants, including spills
and leaks of oil and other substances, into waters of the United
States. The discharge of pollutants into regulated waters is
prohibited, except in accordance with the terms of a permit
issued by the EPA or an analogous state agency. Federal and
state regulatory agencies can impose administrative, civil and
criminal penalties for non-compliance with discharge permits or
other requirements of the Clean Water Act and analogous state
laws and regulations.
Air emissions. The federal Clean Air
Act, and comparable state laws, regulate emissions of various
air pollutants through air emissions permitting programs and the
imposition of other requirements. In addition, the EPA has
developed, and continues to develop, stringent regulations
governing emissions of toxic air pollutants at specified
sources. Federal and state regulatory agencies can impose
administrative, civil and criminal penalties for non-compliance
with air permits or other requirements of the federal Clean Air
Act and associated state laws and regulations.
Recent scientific studies have suggested that emissions of
certain gases, commonly referred to as greenhouse
gases and including carbon dioxide and methane, may be
contributing to warming of the Earths atmosphere. In
response to such studies, the U.S. Congress is considering
legislation to reduce emissions of greenhouse gases. President
Obama has expressed support for legislation to restrict or
regulate emissions of greenhouse gases. In addition, more than
one-third of the states, either individually or through
multi-state regional initiatives, already have begun
implementing legal measures to reduce emissions of greenhouse
gases, primarily through the planned development of emission
inventories or regional greenhouse gas cap and trade programs.
Depending on the particular program, we could be required to
purchase and surrender allowances for greenhouse gas emissions
resulting from our operations. This requirement could increase
our operational and compliance costs and result in reduced
demand for our products.
Also, as a result of the United States Supreme Courts
decision on April 2, 2007 in Massachusetts, et
al. v. EPA, the EPA may regulate greenhouse gas
emissions from mobile sources such as cars and trucks even if
Congress does not adopt new legislation specifically addressing
emissions of greenhouse gases. The Courts holding in
Massachusetts that greenhouse gases including carbon
dioxide fall under the federal Clean Air Acts definition
of air pollutant may also result in future
regulation of carbon dioxide and other greenhouse gas emissions
from stationary sources. In July 2008, the EPA released an
Advance Notice of Proposed Rulemaking regarding
possible future regulation of greenhouse gas emissions under the
Clean Air Act, in response to the Supreme Courts decision
in Massachusetts. In the notice, the EPA evaluated the
potential regulation of greenhouse gases under the Clean Air Act
and other potential methods of regulating greenhouse gases.
Although the notice did not propose any specific, new regulatory
requirements for greenhouse gases, it indicates that federal
regulation of greenhouse gas emissions could occur in the near
future even if Congress does not adopt new legislation
specifically addressing emissions of greenhouse gases. Although
it is not possible at this time to predict how legislation or
new regulations that may be adopted to address greenhouse gas
emissions would impact our business, any such new federal,
regional or state
15
restrictions on emissions of carbon dioxide or other greenhouse
gases that may be imposed in areas in which we conduct business
could result in increased compliance costs or additional
operating restrictions, which could have a material adverse
effect on our business and the demand for our products.
National Environmental Policy Act. Oil
and natural gas exploration and production activities on federal
lands are subject to the National Environmental Policy Act, or
NEPA. NEPA requires federal agencies, including the
Department of Interior, to evaluate major agency actions having
the potential to significantly impact the environment. In the
course of such evaluations, an agency will prepare an
environmental assessment that assesses the potential direct,
indirect and cumulative impacts of a proposed project and, if
necessary, will prepare a more detailed environmental impact
statement that may be made available for public review and
comment. All of our current exploration and production
activities, as well as proposed exploration and development
plans, on federal lands require governmental permits that are
subject to the requirements of NEPA. This process has the
potential to delay the development of oil and natural gas
projects.
OSHA and other laws and regulation. We
are subject to the requirements of the federal Occupational
Safety and Health Act, or OSHA, and comparable state
statutes. The OSHA hazard communication standard, the EPA
community right-to-know regulations under the Title III of
CERCLA and similar state statutes require that we organize
and/or
disclose information about hazardous materials used or produced
in our operations. We believe that we are in substantial
compliance with these applicable requirements and with other
OSHA and comparable requirements.
We believe that we are in substantial compliance with all
existing environmental laws and regulations applicable to our
current operations and that our continued compliance with
existing requirements will not have a material adverse impact on
our financial condition and results of operations. For instance,
we did not incur any material capital expenditures for
remediation or pollution control activities for the year ended
December 31, 2008. Additionally, as of the date of this
report, we are not aware of any environmental issues or claims
that will require material capital expenditures during 2009.
However, we cannot assure you that the passage or application of
more stringent laws or regulations in the future will not have
an negative impact on our financial position or results of
operation.
Our
Employees
At December 31, 2008, we employed 245 persons,
including 128 in operations, 33 in financial and accounting, 33
in land, 16 in geosciences, 17 in reservoir engineering and 18
in administration. Of these, 220 worked at our Midland, Texas
headquarters, including Texas field operations, and 25 in our
New Mexico field operations. Our future success will depend
partially on our ability to attract, retain and motivate
qualified personnel. We are not a party to any collective
bargaining agreements and have not experienced any strikes or
work stoppages. We consider our relations with our employees to
be satisfactory. We also utilize the services of independent
contractors to perform various field and other services.
Available
Information
We file or furnish annual, quarterly and current reports, proxy
statements and other documents with the SEC under the Exchange
Act. The public may read and copy any materials that we file
with the SEC at the SECs Public Reference Room at
100 F Street, N.E., Washington, D.C. 20549. The
public may obtain information on the operation of the Public
Reference Room by calling the SEC at
1-800-SEC-0330.
Also, the SEC maintains an Internet website that contains
reports, proxy and information statements, and other information
regarding issuers, including us, that file electronically with
the SEC. The public can obtain any documents that we file with
the SEC at
http://www.sec.gov.
We also make available free of charge through our internet
website (www.conchoresources.com) our annual report, Quarterly
Reports on
Form 10-Q,
Current Reports on
Form 8-K
and, if applicable, amendments to those reports filed or
furnished pursuant to Section 13(a) of the Exchange Act as
soon as reasonably practicable after we electronically file such
material with, or furnish it to, the SEC.
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You should consider carefully the following risk factors
together with all of the other information included in this
report and other reports filed with the SEC, before investing in
our shares. If any of the following risks were actually to
occur, our business, financial condition or results of
operations could be materially adversely affected. In that case,
the trading price of our shares could decline and you could lose
all or part of your investment.
Risks
Related to Our Business
Crude
oil and natural gas prices are volatile. A decline in crude oil
and natural gas prices could adversely affect our financial
position, financial results, cash flow, access to capital and
ability to grow.
Our future financial condition, revenues, results of operations,
rate of growth and the carrying value of our oil and gas
properties depend primarily upon the prices we receive for our
crude oil and natural gas production and the prices prevailing
from time to time for crude oil and natural gas. Crude oil and
natural gas prices historically have been volatile and are
likely to continue to be volatile in the future, especially
given current geopolitical conditions. This price volatility
also affects the amount of our cash flow we have available for
capital expenditures and our ability to borrow money or raise
additional capital. The prices for crude oil and natural gas are
subject to a variety of factors, including:
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the level of consumer demand for crude oil and natural gas;
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the domestic and foreign supply of crude oil and natural gas;
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commodity processing, gathering and transportation availability,
and the availability of refining capacity;
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the price and level of imports of foreign crude oil and natural
gas;
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the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain crude oil price and
production controls;
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domestic and foreign governmental regulations and taxes;
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the price and availability of alternative fuel sources;
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weather conditions;
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political conditions or hostilities in oil and gas producing
regions, including the Middle East, Africa and South America;
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technological advances affecting energy consumption; and
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worldwide economic conditions.
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Furthermore, crude oil and natural gas prices were particularly
volatile in 2008. For example, the NYMEX crude oil prices in
2008 ranged from a high of $145.29 to a low of $33.87 per Bbl,
and the NYMEX natural gas prices in 2008 ranged from a high of
$13.58 to a low of $4.35 per MMBtu. Further demonstrating the
volatility of crude oil and natural gas prices, the NYMEX crude
oil prices and NYMEX natural gas prices reached lows of $33.98
per Bbl and $4.08 per MMBtu, respectively, during the period
from January 1, 2009 to February 19, 2009.
Further declines in crude oil and natural gas prices would not
only reduce our revenue, but could further reduce the amount of
crude oil and natural gas that we can produce economically and,
as a result, could have a material adverse effect on our
financial condition, results of operations and reserves. If the
oil and gas industry continues to experience significant price
declines, we may, among other things, be unable to maintain or
increase our borrowing capacity, repay current or future
indebtedness or obtain additional capital on attractive terms,
all of which can adversely affect the value of our common stock.
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Drilling
for and producing crude oil and natural gas are high-risk
activities with many uncertainties that could cause our expenses
to increase or our cash flows and production volumes to
decrease.
Our future financial condition and results of operations will
depend on the success of our exploitation, exploration,
development and production activities. Our crude oil and natural
gas exploration and production activities are subject to
numerous risks, including the risk that drilling will not result
in commercially viable crude oil or natural gas production. Our
decisions to purchase, explore, develop or otherwise exploit
prospects or properties will depend in part on the evaluation of
data obtained through geophysical and geological analyses,
production data and engineering studies, the results of which
are often inconclusive or subject to varying interpretations.
Our cost of drilling, completing, equipping and operating wells
is often uncertain before drilling commences. Overruns in
budgeted expenditures are common risks that can make a
particular project uneconomical or less economic than
forecasted. Further, many factors may curtail, delay or cancel
drilling, including the following:
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delays imposed by or resulting from compliance with regulatory
and contractual requirements;
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pressure or irregularities in geological formations;
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shortages of or delays in obtaining equipment and qualified
personnel;
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equipment failures or accidents;
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adverse weather conditions;
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reductions in crude oil and natural gas prices;
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surface access restrictions;
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loss of title or other title related issues;
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crude oil, natural gas liquids or natural gas gathering,
transportation and processing availability restrictions or
limitations; and
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limitations in the market for crude oil and natural gas.
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Estimates
of proved reserves and future net cash flows are not precise.
The actual quantities of our proved reserves and our future net
cash flows may prove to be lower than estimated.
Numerous uncertainties exist in estimating quantities of proved
reserves and future net cash flows therefrom. Our estimates of
proved reserves and related future net cash flows are based on
various assumptions, which may ultimately prove to be inaccurate.
Petroleum engineering is a subjective process of estimating
accumulations of crude oil
and/or
natural gas that cannot be measured in an exact manner.
Estimates of economically recoverable crude oil and natural gas
reserves and of future net cash flows depend upon a number of
variable factors and assumptions, including the following:
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historical production from the area compared with production
from other producing areas;
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the quality, quantity and interpretation of available relevant
data;
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the assumed effects of regulations by governmental agencies;
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the quality, quantity and interpretation of available relevant
data;
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the assumed effects of regulations by governmental agencies;
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assumptions concerning future commodity prices; and
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assumptions concerning future operating costs; severance, ad
valorem and excise taxes; development costs; and workover and
remedial costs.
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Because all reserve estimates are to some degree subjective,
each of the following items, or other items not identified
below, may differ materially from those assumed in estimating
reserves:
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the quantities of crude oil and natural gas that are ultimately
recovered;
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the production and operating costs incurred;
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the amount and timing of future development
expenditures; and
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future commodity prices.
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Furthermore, different reserve engineers may make different
estimates of reserves and cash flows based on the same data. Our
actual production, revenues and expenditures with respect to
reserves will likely be different from estimates and the
differences may be material.
As required by the SEC, the estimated discounted future net cash
flows from proved reserves are based on prices and costs as of
the date of the estimate, while actual future prices and costs
may be materially higher or lower. For example, the estimated
discounted future net cash flows from our proved reserves at
December 31, 2008 were calculated using the West Texas
Intermediate posted crude oil price of $41.00 per Bbl and the
NYMEX natural gas price of $5.71 per MMBtu, adjusted for
location and quality by field, while the actual future net cash
flows also will be affected by other factors, including:
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the amount and timing of actual production;
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levels of future capital spending;
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increases or decreases in the supply of or demand for oil and
gas; and
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changes in governmental regulations or taxation.
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Standardized Measure is a reporting convention that provides a
common basis for comparing oil and gas companies subject to the
rules and regulations of the SEC. It requires the use of
commodity prices, as well as operating and development costs,
prevailing as of the date of computation. Consequently, it may
not reflect the prices ordinarily received or that will be
received for crude oil and natural gas production because of
seasonal price fluctuations or other varying market conditions,
nor may it reflect the actual costs that will be required to
produce or develop the oil and gas properties. Accordingly,
estimates included herein of future net cash flows may be
materially different from the future net cash flows that are
ultimately received. In addition, the ten percent discount
factor, which is required by the SEC to be used in calculating
discounted future net cash flows for reporting purposes, may not
be the most appropriate discount factor based on interest rates
in effect from time to time and risks associated with our
company or the oil and gas industry in general. Therefore, the
estimates of discounted future net cash flows or Standardized
Measure included herein should not be construed as accurate
estimates of the current market value of our proved reserves. If
oil prices were $1.00 per Bbl lower than the price we used, our
PV-10 at
December 31, 2008, would have decreased from
$1,663 million to $1,622 million. If natural gas
prices were $0.10 per Mcf lower than the price we used, our
PV-10 at
December 31, 2008, would have decreased from
$1,663 million to $1,646 million. Any adjustments to
the estimates of proved reserves or decreases in the price of
oil or natural gas may decrease the value of our common stock.
Our
business requires substantial capital expenditures. We may be
unable to obtain needed capital or financing on satisfactory
terms or at all, which could lead to a decline in our crude oil
and natural gas reserves.
The oil and gas industry is capital intensive. We make and
expect to continue to make substantial capital expenditures for
the acquisition, exploration and development of crude oil and
natural gas reserves. At December 31, 2008, total debt
outstanding under our credit facility was $630.0 million,
and $329.7 million was available to be borrowed.
Expenditures for exploration and development of oil and gas
properties are the primary use of our capital resources. We
invested approximately $339.0 million in exploration and
development activities in 2008, and anticipate we could invest
up to approximately $500 million in 2009 for exploration
and development activities, dependent on our cash flow, on our
properties under our original capital budget.
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We intend to finance our future capital expenditures primarily
through cash flow from operations and through borrowings under
our credit facility; however, our financing needs may require us
to alter or increase our capitalization substantially through
the issuance of debt or equity securities. The issuance of
additional equity securities could have a dilutive effect on the
value of our outstanding common stock. Additional borrowings
under our credit facility or the issuance of additional debt
will require that a greater portion of our cash flow from
operations be used for the payment of interest and principal on
our debt, thereby reducing our ability to use cash flow to fund
working capital, capital expenditures and acquisitions. In
addition, our credit facility imposes certain limitations on our
ability to incur additional indebtedness other than indebtedness
under our credit facility. If we desire to issue additional debt
securities other than as expressly permitted under our credit
facility, we will be required to seek the consent of the lenders
in accordance with the requirements of the facility, which
consent may be withheld by the lenders under our credit facility
in their discretion. Additional financing also may not be
available on acceptable terms or at all. In the event additional
capital resources are unavailable, we may curtail drilling,
development and other activities or be forced to sell some of
our assets on an untimely or unfavorable basis.
Our cash flow from operations and access to capital are subject
to a number of variables, including:
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our proved reserves;
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the level of crude oil and natural gas we are able to produce
from existing wells;
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the prices at which our crude oil and natural gas are
sold; and
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our ability to acquire, locate and produce new reserves.
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If our revenues or the borrowing base under our credit facility
decrease as a result of lower oil or natural gas prices,
operating difficulties, declines in reserves, lending
requirements or regulations, or for any other reason, we may
have limited ability to obtain the capital necessary to sustain
our operations at current levels. As a result, we may require
additional capital to fund our operations, and we may not be
able to obtain debt or equity financing to satisfy our capital
requirements. If cash generated from operations or cash
available under our revolving credit facility is not sufficient
to meet our capital requirements, the failure to obtain
additional financing could result in a curtailment of our
operations relating to development of our prospects, which in
turn could lead to a decline in our oil and natural gas
reserves, and could adversely affect our production, revenues
and results of operations.
We may
not be able to obtain funding at all, or obtain funding on
acceptable terms, to meet our future capital needs because of
the deterioration of the credit and capital
markets.
Global financial markets and economic conditions have been, and
will likely continue to be, disrupted and volatile. The debt and
equity capital markets have become uncertain. These issues,
along with significant write-offs in the financial services
sector, the re-pricing of credit risk and the current weak
economic conditions have made, and will likely continue to make,
it difficult to obtain funding.
In particular, the cost of raising money in the debt and equity
capital markets has increased substantially while the
availability of funds from those markets has diminished
significantly. Also, as a result of concern about the stability
of financial markets generally and the solvency of
counterparties specifically, the cost of obtaining money from
the credit markets has increased as many lenders and
institutional investors have increased interest rates, enacted
tighter lending standards and reduced and, in some cases, ceased
to provide funding to borrowers.
In addition, our ability to obtain capital under our credit
facility may be impaired because of the recent downturn in the
financial market, including the issues surrounding the solvency
of certain institutional lenders and the recent failure of
several banks. Specifically, we may be unable to obtain adequate
funding under our credit facility because:
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our lending counterparties may be unwilling or unable to meet
their funding obligations;
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the borrowing base under our credit facility is redetermined at
least twice a year and may decrease due to a decrease in crude
oil or natural gas prices, operating difficulties, declines in
reserves, lending requirements or regulations, or for other
reasons; or
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if any lender is unable or unwilling to fund their respective
portion of any advance under our credit facility, then the other
lenders thereunder are not required to provide additional
funding to make up the portion of the advance that the
defaulting lender refused to fund.
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Due to these factors, we cannot be certain that funding will be
available if needed and to the extent required, on acceptable
terms. If funding is not available when needed, or is available
only on unfavorable terms, we may be unable to implement our
development plan, enhance our existing business, complete
acquisitions or otherwise take advantage of business
opportunities or respond to competitive pressures, any of which
could have a material adverse effect on our production, revenues
and results of operations.
Our
lenders can limit our borrowing capabilities, which may
materially impact our operations.
At December 31, 2008, we had approximately
$630 million of outstanding debt under our credit facility,
and our borrowing base was $960 million. The borrowing base
limitation under our credit facility is semi-annually
redetermined based upon a number of factors, including commodity
prices and reserve levels. In addition to such semi-annual
redeterminations, our lenders may request one additional
redetermination during any twelve-month period. Upon a
redetermination, our borrowing base could be substantially
reduced, and in the event the amount outstanding under our
credit facility at any time exceeds the borrowing base at such
time, we may be required to repay a portion of our outstanding
borrowings. We utilize cash flow from operations, bank
borrowings and equity financings to fund our acquisition,
exploration and development activities. A reduction in our
borrowing base could limit our activities. In addition, we may
significantly alter our capitalization in order to make future
acquisitions or develop our properties. These changes in
capitalization may significantly increase our level of debt. If
we incur additional debt for these or other purposes, the
related risks that we now face could intensify. A higher level
of debt also increases the risk that we may default on our debt
obligations. Our ability to meet our debt obligations and to
reduce our level of debt depends on our future performance which
is affected by general economic conditions and financial,
business and other factors, many of which are beyond our control.
Our
producing properties are located in the Permian Basin of
Southeastern New Mexico and West Texas, making us vulnerable to
risks associated with operating in one major geographic area. In
addition, we have a large amount of proved reserves attributable
to a small number of producing horizons within this
area.
Our producing properties in our core operating areas are
geographically concentrated in the Permian Basin of Southeastern
New Mexico and West Texas. At December 31, 2008,
97.4 percent of our
PV-10 was
attributable to properties located in our core operating areas.
As a result of this concentration, we may be disproportionately
exposed to the impact of regional supply and demand factors,
delays or interruptions of production from wells in this area
caused by governmental regulation, processing or transportation
capacity constraints, market limitations, or interruption of the
processing or transportation of crude oil, natural gas or
natural gas liquids.
In addition to the geographic concentration of our producing
properties described above, at December 31, 2008,
approximately (i) 52.0 percent of our proved reserves
were attributable to the Yeso formation, which includes both the
Paddock and Blinebry intervals, underlying our oil and gas
properties located in Southeastern New Mexico; and
(ii) 15.1 percent of our proved reserves were
attributable to the Wolfberry play in West Texas. This
concentration of assets within a small number of producing
horizons exposes us to additional risks, such as changes in
field-wide rules and regulations that could cause us to
permanently or temporarily shut-in all of our wells within a
field.
Future
price declines could result in a reduction in the carrying value
of our proved oil and gas properties, which could adversely
affect our results of operations.
Declines in commodity prices may result in having to make
substantial downward adjustments to our estimated proved
reserves. If this occurs, or if our estimates of production or
economic factors change, accounting rules may require us to
write-down, as a noncash charge to earnings, the carrying value
of our oil and gas properties for impairments. We are required
to perform impairment tests on proved assets whenever events or
changes in circumstances warrant a review of our proved oil and
gas properties. To the extent such tests indicate a reduction of
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the estimated useful life or estimated future cash flows of our
oil and gas properties, the carrying value may not be
recoverable and therefore require a write-down. We may incur
impairment charges in the future, which could materially
adversely affect our results of operations in the period
incurred.
Part
of our strategy involves exploratory drilling, including
drilling in new or emerging plays. As a result, our drilling
results in these areas are uncertain, and the value of our
undeveloped acreage will decline if drilling results are
unsuccessful.
The results of our exploratory drilling in new or emerging areas
are more uncertain than drilling results in areas that are
developed and have established production. Since new or emerging
plays and new formations have limited or no production history,
we are unable to use past drilling results in those areas to
help predict our future drilling results. As a result, our cost
of drilling, completing and operating wells in these areas may
be higher than initially expected, and the value of our
undeveloped acreage will decline if drilling results are
unsuccessful.
Our
commodity price risk management program may cause us to forego
additional future profits or result in our making cash payments
to our counterparties.
To reduce our exposure to changes in the prices of crude oil and
natural gas, we have entered into and may in the future enter
into additional commodity price risk management arrangements for
a portion of our crude 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 crude oil and natural gas production over a fixed period
of time. Commodity price risk management arrangements expose us
to the risk of financial loss and may limit our ability to
benefit from increases in crude oil and natural gas prices in
some circumstances, including the following:
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the counterparty to a commodity price risk management contract
may default on its contractual obligations to us;
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there may be a change in the expected differential between the
underlying price in a commodity price risk management agreement
and actual prices received; or
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market prices may exceed the prices which we are contracted to
receive, resulting in our need to make significant cash payments
to our counterparties.
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Our commodity price risk management activities could have the
effect of reducing our revenues, net income and the value of our
common stock. At December 31, 2008, the net unrealized gain
on our commodity price risk management contracts was
approximately $172.4 million. An average increase in the
commodity price of $1.00 per barrel of crude oil and $0.10 per
Mcf for natural gas from the commodity prices at
December 31, 2008 would have resulted in a decrease in the
net unrealized gain on our commodity price risk management
contracts, as reflected on our balance sheet at
December 31, 2008, of approximately $3.6 million. We
may continue to incur significant unrealized gains or losses in
the future from our commodity price risk management activities
to the extent market prices increase or decrease and our
derivatives contracts remain in place.
We
have entered into interest rate derivative instruments that may
subject us to loss of income.
We have entered into derivative instruments designed to limit
the interest rate risk under our current credit facility or any
credit facilities we may enter into in the future. These
derivative instruments can involve the exchange of a portion of
our floating rate interest obligations for fixed rate interest
obligations or a cap on our exposure to floating interest rates
to reduce our exposure to the volatility of interest rates.
While we may enter into instruments limiting our exposure to
higher market interest rates, we cannot assure you that any
interest rate derivative instruments we implement will be
effective; and furthermore, even if effective these instruments
may not offer complete protection from the risk of higher
interest rates.
All interest rate derivative instruments involve certain
additional risks, such as:
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the counterparty may default on its contractual obligations to
us;
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there may be issues with regard to the legal enforceability of
such instruments;
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the early repayment of one of our interest rate derivative
instruments could lead to prepayment penalties; or
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unanticipated and significant changes in interest rates may
cause a significant loss of basis in the instrument and a change
in current period expense.
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If we
enter into derivative instruments that require us to post cash
collateral, our cash otherwise available for use in our
operations would be reduced, which could limit our ability to
make future capital expenditures.
The use of derivatives may, in some cases, require the posting
of cash collateral with counterparties. If we enter into
derivative instruments that require cash collateral and
commodity prices or interest rates change in a manner adverse to
us, our cash otherwise available for use in our operations would
be reduced, which could limit our ability to make future capital
expenditures. Future collateral requirements will depend on
arrangements with our counterparties and highly volatile crude
oil and natural gas prices and interest rates.
Nonperformance
by the counterparties to our derivative instruments and
commodity purchase agreements could adversely affect our
financial condition and results of operations.
We routinely enter into derivative instruments with a number of
counterparties to reduce our exposure to changes in oil and
natural gas prices and interest rates. Recently, a number of
financial institutions similar to those that serve as
counterparties to our derivative instruments have been adversely
affected by the global credit crisis. If a counterparty to one
of these derivative instruments cannot or will not perform under
the contract, we will not realize the benefit of the derivative,
which could adversely affect our financial condition and results
of operations.
Additionally, substantially all of our accounts receivable
result from oil and natural gas sales to third parties in the
energy industry. Recent market conditions have resulted in
downgrades to credit ratings of energy industry merchants and
financial institutions, affecting the liquidity of several of
our purchasers and counterparties. We extend credit to our
purchasers based on each partys creditworthiness, but we
generally have not required our purchasers to provide collateral
support for their obligations to us and therefore have no
assurances that our counterparties will have the ability to pay
us. If a purchaser of our oil and natural gas production fails
to meet its obligations under our commodity purchase agreement,
our financial condition and results of operations could be
adversely affected.
Our
identified inventory of drilling locations and recompletion
opportunities are scheduled out over several years, making them
susceptible to uncertainties that could materially alter the
occurrence or timing of their drilling.
We have specifically identified and scheduled the drilling and
recompletion of our drilling and recompletion opportunities as
an estimation of our future multi-year development activities on
our existing acreage. At December 31, 2008, we had
identified 3,589 drilling locations with proved undeveloped
reserves attributable to 823 of such locations, and 2,121
recompletion opportunities with proved undeveloped reserves
attributed to 540 of such opportunities. These identified
opportunities represent a significant part of our growth
strategy. Our ability to drill and develop these opportunities
depends on a number of uncertainties, including (i) our
ability to timely drill wells on lands subject to complex
development terms and circumstances; and (ii) the
availability of capital, equipment, services and personnel,
seasonal conditions, regulatory and third party approvals, crude
oil and natural gas prices, and drilling and recompletion costs
and results. Because of these uncertainties, we may never drill
or recomplete the numerous potential opportunities we have
identified or produce crude oil or natural gas from these or any
other potential opportunities. As such, our actual development
activities may materially differ from those presently
identified, which could adversely affect our production,
revenues and results of operations.
Approximately
44.3 percent of our total estimated net proved reserves at
December 31, 2008, were undeveloped, and those reserves may
not ultimately be developed.
At December 31, 2008, approximately 44.3 percent of
our total estimated net proved reserves were undeveloped.
Recovery of undeveloped reserves requires significant capital
expenditures and successful drilling. Our reserve data assumes
that we can and will make these expenditures and conduct these
operations successfully. These
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assumptions, however, may not prove correct. If we choose not to
spend the capital to develop these reserves, or if we are not
able to successfully develop these reserves, we will be required
to write-off these reserves. Any such write-offs of our reserves
could reduce our ability to borrow money and could reduce the
value of our common stock.
Because
we do not control the development of the properties in which we
own interests, but do not operate, we may not be able to achieve
any production from these properties in a timely
manner.
At December 31, 2008, approximately 6.7 percent of our
PV-10 was
attributable to properties for which we were not the operator.
As a result, the success and timing of drilling and development
activities on such nonoperated properties depend upon a number
of factors, including:
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the nature and timing of drilling and operational activities;
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the timing and amount of capital expenditures;
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the operators expertise and financial resources;
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the approval of other participants in such properties; and
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the selection of suitable technology.
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If drilling and development activities are not conducted on
these properties or are not conducted on a timely basis, we may
be unable to increase our production or offset normal production
declines, which may adversely affect our production, revenues
and results of operations.
Unless
we replace our crude oil and natural gas reserves, our reserves
and production will decline, which would adversely affect our
cash flow, our ability to raise capital and the value of our
common stock.
Unless we conduct successful development, exploitation and
exploration activities or acquire properties containing proved
reserves, our proved reserves will decline as those reserves are
produced. Producing crude oil and natural gas reservoirs
generally are characterized by declining production rates that
vary depending upon reservoir characteristics and other factors.
Our future crude oil and natural gas reserves and production,
and therefore our cash flow and results of operations, are
highly dependent on our success in efficiently developing and
exploiting our current reserves and economically finding or
acquiring additional recoverable reserves. The value of our
common stock and our ability to raise capital will be adversely
impacted if we are not able to replace our reserves that are
depleted by production. We may not be able to develop, exploit,
find or acquire sufficient additional reserves to replace our
current and future production.
We may
be unable to make attractive acquisitions or successfully
integrate acquired companies, and any inability to do so may
disrupt our business and hinder our ability to
grow.
One aspect of our business strategy calls for acquisitions of
businesses that complement or expand our current business. We
may not be able to identify attractive acquisition
opportunities. Even if we do identify attractive candidates, we
may not be able to complete the acquisition of them or do so on
commercially acceptable terms.
In addition, our credit facility imposes certain direct
limitations on our ability to enter into mergers or combination
transactions involving our company. Our credit facility also
limits our ability to incur certain indebtedness, which could
indirectly limit our ability to engage in acquisitions of
businesses. If we desire to engage in an acquisition that is
otherwise prohibited by our credit facility, we will be required
to seek the consent of our lenders in accordance with the
requirements of the facility, which consent may be withheld by
the lenders under our credit facility in their discretion.
Furthermore, given the current situation in the credit markets,
many lenders are reluctant to provide consents in any
circumstances, including to allow accretive transactions.
If we acquire another business, we could have difficulty
integrating its operations, systems, management and other
personnel and technology with our own. These difficulties could
disrupt our ongoing business, distract our management and
employees, increase our expenses and adversely affect our
results of operations. In addition, we
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may incur additional debt or issue additional equity to pay for
any future acquisitions, subject to the limitations described
above.
The
acquisition of the Henry Entities could expose us to potentially
significant liabilities.
In connection with the acquisition of the Henry Entities, we
purchased all of the sellers interests in the Henry
Entities, rather than individual assets; therefore, the Henry
Entities retained their liabilities, subject to certain
exclusions and limitations contained in the purchase agreement,
including certain unknown and contingent liabilities. We
performed limited due diligence in connection with the
acquisition of the Henry Entities and attempted to verify the
representations of the sellers and of the former management of
the Henry Entities, but there may be threatened, contemplated,
asserted or other claims against the Henry Entities related to
environmental, title, regulatory, tax, contract, litigation or
other matters of which we are unaware, which could materially
adversely affect our production, revenues and results of
operations. In addition, although the sellers agreed to
indemnify us on a limited basis against certain liabilities,
these indemnification obligations will expire over time and
expose us to potential unindemnified liabilities, which could
materially adversely affect our production, revenues and results
of operations.
Properties
acquired may prove to be worth less than we paid because of
uncertainties in evaluating recoverable reserves and potential
liabilities.
We obtained the majority of our current reserve base through
acquisitions of producing properties and undeveloped acreage,
including those owned by the Henry Entities. We expect that
acquisitions will continue to contribute to our future growth.
Successful acquisitions of oil and gas properties require an
assessment of a number of factors, including estimates of
recoverable reserves, the timing of recovering reserves,
exploration potential, future crude oil and natural gas prices,
operating costs and potential environmental and other
liabilities. Such assessments are inexact and we cannot make
these assessments with a high degree of accuracy. In connection
with our assessments, we perform a review of the acquired
properties. However, such a review will not reveal all existing
or potential problems. In addition, our review may not permit us
to become sufficiently familiar with the properties to fully
assess their deficiencies and capabilities. We do not inspect
every well. Even when we inspect a well, we do not always
discover structural, subsurface and environmental problems that
may exist or arise. We are sometimes unable to obtain
contractual indemnification for preclosing liabilities,
including environmental liabilities and often acquire interests
in properties on an as is basis with limited
remedies for breaches of representations and warranties.
Competition
in the oil and gas industry is intense, making it more difficult
for us to acquire properties, market crude oil and natural gas
and secure trained personnel.
We operate in a highly competitive environment for acquiring
properties, marketing crude oil and natural gas and securing
trained personnel. Many of our competitors possess and employ
financial, technical and personnel resources substantially
greater than ours, which can be particularly important in the
areas in which we operate. Those companies may be able to pay
more for productive oil and gas properties and exploratory
prospects and to evaluate, bid for and purchase a greater number
of properties and prospects than our financial or personnel
resources permit. In addition, those companies may be able to
offer better compensation packages to attract and retain
qualified personnel than we are able to offer. The cost to
attract and retain qualified personnel has increased over the
past few years due to competition and may increase substantially
in the future. Our ability to acquire additional prospects and
to find and develop reserves in the future will depend on our
ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment.
Also, there is substantial competition for capital available for
investment in the oil and gas industry. We may not be able to
compete successfully in the future in acquiring prospective
reserves, developing reserves, marketing hydrocarbons,
attracting and retaining quality personnel and raising
additional capital. Our failure to acquire properties, market
crude oil and natural gas and secure trained personnel and
adequately compensate personnel could have a material adverse
effect on our production, revenues and results of operations.
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Shortages
of oilfield equipment, services and qualified personnel could
delay our drilling program and increase the prices we pay to
obtain such equipment, services and personnel.
The demand for qualified and experienced field personnel to
drill wells and conduct field operations, geologists,
geophysicists, engineers and other professionals in the oil and
gas industry can fluctuate significantly, often in correlation
with crude oil and natural gas prices, causing periodic
shortages. Historically, there have been shortages of drilling
and workover rigs, pipe and other oilfield equipment as demand
for rigs and equipment has increased along with the number of
wells being drilled. These factors also cause significant
increases in costs for equipment, services and personnel. Higher
crude oil and natural gas prices generally stimulate demand and
result in increased prices for drilling and workover rigs, crews
and associated supplies, equipment and services. It is beyond
our control and ability to predict whether these conditions will
exist in the future and, if so, what their timing and duration
will be. These types of shortages or price increases could
significantly decrease our profit margin, cash flow and
operating results, or restrict our ability to drill the wells
and conduct the operations which we currently have planned and
budgeted or which we may plan in the future.
Our
exploration and development drilling may not result in
commercially productive reserves.
Drilling activities are subject to many risks, including the
risk that commercially productive reservoirs will not be
encountered. New wells that we drill may not be productive, or
we may not recover all or any portion of our investment in such
wells. The seismic data and other technologies we use do not
allow us to know conclusively prior to drilling a well that
crude oil or natural gas is present or may be produced
economically. Drilling for crude oil and natural gas often
involves unprofitable efforts, not only from dry holes but also
from wells that are productive but do not produce sufficient net
reserves to return a profit at then realized prices after
deducting drilling, operating and other costs. The cost of
drilling, completing and operating a well is often uncertain,
and cost factors can adversely affect the economics of a
project. Further, our drilling operations may be curtailed,
delayed or canceled as a result of numerous factors, including:
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unexpected drilling conditions;
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title problems;
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pressure or lost circulation in formations;
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equipment failures or accidents;
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adverse weather conditions;
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compliance with environmental and other governmental or
contractual requirements; and
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increases in the cost of, or shortages or delays in the
availability of, electricity, supplies, materials, drilling or
workover rigs, equipment and services.
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We
periodically evaluate our unproved oil and gas properties for
impairment, and could be required to recognize noncash charges
to earnings of future periods.
At December 31, 2008, we carried unproved property costs of
$377.2 million. GAAP requires periodic evaluation of these
costs on a
project-by-project
basis in comparison to their estimated fair value. These
evaluations will be affected by the results of exploration
activities, commodity price circumstances, planned future sales
or expiration of all or a portion of the leases, contracts and
permits appurtenant to such projects. If the quantity of
potential reserves determined by such evaluations is not
sufficient to fully recover the cost invested in each project,
we will recognize noncash charges to earnings of future periods.
We may
incur substantial losses and be subject to substantial liability
claims as a result of our crude oil and natural gas operations.
In addition, we may not be insured for, or our insurance may be
inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities
arising from uninsured and underinsured events could materially
and adversely affect our business, financial condition or
results of operations. Our crude oil and
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natural gas exploration and production activities are subject to
all of the operating risks associated with drilling for and
producing crude oil and natural gas, including the possibility
of:
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environmental hazards, such as uncontrollable flows of crude
oil, natural gas, brine, well fluids, toxic gas or other
pollution into the environment, including groundwater
contamination;
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abnormally pressured or structured formations;
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mechanical difficulties, such as stuck oilfield drilling and
service tools and casing collapse;
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fires, explosions and ruptures of pipelines;
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personal injuries and death; and
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natural disasters.
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Any of these risks could adversely affect our ability to conduct
operations or result in substantial losses to us as a result of:
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injury or loss of life;
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damage to and destruction of property, natural resources and
equipment;
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pollution and other environmental damage;
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regulatory investigations and penalties;
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suspension of our operations; and
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repair and remediation costs.
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We may elect not to obtain insurance if we believe that the cost
of available insurance is excessive relative to the risks
presented. In addition, pollution and environmental risks
generally are not fully insurable. The occurrence of an event
that is not covered or not fully covered by insurance could have
a material adverse effect on our production, revenues and
results of operations.
Market
conditions or operational impediments may hinder our access to
crude oil and natural gas markets or delay our
production.
Market conditions or the unavailability of satisfactory crude
oil and natural gas processing or transportation arrangements
may hinder our access to crude oil and natural gas markets or
delay our production. The availability of a ready market for our
crude oil and natural gas production depends on a number of
factors, including the demand for and supply of crude oil and
natural gas, the proximity of reserves to pipelines and terminal
facilities, competition for such facilities and the inability of
such facilities to gather, transport or process our production
due to shutdowns or curtailments arising from mechanical,
operational or weather related matters, including hurricanes and
other severe weather conditions. Our ability to market our
production depends in substantial part on the availability and
capacity of gathering and transportation systems, pipelines and
processing facilities owned and operated by third parties. Our
failure to obtain such services on acceptable terms could have a
material adverse effect on our business, financial condition and
results of operations. We may be required to shut in wells due
to lack of a market or inadequacy or unavailability of crude
oil, natural gas liquids or natural gas pipeline or gathering,
transportation or processing capacity. If that were to occur,
then we would be unable to realize revenue from those wells
until suitable arrangements were made to market our production.
We are
subject to complex federal, state, local and other laws and
regulations that could adversely affect the cost, timing, manner
or feasibility of conducting our operations.
Our crude oil and natural gas exploration, development and
production, and saltwater disposal operations are subject to
complex and stringent laws and regulations. In order to conduct
our operations in compliance with these laws and regulations, we
must obtain and maintain numerous permits, approvals and
certificates from various federal, state, local and governmental
authorities. We may incur substantial costs and experience
delays in order to maintain compliance with these existing laws
and regulations. In addition, our costs of compliance may
increase or
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our operations may be otherwise adversely affected if existing
laws and regulations are revised or reinterpreted, or if new
laws and regulations become applicable to our operations. These
and other costs could have a material adverse effect on our
production, revenues and results of operations.
Our business is subject to federal, state and local laws and
regulations as interpreted and enforced by governmental
authorities possessing jurisdiction over various aspects of the
exploration for, and the production of, crude oil and natural
gas. Failure to comply with such laws and regulations, as
interpreted and enforced, could have a material adverse effect
on our production, revenues and results of operations.
We may
incur substantial costs to comply with, and demand for our
products may be reduced by, climate change legislation and
regulatory initiatives.
The United States Congress is considering legislation to reduce
emissions of greenhouse gases and more than one-third of the
states, either individually or through multi-state initiatives,
already have begun implementing legal measures to reduce
emissions of greenhouse gases. In addition, the EPA has
announced possible future regulation of greenhouse gas emissions
under the Clean Air Act. Depending on the nature of potential
regulations and legislation, such future laws and regulations
could result in increased compliance costs or additional
operating restrictions, and could have a material adverse effect
on our business or demand for the oil and natural gas we produce.
Our
operations expose us to significant costs and liabilities with
respect to environmental and operational safety
matters.
We may incur significant delays, costs and liabilities as a
result of environmental, health and safety requirements
applicable to our crude oil and natural gas exploration,
development and production, and saltwater disposal activities.
These delays, costs and liabilities could arise under a wide
range of federal, state and local laws and regulations relating
to protection of the environment, health and safety, including
regulations and enforcement policies that have tended to become
increasingly strict over time. Failure to comply with these laws
and regulations may result in the assessment of administrative,
civil and criminal penalties, imposition of cleanup and site
restoration costs and liens, and, to a lesser extent, issuance
of injunctions to limit or cease operations. In addition, claims
for damages to persons or property, including natural resources,
may result from the environmental, health and safety impacts of
our operations.
Strict as well as joint and several liability may be imposed
under certain environmental laws, which could cause us to become
liable for the conduct of others or for consequences of our own
actions that were in compliance with all applicable laws at the
time those actions were taken. New laws, regulations or
enforcement policies could be more stringent and impose
unforeseen liabilities or significantly increase compliance
costs. If we were not able to recover the resulting costs
through insurance or increased revenues, our production,
revenues and results of operations could be adversely affected.
The
loss of our chief executive officer or other key personnel could
negatively impact our ability to execute our business
strategy.
We depend, and will continue to depend in the foreseeable
future, on the services of our chief executive officer, Timothy
A. Leach, and other key employees who have extensive experience
and expertise in evaluating and analyzing producing oil and gas
properties and drilling prospects, maximizing production from
oil and gas properties, marketing oil and gas production, and
developing and executing acquisition, financing and hedging
strategies. Our ability to hire and retain our officers and key
employees is important to our continued success and growth. The
unexpected loss of the services of one or more of these
individuals could negatively impact our ability to execute our
business strategy.
Uncertainties
associated with enhanced recovery methods may result in us not
realizing an acceptable return on our investments in such
projects.
We inject water into formations on some of our properties to
increase the production of crude oil and natural gas. We may in
the future expand these efforts to more of our properties or
employ other enhanced recovery methods in our operations. The
additional production and reserves, if any, attributable to the
use of enhanced
28
recovery methods are inherently difficult to predict. If our
enhanced recovery methods do not allow for the extraction of
crude oil and natural gas in a manner or to the extent that we
anticipate, we may not realize an acceptable return on our
investments in such projects.
Our
indebtedness could restrict our operations and make us more
vulnerable to adverse economic conditions.
We now have, and will continue to have, a significant amount of
indebtedness, and the terms of our credit facility require us to
pay higher interest rate margins as we utilize a larger
percentage of our available borrowing base. At December 31,
2008, our total debt was $630.0 million. Assuming our total
debt outstanding at December 31, 2008 was held constant, if
interest rates had been higher or lower by 1 percent per
annum, our annual interest expense would have increased or
decreased by approximately $6.3 million. At
December 31, 2008, our total borrowing capacity under our
credit facility was $960 million, of which
$329.7 million was available.
Our current and future indebtedness could have important
consequences to you. For example, it could:
|
|
|
|
|
impair our ability to make investments and obtain additional
financing for working capital, capital expenditures,
acquisitions or other general corporate purposes;
|
|
|
|
limit our ability to use operating cash flow in other areas of
our business because we must dedicate a substantial portion of
these funds to make principal and interest payments on our
indebtedness;
|
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|
|
limit our ability to borrow funds that may be necessary to
operate or expand our business;
|
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|
|
put us at a competitive disadvantage to competitors that have
less debt;
|
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|
|
increase our vulnerability to interest rate increases; and
|
|
|
|
hinder our ability to adjust to rapidly changing economic and
industry conditions.
|
Our ability to meet our debt service and other obligations may
depend in significant part on the extent to which we can
successfully implement our business strategy. We may not be able
to implement or realize the benefits of our business strategy.
Our
credit facility imposes restrictions on us that may affect our
ability to successfully operate our business.
Our credit facility limits our ability to take various actions,
such as:
|
|
|
|
|
incurring additional indebtedness;
|
|
|
|
paying dividends;
|
|
|
|
creating certain additional liens on our assets;
|
|
|
|
entering into sale and leaseback transactions;
|
|
|
|
making investments;
|
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|
|
entering into transactions with affiliates;
|
|
|
|
making material changes to the type of business we conduct or
our business structure;
|
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|
|
making guarantees;
|
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|
|
disposing of assets in excess of certain permitted amounts;
|
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|
|
merging or consolidating with other entities; and
|
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|
|
selling all or substantially all of our assets.
|
In addition, our credit facility requires us to maintain certain
financial ratios and to satisfy certain financial conditions,
which may require us to reduce our debt or take some other
action in order to comply with each of them.
29
These restrictions could also limit our ability to obtain future
financings, make needed capital expenditures, withstand a
downturn in our business or the economy in general, or otherwise
conduct necessary corporate activities. We also may be prevented
from taking advantage of business opportunities that arise
because of the limitations imposed on us by the restrictive
covenants under our credit facility.
A
terrorist attack or armed conflict could harm our business by
decreasing our revenues and increasing our costs.
Terrorist activities, anti-terrorist efforts and other armed
conflict involving the United States may adversely affect the
United States and global economies and could prevent us from
meeting our financial and other obligations. If any of these
events occur or escalate, the resulting political instability
and societal disruption could reduce overall demand for crude
oil and natural gas, potentially putting downward pressure on
demand for our services and causing a reduction in our revenue.
Crude oil and natural gas related facilities could be direct
targets of terrorist attacks, and our operations could be
adversely impacted if significant infrastructure or facilities
we use for the production, transportation or marketing of our
crude oil and natural gas production are destroyed or damaged.
Costs for insurance and other security may increase as a result
of these threats, and some insurance coverage may become more
difficult to obtain, if available at all.
Risks
Relating to Our Common Stock
Our
restated certificate of incorporation, amended and restated
bylaws and Delaware law contain provisions that could discourage
acquisition bids or merger proposals, which may adversely affect
the market price of our common stock.
Our restated certificate of incorporation authorizes our board
of directors to issue preferred stock without stockholder
approval. If our board of directors elects to issue preferred
stock, it could be more difficult for a third party to acquire
us. In addition, some provisions of our restated certificate of
incorporation, amended and restated bylaws and Delaware law
could make it more difficult for a third party to acquire
control of us, even if the change of control would be beneficial
to our stockholders, including:
|
|
|
|
|
the organization of our board of directors as a classified
board, which allows no more than approximately one-third of our
directors to be elected each year;
|
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|
|
stockholders cannot remove directors from our board of directors
except for cause and then only by the holders of not less than
662/3 percent
of the voting power of all outstanding voting stock;
|
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|
|
the prohibition of stockholder action by written
consent; and
|
|
|
|
limitations on the ability of our stockholders to call special
meetings and establish advance notice provisions for stockholder
proposals and nominations for elections to the board of
directors to be acted upon at meetings of stockholders.
|
Because
we have no plans to pay dividends on our common stock,
stockholders must look solely to stock appreciation for a return
on their investment in us.
We do not anticipate paying any cash dividends on our common
stock in the foreseeable future. We currently intend to retain
all future earnings to fund the development and growth of our
business. Any payment of future dividends will be at the
discretion of our board of directors and will depend on, among
other things, our earnings, financial condition, capital
requirements, level of indebtedness, statutory and contractual
restrictions applying to the payment of dividends and other
considerations that our board of directors deems relevant. The
terms of our existing credit facility restricts the payment of
dividends without the prior written consent of the lenders.
Stockholders must rely on sales of their common stock after
price appreciation, which may never occur, as the only way to
realize a return on their investment.
30
The
availability of shares for sale in the future could reduce the
market price of our common stock.
In the future, we may issue securities to raise cash for
acquisitions, the payment of our indebtedness or other purposes.
We may also acquire interests in other companies by using a
combination of cash and our common stock or solely our common
stock. We may also issue securities convertible into our common
stock. Any of these events may dilute your ownership interest in
us and have an adverse impact on the price of our common stock.
In addition, sales of a substantial amount of our common stock
in the public market or the perception that these sales may
occur, could reduce the market price of our common stock. This
could also impair our ability to raise additional capital
through the sale of our securities.
|
|
Item 1B.
|
Unresolved
Staff Comments
|
There are no unresolved staff comments.
Our Oil
and Natural Gas Reserves
The following table sets forth our estimated net proved oil and
natural gas reserves,
PV-10 and
Standardized Measure at December 31, 2008.
PV-10
includes the present value of our estimated future abandonment
and site restoration costs for proved properties net of the
present value of estimated salvage proceeds from each of these
properties. Our reserve estimates are based on independent
engineering evaluations prepared by Netherland,
Sewell & Associates, Inc. and Cawley
Gillespie & Associates, Inc. at December 31, 2008
($41.00 per Bbl West Texas Intermediate posted oil price and
$5.71 per MMBtu NYMEX natural gas price, adjusted for location
and quality by field, were used in the computation of future net
cash flows). The following table sets forth certain proved
reserve information by region at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
Gas (MMcf)
|
|
|
Total (MBoe)
|
|
|
PV-10(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Core Operating Areas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Mexico Permian
|
|
|
56,322
|
|
|
|
232,399
|
|
|
|
95,055
|
|
|
$
|
1,242.8
|
|
Texas Permian
|
|
|
28,319
|
|
|
|
66,439
|
|
|
|
39,392
|
|
|
|
378.0
|
|
Emerging plays and other
|
|
|
1,644
|
|
|
|
7,110
|
|
|
|
2,828
|
|
|
|
42.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
86,285
|
|
|
|
305,948
|
|
|
|
137,275
|
|
|
$
|
1,663.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present value of future income tax discounted at 10%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(464.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,199.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Non-GAAP Financial Measure and Reconciliation
(unaudited)
PV-10 is
derived from the Standardized Measure which is the most directly
comparable GAAP financial measure.
PV-10 is a
computation of the Standardized Measure on a pre-tax basis.
PV-10 is
equal to the Standardized Measure at the applicable date, before
deducting future income taxes, discounted at 10%. We believe
that the presentation of the
PV-10 is
relevant and useful to investors because it presents the
discounted future net cash flows attributable to our estimated
net proved reserves prior to taking into account future
corporate income taxes, and it is a useful measure for
evaluating the relative monetary significance of our oil and
natural gas properties. Further, investors may utilize the
measure as a basis for comparison of the relative size and value
of our reserves to other companies. We use this measure when
assessing the potential return on investment related to our oil
and natural gas properties.
PV-10,
however, is not a substitute for the Standardized Measure. Our
PV-10
measure and the Standardized Measure do not purport to present
the fair value of our oil and natural gas reserves. |
31
The following table sets forth our estimated net proved reserves
by category at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
Gas (MMcf)
|
|
|
Total (MBoe)
|
|
|
Percent of Total
|
|
|
PV-10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
Proved developed producing
|
|
|
41,317
|
|
|
|
162,419
|
|
|
|
68,387
|
|
|
|
49.8
|
%
|
|
$
|
1,072.1
|
|
Proved developed non-producing
|
|
|
5,344
|
|
|
|
16,705
|
|
|
|
8,128
|
|
|
|
5.9
|
%
|
|
|
99.3
|
|
Proved undeveloped
|
|
|
39,624
|
|
|
|
126,824
|
|
|
|
60,760
|
|
|
|
44.3
|
%
|
|
|
491.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total proved
|
|
|
86,285
|
|
|
|
305,948
|
|
|
|
137,275
|
|
|
|
100.0
|
%
|
|
$
|
1,663.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth the estimated timing and cash
flows of developing our proved undeveloped reserves at
December 31, 2008 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future
|
|
|
Future
|
|
|
Future
|
|
|
Future
|
|
|
|
|
|
|
Production
|
|
|
Cash
|
|
|
Production
|
|
|
Development
|
|
|
Future Net
|
|
Year Ended December 31,(a)
|
|
(MBoe)
|
|
|
Inflows
|
|
|
Costs
|
|
|
Costs
|
|
|
Cash Flows
|
|
|
2009
|
|
|
1,957
|
|
|
$
|
82,647
|
|
|
$
|
9,552
|
|
|
$
|
192,656
|
|
|
$
|
(119,561
|
)
|
2010
|
|
|
3,767
|
|
|
|
158,303
|
|
|
|
19,204
|
|
|
|
143,366
|
|
|
|
(4,267
|
)
|
2011
|
|
|
4,711
|
|
|
|
199,055
|
|
|
|
25,310
|
|
|
|
121,547
|
|
|
|
52,198
|
|
2012
|
|
|
4,882
|
|
|
|
205,521
|
|
|
|
27,841
|
|
|
|
86,991
|
|
|
|
90,689
|
|
2013
|
|
|
4,445
|
|
|
|
187,524
|
|
|
|
27,365
|
|
|
|
21,739
|
|
|
|
138,420
|
|
Thereafter
|
|
|
40,998
|
|
|
|
1,724,511
|
|
|
|
412,737
|
|
|
|
82,599
|
|
|
|
1,229,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
60,760
|
|
|
$
|
2,557,561
|
|
|
$
|
522,009
|
|
|
$
|
648,898
|
|
|
$
|
1,386,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Beginning in 2010 and thereafter, the production and cash flows
represent the drilling results from the respective year plus the
incremental effects of proved undeveloped drilling from the
preceding years beginning in 2009. |
The following table sets forth the changes in our proved reserve
volumes by region during the year ended December 31, 2008
(in MBoe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of
|
|
Sales of
|
|
Revisions of
|
|
|
|
|
Extensions and
|
|
Minerals-in-
|
|
Minerals-in-
|
|
Previous
|
|
|
Production
|
|
Discoveries
|
|
Place
|
|
Place
|
|
Estimates
|
|
Core Operating Areas:t
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Mexico Permian
|
|
|
(5,352
|
)
|
|
|
29,657
|
|
|
|
36
|
|
|
|
|
|
|
|
(6,470
|
)
|
Texas Permian
|
|
|
(1,463
|
)
|
|
|
5,037
|
|
|
|
30,138
|
|
|
|
|
|
|
|
(6,884
|
)
|
Emerging Plays and Other
|
|
|
(266
|
)
|
|
|
1,730
|
|
|
|
|
|
|
|
|
|
|
|
112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
(7,081
|
)
|
|
|
36,424
|
|
|
|
30,174
|
|
|
|
|
|
|
|
(13,242
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production. Production volumes of
7.1 MMBoe includes production from our acquisition of the
Henry Properties since August 1, 2008.
Extensions and discoveries. Extensions
and discoveries are primarily the result of extension drilling
in the Yeso formation of Southeastern New Mexico and the
Wolfberry formation in West Texas and exploratory drilling in
certain of our emerging plays.
Purchases of
minerals-in-place. Purchases
of
minerals-in-place
are primarily attributable to the acquisition of the Henry
Properties.
Sales of
minerals-in-place. We
had no significant sales of
minerals-in-place
during 2008.
Revisions of previous
estimates. Revisions of previous estimates
are comprised of 10.1 MMBoe of negative revisions resulting
from commodity price declines and 3.1 MMBoe of negative
revision resulting from technical and performance evaluations.
The Companys proved reserves at December 31, 2008
were determined using year-
32
end NYMEX equivalent prices of $41.00 per Bbl of oil and $5.71
per MMBtu of gas, compared to $92.50 per Bbl of oil and $6.80
per MMBtu of gas at December 31, 2007.
Developed
and Undeveloped Acreage
The following table presents our total gross and net developed
and undeveloped acreage by region at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acres
|
|
Undeveloped Acres
|
|
Total Acres
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Core Operating Areas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Mexico Permian
|
|
|
108,728
|
|
|
|
53,994
|
|
|
|
44,697
|
|
|
|
17,429
|
|
|
|
153,425
|
|
|
|
71,423
|
|
Texas Permian
|
|
|
192,264
|
|
|
|
50,060
|
|
|
|
49,244
|
|
|
|
19,667
|
|
|
|
241,508
|
|
|
|
69,727
|
|
Emerging plays and other(a)
|
|
|
20,218
|
|
|
|
8,230
|
|
|
|
196,931
|
|
|
|
94,345
|
|
|
|
217,149
|
|
|
|
102,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
321,210
|
|
|
|
112,284
|
|
|
|
290,872
|
|
|
|
131,441
|
|
|
|
612,082
|
|
|
|
243,725
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The following table sets forth gross and net acreage at
December 31, 2008 for each of our five emerging plays and
our acreage categorized as Other included in
Emerging plays and other: |
|
|
|
|
|
|
|
|
|
|
|
Total Acres
|
|
|
Gross
|
|
Net
|
|
Southeastern New Mexico
|
|
|
60,915
|
|
|
|
30,581
|
|
Williston Basin of North Dakota
|
|
|
42,802
|
|
|
|
11,223
|
|
Central Basin Platform
|
|
|
22,925
|
|
|
|
22,156
|
|
Western Delaware Basin
|
|
|
68,814
|
|
|
|
23,593
|
|
Arkoma Basin of Arkansas
|
|
|
16,744
|
|
|
|
14,225
|
|
|
|
|
|
|
|
|
|
|
Total emerging plays
|
|
|
212,200
|
|
|
|
101,778
|
|
Other
|
|
|
4,949
|
|
|
|
797
|
|
|
|
|
|
|
|
|
|
|
Total emerging plays and other
|
|
|
217,149
|
|
|
|
102,575
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth the expiration amounts of our
gross and net undeveloped acreage at December 31, 2008 by
region. Expirations may be less or reduced if production is
established
and/or
continuous development activities are undertaken beyond the
primary term of the lease.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009(a)
|
|
2010
|
|
2011
|
|
Thereafter
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Core Operating Areas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Mexico Permian
|
|
|
5,241
|
|
|
|
1,912
|
|
|
|
7,453
|
|
|
|
2,922
|
|
|
|
2,846
|
|
|
|
1,145
|
|
|
|
36,751
|
|
|
|
11,584
|
|
Texas Permian
|
|
|
6,498
|
|
|
|
2,467
|
|
|
|
6,233
|
|
|
|
549
|
|
|
|
5,990
|
|
|
|
1,088
|
|
|
|
|
|
|
|
|
|
Emerging plays and other
|
|
|
88,413
|
|
|
|
28,387
|
|
|
|
41,612
|
|
|
|
16,951
|
|
|
|
11,839
|
|
|
|
9,538
|
|
|
|
8,420
|
|
|
|
4,896
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100,152
|
|
|
|
32,766
|
|
|
|
55,298
|
|
|
|
20,422
|
|
|
|
20,675
|
|
|
|
11,771
|
|
|
|
45,171
|
|
|
|
16,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Due to market conditions and prioritization of capital, we have
deemphasized exploration efforts in certain emerging plays
having significant lease expirations over the next two years,
which includes the Delaware Basin, Central Basin Platform and
Arkoma Basin in Arkansas. We have impaired a significant portion
of the costs associated with these plays. |
33
Productive
wells
The following table sets forth the number of productive oil and
gas wells on our properties at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Productive Wells
|
|
Net Productive Wells
|
|
|
Oil
|
|
Gas
|
|
Total
|
|
Oil
|
|
Gas
|
|
Total
|
|
Core Operating Areas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Mexico Permian
|
|
|
1,515
|
|
|
|
192
|
|
|
|
1,707
|
|
|
|
967.3
|
|
|
|
55.8
|
|
|
|
1,023.1
|
|
Texas Permian
|
|
|
1,625
|
|
|
|
71
|
|
|
|
1,696
|
|
|
|
381.0
|
|
|
|
13.7
|
|
|
|
394.7
|
|
Emerging plays and other
|
|
|
61
|
|
|
|
89
|
|
|
|
150
|
|
|
|
8.5
|
|
|
|
5.3
|
|
|
|
13.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
3,201
|
|
|
|
352
|
|
|
|
3,553
|
|
|
|
1,356.8
|
|
|
|
74.8
|
|
|
|
1,431.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Title to
Our Properties
As is customary in the oil and gas industry, we initially
conduct only a cursory review of the title to our properties on
which we do not have proved reserves. Prior to the commencement
of drilling operations on those properties, we conduct a more
thorough title examination and perform curative work with
respect to significant defects. To the extent title opinions or
other investigations reflect defects affecting those properties,
we are typically responsible for curing any such defects at our
expense. We generally will not commence drilling operations on a
property until we have cured known material title defects on
such property. We have reviewed the title to substantially all
of our producing properties and believe that we have
satisfactory title to our producing properties in accordance
with standards generally accepted in the oil and gas industry.
Prior to completing an acquisition of producing oil and natural
gas properties, we perform title reviews on the most significant
properties and, depending on the materiality of properties, we
may obtain a title opinion or review or update previously
obtained title opinions. Our oil and natural gas properties are
subject to customary royalty and other interests, liens to
secure borrowings under our credit facility, liens for current
taxes and other burdens which we believe do not materially
interfere with the use or affect our carrying value of the
properties.
|
|
Item 3.
|
Legal
Proceedings
|
We are party to the legal proceedings that are described in
Note K of the Notes to Consolidated Financial Statements
included in Item 8. Financial Statements and
Supplementary Data. We are also party to other proceedings
and claims incidental to our business. While many of these other
matters involve inherent uncertainty, we believe that the
liability, if any, ultimately incurred with respect to such
other proceedings and claims will not have a material adverse
effect on our consolidated financial position as a whole or on
our liquidity, capital resources or future results of operations.
|
|
Item 4.
|
Submission
of Matters to a Vote of Shareholders
|
We did not submit any matters to a vote of stockholders during
the fourth quarter of 2008.
34
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
|
Market
Information
Our common stock trades on the NYSE under the symbol
CXO. The following table shows, for the periods
indicated, the high and low sales prices for our common stock,
as reported on the NYSE.
|
|
|
|
|
|
|
|
|
|
|
Price Per Share
|
|
|
High
|
|
Low
|
|
2007:
|
|
|
|
|
|
|
|
|
Third Quarter (August 3, 2007 through September 30,
2007)
|
|
$
|
16.44
|
|
|
$
|
11.60
|
|
Fourth Quarter
|
|
$
|
22.30
|
|
|
$
|
14.30
|
|
2008:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
26.44
|
|
|
$
|
17.33
|
|
Second Quarter
|
|
$
|
40.97
|
|
|
$
|
25.12
|
|
Third Quarter
|
|
$
|
39.07
|
|
|
$
|
22.31
|
|
Fourth Quarter
|
|
$
|
27.79
|
|
|
$
|
14.71
|
|
The last sale price of our common stock on February 23,
2009 was $20.50 per share, as reported on the NYSE.
As of February 23, 2009, there were approximately
13,020 holders of record of our common stock.
Dividends
We have not paid, and do not intend to pay in the foreseeable
future, cash dividends on our common stock. Our credit facility
prohibits the payment of dividends on our common stock.
Repurchase
of Equity Securities
Neither we nor any affiliated purchaser repurchased
any of our equity securities during the fourth quarter of the
fiscal year ended December 31, 2008.
|
|
Item 6.
|
Selected
Financial Data
|
This section presents our selected historical consolidated
financial data. The selected historical consolidated financial
data presented below is not intended to replace our historical
consolidated financial statements. You should read the following
data along with Managements Discussion and Analysis
of Financial Condition and Results of Operations and the
consolidated financial statements and related notes, each of
which is included in this report.
Selected
Historical Financial Information
The following table shows selected historical financial data
related to Concho (as the accounting successor to Concho Equity
Holdings Corp., which is now known as Concho Equity Holdings
LLC) and combined financial data of the Chase Group
Properties. We have accounted for the combination transaction
that occurred on February 27, 2006, as an acquisition by
Concho Equity Holdings Corp. of the Chase Group Properties and a
simultaneous reorganization of Concho such that Concho Equity
Holdings Corp. became our wholly owned subsidiary.
Our historical results of operations for the periods presented
below may not be comparable either from period to period or
going forward, for the following reasons:
|
|
|
|
|
Prior to December 7, 2004, Concho Equity Holdings Corp. did
not own any material assets and did not conduct substantial
operations other than organizational activities;
|
35
|
|
|
|
|
On December 7, 2004, Concho Equity Holdings Corp. acquired
oil and gas assets for approximately $117 million and
commenced oil and gas operations;
|
|
|
|
On February 27, 2006, the initial closing of the Chase Oil
transaction occurred, and we acquired the Chase Group Properties
for approximately 35 million shares of common stock and
approximately $409 million in cash;
|
|
|
|
On March 27, 2007, we entered into a $200 million
second lien term loan facility from which we received proceeds
of $199 million that we used to repay the
$39.8 million outstanding under our prior term loan
facility and to reduce the outstanding balance under our credit
facility by $154 million, with the remaining
$5.2 million used to pay loan fees, accrued interest and
for general corporate purposes;
|
|
|
|
In August 2007, we completed our initial public offering of
common stock from which we received proceeds of
$173 million that we used to retire outstanding borrowings
under our second lien term loan facility totaling
$86.5 million, and to retire outstanding borrowings under
our credit facility totaling $86.5 million; and
|
|
|
|
On July 31, 2008, we closed our acquisition of the Henry
Entities and additional non-operated interests in oil and gas
properties from persons affiliated with the Henry Entities. In
August 2008 and September 2008, we acquired additional
non-operated interests in oil and gas properties from persons
affiliated with the Henry Entities. We paid approximately
$584.1 million in net cash for the acquisition of the Henry
Entities and the related acquisition of the along-side
interests, which was funded with borrowings under our credit
facility, which was amended and restated on July 31, 2008,
and net proceeds of approximately $242.4 million from our
private placement of 8,302,894 shares of our common stock.
|
The historical financial data below for the Chase Group
Properties for the years ended December 31, 2005 and 2004
are derived from the audited financial statements of the Chase
Group Properties. The historical financial data below for Concho
Resources Inc. for the years ended December 31, 2008, 2007,
2006 and 2005, and for the period from inception (April 21,
2004) through December 31, 2004, are derived from the
audited financial statements of Concho.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chase Group
|
|
|
|
Concho Resources Inc.
|
|
|
Properties
|
|
|
|
|
|
|
Inception
|
|
|
|
|
|
|
|
|
|
(April 21,
|
|
|
|
|
|
|
|
|
|
2004) through
|
|
|
Years Ended
|
|
|
|
Years Ended December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2008(a)
|
|
|
2007
|
|
|
2006(b)
|
|
|
2005
|
|
|
2004(c)
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Statement of operations data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
390,945
|
|
|
$
|
195,596
|
|
|
$
|
131,773
|
|
|
$
|
31,621
|
|
|
$
|
1,851
|
|
|
$
|
73,132
|
|
|
$
|
66,529
|
|
Natural gas sales
|
|
|
142,844
|
|
|
|
98,737
|
|
|
|
66,517
|
|
|
|
23,315
|
|
|
|
1,771
|
|
|
|
46,546
|
|
|
|
41,247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
533,789
|
|
|
|
294,333
|
|
|
|
198,290
|
|
|
|
54,936
|
|
|
|
3,622
|
|
|
|
119,678
|
|
|
|
107,776
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
91,234
|
|
|
|
54,267
|
|
|
|
37,822
|
|
|
|
14,635
|
|
|
|
746
|
|
|
|
23,277
|
|
|
|
20,964
|
|
Exploration and abandonments
|
|
|
38,468
|
|
|
|
29,098
|
|
|
|
5,612
|
|
|
|
2,666
|
|
|
|
1,850
|
|
|
|
|
|
|
|
179
|
|
Depreciation, depletion and amortization
|
|
|
123,912
|
|
|
|
76,779
|
|
|
|
60,722
|
|
|
|
11,485
|
|
|
|
956
|
|
|
|
18,646
|
|
|
|
20,196
|
|
Accretion of discount on asset retirement obligations
|
|
|
889
|
|
|
|
444
|
|
|
|
287
|
|
|
|
89
|
|
|
|
7
|
|
|
|
446
|
|
|
|
263
|
|
Impairments of long-lived assets
|
|
|
18,417
|
|
|
|
7,267
|
|
|
|
9,891
|
|
|
|
2,295
|
|
|
|
|
|
|
|
194
|
|
|
|
3,233
|
|
General and administrative
|
|
|
35,553
|
|
|
|
21,336
|
|
|
|
12,577
|
|
|
|
8,055
|
|
|
|
3,086
|
|
|
|
1,702
|
|
|
|
1,387
|
|
Stock-based compensation
|
|
|
5,223
|
|
|
|
3,841
|
|
|
|
9,144
|
|
|
|
3,252
|
|
|
|
1,128
|
|
|
|
|
|
|
|
|
|
Bad debt expense
|
|
|
2,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling fees stacked rigs
|
|
|
|
|
|
|
4,269
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chase Group
|
|
|
|
Concho Resources Inc.
|
|
|
Properties
|
|
|
|
|
|
|
Inception
|
|
|
|
|
|
|
|
|
|
(April 21,
|
|
|
|
|
|
|
|
|
|
2004) through
|
|
|
Years Ended
|
|
|
|
Years Ended December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2008(a)
|
|
|
2007
|
|
|
2006(b)
|
|
|
2005
|
|
|
2004(c)
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Ineffective portion of cash flow hedges
|
|
|
(1,336
|
)
|
|
|
821
|
|
|
|
(1,193
|
)
|
|
|
1,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) loss on derivatives not designated as hedges
|
|
|
(249,870
|
)
|
|
|
20,274
|
|
|
|
|
|
|
|
5,001
|
|
|
|
(684
|
)
|
|
|
1,062
|
|
|
|
7,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
65,395
|
|
|
|
218,396
|
|
|
|
134,862
|
|
|
|
48,626
|
|
|
|
7,089
|
|
|
|
45,327
|
|
|
|
54,158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
468,394
|
|
|
|
75,937
|
|
|
|
63,428
|
|
|
|
6,310
|
|
|
|
(3,467
|
)
|
|
|
74,351
|
|
|
|
53,618
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(29,039
|
)
|
|
|
(36,042
|
)
|
|
|
(30,567
|
)
|
|
|
(3,096
|
)
|
|
|
(272
|
)
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
1,432
|
|
|
|
1,484
|
|
|
|
1,186
|
|
|
|
779
|
|
|
|
168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(27,607
|
)
|
|
|
(34,558
|
)
|
|
|
(29,381
|
)
|
|
|
(2,317
|
)
|
|
|
(104
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
440,787
|
|
|
|
41,379
|
|
|
|
34,047
|
|
|
|
3,993
|
|
|
|
(3,571
|
)
|
|
|
74,351
|
|
|
|
53,618
|
|
Income tax (expense) benefit
|
|
|
(162,085
|
)
|
|
|
(16,019
|
)
|
|
|
(14,379
|
)
|
|
|
(2,039
|
)
|
|
|
915
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
278,702
|
|
|
|
25,360
|
|
|
|
19,668
|
|
|
|
1,954
|
|
|
|
(2,656
|
)
|
|
$
|
74,351
|
|
|
$
|
53,618
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividends
|
|
|
|
|
|
|
(45
|
)
|
|
|
(1,244
|
)
|
|
|
(4,766
|
)
|
|
|
(804
|
)
|
|
|
|
|
|
|
|
|
Effect of induced conversion of preferred stock
|
|
|
|
|
|
|
|
|
|
|
11,601
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) applicable to common shareholders
|
|
$
|
278,702
|
|
|
$
|
25,315
|
|
|
$
|
30,025
|
|
|
$
|
(2,812
|
)
|
|
$
|
(3,460
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
|
|
$
|
3.52
|
|
|
$
|
0.39
|
|
|
$
|
0.63
|
|
|
$
|
(0.70
|
)
|
|
$
|
(3.48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in basic earnings (loss) per share
|
|
|
79,206
|
|
|
|
64,316
|
|
|
|
47,287
|
|
|
|
4,059
|
|
|
|
994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
|
|
$
|
3.46
|
|
|
$
|
0.38
|
|
|
$
|
0.59
|
|
|
$
|
(0.70
|
)
|
|
$
|
(3.48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in diluted earnings (loss) per share
|
|
|
80,587
|
|
|
|
66,309
|
|
|
|
50,729
|
|
|
|
4,059
|
|
|
|
994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
|
|
Chase Group Properties
|
|
|
|
|
Inception
|
|
|
|
|
|
|
(April 21,
|
|
|
|
|
|
|
2004) through
|
|
|
|
|
Years Ended December 31,
|
|
December 31,
|
|
Years Ended December 31,
|
|
|
2008(a)
|
|
2007
|
|
2006(b)
|
|
2005
|
|
2004(c)
|
|
2005
|
|
2004
|
|
|
(In thousands)
|
|
Other financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operations
|
|
$
|
391,397
|
|
|
$
|
169,769
|
|
|
$
|
112,181
|
|
|
$
|
25,070
|
|
|
$
|
(2,193
|
)
|
|
$
|
93,162
|
|
|
$
|
84,202
|
|
Net cash provided by (used in) investing
|
|
|
(946,050
|
)
|
|
|
(160,353
|
)
|
|
|
(596,852
|
)
|
|
|
(61,902
|
)
|
|
|
(122,473
|
)
|
|
|
(35,611
|
)
|
|
|
(30,045
|
)
|
Net cash provided by (used in) financing
|
|
|
541,981
|
|
|
|
19,886
|
|
|
|
476,611
|
|
|
|
45,358
|
|
|
|
125,322
|
|
|
|
(57,551
|
)
|
|
|
(54,157
|
)
|
Capital expenditures
|
|
|
1,185,831
|
|
|
|
190,634
|
|
|
|
1,226,180
|
|
|
|
72,758
|
|
|
|
116,880
|
|
|
|
32,352
|
|
|
|
25,451
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
December 31,
|
|
|
2008(a)
|
|
2007
|
|
2006(b)
|
|
2005
|
|
2004(c)
|
|
2005
|
|
2004
|
|
Balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
17,752
|
|
|
$
|
30,424
|
|
|
$
|
1,122
|
|
|
$
|
9,182
|
|
|
$
|
656
|
|
|
$
|
|
|
|
$
|
|
|
Property and equipment, net
|
|
|
2,401,404
|
|
|
|
1,394,994
|
|
|
|
1,320,655
|
|
|
|
170,583
|
|
|
|
115,455
|
|
|
|
149,042
|
|
|
|
135,568
|
|
Total assets
|
|
|
2,815,203
|
|
|
|
1,508,229
|
|
|
|
1,390,072
|
|
|
|
232,385
|
|
|
|
130,717
|
|
|
|
161,792
|
|
|
|
145,100
|
|
Long-term debt, including current maturities
|
|
|
630,000
|
|
|
|
327,404
|
|
|
|
495,500
|
|
|
|
72,000
|
|
|
|
53,000
|
|
|
|
|
|
|
|
|
|
Equity
|
|
|
1,325,154
|
|
|
|
775,398
|
|
|
|
575,156
|
|
|
|
109,670
|
|
|
|
71,710
|
|
|
|
150,814
|
|
|
|
134,014
|
|
|
|
|
(a) |
|
The acquisition of the Henry Entities occurred on July 31,
2008. See Note D of the Notes to Consolidated Financial
Statements included in Item 8. Financial Statements and
Supplementary Data. |
|
(b) |
|
The acquisition of the Chase Group Properties was substantially
consummated on February 27, 2006. See Note D of the
Notes to Consolidated Financial Statements included in
Item 8. Financial Statements and Supplementary
Data. |
|
(c) |
|
The acquisition of the Lowe Properties was completed on
December 7, 2004. See Selected Historical Financial
and Operating Information for Lowe Properties below: |
Selected
Historical Financial and Operating Information for Lowe
Properties
On December 7, 2004, we acquired the Lowe Properties for
$117 million. The selected financial data below for the
Lowe Properties for the period from January 1, 2004 through
November 30, 2004 were derived from the audited statements
of revenue and direct operating expenses of the Lowe Properties
included in our prospectus dated August 2, 2007 and filed
with the SEC pursuant to Rule 424 (b) on
August 3, 2007 and information provided by the seller.
|
|
|
|
|
|
|
Period from
|
|
|
|
January 1,
|
|
|
|
through
|
|
|
|
November 30,
|
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Revenues
|
|
$
|
34,663
|
|
Direct operating expenses:
|
|
|
|
|
Lease operating expense
|
|
|
6,983
|
|
Production tax expense
|
|
|
2,159
|
|
Other expenses
|
|
|
461
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
9,603
|
|
|
|
|
|
|
Revenues in excess of direct operating expenses
|
|
$
|
25,060
|
|
|
|
|
|
|
|
|
Item 7.
|
Managements
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, as well as the selected historical
consolidated financial data included elsewhere in this report.
Statements in our discussion may be forward-looking statements.
These forward-looking statements involve risks and
uncertainties. We caution that a number of factors could cause
future production, revenues and expenses to differ materially
from our expectations.
38
Overview
We are an independent oil and natural gas company engaged in the
acquisition, development, exploitation and exploration of
producing oil and natural gas properties. Our core operations
are primarily focused in the Permian Basin of Southeastern New
Mexico and West Texas. We have also acquired significant acreage
positions in and are actively involved in drilling or
participating in drilling in emerging plays located in the
Permian Basin of Southeastern New Mexico and the Williston Basin
in North Dakota, where we are applying horizontal drilling,
advanced fracture stimulation and enhanced recovery
technologies. Crude oil comprised 62.9 percent of our
137.3 MMBoe of estimated net proved reserves at
December 31, 2008, and 64.8 percent of our
7.1 MMBoe of production for 2008. We seek to operate the
wells in which we own an interest, and we operated wells that
accounted for 93.1 percent of our proved developed
producing
PV-10 and
64.7 percent of our 3,553 gross wells at
December 31, 2008. By controlling operations, we are able
to more effectively manage the cost and timing of exploration
and development of our properties, including the drilling and
stimulation methods used.
Commodity
prices
Factors that may impact future commodity prices, including the
price of oil and natural gas, include developments generally
impacting the Middle East and Iraq and Iran specifically; the
extent to which members of the OPEC and other oil exporting
nations are able to continue to manage oil supply through export
quotas; the overall global demand for crude oil; and overall
North American gas supply and demand fundamentals, including the
impact of the decline of the U.S. economy, weather
conditions and liquefied natural gas deliveries to the United
States. Although we cannot predict the occurrence of events that
may affect future commodity prices or the degree to which these
prices will be affected, the prices for any commodity that we
produce will generally approximate current market prices in the
geographic region of the production. From time to time, we
expect that we may hedge a portion of our commodity price risk
to mitigate the impact of price volatility on our business. See
Note I of the Notes to Consolidated Financial Statements
included in Item 8. Financial Statements and
Supplementary Data for additional information regarding
our commodity hedge positions at December 31, 2008.
The 2008 oil prices were high compared to historical prices and
have been particularly volatile. The NYMEX crude oil price per
Bbl averaged $99.75, $72.45 and $66.26 for 2008, 2007 and 2006,
respectively. In addition, natural gas prices have been subject
to significant fluctuations during the past several years. The
NYMEX natural gas price per MMBtu averaged $7.41, $6.11 and
$6.06 for 2008, 2007 and 2006, respectively. Further
demonstrating the continuing volatility the NYMEX crude oil
price and NYMEX natural gas price reached lows of $33.98 per Bbl
and $4.08 per MMBtu, respectively, during the period from
January 1, 2009 to February 19, 2009. At
February 19, 2009, the NYMEX crude oil price and NYMEX
natural gas price were $39.48 per Bbl and $4.08 per MMBtu,
respectively.
Recent
events
Henry Entities acquisition. On
July 31, 2008, we closed our acquisition of the Henry
Entities and additional non-operated interests in oil and gas
properties from persons affiliated with the Henry Entities. In
August 2008 and September 2008, we acquired additional
non-operated interests in oil and gas properties from persons
affiliated with the Henry Entities. We paid approximately
$584.1 million in net cash for the acquisition of the Henry
Entities and the related acquisition of the along-side
interests, which was funded with borrowings under our credit
facility, which was amended and restated on July 31, 2008,
and net proceeds of approximately $242.4 million from our
private placement of 8,302,894 shares of our common stock.
Amended and restated credit
facility. On July 31, 2008, we amended
and restated our credit facility in various respects, including
increasing our borrowing base to $960 million, subject to
scheduled semiannual redeterminations, and extending the
maturity date from February 24, 2011 to July 31, 2013.
The initial borrowing under the credit facility was
$675 million. We paid an arrangement fee of
$14.4 million upon closing of the amended and restated
credit facility. On July 31, 2008, we repaid all amounts
outstanding under our 2nd lien credit facility and
terminated the facility. In October 2008, our $960 million
borrowing base was reaffirmed until the next scheduled borrowing
base redetermination in April 2009. Between scheduled borrowing
base redeterminations, we and, if requested by
662/3 percent
of the lenders, the lenders may each request one special
redetermination.
39
Common stock private placement. On
July 31, 2008, we closed a private placement of
approximately 8.3 million shares of our common stock at
$30.11 per share. The private placement resulted in net proceeds
of approximately $242.4 million to us, after payment of
approximately $7.6 million for the fee paid to the
placement agent.
2009 capital budget. On
November 6, 2008, our board of directors approved an
initial capital budget for 2009 of up to approximately
$500 million, predicated on us funding it substantially
within our cash flow. The following is a summary of our initial
2009 capital budget:
|
|
|
|
|
|
|
2009
|
|
|
|
Budget
|
|
|
|
(In millions)
|
|
|
Drilling and recompletion opportunities in our core operating
area
|
|
$
|
398
|
|
Projects operated by third parties
|
|
|
8
|
|
Emerging plays, acquisition of leasehold acreage and other
property interests, and geological and geophysical
|
|
|
72
|
|
Maintenance capital in our core operating areas
|
|
|
22
|
|
|
|
|
|
|
Total 2009 capital budget
|
|
$
|
500
|
|
|
|
|
|
|
In light of the recent drop in commodity prices, we took the
following actions in January 2009:
|
|
|
|
|
reduced our operated drilling rig count in the Wolfberry play
from eight to five;
|
|
|
|
deferred our deepening program on our Southeastern New Mexico
shelf properties; and
|
|
|
|
deferred certain drilling activity in the Lower Abo horizontal
play.
|
The annualized effect of these changes in operating activity
would reduce our 2009 capital spending to approximately
$300 million, assuming our current estimate of 2009 capital
costs. We will monitor our capital expenditures in relation to
our cash flow and expect to adjust our activity and capital
spending level based on changes in commodity prices and the cost
of goods and services and other considerations.
Short-term interruptions in
production. During 2008, our production was
interrupted on several occasions. The following were significant
interruptions:
|
|
|
|
|
None of our properties and facilities were directly impacted by
Hurricane Ike; however, facilities which ultimately received our
production, primarily natural gas liquids, sustained power
interruptions and physical damage. As a result, our production
was either curtailed or shut-in for significant periods of time.
As a result, we estimate that our September 2008 production was
reduced by approximately 117 MBoe and our October 2008
production was reduced by approximately 33 MBoe;
|
|
|
|
On May 16, 2008, a refinery located in New Mexico shut down
for ten days due to repairs. As a result, we shut-in
approximately 37 MBoe of production during the ten day
period;
|
|
|
|
On April 7, 2008, a natural gas processing plant through
which we process and sell a portion of the production from our
New Mexico shelf properties was curtailed for its annual routine
maintenance. The plant resumed full operation on April 19,
2008, and we thereafter began restoring production from all of
our properties that had been affected. Approximately
75 MBoe of our production was shut-in as a result of this
plant shut-down; and
|
|
|
|
During the first quarter of 2008, we experienced short-term
interruptions in our production on the New Mexico shelf
properties due to operational problems with a natural gas
processing plant. There were a total of 10 days of
curtailment during the first quarter, and approximately
17 MBoe of our production was curtailed during this period.
|
Derivative financial instrument
exposure. At December 31, 2008, the fair
value of our financial derivatives was a net asset of
$172.4 million. All of our counterparties to these
financial derivatives are party to our credit facility and have
their outstanding debt commitments and derivative exposures
collateralized pursuant to our credit
40
facility. Pursuant to the terms of our financial derivative
instruments and their collateralization under our credit
facility, we do not have exposure to potential margin
calls on our financial derivative instruments.
In light of the recent drop in commodity prices, most of our
commodity derivative instruments are currently in a net asset
position to us. We currently have no reason to believe that our
counterparties to these commodity derivative contracts are not
financially viable. Currently, all of our counterparties are
parties to our credit facility, and our credit facility does not
allow us to offset amounts we may owe a lender under our credit
facility against amounts we may be owed related to our financial
instruments with such party.
New commodity derivative
contracts. During 2008, we entered into
additional commodity derivative contracts to hedge a portion of
our estimated future production. The following table summarizes
information about these additional commodity derivative
contracts at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
|
Remaining
|
|
|
|
Remaining
|
|
|
Daily
|
|
|
Index
|
|
|
Contract
|
|
|
|
Volume
|
|
|
Volume
|
|
|
Price
|
|
|
Period
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar
|
|
|
768,000
|
|
|
|
2,104
|
|
|
$
|
120.00 - $134.60
|
(a)
|
|
|
1/1/09 - 12/31/09
|
|
Price swap
|
|
|
292,000
|
|
|
|
800
|
|
|
$
|
98.35
|
(a)
|
|
|
1/1/09 - 12/31/09
|
|
Price swap
|
|
|
348,000
|
|
|
|
953
|
|
|
$
|
125.10
|
(a)
|
|
|
1/1/09 - 12/31/09
|
|
Price swap
|
|
|
240,000
|
|
|
|
658
|
|
|
$
|
128.80
|
(a)
|
|
|
1/1/10 - 12/31/10
|
|
Price swap
|
|
|
336,000
|
|
|
|
921
|
|
|
$
|
128.66
|
(a)
|
|
|
1/1/11 - 12/31/11
|
|
Price swap
|
|
|
504,000
|
|
|
|
1,377
|
|
|
$
|
127.80
|
(a)
|
|
|
1/1/12 - 12/31/12
|
|
Natural gas (volumes in MMBtus):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
1,825,000
|
|
|
|
5,000
|
|
|
$
|
8.44
|
(b)
|
|
|
1/1/09 - 12/31/09
|
|
Index basis swap
|
|
|
6,022,500
|
|
|
|
16,500
|
|
|
$
|
1.08
|
(c)
|
|
|
1/1/09 - 12/31/09
|
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the
NYMEX-West Texas Intermediate monthly average futures price. |
|
(b) |
|
The index price for the natural gas price collar is based on the
Inside FERC-El Paso Permian Basin first-of-the-month spot
price. |
|
(c) |
|
The basis differential between the El Paso Permian delivery
point and NYMEX Henry Hub delivery point. |
Commodity derivative contracts assumed in the Henry
Entities acquisition. As part of the Henry
Entities acquisition, we assumed the following commodity
derivative contracts on July 31, 2008. The following table
summarizes information about the remaining portion of these
assumed derivative contracts at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
|
Remaining
|
|
|
|
|
|
|
Remaining
|
|
|
Daily
|
|
|
Index
|
|
|
Contract
|
|
|
|
|
|
|
Volume
|
|
|
Volume
|
|
|
Price
|
|
|
Period
|
|
|
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
443,491
|
|
|
|
1,215
|
|
|
$
|
73.59
|
(a)
|
|
|
1/1/09 - 12/31/09
|
|
|
|
|
|
Price swap
|
|
|
401,746
|
|
|
|
1,101
|
|
|
$
|
72.03
|
(a)
|
|
|
1/1/10 - 12/31/10
|
|
|
|
|
|
Price swap
|
|
|
221,746
|
|
|
|
608
|
|
|
$
|
68.92
|
(a)
|
|
|
1/1/11 - 12/31/11
|
|
|
|
|
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the
NYMEX-West Texas Intermediate monthly average futures price and
the prices represent weighted average prices. |
New interest rate derivative
contracts. During 2008, we entered into
interest rate derivative contracts to hedge a portion of our
future interest rate exposure. We hedged our LIBOR interest rate
on our bank debt by fixing the rate at 1.90 percent for
three years beginning in May of 2009 on $300 million of our
bank debt. For this portion of our bank debt, the all-in
interest rate will be calculated by adding the fixed rate of
1.90 percent to a margin that ranges from 1.25 percent
to 2.00 percent depending on the amount of bank debt
outstanding.
41
Items Impacting
Comparability of our Financial Results
Our historical results of operations for the periods presented
may not be comparable, either from period to period or going
forward, for the reasons described below:
|
|
|
|
|
On February 24, 2006, we entered into a combination
agreement in which we agreed to purchase the Chase Group
Properties and combine them with substantially all of the
outstanding equity interests of Concho Equity Holdings Corp. to
form Concho. We have accounted for the combination
transaction that occurred on February 27, 2006, as an
acquisition by Concho Equity Holdings Corp. of the Chase Group
Properties and a simultaneous reorganization of Concho such that
Concho Equity Holdings Corp. became our wholly owned subsidiary.
Concho Equity Holdings Corp. is our predecessor for accounting
purposes. As a result, our historical financial statements prior
to February 27, 2006, are the financial statements of
Concho Equity Holdings Corp;
|
|
|
|
On February 27, 2006, the initial closing of the Chase Oil
transaction occurred, and we acquired the Chase Group Properties
for approximately 35 million shares of common stock and
approximately $409 million in cash;
|
|
|
|
On March 27, 2007, we entered into a $200 million
second lien term loan facility from which we received proceeds
of $199 million that we used to repay the
$39.8 million outstanding under our prior term loan
facility and to reduce the outstanding balance under our credit
facility by $154 million, with the remaining
$5.2 million used to pay loan fees, accrued interest and
for general corporate purposes;
|
|
|
|
In August 2007, we completed our initial public offering of
common stock from which we received proceeds of
$173 million that we used to retire outstanding borrowings
under our second lien term loan facility totaling
$86.5 million, and to retire outstanding borrowings under
our credit facility totaling $86.5 million; and
|
|
|
|
On July 31, 2008, we closed our acquisition of the Henry
Entities and additional non-operated interests in oil and gas
properties from persons affiliated with the Henry Entities. In
August 2008 and September 2008, we acquired additional
non-operated interests in oil and gas properties from persons
affiliated with the Henry Entities. We paid approximately
$584.1 million in net cash for the acquisition of the Henry
Entities and the related acquisition of the along-side
interests, which was funded with borrowings under our credit
facility, which was amended and restated on July 31, 2008,
and net proceeds of approximately $242.4 million from our
private placement of 8,302,894 shares of our common stock.
|
Results
of Operations
The following table presents selected financial and operating
information for the years ended December 31, 2008, 2007 and
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands, except price and
|
|
|
|
daily volume data)
|
|
|
Statement of operations data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
390,945
|
|
|
$
|
195,596
|
|
|
$
|
131,773
|
|
Natural gas sales
|
|
|
142,844
|
|
|
|
98,737
|
|
|
|
66,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
533,789
|
|
|
|
294,333
|
|
|
|
198,290
|
|
Operating costs and expenses (excluding gains (losses) on
derivatives not designated as hedges)
|
|
|
(315,265
|
)
|
|
|
(198,122
|
)
|
|
|
(134,862
|
)
|
Gains (losses) on derivatives not designated as hedges
|
|
|
249,870
|
|
|
|
(20,274
|
)
|
|
|
|
|
Interest, net and other revenue
|
|
|
(27,607
|
)
|
|
|
(34,558
|
)
|
|
|
(29,381
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
440,787
|
|
|
|
41,379
|
|
|
|
34,047
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands, except price and
|
|
|
|
daily volume data)
|
|
|
Income tax expense
|
|
|
(162,085
|
)
|
|
|
(16,019
|
)
|
|
|
(14,379
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
278,702
|
|
|
$
|
25,360
|
|
|
$
|
19,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
4,586
|
|
|
|
3,014
|
|
|
|
2,295
|
|
Natural gas (MMcf)
|
|
|
14,968
|
|
|
|
12,064
|
|
|
|
9,507
|
|
Total (MBoe)
|
|
|
7,081
|
|
|
|
5,025
|
|
|
|
3,880
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
12,530
|
|
|
|
8,258
|
|
|
|
6,288
|
|
Natural gas (Mcf)
|
|
|
40,896
|
|
|
|
33,052
|
|
|
|
26,047
|
|
Total (Boe)
|
|
|
19,347
|
|
|
|
13,767
|
|
|
|
10,630
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without hedges (Bbl)
|
|
$
|
91.92
|
|
|
$
|
68.58
|
|
|
$
|
60.47
|
|
Oil, with hedges (Bbl)
|
|
$
|
85.25
|
|
|
$
|
64.90
|
|
|
$
|
57.42
|
|
Natural gas, without hedges (Mcf)
|
|
$
|
9.59
|
|
|
$
|
8.08
|
|
|
$
|
6.87
|
|
Natural gas, with hedges (Mcf)
|
|
$
|
9.54
|
|
|
$
|
8.18
|
|
|
$
|
7.00
|
|
Total, without hedges (Boe)
|
|
$
|
79.80
|
|
|
$
|
60.54
|
|
|
$
|
52.62
|
|
Total, with hedges (Boe)
|
|
$
|
75.38
|
|
|
$
|
58.56
|
|
|
$
|
51.12
|
|
Year
ended December 31, 2008, compared to year ended
December 31, 2007
Oil and gas revenues. Revenue from oil
and gas operations was $533.8 million for the year ended
December 31, 2008, an increase of $239.5 million
(81 percent) from $294.3 million for the year ended
December 31, 2007. This increase was primarily due to
(i) the acquisition of the Henry Entities on July 31,
2008, (ii) increased production due to successful drilling
efforts during 2008 and (iii) substantial increases in
realized oil and gas prices. In addition:
|
|
|
|
|
average realized oil prices (after giving effect to hedging
activities) were $85.25 per Bbl during the year ended
December 31, 2008, an increase of 31 percent from
$64.90 per Bbl during the year ended December 31, 2007;
|
|
|
|
total oil production was 4,586 MBbl for the year ended
December 31, 2008, an increase of 1,572 MBbl
(52 percent) from 3,014 MBbl for the year ended
December 31, 2007;
|
|
|
|
average realized natural gas prices (after giving effect to
hedging activities) were $9.54 per Mcf during the year ended
December 31, 2008, an increase of 17 percent from
$8.18 per Mcf during the year ended December 31, 2007;
|
|
|
|
total natural gas production was 14,968 MMcf for the year
ended December 31, 2008, an increase of 2,904 MMcf
(24 percent) from 12,064 MMcf for the year ended
December 31, 2007;
|
|
|
|
average realized barrel of oil equivalent prices (after giving
effect to hedging activities) were $75.38 per Boe during the
year ended December 31, 2008, an increase of
29 percent from $58.56 per Boe during the year ended
December 31, 2007; and
|
|
|
|
total production was 7,081 MBoe for the year ended
December 31, 2008, an increase of 2,056 MBoe
(41 percent) from 5,025 MBoe for the year ended
December 31, 2007.
|
See discussion in Recent events for
information about our 2008 production interruptions.
43
Hedging activities. The oil and gas
prices that we report are based on the market price received for
the commodities adjusted to give effect to the results of our
cash flow hedging activities. We utilize commodity derivative
instruments in order to (i) reduce the effect of the
volatility of price changes on the commodities we produce and
sell, (ii) support our annual capital budget and
expenditure plans and (iii) lock-in commodity prices to
protect economics related to certain capital projects. The
following is a summary of the effects of commodity hedges that
qualify for hedge accounting treatment for the year ended
December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Hedges
|
|
Natural Gas Hedges
|
|
|
Years Ended
|
|
Years Ended
|
|
|
December 31,
|
|
December 31,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
Hedging revenue increase (decrease) (in thousands)
|
|
$
|
(30,591
|
)
|
|
$
|
(11,091
|
)
|
|
$
|
(696
|
)
|
|
$
|
1,291
|
|
Hedged volumes (Bbls and MMBtus, respectively)
|
|
|
951,000
|
|
|
|
1,076,750
|
|
|
|
4,941,000
|
|
|
|
6,482,600
|
|
Hedged revenue increase (decrease) per hedged volume
|
|
$
|
(32.17
|
)
|
|
$
|
(10.30
|
)
|
|
$
|
(0.14
|
)
|
|
$
|
0.20
|
|
During the year ended December 31, 2008, our commodity
price hedges decreased oil revenues by $30.6 million ($6.67
per Bbl). During the year ended December 31, 2007, our
commodity price hedges decreased oil revenues by
$11.1 million ($3.68 per Bbl). The effect of the commodity
price hedges in decreasing oil revenues during the year ended
December 31, 2008 compared to their effect of decreasing
oil revenues during the year ended December 31, 2007 was
the result of (i) a higher average market price of NYMEX
crude oil of $99.75 per Bbl in 2008 as compared to $72.45 per
Bbl in 2007 and (ii) the greater price difference between
NYMEX and the weighted average hedge price in 2008 as compared
to 2007, partially offset by a lower amount of hedged volumes of
951,000 Bbls in 2008 as compared to 1,076,750 Bbls in
2007.
During the year ended December 31, 2008, our commodity
price hedges decreased gas revenues by $0.7 million ($0.05
per Mcf) as a result of the amount reclassified from accumulated
other comprehensive income (AOCI) into natural gas
revenues from cash flow hedges that were dedesignated at
June 30, 2007. Cash settlements for these dedesignated
natural gas contracts were recorded as a gain on derivatives not
designated as hedges. During the year ended December 31,
2007, our commodity price hedges increased gas revenues by
$1.3 million ($0.11 per Mcf) primarily as a result of the
amount reclassified from AOCI to natural gas revenues from cash
flow hedges that were dedesignated at June 30, 2007.
At June 30, 2007, we determined that all of our natural gas
commodity contracts no longer qualified as hedges under the
requirements of Financial Accounting Standards Board
(FASB) Statement of Financial Accounting Standards
(SFAS) No. 133. As a result, amounts in AOCI at
June 30, 2007 related to these dedesignated hedges remained
in AOCI and are reclassified into earnings under natural gas
revenues during the periods which the hedged forecasted
transaction affects earnings. Cash settlements for these natural
gas contracts are recorded to gains (losses) on derivatives not
designated as hedges. Regarding the dedesignated contracts, for
the period January 1, 2007 through June 30, 2007,
when these natural gas contracts qualified to use hedge
accounting, the cash settlement receipts of approximately
$0.2 million were recorded in natural gas revenues. For the
period July 1, 2007 through December 31, 2007, when
these natural gas contracts no longer qualified to use hedge
accounting, a pre-tax amount of $1.1 million was
reclassified from AOCI to natural gas revenues and cash
settlement receipts of $1.8 million was recorded to gains (
losses) on derivatives not designated as hedge. See Note I
of the Notes to Consolidated Financial Statements included in
Item 8. Financial Statements and Supplementary
Data.
The above discussion on hedging activities does not represent
the activities from all of our commodity derivative instruments.
We have other commodity derivative instruments that we do not
designate as hedges for accounting purposes. For further
discussion and information see Gains (losses) on
derivative instruments not designated as hedges below and
Note I of the Notes to Consolidated Financial Statements
included in Item 8. Financial Statements and
Supplementary Data.
44
Oil and gas production costs. The
following tables provide the components of our oil and gas
production costs for the year ended December 31, 2008 and
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
Lease operating expenses
|
|
$
|
43,725
|
|
|
$
|
6.17
|
|
|
$
|
26,480
|
|
|
$
|
5.27
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem
|
|
|
2,738
|
|
|
|
0.39
|
|
|
|
2,012
|
|
|
|
0.40
|
|
Production
|
|
|
43,775
|
|
|
|
6.18
|
|
|
|
24,301
|
|
|
|
4.84
|
|
Workover costs
|
|
|
996
|
|
|
|
0.14
|
|
|
|
1,474
|
|
|
|
0.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas production expenses
|
|
$
|
91,234
|
|
|
$
|
12.88
|
|
|
$
|
54,267
|
|
|
$
|
10.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, in general, we
have control over lease operating expenses and workover costs on
properties we operate, but production and ad valorem taxes are
directly related to commodity price changes.
Lease operating expenses were $43.7 million ($6.17 per Boe)
for the year ended December 31, 2008, an increase of
$17.2 million (65 percent) from $26.5 million
($5.27 per Boe) for the year ended December 31, 2007. The
increase in lease operating expenses is due to (i) the
wells acquired in the Henry Properties acquisition, which
increased the absolute and per unit amount because those wells
have a higher per unit cost as compared to our historical per
unit cost, (ii) our wells successfully drilled and
completed in 2008 and (iii) general inflation of field
service and supply costs associated with rising commodity prices.
Ad valorem taxes have increased primarily as a result of
(i) the Henry Properties acquisition and (ii) the
increase in commodity prices.
Production taxes per unit of production were $6.18 per Boe
during the year ended December 31, 2008, an increase of
28 percent from $4.84 per Boe during the year ended
December 31, 2007. The increase is directly related to the
increase in oil and gas revenues and the related increase in
commodity prices. Over the same period our Boe prices (before
the effects of hedging) increased 32 percent.
Workover expenses were $1.0 million and $1.5 million
for the year ended December 31, 2008 and 2007,
respectively. The 2008 amount related primarily to workovers in
Andrews County, Texas, while the 2007 amount related to a
workover project on a property located in Gaines County, Texas.
Exploration and abandonments
expense. The following table provides a
breakdown of our exploration and abandonments expense for the
year ended December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Geological and geophysical
|
|
$
|
3,139
|
|
|
$
|
4,089
|
|
Exploratory dry holes
|
|
|
3,723
|
|
|
|
21,923
|
|
Leasehold abandonments and other
|
|
|
31,606
|
|
|
|
3,086
|
|
|
|
|
|
|
|
|
|
|
Total exploration and abandonments
|
|
$
|
38,468
|
|
|
$
|
29,098
|
|
|
|
|
|
|
|
|
|
|
Our geological and geophysical expense, which primarily consists
of the costs of acquiring and processing seismic data,
geophysical data and core analysis, during the year ended
December 31, 2008 was $3.1 million, a decrease of
$1.0 million from $4.1 million for the year ended
December 31, 2007. This decrease is primarily attributable
to a comprehensive seismic survey on our New Mexico shelf
properties which was initiated in December 2007.
45
Our exploratory dry hole expense during the year ended
December 31, 2008 is primarily attributable to an
unsuccessful operated exploratory well located in the Central
Basin Platform. Our exploratory dry hole expense during the year
ended December 31, 2007 is primarily attributable to five
unsuccessful operated exploratory wells. The costs associated
with three of these wells drilled in the Western Delaware Basin
in Culberson County, Texas, approximated $17.0 million.
Another of these wells, which was drilled in Lea County, New
Mexico, had costs of approximately $2.4 million. An
additional $0.8 million was charged to exploratory dry hole
costs relative to a target zone in the fifth of these wells in
Eddy County, New Mexico, which was determined to be unsuccessful.
For the year ended December 31, 2008, we recorded
$31.6 million of leasehold abandonments, which relates
primarily to the write-off of (i) our Fayetteville acreage
position in Arkansas and (ii) a prospect in the Central
Basin Platform in West Texas. For the year ended
December 31, 2007, we recorded $3.1 million of
leasehold abandonments, of which $0.7 million related to a
prospect in Lea County, New Mexico, $0.8 million related to
one prospect located in Edwards County, Texas and
$0.5 million related to leasehold expiring in Southeastern
New Mexico. The remaining $1.1 million was related to
several individually minor leaseholds.
Depreciation, depletion and amortization
expense. The following table provides
components of our depreciation, depletion and amortization
expense for the year ended December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
Depletion of proved oil and gas properties
|
|
$
|
121,464
|
|
|
$
|
17.15
|
|
|
$
|
75,744
|
|
|
$
|
15.07
|
|
Depreciation of other property and equipment
|
|
|
1,808
|
|
|
|
0.26
|
|
|
|
1,035
|
|
|
|
0.21
|
|
Amortization of intangible asset operating rights
|
|
|
640
|
|
|
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depletion, depreciation and amortization
|
|
$
|
123,912
|
|
|
$
|
17.50
|
|
|
$
|
76,779
|
|
|
$
|
15.28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil price used to estimate proved oil reserves at period
end
|
|
$
|
41.00
|
|
|
|
|
|
|
$
|
92.50
|
|
|
|
|
|
Natural gas price used to estimate proved gas reserves at period
end
|
|
$
|
5.71
|
|
|
|
|
|
|
$
|
6.80
|
|
|
|
|
|
Depletion of proved oil and gas properties was
$121.5 million ($17.15 per Boe) for the year ended
December 31, 2008, an increase of $45.8 million from
$75.7 million ($15.07 per Boe) for the year ended
December 31, 2007. The increase in depletion expense was
primarily due to (i) the Henry Properties acquisition for
which the depletion rate was higher than that of our historical
assets, (ii) capitalized costs associated with new wells
that were successfully drilled and completed in 2007 and 2008
and (iii) the decrease in the oil and natural gas prices
between the years which were utilized to determine the proved
reserves.
The amortization of the intangible asset is a result of the
value assigned to the operating rights that we acquired in the
Henry Properties acquisition. The intangible asset is currently
being amortized over an estimated life of approximately
25 years.
Impairment of long-lived assets. In
accordance with SFAS No. 144, we periodically review
our long-lived assets to be held and used, including proved oil
and gas properties accounted for under the successful efforts
method of accounting. As a result of this review of the
recoverability of the carrying value of our assets during the
year ended December 31, 2008, we recognized a non-cash
charge against earnings of $18.4 million, which was
comprised primarily of a fields in Reeves and Upton Counties,
Texas and in North Dakota. For the year ended December 31,
2007, we recognized a non-cash charge against earnings of
$7.3 million, 33 percent of which related to a field
in Gaines County, Texas, 30 percent of which related to a
field in Schleicher County, Texas, and 18 percent of which
related to a field in Crane County, Texas. The remaining
19 percent was comprised of multiple immaterial wells in
various counties.
46
General and administrative
expenses. The following table provides
components of our general and administrative expenses for the
year ended December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
General and administrative expenses recurring
|
|
$
|
36,170
|
|
|
$
|
5.11
|
|
|
$
|
22,419
|
|
|
$
|
4.46
|
|
Non-recurring bonus paid to Henry Entities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
employees, see Note K
|
|
|
4,328
|
|
|
|
0.61
|
|
|
|
|
|
|
|
|
|
Non-cash stock-based compensation stock options
|
|
|
3,101
|
|
|
|
0.44
|
|
|
|
2,463
|
|
|
|
0.49
|
|
Non-cash stock-based compensation restricted stock
|
|
|
2,122
|
|
|
|
0.30
|
|
|
|
1,378
|
|
|
|
0.27
|
|
Less: Third-party operating fee reimbursements
|
|
|
(4,945
|
)
|
|
|
(0.70
|
)
|
|
|
(1,083
|
)
|
|
|
(0.21
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses
|
|
$
|
40,776
|
|
|
$
|
5.76
|
|
|
$
|
25,177
|
|
|
$
|
5.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were $40.8 million
($5.76 per Boe) for the year ended December 31, 2008, an
increase of $15.6 million (62 percent) from
$25.2 million ($5.01 per Boe) for the year ended
December 31, 2007. The increase in general and
administrative expenses during the year ended December 31,
2008 over 2007 was primarily due to (i) the non-recurring
bonus paid to Henry Entities employees, (ii) an
increase in non-cash stock-based compensation for both stock
options and restricted stock awards and (iii) an increase
in the number of employees and related personnel expenses,
partially offset by an increase in third-party operating fee
reimbursements.
As part of the Henry Entities acquisition, we agreed to pay
certain of the Henry Entities employees a predetermined
bonus amount, in addition to the compensation we pay these
employees, over the next two years. Since these employees will
earn this bonus over the next two years we are reflecting the
cost in our general and administrative costs. We are reflecting
this bonus amount as non-recurring as it is not controlled by
our management. See Note K of the Notes to Consolidated
Financial Statements included in Item 8. Financial
Statements and Supplementary Data for additional
information related to this bonus.
We earn reimbursements as operator of certain oil and gas
properties in which we own interests. As such, we earned
reimbursements of $4.9 million and $1.1 million during
the year ended December 31, 2008 and 2007, respectively.
This reimbursement is reflected as a reduction of general and
administrative expenses in the consolidated statements of
operations. The increase in this reimbursement is directly
related to the Henry Properties acquisition, as we own a lower
working interest in these operated properties compared to our
historical property base, thus we have a larger third-party
reimbursement as compared to our historical property base.
Bad debt expense. On May 20, 2008,
we entered into a short-term purchase agreement with an oil
purchaser to sell a portion of our oil production affected by a
New Mexico refinery shut down due to repairs. On July 22,
2008, this purchaser declared bankruptcy. We fully reserved the
receivable amount of $2.9 million due from this purchaser
for June and July production during the year ended
December 31, 2008.
Contract drilling fees stacked
rigs. We determined in January 2007 to reduce
our drilling activities for the first three months of 2007. As a
result, we recorded an expense during the year ended
December 31, 2007 of approximately $4.3 million for
contract drilling fees related to stacked rigs subject to
daywork drilling contracts with two drilling contractors. We
resumed the majority of our planned drilling activities in April
2007 and all planned drilling activities in June 2007. These
costs were minimized during the first six months of 2007 as one
contractor secured work for a rig for 71 days during that
period and charged us only the difference between the
then-current operating day rate pursuant to the contract and the
lower operating day rate received from the new customer.
Gains (losses) on derivatives not designated as
hedges. As discussed in Note I of the
Notes to Consolidated Financial Statements included in
Item 8. Financial Statements and Supplementary
Data, during the three months ended June 30, 2007, we
determined that all of our natural gas commodity derivative
contracts no longer qualified as hedges under the requirements
of SFAS No. 133. If the hedge is no longer highly
effective, according to SFAS No. 133, an entity shall
discontinue hedge accounting for an existing hedge,
prospectively, and during
47
the period the hedges became ineffective. In addition, for our
new commodity and interest rate derivative contracts entered
into after August 2007, we chose not to designate any of these
contracts as hedges. As a result, any changes in fair value and
any cash settlements related to these contracts are recorded in
earnings during the related period.
For the year ended December 31, 2008, the related cash
payments for settlements for derivative contracts not designated
as hedges was approximately $6.3 million. The non-cash
mark-to-market adjustment for the derivative contracts not
designated as hedges was a gain of $256.2 million. This is
compared to cash receipts for settlements of $1.8 million
and non-cash mark-to-market losses of $22.1 million for the
year ended December 31, 2007.
Interest expense. Interest expense was
$29.0 million for the year ended December 31, 2008, a
decrease of $7.0 million from $36.0 million for the
year ended December 31, 2007. The weighted average interest
rate for the year ended December 31, 2008 and 2007 was
5.1 percent and 7.7 percent, respectively. The
weighted average debt balance during the year ended
December 31, 2008 and 2007 was approximately
$450.7 million and $436.3 million, respectively.
The increase in weighted average debt balance during the year
ended December 31, 2008 was due to the Henry Properties
acquisition in July 2008, offset by (i) the partial
prepayment in August 2007 of $86.6 million on the
2nd lien credit facility and the repayment in August 2007
of $86.6 million on our previous revolving credit facility
and (ii) a partial prepayment in March 2008 on our previous
revolving credit facility utilizing cash from operations. Also,
in July 2008, we repaid and terminated our 2nd lien credit
facility which resulted in the write-off of approximately
$1.1 million of deferred loan costs and approximately
$0.4 million of original issue discount, both of which are
included in interest expense. In March 2007, we reduced our
previous revolving credit facilitys borrowing base by
$100.0 million, or 21%, resulting in the write-off of
$0.8 million of deferred loan costs, and repaid a term
credit facility, resulting in the write-off of $0.4 million
of deferred loan costs, both of which are included in interest
expense. In August 2007, we made a $86.6 million partial
prepayment on our 2nd lien credit facility from proceeds of
our initial public offering, which resulted in the write-off of
approximately $1.0 million of deferred loan costs and
approximately $0.4 million of original issue discount, both
of which are included in interest expense. The decrease in the
weighted average interest rate is due to (i) improvement in
market interest rates and (ii) the fact that the interest
rate margins under our credit facility (and previous revolving
credit facility) were lower than those under our 2nd lien
credit facility.
Income tax provision. We recorded an
income tax expense of $162.1 million and $16.0 million
for the year ended December 31, 2008 and 2007,
respectively. The effective income tax rate for the year ended
December 31, 2008 and 2007 was 36.8 percent and
38.7 percent, respectively. We estimated a higher effective
state income rate in 2007 than in 2008, which is primarily due
to our estimate of income among the various states in which we
own assets.
Year
ended December 31, 2007, compared to year ended
December 31, 2006
Oil and gas revenues. Revenue from oil
and gas operations was $294.3 million for the year ended
December 31, 2007, an increase of $96.0 million
(48 percent) from $198.3 million for the year ended
December 31, 2006. This increase was primarily because of
increased production as a result of the acquisition of the Chase
Group Properties and secondarily due to successful drilling
efforts during 2006 and 2007, coupled with moderate increases in
realized oil and gas prices. In addition:
|
|
|
|
|
average realized oil prices (after giving effect to hedging
activities) were $64.90 per Bbl during the year ended
December 31, 2007, an increase of 13 percent from
$57.42 per Bbl during the year ended December 31, 2006;
|
|
|
|
total oil production was 3,014 MBbl for the year ended
December 31, 2007, an increase of 719 MBbl
(31 percent) from 2,295 MBbl for the year ended
December 31, 2006;
|
|
|
|
average realized natural gas prices (after giving effect to
hedging activities) were $8.18 per Mcf during the year ended
December 31, 2007, an increase of 17 percent from
$7.00 per Mcf during the year ended December 31, 2006;
|
48
|
|
|
|
|
total natural gas production was 12,064 MMcf for the year
ended December 31, 2007, an increase of 2,557 MMcf
(27 percent) from 9,507 MMcf for the year ended
December 31, 2006;
|
|
|
|
average realized barrel of crude oil equivalent prices (after
giving effect to hedging activities) were $58.56 per Boe during
the year ended December 31, 2007, an increase of
15 percent from $51.12 per Boe during the year ended
December 31, 2006;
|
|
|
|
total production was 5,025 MBoe for the year ended
December 31, 2007, an increase of 1,145 MBoe
(30 percent) from 3,880 MBoe for the year ended
December 31, 2006; and
|
|
|
|
total production during the year ended December 31, 2007
was reduced by approximately 110 MBoe as a result of the
temporary shut-downs of a natural gas processing plant through
which we process and sell a portion of our production.
|
Hedging activities. The oil and gas
prices that we report are based on the market price received for
the commodities adjusted to give effect to the results of our
cash flow hedging activities. We utilize commodity derivative
instruments in order to (i) reduce the effect of the
volatility of price changes on the commodities we produce and
sell, (ii) support our annual capital budgeting and
expenditure plans and (iii) lock-in commodity prices to
protect economics related to certain capital projects. Following
is a summary of the effects of commodity hedges that qualify for
hedge accounting treatment for the year ended December 31,
2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Hedges
|
|
|
Natural Gas Hedges
|
|
|
|
Years Ended
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
Hedging revenue increase (decrease) (in thousands)
|
|
$
|
(11,091
|
)
|
|
$
|
(7,000
|
)
|
|
$
|
1,291
|
|
|
$
|
1,232
|
|
Hedged volumes (Bbls and MMBtus, respectively)
|
|
|
1,076,750
|
|
|
|
1,080,500
|
|
|
|
6,482,600
|
|
|
|
5,447,500
|
|
Hedged revenue increase (decrease) per hedged volume
|
|
$
|
(10.30
|
)
|
|
$
|
(6.48
|
)
|
|
$
|
0.20
|
|
|
$
|
0.23
|
|
During the year ended December 31, 2007, our commodity
price hedges decreased oil revenues by $11.1 million ($3.68
per Bbl). During the year ended December 31, 2006, our
commodity price hedges decreased oil revenues by
$7.0 million ($3.05 per Bbl). The effect of the commodity
price hedges in decreasing oil revenues during the year ended
December 31, 2007 more than their effect of decreasing oil
revenues during the year ended December 31, 2006 was the
result of (i) a higher average market price of NYMEX crude
oil of $72.45 per Bbl in 2007 as compared to $66.26 per Bbl in
2006, and (ii) the higher hedged revenue per hedged volume
in 2007 as compared to 2006, as shown in the table above,
partially offset by a lower amount of hedged volumes in 2007 as
compared to 2006.
During the year ended December 31, 2007, our commodity
price hedges increased gas revenues by $1.3 million ($0.11
per Mcf). During the year ended December 31, 2006, our
commodity price hedges increased gas revenues by
$1.2 million ($0.13 per Mcf). The effect of commodity price
hedges in increasing gas revenues in 2007 more than their effect
of increasing gas revenues in 2006 was the result of a higher
amount of hedged volumes in 2007 as compared to 2006, partially
offset by (i) the lower hedged revenue per hedged volume in
2007 as compared to 2006 and (ii) a higher reference market
price for natural gas of $6.11 per MMBtu in 2007 as compared to
$6.06 per MMBtu in 2006.
At June 30, 2007, we determined that all of our natural gas
commodity contracts no longer qualified as hedges under the
requirements of SFAS No. 133. As a result, amounts in
AOCI at June 30, 2007 related to these dedesignated hedges
remained in AOCI and are reclassified into earnings under
natural gas revenues during the periods which the hedged
forecasted transaction affects earnings. Cash settlements for
these natural gas contracts are recorded to gains (losses) on
derivatives not designated as hedges. Regarding the dedesignated
contracts, for the period January 1, 2007 through
June 30, 2007, when these natural gas contracts qualified
to use hedge accounting, the cash settlement receipts of
approximately $0.19 million were recorded in natural gas
revenues. For the period July 1, 2007 through
December 31, 2007, when these natural gas contracts no
longer qualified to use hedge accounting, a pre-tax amount of
$1.1 million was reclassified from AOCI to natural gas
revenues and cash
49
settlement receipts of $1.8 million was recorded to gains
(losses) on derivatives not designated as hedge. See Note I
of the Notes to Consolidated Financial Statements included in
Item 8. Financial Statements and Supplementary
Data.
Oil and gas production costs. The
following tables provide the components of our oil and gas
production costs for the year ended December 31, 2007 and
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
Lease operating expenses
|
|
$
|
26,480
|
|
|
$
|
5.27
|
|
|
$
|
20,424
|
|
|
$
|
5.26
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem
|
|
|
2,012
|
|
|
|
0.40
|
|
|
|
1,120
|
|
|
|
0.29
|
|
Production
|
|
|
24,301
|
|
|
|
4.84
|
|
|
|
15,762
|
|
|
|
4.06
|
|
Workover costs
|
|
|
1,474
|
|
|
|
0.29
|
|
|
|
516
|
|
|
|
0.14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas production expenses
|
|
$
|
54,267
|
|
|
$
|
10.80
|
|
|
$
|
37,822
|
|
|
$
|
9.75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, in general, we
have control over lease operating expenses and workover costs on
properties we operate, but production and ad valorem taxes are
directly related to commodity price changes.
Lease operating expenses were $26.5 million ($5.27 per Boe)
for the year ended December 31, 2007, an increase of
$6.1 million (30 percent) from $20.4 million
($5.27 per Boe) for the year ended December 31, 2006. The
increase in lease operating expenses is due to (i) lease
operating expenses associated with the Chase Group Properties
acquired in February 2006 of approximately $2.2 million,
(ii) lease operating expenses associated with wells that
were successfully completed in 2006 and 2007 as a result of our
drilling activities and (iii) general inflation of field
service and supply costs associated with rising commodity prices.
Ad valorem taxes have increased primarily as a result of
(i) new wells that were successfully completed in 2006 and
2007 as a result of our drilling activities and (ii) the
increase in commodity prices.
Production taxes per unit of production were $4.84 per Boe
during the year ended December 31, 2007, an increase of
19 percent from $4.06 per Boe during the year ended
December 31, 2006. The increase is directly related to the
increase in oil and gas revenues and the related increase in
commodity prices. Over the same period our Boe prices (before
the effects of hedging) increased 15 percent.
Workover expenses were $1.5 million and $0.5 million
for the year ended December 31, 2007 and 2006,
respectively. The 2007 amount related to a workover project on a
property located in Gaines County, Texas, while the 2006 amount
related primarily to workovers located in Andrews County, Texas.
Exploration and abandonments
expense. The following table provides a
breakdown of our exploration and abandonments expense for the
year ended December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Geological and geophysical
|
|
$
|
4,089
|
|
|
$
|
2,185
|
|
Exploratory dry holes
|
|
|
21,923
|
|
|
|
3,192
|
|
Leasehold abandonments and other
|
|
|
3,086
|
|
|
|
235
|
|
|
|
|
|
|
|
|
|
|
Total exploration and abandonments
|
|
$
|
29,098
|
|
|
$
|
5,612
|
|
|
|
|
|
|
|
|
|
|
Our geological and geophysical expense, which primarily consists
of general and administrative costs for our geology department
as well as seismic data, geophysical data and core analysis,
during the year ended December 31, 2007 was
$4.1 million, an increase of $1.9 million from
$2.2 million for the year ended December 31, 2006.
This
50
87 percent increase is primarily attributable to a
comprehensive seismic survey on our New Mexico shelf properties
which was initiated in December 2007.
Our exploratory dry holes expense during the year ended
December 31, 2007 is primarily attributable to five
operated exploratory wells that were unsuccessful. The costs
associated with three of these wells drilled in the Western
Delaware Basin in Culberson County, Texas approximated
$17.0 million. Another of these wells, which was drilled in
the Southeastern New Mexico Basin in Lea County, New Mexico, had
costs of approximately $2.4 million. An additional
$0.8 million was charged to exploratory dry hole costs
related to an unsuccessful targeted zone in the fifth of these
wells in the Southeastern New Mexico Basin in Eddy County, New
Mexico. Exploration expense of $1.7 million related to
three unsuccessful outside operated wells located in Eddy
County, New Mexico.
Of our exploratory dry holes expense during the year ended
December 31, 2006, $3.2 million was attributable to
one unsuccessful exploratory well in Gaines County, Texas that
we operated and one unsuccessful exploratory well in Val Verde
County, Texas operated by another company.
For the year ended December 31, 2007, we recorded
$3.1 million of leasehold abandonments, of which
$0.7 million related to a prospect in Lea County, New
Mexico, $0.8 million related to one prospect located in
Edwards County, Texas and $0.5 million related to leasehold
expiring in Southeastern New Mexico. The remaining
$1.1 million was related to several individually minor
leaseholds. We had minimal leasehold abandonments during the
year ended December 31, 2006.
Depreciation, depletion and amortization
expense. The following table provides
components of our depreciation, depletion and amortization
expense for the year ended December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
Depletion of proved oil and gas properties
|
|
$
|
75,744
|
|
|
$
|
15.07
|
|
|
$
|
59,872
|
|
|
$
|
15.43
|
|
Depreciation of other property and equipment
|
|
|
1,035
|
|
|
|
0.21
|
|
|
|
850
|
|
|
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depletion, depreciation and amortization
|
|
$
|
76,779
|
|
|
$
|
15.28
|
|
|
$
|
60,722
|
|
|
$
|
15.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil price used to estimate proved oil reserves at period
end
|
|
$
|
92.50
|
|
|
|
|
|
|
$
|
57.75
|
|
|
|
|
|
Natural gas price used to estimate proved gas reserves at period
end
|
|
$
|
6.80
|
|
|
|
|
|
|
$
|
5.64
|
|
|
|
|
|
Depletion of proved oil and gas properties was
$75.7 million ($15.07 per BOE) for the year ended
December 31, 2007, an increase of $15.8 million from
$59.9 million ($15.43 per BOE) for the year ended
December 31, 2006. The increase in depletion expense was
primarily due to (i) the acquisition of the Chase Group
Properties and (ii) capitalized costs associated with new
wells that were successfully completed in 2006 and 2007 as a
result of our drilling activities. The decrease in depletion
expense per Boe was primarily due to an increase in proved oil
and natural gas reserves as a result of our successful
development and exploratory drilling program.
Impairment of long-lived assets. In
accordance with SFAS No. 144, we review our long-lived
assets to be held and used, including proved oil and gas
properties accounted for under the successful efforts method of
accounting. As a result of this review of the recoverability of
the carrying value of our assets during the year ended
December 31, 2007, we recognized a non-cash charge against
earnings of $7.3 million, 33 percent of which related
to wells drilled in Gaines County, Texas, 30 percent of
which related to a well drilled in Schleicher County, Texas and
18 percent of which related to a well drilled in Crane
County, Texas. The remaining 19 percent was comprised of
multiple immaterial wells in various counties. For the year
ended December 31, 2006, we recognized a non-cash charge
against earnings of $9.9 million, 33 percent of which
related to wells located in Pecos and Midland Counties, Texas,
acquired in our Lowe Acquisition, 24 percent of which
related to wells located in Lea and Eddy Counties, New Mexico,
acquired in our Lowe Acquisition, 11 percent of which
related to a well drilled in Eddy County, New Mexico and
9 percent of which related to a well drilled in Mountrail
County, North Dakota. The remaining 23 percent was
comprised of multiple immaterial wells in various counties.
51
Contract drilling fees stacked
rigs. We determined in January 2007 to reduce
our drilling activities for the first three months of 2007. As a
result, we recorded an expense during the six months ended
June 30, 2007 of approximately $4.3 million for
contract drilling fees related to stacked rigs subject to
daywork drilling contracts with two drilling contractors. No
additional costs were incurred from July 1, 2007 through
December 31, 2007. We resumed the majority of our planned
drilling activities in April 2007 and all planned drilling
activities in June 2007. These costs were minimized during the
first six months of 2007 as one contractor secured work for a
rig for 71 days during that period and charged us only the
difference between the then-current operating day rate pursuant
to the contract and the lower operating day rate received from
the new customer.
General and administrative
expenses. The following table provides
components of our general and administrative expenses for the
year ended December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
General and administrative expenses recurring
|
|
$
|
22,419
|
|
|
$
|
4.46
|
|
|
$
|
13,376
|
|
|
$
|
3.45
|
|
Non-cash stock-based compensation Capital Options
|
|
|
|
|
|
|
|
|
|
|
975
|
|
|
|
0.25
|
|
Non-cash stock-based compensation stock options
|
|
|
2,463
|
|
|
|
0.49
|
|
|
|
7,125
|
|
|
|
1.84
|
|
Non-cash stock-based compensation restricted stock
|
|
|
1,378
|
|
|
|
0.27
|
|
|
|
1,044
|
|
|
|
0.27
|
|
Less: Third-party operating fee reimbursements
|
|
|
(1,083
|
)
|
|
|
(0.21
|
)
|
|
|
(799
|
)
|
|
|
(0.21
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses
|
|
$
|
25,177
|
|
|
$
|
5.01
|
|
|
$
|
21,721
|
|
|
$
|
5.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were $25.2 million
($5.01 per BOE) for the year ended December 31, 2007, an
increase of $3.5 million (16 percent) from
$21.7 million ($5.60 per BOE) for the year ended
December 31, 2006. The increase in general and
administrative expenses during the year ended December 31,
2007 was primarily due to the increase in the size and
complexity of our operations following the combination
transaction and related increase in professional fees. In
addition, annual bonuses in the aggregate amount of
$2.5 million were paid to the officers and employees in
April 2007 representing bonuses for 2006 performance as compared
to $0.9 million aggregate bonuses paid to employees in
February 2006.
We earn revenue as operator of certain oil and gas properties in
which we own interests. As such, we earned revenue of
$1.1 million and $0.8 million during the year ended
December 31, 2007 and 2006, respectively. This revenue is
reflected as a reduction of general and administrative expenses
in the consolidated statements of operations.
Gains (losses) on derivatives not designated as
hedges. As discussed in Note I of the
Notes to Consolidated Financial Statements included in
Item 8. Financial Statements and Supplementary
Data, during the three months ended June 30, 2007, we
determined that all of our natural gas commodity derivative
contracts no longer qualified as hedges under the requirements
of SFAS No. 133. If the hedge is no longer highly
effective, according to SFAS No. 133, an entity shall
discontinue hedge accounting for an existing hedge,
prospectively, and during the period the hedges became
ineffective. In addition, for our new commodity and interest
rate derivative contracts entered into after August 2007, we
chose not to designate any of these contracts as hedges. As a
result, any changes in fair value and any cash settlements
related to these contracts are recorded in earnings during the
related period.
This is compared to cash receipts for settlements of
$1.8 million and non-cash mark-to-market losses of
$22.1 million for the year ended December 31, 2007.
Interest expense. Interest expense was
$36.0 million for the year ended December 31, 2007, an
increase of $5.6 million from $30.6 million for the
year ended December 31, 2006. The weighted average interest
rate for the year ended December 31, 2007 and 2006 was
7.7 percent and 7.5 percent, respectively. The
weighted average debt balance during the year ended
December 31, 2007 and 2006 was approximately
$436.3 million and $406.8 million, respectively.
The increase in weighted average debt balance during the year
ended December 31, 2007 was our borrowings to fund our
drilling activities, partially offset by the partial prepayment
in August 2007 of $86.6 million on our
52
2nd lien credit facility and the repayment in August 2007
of $86.6 million on our then revolving credit facility. The
increase in interest expense is due to a slight increase in the
weighted average interest rate, the increase in the weighted
average debt and the acceleration of deferred loan cost
amortization and original issue discount amortization. In March
2007, we reduced our then revolving credit facility borrowing
base by $100.0 million, or 21 percent, resulting in
accelerated amortization of $0.8 million, and the full
repayment of the 2nd lien credit facility resulting in
accelerated amortization of $0.4 million. The prepayment of
$86.6 million on our New 2nd lien credit facility in
August 2007 resulted in accelerated amortization of
$1.0 million in deferred loan costs and $0.4 million
in original issue discount.
Income tax provision. We recorded
income tax expense of $16.0 million and $14.4 million
for the year ended December 31, 2007 and 2006,
respectively. The effective income tax rate for the year ended
December 31, 2007 and 2006 was 38.7 percent and
42.2 percent, respectively. We estimated a lower effective
state income rate in 2007 than in 2006, which is primarily due
to our estimate of income among the various states in which we
own assets.
Capital
Commitments, Capital Resources and Liquidity
Capital commitments. Our primary needs
for cash are development, exploration and acquisition of oil and
gas assets, payment of contractual obligations and working
capital obligations. Funding for these cash needs may be
provided by any combination of internally-generated cash flow,
proceeds from the disposition of assets or alternative financing
sources as discussed in Capital resources below.
Oil and gas properties. Our capital
expenditures on oil and gas properties, excluding acquisitions
and asset retirement obligations, during the years ended
December 31, 2008, 2007 and 2006 totaled
$339.0 million, $180.5 million and
$173.0 million, respectively. These expenditures were
primarily funded by cash flow from operations.
On November 6, 2008, our board of directors approved an
initial capital budget for 2009 of up to approximately
$500 million. The capital budget is predicated on us
funding it substantially within cash flow. In light of the
recent drop in commodity prices we took the following actions in
January 2009:
|
|
|
|
|
reduced our operated drilling rig count in the Wolfberry play
from eight to five;
|
|
|
|
deferred our deepening program on our Southeastern New Mexico
shelf properties; and
|
|
|
|
deferred certain drilling activity in the Lower Abo horizontal
play.
|
The annualized effect of these changes in operating activity
would reduce the Companys 2009 capital spending to
approximately $300 million, assuming the Companys
current estimate of 2009 capital costs. We will monitor our
capital expenditures in relation to our cash flow on a quarterly
basis and will adjust our activity and capital spending level
based on changes in commodity prices and the cost of goods and
services.
Other than leasehold acreage and other property interests, our
2009 capital budget is exclusive of acquisitions. We do not have
a specific acquisition budget since the timing and size of
acquisitions are difficult to forecast. We evaluate
opportunities to purchase or sell oil and natural gas properties
in the marketplace and could participate as a buyer or seller of
properties at various times. We seek to acquire oil and gas
properties that provide opportunities for the addition of
reserves and production through a combination of exploitation,
development, high-potential exploration and control of
operations and that will allow us to apply our operating
expertise.
Although we cannot provide any assurance, we believe that our
remaining cash balance and our cash flows will be sufficient to
satisfy our 2009 capital budget; however, we could use our
credit facility to fund such expenditures. The actual amount and
timing of our expenditures may differ materially from our
estimates as a result of, among other things, actual drilling
results, the timing of expenditures by third parties on projects
that we do not operate, the availability of drilling rigs and
other services and equipment, and regulatory, technological and
competitive developments. In addition, under certain
circumstances we would consider increasing or reallocating our
2009 capital budget.
53
Acquisitions. Our expenditures for
acquisitions of proved and unproved properties during the years
ended December 31, 2008, 2007 and 2006 totaled
$838.0 million, $7.3 million and
$1,044.7 million, respectively. The Henry Properties
acquisition in July 2008 was primarily funded by a private
placement of our common stock and borrowings under our credit
facility. In February 2006, through the combination transaction
we acquired the Chase Group Properties which was funded through
our credit facility and the issuance of our common stock.
Contractual obligations. Our
contractual obligations include long-term debt, operating lease
obligations, drilling commitments (including commitments to pay
day rates for drilling rigs), employment agreements, contractual
bonus payments, derivative obligations and other liabilities.
We had the following contractual obligations at
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
Less Than
|
|
|
1 - 3
|
|
|
3 - 5
|
|
|
More Than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
|
(In thousands)
|
|
|
Long-term debt(a)
|
|
$
|
630,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
630,000
|
|
|
$
|
|
|
Operating lease obligations(b)
|
|
|
4,743
|
|
|
|
970
|
|
|
|
2,955
|
|
|
|
818
|
|
|
|
|
|
Drilling commitments(c)
|
|
|
28,730
|
|
|
|
25,858
|
|
|
|
2,872
|
|
|
|
|
|
|
|
|
|
Employment agreements with executive officers(d)
|
|
|
5,970
|
|
|
|
2,190
|
|
|
|
3,780
|
|
|
|
|
|
|
|
|
|
Henry Entities bonus obligation(e)
|
|
|
16,446
|
|
|
|
10,387
|
|
|
|
6,059
|
|
|
|
|
|
|
|
|
|
Derivative assets(f)
|
|
|
(172,440
|
)
|
|
|
(111,283
|
)
|
|
|
(61,157
|
)
|
|
|
|
|
|
|
|
|
Asset retirement obligations(g)
|
|
|
16,809
|
|
|
|
2,611
|
|
|
|
604
|
|
|
|
598
|
|
|
|
12,996
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations
|
|
$
|
530,258
|
|
|
$
|
(69,267
|
)
|
|
$
|
(44,887
|
)
|
|
$
|
631,416
|
|
|
$
|
12,996
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
See Note J of the Notes to Consolidated Financial
Statements included in Item 8. Financial Statements
and Supplementary Data. The amounts included in the table
above represent principal maturities only. |
|
(b) |
|
See Note K of the Notes to Consolidated Financial
Statements included in Item 8. Financial Statements
and Supplementary Data. |
|
(c) |
|
Consists of daywork drilling contracts related to drilling rigs
contracted for 2009 and 2010. See Note K of the Notes to
Consolidated Financial Statements included in Item 8.
Financial Statements and Supplementary Data. |
|
(d) |
|
Represents amounts of cash compensation we are obligated to pay
to our executive officers under employment agreements assuming
such employees continue to serve the entire term of their
employment agreement and their cash compensation is not
adjusted. An executive officer resigned as of March 31,
2008, and we will be obligated to pay him 1/12th of his base
salary for each month from April 2008 through March 2009 as
consideration for such persons covenant not to compete
with us in accordance with his employment agreement.
Additionally, Steven L. Beal, our President and Chief Operating
Officer, has given notice of his intent to retire from the
Company effective June 30, 2009. As a result, only six
months of Mr. Beals salary is included. |
|
(e) |
|
Represents bonuses we agreed to pay certain employees of the
Henry Entities at each of the first and second anniversaries of
the closing of the Henry Properties acquisition. See Note D
of the Notes to Consolidated Financial Statements included in
Item 8. Financial Statements and Supplementary
Data. |
|
(f) |
|
Derivative obligations represent net asset for commodity and
interest rate derivatives that were valued at December 31,
2008. The ultimate settlement amounts of our derivative
obligations are unknown because they are subject to continuing
market risk. See Item 7A. Quantitative and
Qualitative Disclosures About Market Risk and Note I
of the Notes to Consolidated Financial Statements included in
Item 8. Financial Statements and Supplementary
Data for additional information regarding our derivative
obligations. |
|
(g) |
|
Amounts represent costs related to expected oil and gas property
abandonments related to proved reserves by period, net of any
future accretion. |
Off-balance sheet
arrangements. Currently, we do not have any
material off-balance sheet arrangements.
54
Capital resources. Our primary sources
of liquidity have been cash flows generated from operating
activities and financing provided by our credit facilities. We
believe that funds from operating cash flows and our credit
facility should be sufficient to meet both our short-term
working capital requirements and our 2009 capital budget plan.
Cash flow from operating activities. Our net
cash provided by operating activities was $391.4 million,
$169.8 million and $112.2 million for the years ended
December 31, 2008, 2007 and 2006, respectively. The
increase in operating cash flows during the years ended
December 31, 2008 over 2007 was principally due to
(i) increases in our oil and gas production as a result of
our exploration and development program, (ii) five months
of activity from the acquired Henry Properties and
(iii) increases in average realized oil and natural gas
prices. The increase in operating cash flows during the year
ended December 31, 2007 over 2006 was principally due to
increases in our oil and gas production as a result of our
exploration and development program and cash flow from
production attributable to the Chase Group Properties that we
acquired in the combination transaction in February 2006.
Cash flow used in investing activities. During
the years ended December 31, 2008, 2007 and 2006, we
invested $946.1 million, $162.6 million and
$595.6 million, respectively, for additions to, and
acquisitions of, oil and gas properties, inclusive of dry hole
costs. Cash flows used in investing activities were
substantially higher during the year ended December 31,
2008 over 2007, primarily due to the Henry Properties
acquisition, as well as increased drilling activity in 2008.
Cash flows used in investing activities were substantially
higher during the year ended December 31, 2006, primarily
due to the approximately $409.0 million cash portion of the
consideration we paid to the Chase Group in the combination
transaction and drilling activities in 2006. In order to
preserve liquidity, we reduced our drilling activities and
curtailed capital expenditures during the year ended
December 31, 2007, until we were able to complete our
second lien term loan facility in March 2007.
Cash flow from financing activities. Net cash
provided by financing activities was $542.0 million,
$19.9 million and $476.6 million for the years ended
December 31, 2008, 2007 and 2006, respectively. During the
year ended December 31, 2008, we borrowed
$767.8 million under our credit facilities and issued
approximately 8.3 million shares of our common stock to
fund the Henry Properties acquisition. In March 2007, we entered
into a $200 million 2nd lien credit facility. The
proceeds were principally used to repay the outstanding balance
under our prior term loan facility and to reduce the outstanding
balance under our credit facility. Cash provided by financing
activities during the year ended December 31, 2006 was
primarily due to borrowings under our revolving credit facility
to fund the approximately $409.0 million cash portion of
the consideration paid to the Chase Group pursuant to the
combination transaction and proceeds from private issuances of
equity in our company.
On July 31, 2008, we amended and restated our senior credit
facility in various respects, including increasing the borrowing
base to $960 million, subject to scheduled semiannual
redetermination, and extending the maturity date from
February 24, 2011 to July 31, 2013. We paid an
arrangement fee of $14.4 million at closing of the credit
facility. In October 2008, the borrowing base was reaffirmed at
$960 million. The amount outstanding under the credit
facility at December 31, 2008 was $630.0 million.
Between scheduled borrowing base redeterminations, we and, if
requested by
662/3 percent
of the lenders, the lenders may each request one special
redetermination.
Advances on the credit facility bear interest, at our option,
based on (i) the prime rate of JPMorgan Chase Bank
(JPM Prime Rate) or (ii) a Eurodollar rate
(substantially equal to the London Interbank Offered Rate). The
interest rates of Eurodollar rate advances and JPM Prime Rate
advances vary, with interest margins ranging from 125 to
275 basis points and zero to 125 basis points,
respectively, per annum depending on the balance outstanding. We
pay commitment fees on the unused portion of the available
borrowing base ranging from 25 to 50 basis points per
annum. Our credit facility bore interest at 1.96 percent
per annum at December 31, 2008.
On July 31, 2008, we repaid all the amounts outstanding
under our 2nd lien credit facility and terminated the
facility.
On June 5, 2008, we entered into a common stock purchase
agreement with certain unaffiliated third-party investors to
sell certain shares of our common stock in a private placement
(the Private Placement) contemporaneous with the
closing of the Acquisition. On July 31, 2008, we issued
8,302,894 shares of our common stock at
55
$30.11 per share pursuant to the Private Placement. We paid the
placement agent of the Private Placement a fee of approximately
$7.6 million, which resulted in net proceeds to us of
$242.4 million.
In conducting our business, we may utilize various financing
sources, including (i) fixed and floating rate debt,
(ii) convertible securities, (iii) preferred stock and
(iv) common stock. We may also sell assets and issue
securities in exchange for oil and gas assets or interests in
oil and 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 Senior Credit
Facility.
Financial markets. The current state of
the financial markets is uncertain. There have been financial
related institutions that have (i) failed and been forced
into government receivership, (ii) declared bankruptcy,
(iii) been forced to seek additional capital and liquidity
to maintain viability or (iv) merged to survive. The
U.S. and world economy is experiencing a slow-down which is
having an adverse impact on the financial markets.
At December 31, 2008, we had $329.7 million of
borrowing capacity under our credit facility. Even in light of
the current uncertainty in the financial markets, we currently
believe that our lenders under our credit facility have the
ability to fund additional borrowings we may need for our
business.
We currently pay floating rate interest under our credit
facility and we are unable to predict, especially in light of
the current uncertainty in the financial markets, whether we
will incur increased interest costs due to rising interest
rates. We have utilized the use of interest rate derivatives to
mitigate the cost of rising interest rates, and we may do
additional interest rate derivatives in the future.
In the current financial markets, we do not believe that we
could refinance our credit facility and obtain comparable terms.
Since our credit facility matures in July 2013, we have no
immediate need to seek refinancing of our credit facility.
To the extent we need additional funds, beyond those available
under our credit facility, to operate our business or make
acquisitions we would have to pursue other financing sources.
These sources could include issuance of (i) fixed and
floating rate debt, (ii) convertible securities,
(iii) preferred stock, (iv) common stock or
(v) other securities. We may also sell assets. However, in
light of the current financial markets there are no assurances
that we could obtain additional funding, or if available, at
what cost and terms.
Liquidity. Our principal sources of
short-term liquidity are cash on hand and unused borrowing
capacity under our credit facility. At December 31, 2008,
we had $17.8 million of cash on hand.
At December 31, 2008, our borrowing base under our credit
facility was $960 million, which provides us with
$329.7 million of unused borrowing capacity. Our borrowing
base is redetermined semi-annually, with the next
redetermination occurring in April 2009. In addition to such
semi-annual redeterminations, our lenders may request one
additional redetermination during any twelve-month period. In
general, redeterminations are based upon a number of factors,
including commodity prices and reserve levels. Upon a
redetermination, our borrowing base could be substantially
reduced. In light of the current commodity prices and the state
of the financial community, there is no assurance that our
borrowing base will not be reduced.
Book capitalization and current
ratio. Our book capitalization at
December 31, 2008 was $1,955.2 million, consisting of
debt of $630.0 million and stockholders equity of
$1,325.2 million. Our debt to book capitalization was
32 percent and 30 percent at December 31, 2008
and 2007, respectively. Our ratio of current assets to current
liabilities was 1.03 to 1.00 at December 31, 2008 as
compared to 0.84 to 1.00 at December 31, 2007.
Inflation and changes in prices. Our
revenues, the value of our assets, our ability to obtain bank
funding 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 2008, we received an average of
$91.92 per barrel of oil and $9.59 per Mcf of natural gas before
consideration of commodity derivative contracts compared to
$68.58 per barrel of oil and $8.08 per Mcf of natural gas in the
prior year. Although certain of our costs are affected by
general inflation, inflation does not normally have a
significant effect on our business. In a trend that began in
2004 and continued through the first six months of 2008,
commodity prices for oil and gas increased significantly. The
higher prices have led to
56
increased activity in the industry and, consequently, rising
costs. These cost trends have put pressure not only on our
operating costs but also on capital costs. We expect these costs
to moderate into 2009 as a result of the recent rapid diminution
in prices for oil and natural gas.
Critical
Accounting Policies and Practices
Our historical consolidated financial statements and related
notes to consolidated financial statements contain information
that is pertinent to our managements discussion and
analysis of financial condition and results of operations.
Preparation of financial statements in conformity with
accounting principles generally accepted in the United States
requires that our management make estimates, judgments and
assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses, and the disclosure of
contingent assets and liabilities. However, the accounting
principles used by us generally do not change our reported cash
flows or liquidity. Interpretation of the existing rules must be
done and judgments made on how the specifics of a given rule
apply to us.
In managements opinion, the more significant reporting
areas impacted by managements judgments and estimates are
revenue recognition, the choice of accounting method for oil and
natural gas activities, oil and natural gas reserve estimation,
asset retirement obligations, impairment of long-lived assets
and valuation of stock-based compensation. Managements
judgments and estimates in these areas are based on information
available from both internal and external sources, including
engineers, geologists and historical experience in similar
matters. Actual results could differ from the estimates, as
additional information becomes known.
Successful
Efforts Method of Accounting
We utilize the successful efforts method of accounting for our
oil and natural gas exploration and development activities under
this method. Exploration expenses, including geological and
geophysical costs, lease rentals and exploratory dry holes, are
charged against income as incurred. Costs of successful wells
and related production equipment, undeveloped leases and
developmental dry holes are also capitalized. This accounting
method may yield significantly different results than the full
cost method of accounting. Exploratory drilling costs are
initially capitalized, but are charged to expense if and when
the well is determined not to have found proved reserves.
Generally, a gain or loss is recognized when producing
properties are sold.
The application of the successful efforts method of accounting
requires managements judgment to determine the proper
designation of wells as either developmental or exploratory,
which will ultimately determine the proper accounting treatment
of costs of dry holes. Once a well is drilled, the determination
that proved reserves have been discovered may take considerable
time, and requires both judgment and application of industry
experience. The evaluation of oil and gas leasehold acquisition
costs included in unproved properties requires managements
judgment to estimate the fair value of such properties. Drilling
activities in an area by other companies may also effectively
condemn our leasehold positions.
Non-producing properties consist of undeveloped leasehold costs
and costs associated with the purchase of certain proved
undeveloped reserves. Individually significant non-producing
properties are periodically assessed for impairment of value.
Depletion of capitalized drilling and development costs of oil
and natural gas properties is computed using the
unit-of-production method on an individual property or unit
basis based on total estimated proved developed oil and natural
gas reserves. Depletion of producing leaseholds is based on the
unit-of-production method using our total estimated net proved
reserves. In arriving at rates under the unit-of-production
method, the quantities of recoverable oil and natural gas are
established based on estimates made by our geologists and
engineers and independent engineers. Service properties,
equipment and other assets are depreciated using the
straight-line method over estimated useful lives of 1 to
50 years. Upon sale or retirement of depreciable or
depletable property, the cost and related accumulated
depreciation and depletion are eliminated from the accounts and
the resulting gain or loss is recognized.
57
Oil
and Natural Gas Reserves and Standardized Measure of Discounted
Future Cash Flows
Our independent engineers and technical staff prepare the
estimates of our oil and natural gas reserves and associated
future net cash flows. Current accounting guidance allows only
proved oil and natural gas reserves to be included in our
financial statement disclosures. The SEC has defined proved
reserves as the estimated quantities of crude oil and natural
gas which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating
conditions. Even though our independent engineers and technical
staff are knowledgeable and follow authoritative guidelines for
estimating reserves, they must make a number of subjective
assumptions based on professional judgments in developing the
reserve estimates. Reserve estimates are updated at least
annually and consider recent production levels and other
technical information about each field. Periodic revisions to
the estimated reserves and future cash flows may be necessary as
a result of a number of factors, including reservoir
performance, new drilling, oil and natural gas prices, cost
changes, technological advances, new geological or geophysical
data, or other economic factors. We cannot predict the amounts
or timing of future reserve revisions. If such revisions are
significant, they could significantly alter future depletion and
result in impairment of long-lived assets that may be material.
Asset
Retirement Obligations
In June 2001, the FASB issued SFAS No. 143,
Accounting for Asset Retirement Obligations, which
applies to legal obligations associated with the retirement of
long-lived assets that result from the acquisition,
construction, development and the normal operation of a
long-lived asset. The primary impact of this standard on us
relates to oil and natural gas wells on which we have a legal
obligation to plug and abandon. SFAS No. 143 requires
us to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred and
a corresponding increase in the carrying amount of the related
long-lived asset. The determination of the fair value of the
liability requires us to make numerous judgments and estimates,
including judgments and estimates related to future costs to
plug and abandon wells, future inflation rates and estimated
lives of the related assets.
Impairment
of Long-Lived Assets
All of our long-lived assets are monitored for potential
impairment when circumstances indicate that the carrying value
of an asset may be greater than its future net cash flows,
including cash flows from risk adjusted proved reserves. The
evaluations involve a significant amount of judgment since the
results are based on estimated future events, such as future
sales prices for oil and natural gas, future costs to produce
these products, estimates of future oil and natural gas reserves
to be recovered and the timing thereof, the economic and
regulatory climates and other factors. The need to test an asset
for impairment may result from significant declines in sales
prices or downward revisions to estimated quantities of oil and
natural gas reserves. Any assets held for sale are reviewed for
impairment when we approve the plan to sell. Estimates of
anticipated sales prices are highly judgmental and subject to
material revision in future periods. Because of the uncertainty
inherent in these factors, we cannot predict when or if future
impairment charges will be recorded.
Valuation
of Stock-Based Compensation
We adopted the modified prospective approach as
prescribed under SFAS No. 123(R) on January 1,
2006. Under this approach, we are required to expense all
options and other stock-based compensation that vested during
the year of adoption based on the fair value of the award on the
grant date. The calculation of the fair value of stock-based
compensation requires the use of estimates to derive the inputs
necessary for using the various valuation methods utilized by
us. We utilize (i) the Black-Scholes option pricing model
to measure the fair value of stock options and (ii) the
stock price on the date of grant for the fair value of
restricted stock awards.
Recent
Accounting Pronouncements
In February 2007, the FASB issued SFAS No. 159,
The Fair Value Option for Financial Assets and
Financial Liabilities, Including an Amendment of FASB Statement
No. 115, which became effective in 2008.
SFAS No. 159 permits entities to measure eligible
financial assets, financial liabilities and firm commitments at
fair value, on an
instrument-by-instrument
basis, that are otherwise not permitted to be accounted for at
fair value under other
58
generally accepted accounting principles. The fair value
measurement election is irrevocable and subsequent changes in
fair value must be recorded in earnings. We adopted this
statement January 1, 2008 and did not elect the fair value
option for any of its eligible financial instruments or other
items. As such, the adoption had no impact on the consolidated
financial statements.
In April 2007, the FASB issued FASB Staff Position
FIN 39-1,
Amendment of FASB Interpretation No. 39
(FIN No. 39-1).
FIN No. 39-1
clarifies that a reporting entity that is party to a master
netting arrangement can offset fair value amounts recognized for
the right to reclaim cash collateral (a receivable) or the
obligation to return cash collateral (a payable) against fair
value amounts recognized for derivative instruments that have
been offset under the same master netting arrangement.
FIN No. 39-1
is effective for financial statements issued for fiscal years
beginning after November 15, 2007. Adoption of
FIN No. 39-1
has not had a material impact on our consolidated financial
statements.
In June 2007, the FASB ratified a consensus opinion reached by
the Emerging Issues Task Force (EITF) on EITF Issue
06-11,
Accounting for Income Tax Benefits of Dividends on
Share-Based Payment Awards. EITF Issue
06-11
requires an employer to recognize tax benefits realized from
dividend or dividend equivalents paid to employees for certain
share-based payment awards as an increase to additional paid-in
capital and include such amounts in the pool of excess tax
benefits available to absorb future tax deficiencies on
share-based payment awards. If an entitys estimate of
forfeitures increases (or actual forfeitures exceed the
entitys estimates), or if an award is no longer expected
to vest, entities should reclassify the dividends or dividend
equivalents paid on that award from retained earnings to
compensation cost. However, the tax benefits from dividends that
are reclassified from additional paid-in capital to the income
statement are limited to the entitys pool of excess tax
benefits available to absorb tax deficiencies on the date of
reclassification. The consensus in EITF Issue
06-11 is
effective for fiscal years, and interim periods within those
fiscal years, beginning after December 15, 2007.
Retrospective application of EITF Issue
06-11 is not
permitted. Early adoption is permitted; however, we did not
adopt EITF Issue
06-11 until
the required effective date of January 1, 2008. The
adoption of EITF Issue
06-11 has
not had a significant effect on our financial statements since
we historically have accounted for the income tax benefits of
dividends paid for share-based payment awards in the manner
described in the consensus.
In December 2007, the FASB issued SFAS No. 141
(revised 2007), Business Combinations
(SFAS No. 141(R)), which replaces FASB
Statement No. 141. SFAS No. 141(R) establishes
principles and requirements for how an acquirer recognizes and
measures in its financial statements the identifiable assets
acquired, the liabilities assumed, any non-controlling interest
in the acquiree and the goodwill acquired.
SFAS No. 141(R) also establishes disclosure
requirements that will enable users to evaluate the nature and
financial effects of the business combination.
SFAS No. 141(R) is effective for acquisitions that
occur in an entitys fiscal year that begins after
December 15, 2008, which will be our fiscal year 2009. The
impact, if any, will depend on the nature and size of business
combinations we consummate after the effective date.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statements an amendment of ARB
No. 51. SFAS No. 160 requires that
accounting and reporting for minority interests will be
recharacterized as noncontrolling interests and classified as a
component of equity. SFAS No. 160 also establishes
reporting requirements that provide sufficient disclosures that
clearly identify and distinguish between the interests of the
parent and the interests of the noncontrolling owners.
SFAS No. 160 applies to all entities that prepare
consolidated financial statements, except not-for-profit
organizations, but will affect only those entities that have an
outstanding noncontrolling interest in one or more subsidiaries
or that deconsolidate a subsidiary. This statement is effective
as of the beginning of an entitys first fiscal year
beginning after December 15, 2008, which will be our fiscal
year 2009. Based upon our December 31, 2008 consolidated
balance sheet, the statement would have no impact.
In December 2007, the SEC issued Staff Accounting Bulletin
(SAB) No. 110, Share-Based
Payment (SAB No. 110).
SAB No. 110 amends SAB No. 107,
Share-Based Payment, and allows for the
continued use, under certain circumstances, of the simplified
method in developing an estimate of the expected term on stock
options accounted for under SFAS No. 123R,
Share-Based Payment (revised 2004).
SAB No. 110 is effective for stock options granted
after December 31, 2007. We continued to use the simplified
method in developing an estimate of the expected term on stock
options granted in 2008. We do not have sufficient historical
exercise data to
59
provide a reasonable basis upon which to estimate expected term
due to the limited period of time our shares of common stock
have been publicly traded.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities (SFAS No. 161), which
amends and expands the disclosure requirements of
SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities
(SFAS No. 133), to provide an enhanced
understanding of an entitys use of derivative instruments,
how they are accounted for under SFAS No. 133 and
their effect on the entitys financial position, financial
performance and cash flows. The provisions of
SFAS No. 161 are effective as of January 1, 2009.
We are currently evaluating the impact on our consolidated
financial statements of adopting SFAS No. 161.
In April 2008, the FASB issued FASB Staff Position
(FSP)
No. SFAS No. 142-3,
Determination of the Useful Life of Intangible Assets
(FSP
SFAS No. 142-3).
FSP
SFAS No. 142-3
amends the factors that should be considered in developing
renewal or extension assumptions used to determine the useful
life of a recognized intangible asset under
SFAS No. 142, Goodwill and Other Intangible Assets
(SFAS No. 142). The intent of FSP
SFAS No. 142-3
is to improve the consistency between the useful life of a
recognized intangible asset under SFAS No. 142 and the
period of expected cash flows used to measure the fair value of
the asset under SFAS No. 141R and other applicable
accounting literature. FSP
SFAS No. 142-3
is effective for financial statements issued for fiscal years
beginning after December 15, 2008 and must be applied
prospectively to intangible assets acquired after the effective
date. We are currently evaluating the potential impact, if any,
of FSP
SFAS No. 142-3
on our financial statements.
In May 2008, the FASB issued SFAS No. 162,
The Hierarchy of Generally Accepted Accounting
Principles, which identifies the sources of accounting
principles and the framework for selecting the principles used
in the preparation of financial statements of nongovernmental
entities that are presented in conformity with generally
accepted accounting principles (GAAP) in the United
States of America. This statement is effective 60 days
following the SECs approval of the Public Company
Accounting Oversight Board amendments to AU Section 411,
The Meaning of Present Fairly in Conformity with
Generally Accepted Accounting Principles. We do not
expect the adoption of SFAS No. 162 to have an impact
on our financial statements.
In June 2008, the FASB issued Staff Position
No. EITF 03-6-1
Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating Securities,
(FSP
EITF 03-6-1)
which provides that unvested share-based payment awards that
contain non-forfeitable rights to dividends or dividend
equivalents (whether paid or unpaid) are participating
securities and, therefore, need to be included in the earnings
allocation in computing earnings per share under the two class
method. FSP
EITF 03-6-1
was effective for us on January 1, 2009 and all
prior-period EPS data (including any amounts related to interim
periods, summaries of earnings and selected financial data) will
be adjusted retroactively to conform to its provisions. Early
application of FSP
EITF 03-6-1
is not permitted. Although restricted stock awards meet this
definition, we do not expect the application of FSP
EITF 03-6-1
to have a significant impact on our reported earnings per share.
In October 2008, the FASB issued FSP
No. SFAS 157-3,
Determining the Fair Value of a Financial Asset When
the Market for That Asset is Not Active. FSP
No. SFAS 157-3
clarifies the application of SFAS No. 157 as it
relates to the valuation of financial assets in a market that is
not active for those financial assets. This FSP is effective
immediately and includes those periods for which financial
statements have not been issued. We currently do not have any
financial assets that are valued using inactive markets, and as
a result, we are not impacted by the issuance of FSP
No. SFAS 157-3.
Recent
Developments in Reserve Reporting
The SEC recently approved new disclosure rules that allow oil
and natural gas companies to more accurately report their assets
in terms of volumes and values that investors can understand and
use to make informed decisions. The new reporting requirement is
effective on December 15, 2009. The new disclosure
requirements include provisions that:
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permit the use of new technologies to determine proved reserves
if those technologies have been demonstrated empirically to lead
to reliable conclusions about reserves volumes;
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60
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|
allow companies to disclose in SEC filed documents their
probable and possible reserves to investors (currently, the SEC
rules limit disclosure to only proved reserves);
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require companies to report the independence and qualifications
of a reserves preparer or auditor;
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file reports when a third party is relied upon to prepare
reserves estimates or conducts a reserves audit; and
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report oil and gas reserves using an average price based upon
the prior
12-month
period rather than year-end prices.
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We are currently evaluating the impact these new reserve
reporting requirements will have on our consolidated financial
statements and our annual report on
Form 10-K.
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Item 7A.
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Quantitative
and Qualitative Disclosure About Market Risk
|
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 December 31, 2008,
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 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, as described under Item 1.
Business and properties Marketing
arrangements. We monitor our exposure to these
counterparties primarily by reviewing credit ratings, financial
statements and payment history. We extend credit terms based on
our evaluation of each counterpartys creditworthiness.
Although we have not generally required our counterparties to
provide collateral to support their obligation to us, we may, if
circumstances dictate, require collateral in the future. In this
manner, we reduce credit risk.
Commodity price
risk. We are exposed to market risk as
the prices of crude oil and natural gas are subject to
fluctuations resulting from changes in supply and demand. To
reduce our exposure to changes in the prices of oil and natural
gas we have entered into, and may in the future enter into
additional commodity price risk management arrangements for a
portion of our oil and natural gas production. The agreements
that we have entered into generally have the effect of providing
us with a fixed price for a portion of our expected future oil
and natural gas production over a fixed period of time. Our
commodity price risk management activities could have the effect
of reducing our revenues, net income and the value of our common
stock. At December 31, 2008, the net unrealized asset on
our commodity price risk management contracts was
$172.4 million. An average increase in the commodity price
of $1.00 per barrel of crude oil and $0.10 per Mcf for natural
gas from the commodity prices at December 31, 2008, would
have resulted in a decrease in the net unrealized asset on our
commodity price risk management contracts, as reflected on our
consolidated balance sheet at December 31, 2008, of
approximately $3.6 million.
At December 31, 2008, we had (i) a oil price collar
and oil price swaps that settle on a monthly basis covering
future oil production from January 1, 2008 through
December 31, 2012 and (ii) a natural gas price swap
and a natural gas basis swap covering future natural gas
production for 2009, see Note I of the Notes to
Consolidated Financial Statements included in Item 8.
Financial Statements and Supplementary Data for additional
information on the commodity derivative contracts. The average
NYMEX oil futures price and average NYMEX natural gas futures
prices for the year ended December 31, 2008, was $99.75 per
Bbl and $7.41 per MMBtu, respectively. At February 19,
2008, the NYMEX oil futures price and NYMEX natural gas futures
price was $39.48 per Bbl and $4.08 per MMBtu, respectively. The
decrease in oil and natural gas prices, should it continue into
2009, should
61
increase the fair value asset of our commodity derivative
contracts from their recorded balance at December, 2008. Changes
in the recorded fair value of the undesignated commodity
derivative contracts are marked to market through earnings as
unrealized gains or losses. The potential increase in fair value
asset would be recorded in earnings as unrealized gains.
However, an increase in the average NYMEX oil and natural gas
futures price above those at December 31, 2008 would result
in an decrease in fair value asset and unrealized losses in
earnings. We are currently unable to estimate the effects on the
earnings of future periods resulting from changes in the market
value of our commodity derivative contracts.
Interest rate
risk. Our exposure to changes in interest
rates relates primarily to long-term debt obligations. We manage
our interest rate exposure by limiting our variable-rate debt to
a certain percentage of total capitalization and by monitoring
the effects of market changes in interest rates. To reduce our
exposure to changes in interest rates we have entered into, and
may in the future enter into additional interest rate risk
management arrangements for a portion of our outstanding debt.
The agreements that we have entered into generally have the
effect of providing us with a fixed interest rate for a portion
of our variable rate debt. We may utilize interest rate
derivatives to alter interest rate exposure in an attempt to
reduce interest rate expense related to existing debt issues.
Interest rate derivatives are used solely to modify interest
rate exposure and not to modify the overall leverage of the debt
portfolio. We are exposed to changes in interest rates as a
result of our credit facility, and the terms of our credit
facility require us to pay higher interest rate margins as we
utilize a larger percentage of our available borrowing base.
At December 31, 2008, we had interest rate swaps on
$300 million of notional principal that fixed the LIBOR
interest rate (does not include the interest rate margins
discussed above) at 1.90 percent for the three years
beginning in May 2009. An average decrease in future interest
rates of 25 basis points from the future rate at
December 31, 2008, would have resulted in a decrease in the
net unrealized asset on our interest rate risk management
contracts, as reflected on our consolidated balance sheet at
December 31, 2008, of approximately $2.0 million.
We had total indebtedness of $630.0 million outstanding
under our credit facility at December 31, 2008. The impact
of a 1 percent increase in interest rates on this amount of
debt, assuming the interest rate swaps were outstanding, would
result in increased annual interest expense of approximately
$6.3 million and a corresponding decrease in net income
before income tax.
The fair value of our derivative instruments is determined based
on counterparties estimates and valuation models. We did
not change our valuation method during 2008. During 2008, we
were party to commodity and interest rate derivative
instruments. See Note I of the Notes to Consolidated
Financial Statements included in Item 8. Financial
Statements and Supplementary Data for additional
information regarding our derivative instruments. The following
table reconciles the changes that occurred in the fair values of
our derivative instruments during 2008:
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Derivative Instruments Net Assets (Liabilities)(a)
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Commodities
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Interest Rate
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Total
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(In thousands)
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Fair value of contracts outstanding at December 31, 2007
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$
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(45,065
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)
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$
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$
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(45,065
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)
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Fair value of contracts from acquisitions
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(62,662
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)
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(62,662
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)
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Changes in fair values(b)
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244,305
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(1,083
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)
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243,222
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Contract maturities
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36,945
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36,945
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Fair value of contracts outstanding at December 31, 2008
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$
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173,523
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$
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(1,083
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)
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$
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172,440
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(a) |
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Represents the fair values of open derivative contracts subject
to market risk. |
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(b) |
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At inception, new derivative contracts entered into by us have
no intrinsic value. |
62
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Item 8.
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Financial
Statements and Supplementary Data
|
Our consolidated financial statements and supplementary
financial data are included in this report beginning on
page F-1.
63
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Item 9.
|
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure
|
We had no changes in, and no disagreements with our accountants,
on accounting and financial disclosure.
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Item 9A.
|
Controls
and Procedures
|
Evaluation of disclosure controls and
procedures. The Companys
management, with the participation of its principal executive
officer and principal financial officer, have evaluated, as
required by
Rule 13a-15(b)
under the Exchange Act, the Companys disclosure controls
and procedures (as defined in Exchange Act
Rule 13a-15(e))
as of the end of the period covered by this Report. Based on
that evaluation, the principal executive officer and principal
financial officer concluded that the design and operation of the
Companys disclosure controls and procedures are effective
in ensuring that information required to be disclosed by the
Company in the reports that it files or submits under the
Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the SECs rules and
forms.
Changes in internal control over financial
reporting. There have been no changes in
the Companys internal control over financial reporting (as
defined in
Rule 13a-15(f)
under the Exchange Act) that occurred during the Companys
last fiscal quarter that have materially affected or are
reasonably likely to materially affect the Companys
internal control over financial reporting.
Henry Properties
acquisition. Because the Henry
Properties acquisition was completed in the third quarter of
2008 management did not include the internal control processes
for these related entities in its assessment of internal control
over financial reporting at December 31, 2008. See more
details below relating to the exclusion of these acquisitions
from Managements Report on Internal Control Over Financial
Reporting. Additionally, this acquisition is excluded from the
certifications required under Section 302 of the
Sarbanes-Oxley Act of 2002, which are attached as exhibits to
this report. Management will include all aspects of internal
controls for this acquisition in its 2009 assessment. The Henry
Properties acquisition represents 33 percent of our total
assets at December 31, 2008 and 11 percent of our
total revenues for the year ended December 31, 2008.
64
MANAGEMENTS
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for establishing
and maintaining adequate internal control over financial
reporting. The Companys internal control over financial
reporting is a process designed under the supervision of the
Companys Chief Executive Officer and Chief Financial
Officer to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of the
Companys financial statements for external purposes in
accordance with generally accepted accounting principles.
As of December 31, 2008, management assessed the
effectiveness of the Companys internal control over
financial reporting based on the criteria for effective internal
control over financial reporting established in Internal
Control Integrated Framework, issued by the
Committee of Sponsoring Organizations of the Treadway
Commission. Management excluded from its assessment of internal
controls over financial reporting the Henry Properties
acquisition, which closed in the third quarter of 2008 and
constitute 33 percent of total assets and 11 percent
of revenues of the consolidated financial statement amounts as
of and for the year ended December 31, 2008. Based on our
assessment and those criteria, management determined that the
Company maintained effective internal control over financial
reporting as of December 31, 2008.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
Grant Thornton LLP, the independent registered public accounting
firm that audited the consolidated financial statements of the
Company included in this annual report on
Form 10-K,
has issued an attestation report on the effectiveness of the
Companys internal control over financial reporting as of
December 31, 2008. The report, which expresses an
unqualified opinion on the effectiveness of the Companys
internal control over financial reporting as of
December 31, 2008, is included in this Item under the
heading Report of Independent Registered Public Accounting
Firm on Internal Control Over Financial Reporting.
65
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Concho Resources Inc.
We have audited Concho Resources Inc.s (a Delaware
Corporation) internal control over financial reporting as of
December 31, 2008, based on criteria established in
Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO). Concho Resources Inc.s management is responsible
for maintaining effective internal control over financial
reporting and for its assessment of the effectiveness of
internal control over financial reporting included in the
accompanying Managements Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion
on Concho Resources Inc.s internal control over financial
reporting based on our audit. Our audit of, and opinion on,
Concho Resources Inc.s internal control over financial
reporting does not include internal control over financial
reporting of Henry Properties acquisition whose financial
statements reflect total assets and revenues constituting
33 percent and 11 percent, respectively, of the
related consolidated financial statement amounts as of and for
the year ended December 31, 2008. As indicated in
Managements Report, the Henry Properties were acquired
during 2008 and therefore, managements assertion on the
effectiveness of Concho Resources Inc.s internal control
over financial reporting excluded internal control over
financial reporting of the Henry Properties.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a
process designed 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. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, Concho Resources Inc. maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2008, based on criteria
established in Internal Control Integrated
Framework issued by COSO.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Concho Resources Inc. and
subsidiaries as of December 31, 2008 and 2007 and the
related consolidated statements of operations,
stockholders equity and cash flows for each of the three
years in the period ended December 31, 2008, and our report
dated February 27, 2009 expressed an unqualified opinion
thereon.
/s/ GRANT THORNTON LLP
February 27, 2009
Tulsa, Oklahoma
66
|
|
Item 9B.
|
Other
Information
|
None.
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance
|
Item 10 will be incorporated by reference pursuant to
Regulation 14A under the Exchange Act. The Registrant
expects to file a definitive proxy statement with the SEC within
120 days after the close of the year ended
December 31, 2008.
|
|
Item 11.
|
Executive
Compensation
|
Item 11 will be incorporated by reference pursuant to
Regulation 14A under the Exchange Act. The Registrant
expects to file a definitive proxy statement with the SEC within
120 days after the close of the year ended
December 31, 2008.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
Equity
Compensation Plans
At December 31, 2008, a total of 5,850,000 shares of
common stock were authorized for issuance under our equity
compensation plan. In the table below, we describe certain
information about these shares and the equity compensation plan
which provides for their authorization and issuance. You can
find descriptions of our stock incentive plan under Note G
of the Notes to Consolidated Financial Statements included in
Item 8. Financial Statements and Supplementary
Data.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Securities
|
|
|
|
|
|
|
|
|
|
Remaining Available for
|
|
|
|
|
|
|
Weighted-Average
|
|
|
Future Issuance Under
|
|
|
|
|
|
|
Exercise
|
|
|
Equity Compensation
|
|
|
|
Number of Securities to be
|
|
|
Price of
|
|
|
Plans (Excluding
|
|
|
|
Issued Upon Exercise of
|
|
|
Outstanding
|
|
|
Securities Reflected in
|
|
Plan Category
|
|
Outstanding Options
|
|
|
Options
|
|
|
Column(a))
|
|
|
Equity compensation plan approved by security holders(a)
|
|
|
2,731,324
|
|
|
$
|
12.46
|
|
|
|
1,993,507
|
|
Equity compensation plan not approved by security holders(b)
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,731,324
|
|
|
|
|
|
|
|
1,993,507
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
2006 Stock Incentive Plan. See Note G of the Notes to
Consolidated Financial Statements included in Item 8.
Financial Statements and Supplementary Data. |
|
(b) |
|
None. |
The remaining information required by Item 12 will be
incorporated by reference pursuant to Regulation 14A under
the Exchange Act. The Registrant expects to file a definitive
proxy statement with the SEC within 120 days after the
close of the year ended December 31, 2008.
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
Item 13 will be incorporated by reference pursuant to
Regulation 14A under the Exchange Act. The Registrant
expects to file a definitive proxy statement with the SEC within
120 days after the close of the year ended
December 31, 2008.
67
|
|
Item 14.
|
Principal
Accounting Fees and Services
|
Item 14 will be incorporated by reference pursuant to
Regulation 14A under the Exchange Act. The Registrant
expects to file a definitive proxy statement with the SEC within
120 days after the close of the year ended
December 31, 2008.
PART IV
|
|
Item 15.
|
Exhibits,
Financial Statement Schedules, and Reports on
Form 8-K
|
|
|
(a)
|
Listing
of Financial Statements
|
Financial
Statements
The following consolidated financial statements of the Company
are included in Financial Statements and Supplementary
Data:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2008 and 2007
Consolidated Statements of Operations for the Years Ended
December 31, 2008, 2007 and 2006
Consolidated Statements of Stockholders Equity for the
Years Ended December 31, 2008, 2007 and 2006
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2008, 2007 and 2006
Notes to Consolidated Financial Statements
Unaudited Supplementary Information
The exhibits to this Report required to be filed pursuant to
Item 15(b) are listed below and in the Index to
Exhibits attached hereto.
|
|
(c)
|
Financial
Statement Schedules
|
No financial statement schedules are required to be filed as
part of the Report or they are inapplicable.
Exhibits
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
2.1
|
|
|
Purchase Agreement, dated June 5, 2008, by and among Concho
Resources Inc., James C. Henry and Paula Henry, Henry Securities
Ltd., Henchild LLC, Henry Family Investment Group, Henry Holding
LP, Henry Energy LP, Aguasal Holding, HELP Investment LLC, Henry
Capital LLC, Henry Operating LLC, Henry Petroleum LP, Quail
Ranch LLC, Aguasal Management LLC, and Aguasal LP (filed as
Exhibit 2.1 to the Companys Current Report on
Form 8-K
on June 9, 2008, and incorporated herein by reference).
|
|
3.1
|
|
|
Restated Certificate of Incorporation (filed as Exhibit 3.1
to the Companys Current Report on
Form 8-K
on August 6, 2007, and incorporated herein by reference).
|
|
3.2
|
|
|
Amended and Restated Bylaws of Concho Resources Inc., as amended
March 25, 2008 (filed as Exhibit 3.1 to the
Companys Current Report on
Form 8-K
on March 26, 2008, and incorporated herein by reference).
|
|
4.1
|
|
|
Specimen Common Stock Certificate (filed as Exhibit 4.1 to
the Companys Current Report on
Form S-1/A
on July 5, 2007, and incorporated herein by reference).
|
68
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
10.1
|
|
|
Credit Agreement, dated as of February 24, 2006, by and
among Concho Resources Inc., JPMorgan Chase Bank, N.A., as
administrative agent, Bank of America, N.A., as syndication
agent, Wachovia Bank, National Association, and BNP Paribas, as
documentation agents, and other lenders party thereto(filed as
Exhibit 10.1 to the Companys Current Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
|
10.2
|
|
|
Second Lien Credit Agreement, dated as of March 23, 2007,
among Concho Resources Inc., Bank of America, N.A., as
administrative agent, and Banc of America LLC, as sole lead
arranger and sole booking manager (filed as Exhibit 10.2 to
the Companys Current Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
|
10.3
|
|
|
Form of Drilling Agreement with Silver Oak Drilling, LLC (filed
as Exhibit 10.4 to the Companys Current Report on
Form S-1/A
on July 5, 2007, and incorporated herein by reference).
|
|
10.4
|
|
|
Salt Water Disposal System Ownership and Operating Agreement
dated February 24, 2006, among COG Operating LLC, Chase Oil
Corporation, Caza Energy LLC and Mack Energy Corporation (filed
as Exhibit 10.5 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10.5
|
|
|
Transition Services Agreement dated April 23, 2007, between
COG Operating LLC and Mack Energy Corporation (filed as
Exhibit 10.3 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10.6
|
|
|
Combination Agreement dated February 24, 2006, among Concho
Resources Inc., Concho Equity Holdings Corp., Chase Oil
Corporation, Caza Energy LLC and the other signatories thereto
(filed as Exhibit 2.1 to the Companys Current Report
on
Form S-1
on April 24, 2007, and incorporated herein by reference).
The Combination Agreement filed as Exhibit 2.1 omits
certain of the schedules and exhibits to the Combination
Agreement in accordance with Item 601(b)(2) of
Regulation S-K.
A list briefly identifying the contents of all omitted schedules
and exhibits is included with the Combination Agreement filed as
Exhibit 2.1. Concho Resources agrees to furnish
supplementally a copy of any omitted schedule or exhibit to the
Securities and Exchange Commission upon request.
|
|
10.7
|
|
|
Software License Agreement dated March 2, 2006, between
Enertia Software Systems and Concho Resources Inc. (filed as
Exhibit 10.6 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10.8
|
|
|
Leasehold Acquisition Agreement dated April 1, 2005, by and
between Trey Resources, Inc. and COG Oil and Gas LP (filed as
Exhibit 10.7 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10.9
|
|
|
Transfer of Operating Rights (Sublease) in a Lease for Oil and
Gas for Valhalla properties (filed as Exhibit 10.8 to the
Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10.10
|
|
|
Assignment of Oil and Gas Leases from Caza Energy LLC (filed as
Exhibit 10.9 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10.11
|
**
|
|
Escrow Agreement dated February 27, 2006, among Concho
Resources Inc., Timothy A. Leach, Steven L. Beal, David W.
Copeland, Curt F. Kamradt and E. Joseph Wright and the other
signatories thereto (filed as Exhibit 10.10 to the
Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10.12
|
|
|
Business Opportunities Agreement dated February 27, 2006,
among Concho Resources Inc. and the other signatories thereto
(filed as Exhibit 10.11 to the Companys Current
Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10.13
|
|
|
Registration Rights Agreement dated February 27, 2006,
among Concho Resources Inc. and the other signatories thereto
(filed as Exhibit 10.12 to the Companys Current
Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10.14
|
**
|
|
Concho Resources Inc. 2006 Stock Incentive Plan (filed as
Exhibit 10.13 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
69
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
10.15
|
**
|
|
Concho Resources Inc. Summary of Executive Officer Compensation
Program (filed as Exhibit 10.15 to the Companys
Current Report on
Form 10-K
on March 28, 2008, and incorporated herein by reference).
|
|
10.16
|
**
|
|
Form of Nonstatutory Stock Option Agreement (filed as
Exhibit 10.16 to the Companys Current Report on
Form 10-K
on March 28, 2008, and incorporated herein by reference).
|
|
10.17
|
**
|
|
Form of Restricted Stock Agreement (for employees) (filed as
Exhibit 10.16 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10.18
|
**
|
|
Form of Restricted Stock Agreement (for non-employee directors)
(filed as Exhibit 10.18 to the Companys Current
Report on
Form 10-K
on March 28, 2008, and incorporated herein by reference).
|
|
10.19
|
**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and Timothy A. Leach (filed as
Exhibit 10.1 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10.20
|
**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and Steven L. Beal (filed as
Exhibit 10.2 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10.21
|
**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and E. Joseph Wright (filed as
Exhibit 10.3 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10.22
|
**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and Darin G. Holderness (filed as
Exhibit 10.4 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10.23
|
**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and David W. Copeland (filed as
Exhibit 10.5 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10.24
|
**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and Matthew G. Hyde (filed as
Exhibit 10.6 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10.25
|
**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and Jack F. Harper (filed as
Exhibit 10.7 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10.26
|
**
|
|
Form of Indemnification Agreement between Concho Resources Inc.
and each of the officers and directors thereof (filed as
Exhibit 10.23 to the Companys current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10.27
|
**
|
|
Indemnification Agreement, dated May 21, 2008, by and
between Concho Resources, Inc. and Matthew G. Hyde (filed as
Exhibit 10.1 to the Companys current Report on
Form 8-K
on May 28, 2008, and incorporated herein by reference).
|
|
10.28
|
**
|
|
Indemnification Agreement, dated August 25, 2008, by and
between Concho Resources, Inc. and Darin G. Holderness (filed as
Exhibit 10.1 to the Companys current Report on
Form 8-K
on August 29, 2008, and incorporated herein by reference).
|
|
10.29
|
**
|
|
Indemnification Agreement, dated February 27, 2008, by and
between Concho Resources, Inc. and William H. Easter III
(filed as Exhibit 10.1 to the Companys current Report
on
Form 8-K
on March 4, 2008, and incorporated herein by reference).
|
|
10.30
|
|
|
Gas Purchase Contract between COG Oil & Gas LP and
Duke Energy Field Services, LP dated November 1, 2006
(filed as Exhibit 10.25 to the Companys current
Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
Confidential treatment of certain provisions of this exhibit has
previously been granted by the Securities and Exchange
Commission. Omitted material for which confidential treatment
has been granted has been filed separately with the Securities
and Exchange Commission.
|
|
10.31
|
|
|
Letter Agreement between COG Operating LLC and Navajo Refining
Company, L.P. dated January 15, 2007 (filed as
Exhibit 10.26 to the Companys current Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
70
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
10.32
|
|
|
First Amendment to Credit Agreement, dated as of July 6,
2006, among Concho Resources Inc., certain of its subsidiaries,
JPMorgan Chase Bank, N.A. and the other leaders party thereto
(filed as Exhibit 10.27 to the Companys current
Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
|
10.33
|
|
|
Second Amendment to Credit Agreement, dated as of March 7,
2007, among Concho Resources Inc., certain of its subsidiaries,
JPMorgan Chase Bank, N.A. and the other leaders party thereto
(filed as Exhibit 10.28 to the Companys current
Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
|
10.34
|
|
|
Third Amendment to Credit Agreement, dated as of May 19,
2008, by and among Concho Resources Inc., certain of its
subsidiaries, JPMorgan Chase Bank, N.A. and the other leaders
party thereto (filed as Exhibit 10.1 to the Companys
Current Report on
Form 8-K
on May 23, 2008, and incorporated herein by reference).
|
|
10.35
|
**
|
|
Form of option letter agreement among Concho Resources Inc.,
Concho Equity Holdings Corp. and each of Messrs. Leach and
Beal (filed as Exhibit 10.29 to the Companys current
Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
|
10.36
|
**
|
|
Form of option letter agreement among Concho Resources Inc.,
Concho Equity Holdings Corp. and each of Messrs. Copeland,
Kamradt, Thomas and Wright (filed as Exhibit 10.30 to the
Companys current Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
|
10.37
|
**
|
|
Form of Amendment to Stock Option Award Agreement with executive
officers related to the Pre-Combination Options (filed as
Exhibit 10.1 to the Companys current Report on
Form 8-K
on November 20, 2007, and incorporated herein by reference).
|
|
10.38
|
**
|
|
Form of Amendment to Nonstatutory Stock Option Agreement with
executive officers related to the June 2006 Options (filed as
Exhibit 10.2 to the Companys current Report on
Form 8-K
on November 20, 2007, and incorporated herein by reference).
|
|
10.39
|
**
|
|
Form of Restricted Stock Agreement with executive officers
related to the June 2006 Options (filed as Exhibit 10.3 to
the Companys current Report on
Form 8-K
on November 20, 2007, and incorporated herein by reference).
|
|
10.40
|
**
|
|
Summary of Director Compensation Program (filed as
Exhibit 10.41 to the Companys Current Report on
Form 10-K
on March 28, 2008, and incorporated herein by reference).
|
|
10.41
|
|
|
Common Stock Purchase Agreement, dated June 5, 2008, by and
among Concho Resources Inc. and the purchasers named therein
(filed as Exhibit 10.1 to the Companys Current Report
on
Form 8-K
on June 9, 2008, and incorporated herein by reference).
|
|
10.42
|
|
|
Registration Rights Agreement, dated July 31, 2008, by and
between Concho Resources Inc. and the purchasers named therein
(filed as Exhibit 10.1 to the Companys Current Report
on
Form 8-K
on August 6, 2008, and incorporated herein by reference).
|
|
10.43
|
|
|
Amended and Restated Credit Agreement, dated July 31, 2008,
by and among Concho Resources Inc., JP Morgan Chase Bank, N.A.,
Bank of America, N.A., Calyon New York Branch, ING Capital LLC
and BNP Paribas and certain other lenders party thereto (filed
as Exhibit 10.2 to the Companys Current Report on
Form 8-K
on August 6, 2008, and incorporated herein by reference).
|
|
21.1
|
(a)
|
|
Subsidiaries of Concho Resources Inc.
|
|
23.1
|
(a)
|
|
Consent of Grant Thornton LLP
|
|
23.2
|
(a)
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
23.3
|
(a)
|
|
Consent of Cawley, Gillespie & Associates, Inc.
|
|
31.1
|
(a)
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31.2
|
(a)
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32.1
|
(b)
|
|
Certification of Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32.2
|
(b)
|
|
Certification of Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
(a) |
|
Filed herewith. |
|
(b) |
|
Furnished herewith. |
|
** |
|
Management contract or compensatory plan or arrangement. |
71
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
Timothy A. Leach
Director, Chairman of the Board of Directors and
Chief Executive Officer (Principal Executive Officer)
Date: February 27, 2009
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
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Signature
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Title
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Date
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/s/ TIMOTHY
A. LEACH
Timothy
A. Leach
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Director, Chairman of the Board of Directors and Chief Executive
Officer (Principal Executive Officer)
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February 27, 2009
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/s/ STEVEN
L. BEAL
Steven
L. Beal
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Director, President and Chief Operating Officer
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February 27, 2009
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/s/ DARIN
G. HOLDERNESS
Darin
G. Holderness
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Vice President, Chief Financial Officer and Treasurer (Principal
Financial and Accounting Officer)
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February 27, 2009
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/s/ TUCKER
S. BRIDWELL
Tucker
S. Bridwell
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Director
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February 27, 2009
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/s/ WILLIAM
H. EASTER III
William
H. Easter III
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Director
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February 27, 2009
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/s/ W.
HOWARD KEENAN, JR.
W.
Howard Keenan, JR.
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Director
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February 27, 2009
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/s/ RAY
M. POAGE
Ray
M. Poage
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Director
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February 27, 2009
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/s/ A.
WELLFORD TABOR
A.
Wellford Tabor
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Director
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February 27, 2009
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72
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Concho Resources Inc.
We have audited the accompanying consolidated balance sheets of
Concho Resources Inc. (a Delaware corporation) and subsidiaries
as of December 31, 2008 and 2007, and the related
consolidated statements of operations, stockholders equity
and cash flows for each of the three years in the period ended
December 31, 2008. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit also includes examining,
on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing
the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of Concho Resources Inc. and subsidiaries as of
December 31, 2008 and 2007, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2008, in conformity with
accounting principles generally accepted in the United States of
America.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States),
Concho Resources Inc.s internal control over financial
reporting as of December 31, 2008, based on criteria
established in Internal Control Integrated
Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) and our report
dated February 27, 2009 expressed an unqualified opinion
thereon.
/s/ GRANT THORNTON LLP
February 27, 2009
Tulsa, Oklahoma
F-2
CONCHO
RESOURCES INC.
|
|
|
|
|
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|
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|
|
December 31,
|
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|
|
2008
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|
|
2007
|
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|
(In thousands, except share and per share data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
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|
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Cash and cash equivalents
|
|
|
$17,752
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|
|
|
$30,424
|
|
Accounts receivable, net of allowance for doubtful accounts:
|
|
|
|
|
|
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|
|
Oil and gas
|
|
|
48,793
|
|
|
|
36,735
|
|
Joint operations and other
|
|
|
92,833
|
|
|
|
21,183
|
|
Related parties
|
|
|
314
|
|
|
|
|
|
Derivative instruments
|
|
|
113,149
|
|
|
|
1,866
|
|
Deferred income taxes
|
|
|
|
|
|
|
13,502
|
|
Prepaid costs and other
|
|
|
5,942
|
|
|
|
4,273
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
278,783
|
|
|
|
107,983
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, at cost:
|
|
|
|
|
|
|
|
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Oil and gas properties, successful efforts method
|
|
|
2,693,574
|
|
|
|
1,555,018
|
|
Accumulated depletion and depreciation
|
|
|
(306,990
|
)
|
|
|
(167,109
|
)
|
|
|
|
|
|
|
|
|
|
Total oil and gas properties, net
|
|
|
2,386,584
|
|
|
|
1,387,909
|
|
Other property and equipment, net
|
|
|
14,820
|
|
|
|
7,085
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
2,401,404
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|
|
|
1,394,994
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|
|
|
|
|
|
|
|
|
|
Deferred loan costs, net
|
|
|
15,701
|
|
|
|
3,426
|
|
Inventory
|
|
|
19,956
|
|
|
|
1,459
|
|
Intangible asset, net operating rights
|
|
|
37,768
|
|
|
|
|
|
Noncurrent derivative instruments
|
|
|
61,157
|
|
|
|
|
|
Other assets
|
|
|
434
|
|
|
|
367
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
$2,815,203
|
|
|
|
$1,508,229
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
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|
|
Trade
|
|
|
$7,462
|
|
|
|
$14,222
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|
Related parties
|
|
|
312
|
|
|
|
2,119
|
|
Other current liabilities:
|
|
|
|
|
|
|
|
|
Bank overdrafts
|
|
|
9,434
|
|
|
|
5,651
|
|
Revenue payable
|
|
|
22,286
|
|
|
|
14,494
|
|
Accrued and prepaid drilling costs
|
|
|
154,196
|
|
|
|
39,276
|
|
Derivative instruments
|
|
|
1,866
|
|
|
|
36,414
|
|
Deferred income taxes
|
|
|
37,205
|
|
|
|
|
|
Current portion of long-term debt
|
|
|
|
|
|
|
2,000
|
|
Other current liabilities
|
|
|
38,057
|
|
|
|
14,466
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
270,818
|
|
|
|
128,642
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
630,000
|
|
|
|
325,404
|
|
Noncurrent derivative instruments
|
|
|
|
|
|
|
10,517
|
|
Deferred income taxes
|
|
|
573,763
|
|
|
|
259,070
|
|
Asset retirement obligations and other long-term liabilities
|
|
|
15,468
|
|
|
|
9,198
|
|
Commitments and contingencies (Note K)
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value; 10,000,000 shares
authorized; none issued and outstanding at December 31,
2008 and 2007
|
|
|
|
|
|
|
|
|
Common stock, $0.001 par value; 300,000,000 authorized;
84,828,824 and 75,832,310 shares issued at
December 31, 2008 and 2007, respectively
|
|
|
85
|
|
|
|
76
|
|
Additional paid-in capital
|
|
|
1,009,025
|
|
|
|
752,380
|
|
Notes receivable from employees
|
|
|
|
|
|
|
(330
|
)
|
Retained earnings
|
|
|
316,169
|
|
|
|
37,467
|
|
Accumulated other comprehensive loss
|
|
|
|
|
|
|
(14,195
|
)
|
Treasury stock, at cost; 3,142 and no shares at
December 31, 2008 and 2007, respectively
|
|
|
(125
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
1,325,154
|
|
|
|
775,398
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
|
$2,815,203
|
|
|
|
$1,508,229
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-3
CONCHO
RESOURCES INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
390,945
|
|
|
$
|
195,596
|
|
|
$
|
131,773
|
|
Natural gas sales
|
|
|
142,844
|
|
|
|
98,737
|
|
|
|
66,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
533,789
|
|
|
|
294,333
|
|
|
|
198,290
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
91,234
|
|
|
|
54,267
|
|
|
|
37,822
|
|
Exploration and abandonments
|
|
|
38,468
|
|
|
|
29,098
|
|
|
|
5,612
|
|
Depreciation, depletion and amortization
|
|
|
123,912
|
|
|
|
76,779
|
|
|
|
60,722
|
|
Accretion of discount on asset retirement obligations
|
|
|
889
|
|
|
|
444
|
|
|
|
287
|
|
Impairments of long-lived assets
|
|
|
18,417
|
|
|
|
7,267
|
|
|
|
9,891
|
|
General and administrative (including non-cash stock-based
compensation of $5,223, $3,841 and $9,144 for the years ended
December 31, 2008, 2007 and 2006, respectively)
|
|
|
40,776
|
|
|
|
25,177
|
|
|
|
21,721
|
|
Bad debt expense
|
|
|
2,905
|
|
|
|
|
|
|
|
|
|
Contract drilling fees stacked rigs
|
|
|
|
|
|
|
4,269
|
|
|
|
|
|
Ineffective portion of cash flow hedges
|
|
|
(1,336
|
)
|
|
|
821
|
|
|
|
(1,193
|
)
|
(Gain) loss on derivatives not designated as hedges
|
|
|
(249,870
|
)
|
|
|
20,274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
65,395
|
|
|
|
218,396
|
|
|
|
134,862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
468,394
|
|
|
|
75,937
|
|
|
|
63,428
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(29,039
|
)
|
|
|
(36,042
|
)
|
|
|
(30,567
|
)
|
Other, net
|
|
|
1,432
|
|
|
|
1,484
|
|
|
|
1,186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(27,607
|
)
|
|
|
(34,558
|
)
|
|
|
(29,381
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
440,787
|
|
|
|
41,379
|
|
|
|
34,047
|
|
Income tax expense
|
|
|
(162,085
|
)
|
|
|
(16,019
|
)
|
|
|
(14,379
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
278,702
|
|
|
|
25,360
|
|
|
|
19,668
|
|
Preferred stock dividends
|
|
|
|
|
|
|
(45
|
)
|
|
|
(1,244
|
)
|
Effect of induced conversion of preferred stock
|
|
|
|
|
|
|
|
|
|
|
11,601
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income applicable to common shareholders
|
|
$
|
278,702
|
|
|
$
|
25,315
|
|
|
$
|
30,025
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
|
|
$
|
3.52
|
|
|
$
|
0.39
|
|
|
$
|
0.63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares used in basic earnings per share
|
|
|
79,206
|
|
|
|
64,316
|
|
|
|
47,287
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
|
|
$
|
3.46
|
|
|
$
|
0.38
|
|
|
$
|
0.59
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares used in diluted earnings per share
|
|
|
80,587
|
|
|
|
66,309
|
|
|
|
50,729
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
CONCHO
RESOURCES INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivable
|
|
|
Retained
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
6% Series A
|
|
|
|
|
|
|
|
|
Additional
|
|
|
from
|
|
|
Earnings
|
|
|
Comprehensive
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Preferred Stock
|
|
|
Common Stock
|
|
|
Paid-in
|
|
|
Officers and
|
|
|
(Accumulated
|
|
|
Income
|
|
|
Treasury Stock
|
|
|
Stockholders
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Employees
|
|
|
Deficit)
|
|
|
(Loss)
|
|
|
Shares
|
|
|
Amount
|
|
|
Equity
|
|
|
|
(In thousands)
|
|
|
BALANCE AT DECEMBER 31, 2005
|
|
|
12,959
|
|
|
$
|
130
|
|
|
|
8,142
|
|
|
$
|
8
|
|
|
$
|
135,876
|
|
|
$
|
(9,012
|
)
|
|
$
|
(6,272
|
)
|
|
$
|
(11,060
|
)
|
|
|
|
|
|
$
|
|
|
|
$
|
109,670
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,668
|
|
Deferred hedge gains, net of tax of $4,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,736
|
|
|
|
|
|
|
|
|
|
|
|
7,736
|
|
Net settlement losses included in earnings, net of taxes of
$2,030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,738
|
|
|
|
|
|
|
|
|
|
|
|
3,738
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31,142
|
|
Issuance of subscribed units
|
|
|
4,518
|
|
|
|
45
|
|
|
|
2,259
|
|
|
|
2
|
|
|
|
45,329
|
|
|
|
(3,158
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,218
|
|
Issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
578
|
|
|
|
1
|
|
|
|
577
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
578
|
|
Conversion of preferred stock
|
|
|
(17,477
|
)
|
|
|
(175
|
)
|
|
|
13,106
|
|
|
|
13
|
|
|
|
162
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock for acquisition
|
|
|
|
|
|
|
|
|
|
|
34,795
|
|
|
|
35
|
|
|
|
384,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
384,336
|
|
Stock-based compensation for restricted stock
|
|
|
|
|
|
|
|
|
|
|
214
|
|
|
|
|
|
|
|
1,044
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,044
|
|
Cancellation of restricted stock
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation for stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,125
|
|
Stock-based compensation on issuance of units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
975
|
|
Accrued interest officer and employee notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(688
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(688
|
)
|
6% Series A preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,244
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,244
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2006
|
|
|
|
|
|
|
|
|
|
|
59,093
|
|
|
|
59
|
|
|
|
575,389
|
|
|
|
(12,858
|
)
|
|
|
12,152
|
|
|
|
414
|
|
|
|
|
|
|
|
|
|
|
|
575,156
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,360
|
|
Deferred hedge losses, net of taxes of $13,204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20,579
|
)
|
|
|
|
|
|
|
|
|
|
|
(20,579
|
)
|
Net settlement losses included in earnings, net of taxes of
$3,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,970
|
|
|
|
|
|
|
|
|
|
|
|
5,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,751
|
|
Stock-based compensation for restricted stock
|
|
|
|
|
|
|
|
|
|
|
138
|
|
|
|
|
|
|
|
1,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,378
|
|
Cancellation of restricted stock
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation for stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,463
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,463
|
|
Amendment of certain outstanding stock options due to 409A
modification
|
|
|
|
|
|
|
|
|
|
|
83
|
|
|
|
|
|
|
|
(192
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(192
|
)
|
Issuance of common stock for acquisition obligation
|
|
|
|
|
|
|
|
|
|
|
54
|
|
|
|
|
|
|
|
650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
650
|
|
Net proceeds from initial public equity offering
|
|
|
|
|
|
|
|
|
|
|
16,466
|
|
|
|
17
|
|
|
|
172,692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
172,709
|
|
Proceeds from notes receivable officers and employees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,830
|
|
Accrued interest officer and employee notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(302
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(302
|
)
|
6% Series A preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2007
|
|
|
|
|
|
|
|
|
|
|
75,832
|
|
|
|
76
|
|
|
|
752,380
|
|
|
|
(330
|
)
|
|
|
37,467
|
|
|
|
(14,195
|
)
|
|
|
|
|
|
|
|
|
|
|
775,398
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
278,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
278,702
|
|
Deferred hedge losses, net of taxes of $3,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,864
|
)
|
|
|
|
|
|
|
|
|
|
|
(4,864
|
)
|
Net settlement losses included in earnings, net of taxes of
$12,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,059
|
|
|
|
|
|
|
|
|
|
|
|
19,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
292,897
|
|
Issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
8,303
|
|
|
|
8
|
|
|
|
242,418
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
242,426
|
|
Stock options exercised
|
|
|
|
|
|
|
|
|
|
|
612
|
|
|
|
1
|
|
|
|
5,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,391
|
|
Stock-based compensation for restricted stock
|
|
|
|
|
|
|
|
|
|
|
128
|
|
|
|
|
|
|
|
2,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,122
|
|
Cancellation of restricted stock
|
|
|
|
|
|
|
|
|
|
|
(46
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation for stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,101
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,101
|
|
Excess tax benefits related to stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,614
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,614
|
|
Proceeds from notes receivable employees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
333
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
333
|
|
Accrued interest employee notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
(125
|
)
|
|
|
(125
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2008
|
|
|
|
|
|
$
|
|
|
|
|
84,829
|
|
|
$
|
85
|
|
|
$
|
1,009,025
|
|
|
$
|
|
|
|
$
|
316,169
|
|
|
$
|
|
|
|
|
3
|
|
|
$
|
(125
|
)
|
|
$
|
1,325,154
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
CONCHO
RESOURCES INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
278,702
|
|
|
$
|
25,360
|
|
|
$
|
19,668
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
123,912
|
|
|
|
76,779
|
|
|
|
60,722
|
|
Impairments of long-lived assets
|
|
|
18,417
|
|
|
|
7,267
|
|
|
|
9,891
|
|
Accretion of discount on asset retirement obligations
|
|
|
889
|
|
|
|
444
|
|
|
|
287
|
|
Exploration expense, including dry holes
|
|
|
35,328
|
|
|
|
25,009
|
|
|
|
3,387
|
|
Non-cash compensation expense
|
|
|
5,223
|
|
|
|
3,841
|
|
|
|
9,144
|
|
Deferred income taxes
|
|
|
153,484
|
|
|
|
13,716
|
|
|
|
12,618
|
|
Gain on sale of assets
|
|
|
(777
|
)
|
|
|
(368
|
)
|
|
|
(3
|
)
|
Ineffective portion of cash flow hedges
|
|
|
(1,336
|
)
|
|
|
821
|
|
|
|
(1,193
|
)
|
(Gain) loss on derivatives not designated as hedges
|
|
|
(249,870
|
)
|
|
|
20,274
|
|
|
|
|
|
Dedesignated cash flow hedges reclassified from accumulated
other comprehensive income (loss)
|
|
|
696
|
|
|
|
(1,103
|
)
|
|
|
|
|
Other non-cash items
|
|
|
6,517
|
|
|
|
3,376
|
|
|
|
1,150
|
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
42,514
|
|
|
|
(5,759
|
)
|
|
|
(27,683
|
)
|
Prepaid costs and other
|
|
|
(5,542
|
)
|
|
|
(169
|
)
|
|
|
(2,162
|
)
|
Inventory
|
|
|
(16,819
|
)
|
|
|
(150
|
)
|
|
|
(291
|
)
|
Accounts payable
|
|
|
(25,234
|
)
|
|
|
(3,493
|
)
|
|
|
13,853
|
|
Revenue payable
|
|
|
7,074
|
|
|
|
4,593
|
|
|
|
2,372
|
|
Other current liabilities
|
|
|
18,219
|
|
|
|
(669
|
)
|
|
|
10,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
391,397
|
|
|
|
169,769
|
|
|
|
112,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures on oil and gas properties
|
|
|
(347,702
|
)
|
|
|
(162,378
|
)
|
|
|
(182,389
|
)
|
Acquisition of oil and gas properties, businesses and other
assets
|
|
|
(584,220
|
)
|
|
|
(255
|
)
|
|
|
(413,229
|
)
|
Additions to other property and equipment
|
|
|
(8,808
|
)
|
|
|
(2,813
|
)
|
|
|
(1,234
|
)
|
Proceeds from the sale of oil and gas properties and other assets
|
|
|
1,034
|
|
|
|
3,278
|
|
|
|
|
|
Settlements received (paid) on derivatives not designated as
hedges
|
|
|
(6,354
|
)
|
|
|
1,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(946,050
|
)
|
|
|
(160,353
|
)
|
|
|
(596,852
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt
|
|
|
767,800
|
|
|
|
300,200
|
|
|
|
664,993
|
|
Payments of long-term debt
|
|
|
(465,700
|
)
|
|
|
(468,800
|
)
|
|
|
(241,493
|
)
|
Exercise of stock options
|
|
|
5,391
|
|
|
|
|
|
|
|
|
|
Excess tax benefit from stock-based compensation
|
|
|
3,614
|
|
|
|
|
|
|
|
|
|
Net proceeds from issuance of common stock
|
|
|
242,426
|
|
|
|
172,709
|
|
|
|
61,178
|
|
Payments of preferred stock dividends
|
|
|
|
|
|
|
(132
|
)
|
|
|
(2,567
|
)
|
Proceeds from repayment of officer and employee notes
|
|
|
333
|
|
|
|
12,830
|
|
|
|
|
|
Payments for loan origination costs
|
|
|
(15,541
|
)
|
|
|
(2,572
|
)
|
|
|
(5,500
|
)
|
Purchase of treasury stock
|
|
|
(125
|
)
|
|
|
|
|
|
|
|
|
Bank overdrafts
|
|
|
3,783
|
|
|
|
5,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
541,981
|
|
|
|
19,886
|
|
|
|
476,611
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(12,672
|
)
|
|
|
29,302
|
|
|
|
(8,060
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
30,424
|
|
|
|
1,122
|
|
|
|
9,182
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
17,752
|
|
|
$
|
30,424
|
|
|
$
|
1,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL CASH FLOWS:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest and fees, net of $1,233, $2,647 and
$2,129 capitalized interest
|
|
$
|
27,747
|
|
|
$
|
41,036
|
|
|
$
|
23,882
|
|
Cash paid for income taxes
|
|
$
|
11,304
|
|
|
$
|
2,050
|
|
|
$
|
1,725
|
|
NON-CASH INVESTING AND FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock in acquisition of oil and gas
properties and other assets
|
|
$
|
|
|
|
$
|
650
|
|
|
$
|
384,336
|
|
Deferred tax effect of acquired oil and gas properties
|
|
$
|
206,497
|
|
|
$
|
(444
|
)
|
|
$
|
227,735
|
|
Issuance of notes receivable in connection with capital options
|
|
$
|
|
|
|
$
|
|
|
|
$
|
3,158
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-6
CONCHO
RESOURCES INC.
December 31,
2008, 2007 and 2006
|
|
Note A.
|
Organization
and nature of operations
|
Concho Resources Inc. (Resources) is a Delaware
corporation formed by Concho Equity Holdings Corp.
(CEHC) on February 22, 2006, for purposes of
effecting the combination of CEHC, Chase Oil Corporation, Caza
Energy LLC (Caza) and certain other parties thereto
(collectively with Chase Oil Corporation and Caza, the
Chase Group). Pursuant to the Combination Agreement
dated February 24, 2006, Resources acquired working
interests in oil and natural gas properties in Southeastern New
Mexico from the Chase Group (the Chase Group
Properties) and issued shares of Resources common stock to
certain stockholders of CEHC in exchange for their capital stock
of CEHC. CEHC is a Delaware corporation formed on April 21,
2004 by certain members of Resources management team and
private equity investors. CEHC commenced substantial oil and gas
operations in December 2004 upon its acquisition of oil and gas
properties located in Southeastern New Mexico and West Texas.
The combination transaction described above (the
Combination) was accounted for as an acquisition by
CEHC of the Chase Group Properties and a simultaneous
reorganization of Resources such that CEHC is now a wholly-owned
subsidiary of Resources. Prior to the Combination, Resources had
no assets, operations or net equity. Upon the closing of the
Combination, the executive officers of CEHC became the executive
officers of Resources. Resources and its wholly-owned
subsidiaries are collectively referred to herein as the
Company.
In the Combination, CEHCs shareholders received
23,767,691 shares of common stock of the Company in
exchange for their preferred and common shares of CEHC,
excluding eighteen holders owning an aggregate of
254,621 shares of CEHC 6% Series A Preferred
Stock and 127,313 shares of CEHC common stock, as discussed
in Note F. In addition, the Chase Group transferred the
Chase Group Properties to the Company in exchange for cash in
the aggregate amount of approximately $409 million and
34,794,638 shares of the Companys common stock. In
connection with the Companys initial public offering and
secondary public offering (see Note F), the Chase Group
sold a total of 18,638,014 shares of the Companys
common stock. At December 31, 2008 and December 31,
2007, the Chase Group owned approximately 9 percent and
21 percent, respectively, of the total outstanding common
stock of the Company.
The Companys principal business is the acquisition,
development, exploitation and exploration of oil and gas
properties in the Permian Basin region of Southeastern New
Mexico and West Texas.
|
|
Note B.
|
Summary
of significant accounting policies
|
Principles of consolidation. The
consolidated financial statements of the Company include the
accounts of the Company and its wholly-owned subsidiaries,
including CEHC. 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 gas properties are determined
using estimates of proved oil and 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 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,
purchase price allocations for business and oil and gas property
acquisitions and fair value of stock-based compensation.
Cash equivalents. The Company considers
all cash on hand, depository accounts held by banks, money
market accounts and investments with an original maturity of
three months or less to be cash equivalents. The
F-7
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Companys cash and cash equivalents are held in a few
financial institutions in amounts that exceed the insurance
limits of the Federal Deposit Insurance Corporation. However,
management believes that the Companys counterparty risks
are minimal based on the reputation and history of the
institutions selected.
Accounts receivable. The Company sells
oil and gas to various customers and participates with other
parties in the drilling, completion and operation of oil and gas
wells. Joint interest and oil and gas sales receivables related
to these operations are generally unsecured. The Company
determines joint interest operations accounts receivable
allowances based on managements assessment of the
creditworthiness of the joint interest owners and the
Companys ability to realize the receivables through
netting of anticipated future production revenues. Receivables
are considered past due if full payment is not received by the
contractual due date. Past due accounts are generally written
off against the allowance for doubtful accounts only after all
collection attempts have been exhausted. The Company had an
allowance for doubtful accounts of approximately
$2.9 million and none at December 31, 2008 and 2007,
respectively, and the Company did not write off any receivables
against the allowance for doubtful accounts in 2008, 2007 or
2006.
Assets held for sale. The Company
capitalizes the costs of acquiring oil and gas leaseholds held
for resale, including lease bonuses and any advance rentals
required at the time of assignment of the lease to the Company.
Advance rentals paid after assignment are charged to expense as
carrying costs in the period incurred. Costs of oil and gas
leases held for resale are valued at lower of cost or net
realizable value and included in current assets since they could
be sold within one year, although the holding period of
individual leases may be in excess of one year. The cost of oil
and gas leases sold is determined on a specific identification
basis.
Inventory. Inventory consists primarily
of tubular goods that the Company plans to utilize in its
ongoing exploration and development activities and is carried at
the lower of cost or market value, on a weighted average cost
basis.
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 $15.7 million and
$3.4 million, net of accumulated amortization of
$3.3 million and $3.6 million, at December 31,
2008 and December 31, 2007, respectively.
Future amortization expense of deferred loan costs at
December 31, 2008 is as follows:
|
|
|
|
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
2009
|
|
$
|
3,426
|
|
2010
|
|
|
3,426
|
|
2011
|
|
|
3,426
|
|
2012
|
|
|
3,426
|
|
2013
|
|
|
1,997
|
|
|
|
|
|
|
Total
|
|
$
|
15,701
|
|
|
|
|
|
|
Oil and gas properties. The Company
utilizes the successful efforts method of accounting for its oil
and gas properties under the provisions of Financial Accounting
Standards Board (FASB) Statement of Financial
Accounting Standards (SFAS) No. 19,
Financial Accounting and Reporting by Oil and Gas
Producing Companies. Under this method all costs
associated with productive wells and nonproductive development
wells are capitalized, while nonproductive exploration costs are
expensed. Capitalized acquisition costs relating to proved
properties are depleted using the unit-of-production method
based on proved reserves. The depletion of capitalized
exploratory drilling and development costs is based on the
unit-of-production method using proved developed reserves on a
field basis.
F-8
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The Company generally does not carry the costs of drilling an
exploratory well as an asset in its Consolidated Balance Sheets
for more than one year following the completion of drilling
unless the exploratory well finds oil and gas reserves in an
area requiring a major capital expenditure and both of the
following conditions are met:
(i) The well has found a sufficient quantity of reserves to
justify its completion as a producing well.
(ii) The Company is making sufficient progress assessing
the reserves and the economic and operating viability of the
project.
Due to the capital intensive nature and the geographical
location of certain projects, it may take the Company longer
than one year to evaluate the future potential of the
exploration well and economics associated with making a
determination on its commercial viability. In these instances,
the projects feasibility is not contingent upon price
improvements or advances in technology, but rather the
Companys ongoing efforts and expenditures related to
accurately predicting the hydrocarbon recoverability based on
well information, gaining access to other companies
production, transportation or processing facilities
and/or
getting partner approval to drill additional appraisal wells.
These activities are ongoing and being pursued constantly.
Consequently, the Companys assessment of suspended
exploratory well costs is continuous until a decision can be
made that the well has found proved reserves or is noncommercial
and is charged to exploration and abandonments expense. See
Note C for additional information regarding the
Companys suspended exploratory well costs.
Proceeds from the sales of individual properties and the
capitalized costs of individual properties sold or abandoned are
credited and charged, respectively, to accumulated depletion.
Generally, no gain or loss is recognized until the entire
amortization base is sold. However, gain or loss is recognized
from the sale of less than an entire amortization base if the
disposition is significant enough to materially impact the
depletion rate of the remaining properties in the amortization
base. Ordinary maintenance and repair costs are expensed as
incurred.
Costs of significant nonproducing properties, wells in the
process of being drilled and development projects are excluded
from depletion until such time as the related project is
developed and proved reserves are established or impairment is
determined. The Company capitalizes interest, if debt is
outstanding, on expenditures for significant development
projects until such projects are ready for their intended use.
At December 31, 2008 and 2007 the Company had excluded
$27.8 million and $19.0 million, respectively, of
capitalized costs from depletion and had capitalized interest of
$1.2 million, $2.6 million and $2.1 million,
during 2008, 2007 and 2006, respectively.
In accordance with SFAS No. 144, Accounting for
the Impairment or Disposal of Long-Lived Assets, the
Company reviews its long-lived assets to be held and used,
including proved oil and gas properties, whenever events or
circumstances indicate that the carrying value of those assets
may not be recoverable. An impairment loss is indicated if the
sum of the expected future cash flows is less than the carrying
amount of the assets. In this circumstance, the Company
recognizes an impairment loss for the amount by which the
carrying amount of the asset exceeds the estimated fair value of
the asset. The Company reviews its oil and gas properties by
amortization base or by individual well for those wells not
constituting part of an amortization base. For each property
determined to be impaired, an impairment loss equal to the
difference between the carrying value of the properties and the
estimated fair value (discounted future cash flows) of the
properties would be recognized at that time. Estimating future
cash flows involves the use of judgments, including estimation
of the proved and unproved oil and gas reserve quantities,
timing of development and production, expected future commodity
prices, capital expenditures and production costs. The Company
recognized impairment expense of $18.4 million,
$7.3 million and $9.9 million during the years ended
December 31, 2008, 2007 and 2006, respectively, related to
its proved oil and gas properties.
Unproved oil and gas properties are each periodically assessed
for impairment by considering future drilling plans, the results
of exploration activities, commodity price outlooks, planned
future sales or expiration of all or a portion of such projects.
During the years ended December 31, 2008, 2007 and 2006,
the Company recognized expense of $31.6 million,
$3.1 million and $0.2 million, respectively, related
to abandoned prospects, which is included in exploration and
abandonments in the accompanying consolidated statements of
operations.
F-9
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Other property and equipment. Other
capital assets include buildings, vehicles, computer equipment
and software, telecommunications equipment, leasehold
improvements and furniture and fixtures. These items are
recorded at cost and are depreciated using the straight-line
method based on expected lives of the individual assets or group
of assets ranging from two to 15 years.
Intangible assets. The Company has
capitalized certain operating rights acquired in an acquisition,
see Note D. The gross operating rights of approximately
$38.4 million, which have no residual value, are amortized
over the estimated economic life of approximately 25 years.
Impairment will be assessed if indicators of potential
impairment exist or when there is a material change in the
remaining useful economic life. Amortization expense for the
year ended December 31, 2008 was approximately
$0.6 million. The following table reflects the estimated
aggregate amortization expense for each of the periods presented
below:
|
|
|
|
|
|
|
(In Thousands)
|
|
|
2009
|
|
$
|
1,536
|
|
2010
|
|
|
1,536
|
|
2011
|
|
|
1,536
|
|
2012
|
|
|
1,536
|
|
2013
|
|
|
1,536
|
|
Thereafter
|
|
|
30,088
|
|
|
|
|
|
|
Total
|
|
$
|
37,768
|
|
|
|
|
|
|
Environmental. The Company is subject
to extensive Federal, state and local environmental laws and
regulations. These laws, which are often changing, regulate the
discharge of materials into the environment and may require the
Company to remove or mitigate the environmental effects of the
disposal or release of petroleum or chemical substances at
various sites. Environmental expenditures are expensed.
Expenditures that relate to an existing condition caused by past
operations and that have no future economic benefits are
expensed. Liabilities for expenditures of a noncapital nature
are recorded when environmental assessment
and/or
remediation is probable and the costs can be reasonably
estimated. Such liabilities are generally undiscounted unless
the timing of cash payments is fixed and readily determinable.
Management believes no material liabilities of this nature
existed at December 31, 2008 or 2007.
Oil and gas sales and imbalances. Oil
and gas revenues are recorded at the time of delivery of such
products to pipelines for the account of the purchaser or at the
time of physical transfer of such products to the purchaser. The
Company follows the sales method of accounting for oil and gas
sales, recognizing revenues based on the Companys share of
actual proceeds from the oil and gas sold to purchasers. Oil and
gas imbalances are generated on properties for which two or more
owners have the right to take production in-kind
and, in doing so, take more or less than their respective
entitled percentage. Imbalances are tracked by well, but the
Company does not record any receivable from or payable to the
other owners unless the imbalance has reached a level at which
it exceeds the remaining reserves in the respective well. If
reserves are insufficient to offset the imbalance and the
Company is in an overtake position, a liability is recorded for
the amount of shortfall in reserves valued at a contract price
or the market price in effect at the time the imbalance is
generated. If the Company is in an undertake position, a
receivable is recorded for an amount that is reasonably expected
to be received, not to exceed the current market value of such
imbalance.
F-10
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table reflects the Companys gas imbalance
positions at December 31, 2008 and 2007 as well as amounts
reflected in oil and gas production expense for the years ended
December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2008
|
|
2007
|
|
|
(Dollars in thousands)
|
|
Gas imbalance liability (included in asset retirement
obligations and other long-term liabilities)
|
|
$
|
472
|
|
|
$
|
621
|
|
Overtake position (Mcf)
|
|
|
85,698
|
|
|
|
96,215
|
|
Gas imbalance receivable (included in other assets)
|
|
$
|
406
|
|
|
$
|
367
|
|
Undertake position (Mcf)
|
|
|
90,321
|
|
|
|
81,569
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2008
|
|
2007
|
|
Value of net undertake arising during the year (reducing oil and
gas production expense)
|
|
$
|
189
|
|
|
$
|
14
|
|
Net undertake position arising during the year (Mcf)
|
|
|
19,269
|
|
|
|
4,264
|
|
Derivative instruments and hedging. The
Company applies the provisions of SFAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities, as amended. This statement requires the
recognition of all derivative instruments as either assets or
liabilities measured at fair value. The Company netted the fair
value of derivative instruments by counterparty in the
accompanying consolidated balance sheets where the right of
offset exists as permitted by FASB Interpretation
(FIN) No. 39, Offsetting of Amounts
Related to Certain Contracts.
Under the provisions of SFAS No. 133, the Company may
designate a derivative instrument as hedging the exposure to
changes in the fair value of an asset or a liability or an
identified portion thereof that is attributable to a particular
risk (a fair value hedge) or as hedging the exposure
to variability in expected future cash flows that are
attributable to a particular risk (a cash flow
hedge). Special accounting for qualifying hedges allows
the effective portion of a derivative instruments gains
and losses to offset related results on the hedged item in the
statement of operations and requires that a company formally
document, designate and assess the effectiveness of the
transactions that receive hedge accounting treatment. Both at
the inception of a hedge and on an ongoing basis, a hedge must
be expected to be highly effective in achieving offsetting
changes in fair value or cash flows attributable to the
underlying risk being hedged. If the Company determines that a
derivative instrument is no longer highly effective as a hedge,
it discontinues hedge accounting prospectively and future
changes in the fair value of the derivative are recognized in
current earnings. The amount already reflected in accumulated
other comprehensive (loss) income (AOCI) remains
there until the hedged item affects earnings or it is probable
that the hedged item will not occur by the end of the originally
specified time period or within two months thereafter. The
Company assesses and measures hedge effectiveness at the end of
each quarter.
In accordance with SFAS No. 133, changes in the fair
value of derivative instruments that are fair value hedges are
offset against changes in the fair value of the hedged assets,
liabilities or firm commitments, through earnings. Effective
changes in the fair value of derivative instruments that are
cash flow hedges are recognized in AOCI and reclassified into
earnings in the period in which the hedged item affects
earnings. Ineffective portions of a derivative instruments
change in fair value are immediately recognized in earnings.
Derivative instruments that do not qualify, or cease to qualify,
as hedges must be adjusted to fair value and the adjustments are
recorded through net income.
Asset retirement obligations. The
Company accounts for the obligations in accordance with
SFAS No. 143, Asset Retirement
Obligations. SFAS No. 143 requires entities to
record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related
long-lived asset. Subsequently, the asset retirement cost
included in the carrying amount of the related asset
F-11
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
is allocated to expense through depreciation of the asset.
Changes in the liability due to passage of time are recognized
as an increase in the carrying amount of the liability and as
corresponding accretion expense.
Treasury stock. Treasury stock
purchases are recorded at cost. Upon reissuance, the cost of
treasury shares held is reduced by the average purchase price
per share of the aggregate treasury shares held.
General and administrative expense. The
Company receives fees for the operation of jointly owned oil and
gas properties and records such reimbursements as reductions of
general and administrative expense. Such fees totaled
approximately $4.9 million, $1.1 million and
$0.8 million for the years ended December 31, 2008,
2007 and 2006, respectively.
Stock-based compensation. The Company
applies the provisions of SFAS No. 123R, Share
Based Payment, to transactions in which the Company
exchanges its equity instruments for employee services, and
transactions in which the Company incurs liabilities that are
based on the fair value of the Companys equity instruments
or that may be settled by the issuance of those equity
instruments in exchange for employee services. The cost of
employee services received in exchange for equity instruments,
including employee stock options, is measured based on the
grant-date fair value of those instruments. That cost is
recognized as compensation expense over the requisite service
period (generally the vesting period). Generally, no
compensation cost is recognized for equity instruments that do
not vest.
Income taxes. The Company accounts for
income taxes in accordance with the provisions of
SFAS No. 109, Accounting for Income Taxes.
Under the asset and liability method of SFAS No. 109,
deferred tax assets and liabilities are recognized for the
future tax consequences attributable to differences between the
financial statement carrying amounts of existing assets and
liabilities and their respective tax bases. Deferred tax assets
and liabilities are measured using enacted tax rates expected to
apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. Under
SFAS No. 109, the effect on deferred tax assets and
liabilities of a change in tax rate is recognized in income in
the period that includes the enactment date. A valuation
allowance is established to reduce deferred tax assets if it is
more likely than not that the related tax benefits will not be
realized.
The Company adopted the provisions of FIN No. 48,
Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109, on
January 1, 2007. FIN No. 48 clarifies the
accounting for uncertainty in income taxes recognized in an
enterprises financial statements in accordance with
SFAS No. 109 and prescribes a recognition threshold
and measurement process for financial statement recognition and
measurement of a tax position taken or expected to be taken in a
tax return. FIN No. 48 also provides guidance on
derecognition, classification, interest and penalties,
accounting in interim periods, disclosure and transition.
Reclassifications. Certain prior period
amounts have been reclassified to conform to the 2008
presentation. These reclassifications had no impact on net
income, total stockholders equity or cash flows.
Recent accounting pronouncements. In
February 2007, the FASB issued SFAS No. 159,
The Fair Value Option for Financial Assets and
Financial Liabilities, Including an Amendment of FASB Statement
No. 115, which became effective in 2008.
SFAS No. 159 permits entities to measure eligible
financial assets, financial liabilities and firm commitments at
fair value, on an
instrument-by-instrument
basis, that are otherwise not permitted to be accounted for at
fair value under other generally accepted accounting principles.
The fair value measurement election is irrevocable and
subsequent changes in fair value must be recorded in earnings.
The Company adopted this statement January 1, 2008 and did
not elect the fair value option for any of its eligible
financial instruments or other items. As such, the adoption had
no impact on the consolidated financial statements.
In April 2007, the FASB issued FASB Staff Position
FIN 39-1,
Amendment of FASB Interpretation No. 39
(FIN No. 39-1).
FIN No. 39-1
clarifies that a reporting entity that is party to a master
netting arrangement can offset fair value amounts recognized for
the right to reclaim cash collateral (a receivable) or the
obligation to return cash collateral (a payable) against fair
value amounts recognized for derivative instruments that have
been offset
F-12
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
under the same master netting arrangement.
FIN No. 39-1
is effective for financial statements issued for fiscal years
beginning after November 15, 2007. Adoption of
FIN No. 39-1
has not had a material impact on the Companys consolidated
financial statements.
In June 2007, the FASB ratified a consensus opinion reached by
the Emerging Issues Task Force (EITF) on EITF Issue
06-11,
Accounting for Income Tax Benefits of Dividends on
Share-Based Payment Awards. EITF Issue
06-11
requires an employer to recognize tax benefits realized from
dividend or dividend equivalents paid to employees for certain
share-based payment awards as an increase to additional paid-in
capital and include such amounts in the pool of excess tax
benefits available to absorb future tax deficiencies on
share-based payment awards. If an entitys estimate of
forfeitures increases (or actual forfeitures exceed the
entitys estimates), or if an award is no longer expected
to vest, entities should reclassify the dividends or dividend
equivalents paid on that award from retained earnings to
compensation cost. However, the tax benefits from dividends that
are reclassified from additional paid-in capital to the income
statement are limited to the entitys pool of excess tax
benefits available to absorb tax deficiencies on the date of
reclassification. The consensus in EITF Issue
06-11 is
effective for fiscal years, and interim periods within those
fiscal years, beginning after December 15, 2007.
Retrospective application of EITF Issue
06-11 is not
permitted. Early adoption is permitted; however, the Company did
not adopt EITF Issue
06-11 until
the required effective date of January 1, 2008. The
adoption of EITF Issue
06-11 has
not had a significant effect on the Companys financial
statements since the Company historically has accounted for the
income tax benefits of dividends paid for share-based payment
awards in the manner described in the consensus.
In December 2007, the FASB issued SFAS No. 141
(revised 2007), Business Combinations
(SFAS No. 141(R)), which replaces FASB
Statement No. 141. SFAS No. 141(R) establishes
principles and requirements for how an acquirer recognizes and
measures in its financial statements the identifiable assets
acquired, the liabilities assumed, any non-controlling interest
in the acquiree and the goodwill acquired.
SFAS No. 141(R) also establishes disclosure
requirements that will enable users to evaluate the nature and
financial effects of the business combination.
SFAS No. 141(R) is effective for acquisitions that
occur in an entitys fiscal year that begins after
December 15, 2008, which will be our fiscal year 2009. The
impact, if any, will depend on the nature and size of business
combinations the Company consummates after the effective date.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statements an amendment of ARB
No. 51. SFAS No. 160 requires that
accounting and reporting for minority interests will be
recharacterized as noncontrolling interests and classified as a
component of equity. SFAS No. 160 also establishes
reporting requirements that provide sufficient disclosures that
clearly identify and distinguish between the interests of the
parent and the interests of the noncontrolling owners.
SFAS No. 160 applies to all entities that prepare
consolidated financial statements, except not-for-profit
organizations, but will affect only those entities that have an
outstanding noncontrolling interest in one or more subsidiaries
or that deconsolidate a subsidiary. This statement is effective
as of the beginning of an entitys first fiscal year
beginning after December 15, 2008, which will be the
Companys fiscal year 2009. Based upon the Companys
December 31, 2008 consolidated balance sheet, the statement
would have no impact.
In December 2007, the SEC issued Staff Accounting Bulletin
(SAB) No. 110, Share-Based
Payment (SAB No. 110).
SAB No. 110 amends SAB No. 107,
Share-Based Payment, and allows for the
continued use, under certain circumstances, of the simplified
method in developing an estimate of the expected term on stock
options accounted for under SFAS No. 123R,
Share-Based Payment (revised 2004).
SAB No. 110 is effective for stock options granted
after December 31, 2007. The Company continued to use the
simplified method in developing an estimate of the expected term
on stock options granted in 2008. The Company does not have
sufficient historical exercise data to provide a reasonable
basis upon which to estimate expected term due to the limited
period of time the Companys shares of common stock have
been publicly traded.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities, which amends and expands the disclosure
requirements of SFAS No. 133 to provide an enhanced
understanding of an entitys use of derivative instruments,
how they are accounted for under SFAS No. 133 and
their
F-13
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
effect on the entitys financial position, financial
performance and cash flows. The provisions of
SFAS No. 161 are effective as of January 1, 2009.
The Company is currently evaluating the impact on its
consolidated financial statements of adopting
SFAS No. 161.
In April 2008, the FASB issued FASB Staff Position
(FSP)
No. SFAS 142-3,
Determination of the Useful Life of Intangible Assets
(FSP
SFAS No. 142-3).
FSP
SFAS No. 142-3
amends the factors that should be considered in developing
renewal or extension assumptions used to determine the useful
life of a recognized intangible asset under
SFAS No. 142, Goodwill and Other Intangible Assets
(SFAS No. 142). The intent of FSP
SFAS No. 142-3
is to improve the consistency between the useful life of a
recognized intangible asset under SFAS No. 142 and the
period of expected cash flows used to measure the fair value of
the asset under SFAS No. 141R and other applicable
accounting literature. FSP
SFAS No. 142-3
is effective for financial statements issued for
fiscal years beginning after December 15, 2008 and must be
applied prospectively to intangible assets acquired after the
effective date. The Company is currently evaluating the
potential impact, if any, of FSP
SFAS No. 142-3
on its financial statements.
In May 2008, the FASB issued SFAS No. 162,
The Hierarchy of Generally Accepted Accounting
Principles, which identifies the sources of accounting
principles and the framework for selecting the principles used
in the preparation of financial statements of nongovernmental
entities that are presented in conformity with generally
accepted accounting principles (GAAP) in the United
States of America. This statement is effective 60 days
following the SECs approval of the Public Company
Accounting Oversight Board amendments to AU Section 411,
The Meaning of Present Fairly in Conformity with
Generally Accepted Accounting Principles. The Company
does not expect the adoption of SFAS No. 162 to have
an impact on its consolidated financial statements.
In June 2008, the FASB issued Staff Position
No. EITF 03-6-1
Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating Securities,
(FSP
EITF 03-6-1)
which provides that unvested share-based payment awards that
contain non-forfeitable rights to dividends or dividend
equivalents (whether paid or unpaid) are participating
securities and, therefore, need to be included in the earnings
allocation in computing earnings per share under the two class
method. FSP
EITF 03-6-1
was effective for us on January 1, 2009 and all
prior-period EPS data (including any amounts related to interim
periods, summaries of earnings and selected financial data) will
be adjusted retroactively to conform to its provisions. Early
application of FSP
EITF 03-6-1
is not permitted. Although restricted stock awards meet this
definition, the Company does not expect the application of FSP
EITF 03-6-1
to have a significant impact on its reported earnings per share.
In October 2008, the FASB issued FSP
No. SFAS 157-3,
Determining the Fair Value of a Financial Asset When
the Market for That Asset is Not Active. FSP
No. SFAS 157-3
clarifies the application of SFAS No. 157 as it
relates to the valuation of financial assets in a market that is
not active for those financial assets. This FSP is effective
immediately and includes those periods for which financial
statements have not been issued. The Company currently does not
have any financial assets that are valued using inactive
markets, and as a result, the Company is not impacted by the
issuance of FSP
No. SFAS 157-3.
Recent developments in reserve
reporting. The United States Securities and
Exchange Commission (SEC) recently approved new
disclosure rules that allow oil and natural gas companies to
more accurately report their assets in terms of volumes and
values that investors can understand and use to make informed
decisions. The new reporting requirement is effective on
December 15, 2009. The new disclosure requirements include
provisions that:
|
|
|
|
|
permit the use of new technologies to determine proved reserves
if those technologies have been demonstrated empirically to lead
to reliable conclusions about reserves volumes;
|
|
|
|
allow companies to disclose in SEC filed documents their
probable and possible reserves to investors (currently, the SEC
rules limit disclosure to only proved reserves);
|
|
|
|
require companies to report the independence and qualifications
of a reserves preparer or auditor;
|
F-14
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
file reports when a third party is relied upon to prepare
reserves estimates or conducts a reserves audit; and
|
|
|
|
report oil and gas reserves using an average price based upon
the prior
12-month
period rather than year-end prices.
|
The Company is currently evaluating the impact these new reserve
reporting requirements will have on its consolidated financial
statements.
|
|
Note C.
|
Exploratory
well costs
|
The Company capitalizes exploratory well costs until a
determination is made that the well has either found proved
reserves or that it is impaired. The capitalized exploratory
well costs are presented in unproved properties in the
Consolidated Balance Sheets. If the exploratory well is
determined to be impaired, the well costs are charged to expense.
The following table reflects the Companys capitalized
exploratory well activity during each of the years ended
December 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Beginning capitalized exploratory well costs
|
|
$
|
21,056
|
|
|
$
|
26,503
|
|
|
$
|
4,370
|
|
Additions to exploratory well costs pending the determination of
proved reserves
|
|
|
25,621
|
|
|
|
97,368
|
|
|
|
25,170
|
|
Reclassifications due to determination of proved reserves
|
|
|
(18,327
|
)
|
|
|
(95,869
|
)
|
|
|
(2,759
|
)
|
Exploratory well costs charged to expense
|
|
|
(2,797
|
)
|
|
|
(6,946
|
)
|
|
|
(278
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending capitalized exploratory well costs
|
|
$
|
25,553
|
|
|
$
|
21,056
|
|
|
$
|
26,503
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table provides an aging at December 31, 2008
and 2007 of capitalized exploratory well costs based on the date
the drilling was completed:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Wells in drilling progress
|
|
$
|
7,765
|
|
|
$
|
4,199
|
|
Capitalized exploratory well costs that have been capitalized
for a period of one year or less
|
|
|
17,788
|
|
|
|
16,857
|
|
Capitalized exploratory well costs that have been capitalized
for a period greater than one year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalized exploratory well costs
|
|
$
|
25,553
|
|
|
$
|
21,056
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2008, the Company had 18 gross
exploratory wells either drilling or waiting on results from
completion. There are 4 wells in the New Mexico Permian
area, 9 wells in the Texas Permian area, 3 wells in
the Arkoma Basin in Arkansas and 2 wells in the Williston
Basin of North Dakota.
|
|
Note D.
|
Acquisition
and business combination
|
Henry Entities acquisition. On
July 31, 2008, the Company closed our acquisition of Henry
Petroleum LP and certain entities affiliated with Henry
Petroleum LP (which we refer to as Henry or the
Henry Entities) and additional non-operated
interests in oil and gas properties from persons affiliated with
the Henry Entities. In August 2008 and September 2008, we
acquired additional non-operated interests in oil and gas
properties from persons
F-15
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
affiliated with the Henry Entities. The assets acquired in the
Henry Entities acquisition are referred to as the Henry
Properties. The Company paid $584.1 million in cash
for the Henry Properties acquisition.
The cash paid for the Henry Properties acquisition was funded
with (i) borrowings under the Companys credit
facility, see Note J, and (ii) proceeds from a private
placement of approximately 8.3 million shares of the
Companys common stock, see Note F.
The Henry Properties acquisition is being accounted for using
the purchase method of accounting for business combinations.
Under the purchase method of accounting, the Company recorded
the Henry Properties assets and liabilities at fair value.
The purchase price of the acquired Henry Properties net
assets is based on the total value of the cash consideration.
The initial purchase price allocation is preliminary and subject
to adjustment. Any future adjustments to the allocation of the
total purchase price are not anticipated to be material to the
Companys consolidated financial statements.
The following tables represent the preliminary allocation of the
total purchase price of the Henry Properties to the acquired
assets and liabilities of the Henry Properties and the
consideration paid for the Henry Properties. The allocation
represents the fair values assigned to each of the assets
acquired and liabilities assumed:
|
|
|
|
|
|
|
(In thousands)
|
|
|
Fair value of Henry Properties net assets:
|
|
|
|
|
Current assets, net of cash acquired of $19,049(a)
|
|
$
|
86,321
|
|
Proved oil and gas properties
|
|
|
595,005
|
|
Unproved oil and gas properties
|
|
|
233,199
|
|
Other long-term assets
|
|
|
6,977
|
|
Intangible assets operating rights
|
|
|
38,409
|
|
|
|
|
|
|
Total assets acquired
|
|
|
959,911
|
|
|
|
|
|
|
Current liabilities
|
|
|
(113,729
|
)
|
Asset retirement obligations and other long-term liabilities
|
|
|
(7,529
|
)
|
Noncurrent derivative liabilities
|
|
|
(39,037
|
)
|
Deferred tax liability
|
|
|
(215,475
|
)
|
|
|
|
|
|
Total liabilities assumed
|
|
|
(375,770
|
)
|
|
|
|
|
|
Net purchase price
|
|
$
|
584,141
|
|
|
|
|
|
|
Consideration paid for Henry Properties net assets:
|
|
|
|
|
Cash consideration paid, net of cash acquired of $19,049
|
|
$
|
578,491
|
|
Acquisition costs(b)
|
|
|
5,650
|
|
|
|
|
|
|
Total purchase price
|
|
$
|
584,141
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes a deferred tax asset of approximately $9.0 million. |
|
(b) |
|
Estimated acquisition costs include legal and accounting fees,
advisory fees and other acquisition-related costs. |
F-16
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following unaudited pro forma combined condensed financial
data for the years ended December 31, 2008 and 2007 was
derived from the historical financial statements of the Company
and Henry Properties giving effect to the acquisition as if it
had occurred on January 1 of each period. The unaudited pro
forma combined condensed financial data has been included for
comparative purposes only and is not necessarily indicative of
the results that might have occurred had the Henry Properties
acquisition taken place as of the dates indicated and is not
intended to be a projection of future results.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2008
|
|
2007
|
|
|
(In thousands, except per share data)
|
|
Operating revenues
|
|
$
|
629,214
|
|
|
$
|
389,758
|
|
Net income (loss) applicable to common shareholders
|
|
$
|
257,540
|
|
|
$
|
(7,471
|
)
|
Earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
2.94
|
|
|
$
|
(0.10
|
)
|
Diluted
|
|
$
|
2.90
|
|
|
$
|
(0.10
|
)
|
Chase Group combination. On
February 27, 2006, the Company closed a Combination
Agreement with the Chase Group whereby ownership in oil and gas
properties and non-producing leasehold acreage in Southeastern
New Mexico (the Chase Group Properties) were
combined with the properties previously owned by CEHC. The Chase
Group received cash in the aggregate amount of $409 million
and 34,794,638 shares of Resources common stock valued at
$384 million for an aggregate purchase price of
$793 million including transaction costs. The results of
the Chase Group Properties have been included in the
consolidated financial statements since that date.
|
|
Note E.
|
Asset
retirement obligations
|
The Companys asset retirement obligations represent the
estimated present value of the estimated cash flows the Company
will incur to plug, abandon and remediate its producing
properties at the end of their productive lives, in accordance
with applicable state laws. The Company does not provide for a
market risk premium associated with asset retirement obligations
because a reliable estimate cannot be determined. The Company
has no assets that are legally restricted for purposes of
settling asset retirement obligations.
The following table summarizes the Companys asset
retirement obligation transactions recorded in accordance with
the provisions of SFAS No. 143 during the years ended
December 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Asset retirement obligations, beginning of period
|
|
$
|
9,418
|
|
|
$
|
8,700
|
|
|
$
|
1,120
|
|
Liabilities incurred from new wells
|
|
|
1,197
|
|
|
|
471
|
|
|
|
1,288
|
|
Liabilities assumed in acquisitions
|
|
|
7,062
|
|
|
|
|
|
|
|
6,155
|
|
Accretion expense
|
|
|
889
|
|
|
|
444
|
|
|
|
287
|
|
Liabilities settled upon plugging and abandoning wells
|
|
|
|
|
|
|
(26
|
)
|
|
|
|
|
Revision of estimates
|
|
|
(1,757
|
)
|
|
|
(171
|
)
|
|
|
(150
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, end of period
|
|
$
|
16,809
|
|
|
$
|
9,418
|
|
|
$
|
8,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note F.
|
Stockholders
equity and stock issued subject to limited recourse
notes
|
Common stock private placement. On
June 5, 2008, the Company entered into a common stock
purchase agreement with certain unaffiliated third-party
investors to sell certain shares of the Companys common
stock in a
F-17
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
private placement (the Private Placement)
contemporaneous with the closing of the Henry Properties
acquisition. On July 31, 2008, the Company issued
8,302,894 shares of its common stock at $30.11 per share.
The Private Placement resulted in net proceeds of approximately
$242.4 million to the Company, after payment of
approximately $7.6 million for the fee paid to the
placement agent.
In connection with the Private Placement, the Company entered
into a registration rights agreement with the investors. On
October 24, 2008, pursuant to the registration rights
agreement, the Company filed a registration statement to
register the shares of common stock issued in the Private
Placement.
Initial public offering. On
August 7, 2007, the Company completed an initial public
offering (the IPO) of its common stock. The Company
sold 13,332,851 shares of its common stock in the IPO and
certain shareholders, including its executive officers and
certain members of the Chase Group, sold 7,554,256 shares
of the Companys common stock at $11.50 per share. After
deducting underwriting discounts of approximately
$9.6 million and offering expenses of approximately
$4.5 million, the Company received net proceeds of
approximately $139.2 million. In conjunction with the IPO,
the underwriters were granted an option to purchase 3,133,066
additional shares of the Companys common stock. The
underwriters fully exercised this option and purchased the
additional shares on August 9, 2007. After deducting
underwriting discounts of approximately $2.2 million, the
Company received net proceeds of approximately
$33.8 million. The aggregate net proceeds of approximately
$173.0 million received by the Company at closing on
August 7, 2007 and August 9, 2007 were utilized to
reduce bank debt.
Secondary public offering. On
December 19, 2007, the Company completed a secondary public
offering of 11,845,000 shares of the Companys common
stock, which was sold by certain of the Companys
stockholders, including certain members of the Chase group. The
Chase Group sold 10,194,732 shares of the Companys
common stock in the aggregate and certain other stockholders of
the Company sold 1,650,268 shares of the Companys
common stock in the aggregate, including one of the
Companys executive officers who sold 45,000 shares of
the Companys common stock. Chase Oil Corporation granted
the underwriters an option to purchase up to 1,776,615
additional shares of the Companys common stock to cover
over-allotments, which was fully exercised on December 19,
2007. The Company did not receive any proceeds from the sale of
the Companys common stock in this secondary offering.
Treasury stock. On June 12, 2008,
the restrictions on certain restricted stock awards issued to
five of the Companys executive officers lapsed.
Immediately upon the lapse of restrictions, these executive
officers became liable for certain federal income taxes on the
value of such shares. In accordance with the Companys 2006
Stock Incentive Plan and the applicable restricted stock award
agreements, four of such officers elected to deliver shares of
the Companys common stock to the Company to satisfy such
tax liability, and the Company acquired 3,142 shares to be
held as treasury stock in the approximate amount of $125,000.
Equity commitments. Pursuant to a stock
purchase agreement (the Stock Purchase Agreement)
entered into on August 13, 2004, CEHC obtained private
equity commitments totaling $202.5 million, comprised of
equity commitments from fourteen private investors (the
Private Investors) of approximately
$188.9 million and equity commitments from the five
original officers (the Officers) of the Company in
the aggregate amount of approximately $13.6 million. The
original commitments were subject to call by a vote of the board
of directors over a four year period beginning August 13,
2004 (the Take-Down Period), with the first date on
which capital was called being August 13, 2004. Subsequent
calls were made on November 11, 2004, June 22, 2005,
December 7, 2005 and February 10, 2006. The percentage
of total commitments called per capital call date was
approximately 15.0 percent, 23.3 percent,
10.0 percent, 15.0 percent and 22.0 percent,
respectively. In conjunction with the exchange of CEHC common
stock for Resources common stock as of the date of the
Combination, the remaining 14.7 percent of these private
equity commitments was terminated.
In addition to this arrangement between CEHC, the Private
Investors and the Officers, certain employees and other officers
of the Company entered into separate subscription agreements
with the Company. The officers and employees equity
purchases were paid for in a combination of cash and the
issuance of notes payable to the
F-18
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Company with recourse only to any equity security of the Company
held by the respective officer or employee (the Purchase
Notes). Based on guidance contained in
SFAS No. 123R, the agreements to sell stock to the
Companys officers and employees subject to the Purchase
Notes are accounted for as the issuance of options
(Bundled Capital Options for the Officers and
Capital Options for employees) on the dates that the
various subscription agreements were signed and the purchase
commitments were made.
Capital calls. From inception of CEHC
through February 23, 2006, the Private Investors purchased
16,113,170 Preferred Units for $161.1 million in cash; the
Companys officers purchased 2,240,083 CEHC common shares
and 938,303 Preferred Units for $3.6 million in cash and
Purchase Notes totaling $8.0 million, and certain employees
purchased 425,221 Preferred Units for $1.0 million in cash
and Purchase Notes totaling $3.8 million.
6% Series A preferred
stock. Preferred stock dividends were
generally paid on the anniversary of date of issuance of
preferred stock as a part of the Preferred Units. There were no
dividend payments made during the year ended December 31,
2008, because there was no outstanding preferred stock.
Preferred stock dividends of approximately $132,000 and
$2.6 million were paid during the years ended
December 31, 2007 and 2006, respectively. As discussed in
Note A and below, the majority of the CEHC preferred stock
was converted into Resources common stock in the Combination.
Final dividend payments on converted CEHC 6% Series A
Preferred Stock were made in March 2006.
Dividend payments continued to be made through April 16,
2007 to the eighteen employee shareholders that did not convert
their shares of CEHC preferred stock to Resources common stock
in the Combination. On April 16, 2007, these CEHC preferred
shares were exchanged for 190,972 shares of the
Companys common stock. These shares are reported as if
converted on the date of the Combination.
Purchase Notes. On April 23, 2007,
the Companys officers repaid their Purchase Notes in full,
including principal of $9.4 million and accrued interest of
$1.0 million in the aggregate. The agreements to sell stock
to the executive officers of the Company subject to Purchase
Notes were accounted for as the issuance of options. As such,
the repayment of the executive officer Purchase Notes represents
the full exercise of the options on the Bundled Capital Options
the officers held as well as the Capital Options of one certain
employee who was formerly an executive officer.
At December 31, 2008, all Purchase Notes from all employees
had been paid in full. As such, the repayment of the Purchase
Notes represent the full exercise of the options on the Capital
Options held by certain employees. At December 31, 2007,
the Company had Purchase Notes receivable from certain employees
of approximately $330,000 comprised of an aggregate principal
amounts of $288,000 and accrued interest of $42,000.
F-19
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Stock issuances treated as Capital
Options. The following table summarizes the
Bundled Capital Options activity for the years ended
December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Weighted
|
|
|
|
Bundled Capital
|
|
|
Average
|
|
|
|
Options
|
|
|
Exercise Price
|
|
|
Outstanding at December 31, 2005
|
|
|
1,100,000
|
|
|
$
|
9.52
|
|
Bundled Capital Options granted
|
|
|
|
|
|
$
|
|
|
Cancelled/forfeited
|
|
|
(161,697
|
)
|
|
$
|
9.52
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006
|
|
|
938,303
|
|
|
$
|
9.52
|
|
Bundled Capital Options exercised
|
|
|
(938,303
|
)
|
|
$
|
9.52
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Vested outstanding at:
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
938,303
|
|
|
$
|
9.52
|
|
December 31, 2007
|
|
|
|
|
|
$
|
|
|
The following table summarizes the Capital Options activity for
the years ended December 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Weighted
|
|
|
|
Capital
|
|
|
Average
|
|
|
|
Options
|
|
|
Exercise Price
|
|
|
Outstanding at December 31, 2005
|
|
|
482,500
|
|
|
$
|
9.74
|
|
$15 Capital Options granted
|
|
|
16,000
|
|
|
$
|
12.13
|
|
Cancelled/forfeited
|
|
|
(73,279
|
)
|
|
$
|
9.81
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006
|
|
|
425,221
|
|
|
$
|
9.81
|
|
$10 Capital Options exercised
|
|
|
(270,828
|
)
|
|
$
|
8.97
|
|
$15 Capital Options exercised
|
|
|
(116,008
|
)
|
|
$
|
12.26
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
38,385
|
|
|
$
|
8.34
|
|
$10 Capital Options exercised
|
|
|
(38,385
|
)
|
|
$
|
8.34
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Vested outstanding at:
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
425,221
|
|
|
$
|
9.81
|
|
December 31, 2007
|
|
|
38,385
|
|
|
$
|
8.34
|
|
December 31, 2008
|
|
|
|
|
|
$
|
|
|
The following table summarizes information about the
Companys vested Capital Options outstanding and
exercisable at December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
|
|
Weighted
|
|
|
|
|
|
|
|
|
Options
|
|
Average
|
|
Weighted
|
|
|
|
|
|
|
Outstanding,
|
|
Remaining
|
|
Average
|
|
|
|
|
|
|
Vested and
|
|
Contractual
|
|
Exercise
|
|
Intrinsic
|
|
|
|
|
Exercisable
|
|
Life
|
|
Price
|
|
Value
|
|
Vested Capital Options Outstanding and Exercisable at
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
10.00
|
|
|
|
38,385
|
|
|
|
2.52 years
|
|
|
$
|
8.34
|
|
|
$
|
562,000
|
|
F-20
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table summarizes the stock-based compensation for
all Capital Options and is included in general and
administrative expense in the accompanying consolidated
statement of operations for the year ended December 31,
2006. There was no stock-based compensation for Capital Options
in 2008 and 2007.
|
|
|
|
|
Stock-based compensation expense from Capital Options
|
|
$
|
975,000
|
|
|
|
|
|
|
Bundled Capital Options:
|
|
|
|
|
Stock-based compensation expense
|
|
$
|
508,000
|
|
Options vesting during period
|
|
|
242,000
|
|
Weighted average grant date fair value per option
|
|
$
|
2.10
|
|
Capital Options:
|
|
|
|
|
Stock-based compensation expense
|
|
$
|
467,000
|
|
Options vesting during period
|
|
|
119,799
|
|
Weighted average grant date fair value per option
|
|
$
|
3.90
|
|
Conversion of CEHC 6% Series A Preferred Stock and
CEHC common stock. On February 27, 2006,
concurrent with the closing of the Combination described in
Note A, the majority of the shares outstanding of CEHC
preferred stock and outstanding shares of CEHC common stock were
converted to shares of the Companys common stock, as
described below.
Eighteen employee shareholders owning an aggregate of
254,621 shares of CEHC preferred stock and
127,313 shares of CEHC common stock did not convert their
shares to the Companys common stock at the date of the
Combination. On April 16, 2007, these remaining shares of
CEHC were exchanged for 318,285 shares of the
Companys common stock. These shares are reported as if
converted on the date of the Combination. In addition, CEHC made
a final dividend payment to these eighteen employee shareholders
on their CEHC preferred stock in the aggregate amount of
approximately $99,000 on April 16, 2007.
Also in conjunction with the Combination described in
Note A and the conversion of CEHC preferred stock into the
Companys common stock at the ratio of 0.75:1, the CEHC
Bundled Capital Options were converted into the Companys
Bundled Capital Options and CEHC Capital Options were converted
into the Companys Capital Options. The Companys
Capital Options are considered to be exercisable for
1.25 shares of the Companys common stock.
Common stock held in escrow. On
February 27, 2006 the Company entered into an agreement
with certain stockholders of the Company in which certain of the
Companys shareholders placed 430,755 shares of
Resources common stock in an escrow account (the Escrow
Agreement). The Escrow Agreement provided that if, on or
before February 27, 2007 (the Initial Period),
the Company consummated one of two specified transactions, the
shares held in escrow would be released to the Company for
reissuance to Messrs. Leach, Beal, Copeland, Kamradt and
Wright. Neither of those specified transactions occurred in the
Initial Period. However, the Escrow Agreement specified that if
neither of the two specified transactions occurred during the
Initial Period, a sale of the Company in a business combination
on or before August 26, 2007 where the per share valuation
of the Companys common stock in such sale was equal to or
greater than $28.00 per share would result in the release of the
shares held in escrow to the Company for reissuance to
Messrs. Leach, Beal, Copeland, Kamradt and Wright. These
conditions for release of these shares to Messrs. Leach,
Beal, Copeland, Kamradt and Wright were not met by
August 26, 2007, and thereafter the escrow agent
distributed the escrowed shares to the original owners of the
shares.
Defined contribution plan. The Company
sponsors a 401(k) defined contribution plan for the benefit of
substantially all employees and maintains certain other acquired
plans. The Company matches 100 percent of employee
contributions, not to exceed 6 percent of the
employees annual salary. The Company contributions to the
plans for the years ended December 31, 2008, 2007 and 2006
were approximately $1.2 million, $419,000, and
F-21
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
$321,000, respectively. The increase in contributions for the
year ended December 31, 2008, were primarily attributable
to the addition of employees due to the Henry Entities
acquisition on July 31, 2008.
Stock incentive plan. The
Companys 2006 Stock Incentive Plan (together with
applicable option agreements and restricted stock agreements,
the Plan) provides for granting stock options and
restricted stock awards to employees and individuals associated
with the Company. The following table shows the number of awards
available under the Companys Plan at December 31,
2008:
|
|
|
|
|
|
|
Number of
|
|
|
Common Shares
|
|
Approved and authorized awards
|
|
|
5,850,000
|
|
Stock option grants, net of forfeitures
|
|
|
(3,343,684
|
)
|
Restricted stock grants, net of forfeitures
|
|
|
(512,809
|
)
|
|
|
|
|
|
Awards available for future grant
|
|
|
1,993,507
|
|
|
|
|
|
|
Restricted stock awards. All restricted
shares are treated as issued and outstanding in the accompanying
consolidated balance sheets. If an employee terminates
employment prior the lapse date, the awarded shares are
forfeited and cancelled and are no longer considered issued and
outstanding. A summary of the Companys restricted stock
awards for the years ended December 31, 2008, 2007 and 2006
is presented below:
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Grant Date
|
|
|
|
Restricted
|
|
|
Fair Value
|
|
|
|
Shares
|
|
|
Per Share
|
|
|
Restricted stock:
|
|
|
|
|
|
|
|
|
Outstanding at January 1, 2006
|
|
|
|
|
|
|
|
|
Shares granted
|
|
|
213,584
|
|
|
$
|
15.40
|
|
Shares cancelled/forteited
|
|
|
(1,368
|
)
|
|
|
|
|
Lapse of restrictions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006
|
|
|
212,216
|
|
|
|
|
|
Shares granted
|
|
|
220,995
|
|
|
$
|
9.22
|
|
Shares cancelled/forteited
|
|
|
(1,662
|
)
|
|
|
|
|
Lapse of restrictions
|
|
|
(60,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
371,549
|
|
|
|
|
|
Shares granted
|
|
|
128,001
|
|
|
$
|
32.13
|
|
Shares cancelled/forteited
|
|
|
(46,741
|
)
|
|
|
|
|
Lapse of restrictions
|
|
|
(45,458
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
407,351
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A summary of the impact on the consolidated statements of
operations for the Companys restricted stock awards during
the years ended December 31, 2008, 2007 and 2006 is
presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
(In thousands)
|
|
Stock-based compensation expense related to restricted stock
|
|
$
|
2,122
|
|
|
$
|
1,378
|
|
|
$
|
1,044
|
|
Income tax benefit related to restricted stock
|
|
$
|
808
|
|
|
$
|
533
|
|
|
$
|
407
|
|
Deductions in current taxable income related to restricted stock
|
|
$
|
1,234
|
|
|
$
|
|
|
|
$
|
|
|
F-22
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Stock option awards. The stock options
granted from August 13, 2004 through February 27, 2006
under the Stock Option Plan were to purchase Preferred Units. A
portion of the options vested based upon passage of time
(Time Vesting) and a portion of the options vested
based upon the Company obtaining certain results related to a
liquidation value (Performance Vesting).
Seventy-eight percent of the aggregate options granted were
vested based on Time Vesting, in which they vested one-third
each year for a three year period, which would result in
approximately 61 percent, 28 percent and
11 percent of their total grant date fair value being
expensed in the first, second and third years, respectively,
commencing on the first anniversary of the date of grant. The
remaining 22 percent of the aggregate options granted were
vested based on Performance Vesting. Performance Vesting was
considered to be achieved when the Company attained a
liquidation valuation which resulted in a 25 percent
internal rate of return and a return on investment of two times
the total dollars invested by the original shareholders of the
Company, upon the occurrence of one of the following events:
(i) the liquidation, dissolution or winding up of the
affairs of the Company,
(ii) a sale of all or substantially all of the assets of
the Company and a distribution to the shareholders of the
proceeds of such sale, or
(iii) any merger, consolidation or other transaction
resulting in at least 50 percent of the voting securities
of the Company being owned by a single person or a group.
As a result of the Combination, event (iii) listed above
occurred, which resulted in a change of control as defined in
the Stock Option Plan. As such, the 78 percent of the
aggregate options which vested based on Time Vesting were
immediately vested as of the date of the Combination.
CEHCs board of directors determined that, based upon the
value received by the CEHC shareholders in the Combination, the
thresholds for internal rate of return and return on investment
which determined the portion of vesting based on Performance
Vesting, were not met and that 22 percent portion of the
options were not vested.
The CEHC board of directors determined that CEHC would vest the
22 percent of aggregate stock options based on Performance
Vesting for only the stock option holders who were non-officers,
if CEHCs officers agreed that the 22 percent of
aggregate stock options based on Performance Vesting for the
officers would vest at the end of three years after the closing
of the Combination, which will result in approximately
33 percent, 33 percent and 34 percent of their
total grant date fair value being expensed in the first, second,
and third years, respectively, commencing on the first
anniversary of the date of grant; each officer so agreed.
A summary of CEHCs stock option activity, under the Stock
Option Plan, for the period ended February 27, 2006
(Combination date) is presented below. The amounts shown are
immediately prior to the conversion of CEHC stock options to
Resources stock options as a result of the Combination:
|
|
|
|
|
|
|
|
|
|
|
January 1, 2006
|
|
|
|
Through February 27, 2006
|
|
|
|
|
|
|
Weighted
|
|
|
|
Number of
|
|
|
Average
|
|
|
|
Units(a)
|
|
|
Price
|
|
|
Outstanding at beginning of period
|
|
|
1,365,075
|
|
|
$
|
10.32
|
|
Options granted
|
|
|
514,267
|
|
|
$
|
10.68
|
|
Options forfeited
|
|
|
|
|
|
$
|
|
|
Options exercised
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
1,879,342
|
|
|
$
|
10.42
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period
|
|
|
1,562,770
|
|
|
$
|
10.51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Each option Unit can be exercised for on Preferred Unit which is
comprised of one-half of a share of CEHC common stock and one
share of CEHC preferred stock. |
F-23
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Also in conjunction with the Combination described in
Note A and Note D and the conversion of CEHC preferred
stock into Resources common stock at the ratio of 0.75:1, the
CEHC unit options were converted into Resources stock options.
Each CEHC unit option, (considered to be exchangeable for one
share of CEHC preferred stock and one-half of a share of CEHC
common stock), was converted into 1.25 options to purchase
common stock of Resources. Each Resources stock option is
considered to be exchangeable for one share of Resources common
stock. The following table summarizes the conversion of the CEHC
unit options in conjunction with the Combination:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CEHC
|
|
|
|
|
|
Resources
|
|
|
|
|
CEHC
|
|
Unit
|
|
|
Conversion
|
|
|
Option
|
|
|
Resources
|
|
Unit Option Exercise Price
|
|
Options
|
|
|
Rate
|
|
|
Exercise Price
|
|
|
Options
|
|
|
$10.00
|
|
|
1,721,010
|
|
|
|
1.25:1
|
|
|
$
|
8.00
|
|
|
|
2,151,129
|
|
$15.00
|
|
|
158,332
|
|
|
|
1.25:1
|
|
|
$
|
12.00
|
|
|
|
197,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,879,342
|
|
|
|
|
|
|
|
|
|
|
|
2,349,113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A summary of the Companys stock option activity under the
Plan, for the years ended December 31, 2008 and 2007 and
for the period from February 27, 2006 through
December 31, 2006 is presented below. The amounts shown
below are on a post-combination and post-conversion basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
February 27, 2006
|
|
|
|
2008
|
|
|
2007
|
|
|
through December 31, 2006
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Exercise
|
|
|
Number of
|
|
|
Exercise
|
|
|
Number of
|
|
|
Exercise
|
|
|
|
Options
|
|
|
Price
|
|
|
Options
|
|
|
Price
|
|
|
Options
|
|
|
Price
|
|
|
Stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of period
|
|
|
3,011,722
|
|
|
$
|
9.71
|
|
|
|
2,797,997
|
|
|
$
|
8.93
|
|
|
|
2,349,113
|
|
|
$
|
8.34
|
|
Options granted
|
|
|
607,555
|
|
|
$
|
23.54
|
|
|
|
215,000
|
|
|
$
|
12.85
|
|
|
|
450,000
|
|
|
$
|
12.00
|
|
Options forfeited
|
|
|
(275,593
|
)
|
|
$
|
14.96
|
|
|
|
(1,275
|
)
|
|
$
|
8.00
|
|
|
|
(1,116
|
)
|
|
$
|
10.88
|
|
Options exercised
|
|
|
(612,360
|
)
|
|
$
|
8.80
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
2,731,324
|
|
|
$
|
12.46
|
|
|
|
3,011,722
|
|
|
$
|
9.71
|
|
|
|
2,797,997
|
|
|
$
|
8.93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at end of period
|
|
|
1,567,389
|
|
|
$
|
9.18
|
|
|
|
2,063,499
|
|
|
$
|
8.79
|
|
|
|
1,952,274
|
|
|
$
|
8.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period
|
|
|
517,019
|
|
|
$
|
11.16
|
|
|
|
508,462
|
|
|
$
|
10.58
|
|
|
|
1,952,274
|
|
|
$
|
8.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-24
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table summarizes information about the
Companys vested stock options outstanding and exercisable
at December 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Number
|
|
|
Remaining
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Vested and
|
|
|
Contractual
|
|
|
Exercise
|
|
|
Intrinsic
|
|
|
|
|
|
|
Exercisable
|
|
|
Life
|
|
|
Price
|
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Vested options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
8.00
|
|
|
|
1,232,647
|
|
|
|
2.58 years
|
|
|
$
|
8.00
|
|
|
$
|
18,268
|
|
Exercise price
|
|
$
|
12.00
|
|
|
|
143,492
|
|
|
|
4.99 years
|
|
|
$
|
12.00
|
|
|
|
1,553
|
|
Exercise price
|
|
$
|
14.68
|
|
|
|
191,250
|
|
|
|
7.78 years
|
|
|
$
|
14.68
|
|
|
|
1,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,567,389
|
|
|
|
|
|
|
$
|
9.18
|
|
|
$
|
21,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
8.00
|
|
|
|
236,227
|
|
|
|
5.62 years
|
|
|
$
|
8.00
|
|
|
$
|
3,501
|
|
Exercise price
|
|
$
|
12.00
|
|
|
|
89,542
|
|
|
|
6.78 years
|
|
|
$
|
12.00
|
|
|
|
969
|
|
Exercise price
|
|
$
|
14.68
|
|
|
|
191,250
|
|
|
|
7.78 years
|
|
|
$
|
14.68
|
|
|
|
1,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
517,019
|
|
|
|
|
|
|
$
|
11.16
|
|
|
$
|
6,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
8.00
|
|
|
|
1,753,819
|
|
|
|
3.15 years
|
|
|
$
|
8.00
|
|
|
$
|
22,116
|
|
Exercise price
|
|
$
|
12.00
|
|
|
|
197,180
|
|
|
|
5.72 years
|
|
|
$
|
12.00
|
|
|
|
1,698
|
|
Exercise price
|
|
$
|
15.40
|
|
|
|
112,500
|
|
|
|
8.45 years
|
|
|
$
|
15.40
|
|
|
|
586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,063,499
|
|
|
|
|
|
|
$
|
10.58
|
|
|
$
|
24,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
8.00
|
|
|
|
275,685
|
|
|
|
6.62 years
|
|
|
$
|
8.00
|
|
|
$
|
3,476
|
|
Exercise price
|
|
$
|
12.00
|
|
|
|
120,277
|
|
|
|
7.78 years
|
|
|
$
|
12.00
|
|
|
|
1,036
|
|
Exercise price
|
|
$
|
15.40
|
|
|
|
112,500
|
|
|
|
8.45 years
|
|
|
$
|
15.40
|
|
|
|
586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
508,462
|
|
|
|
|
|
|
$
|
10.58
|
|
|
$
|
5,098
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested and exercisable options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price
|
|
$
|
8.00
|
|
|
|
1,755,094
|
|
|
|
8.47 years
|
|
|
$
|
8.00
|
|
|
$
|
15,099
|
|
Exercise price
|
|
$
|
12.00
|
|
|
|
197,180
|
|
|
|
8.86 years
|
|
|
$
|
12.00
|
|
|
$
|
769
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,952,274
|
|
|
|
|
|
|
$
|
8.40
|
|
|
$
|
15,868
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-25
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table summarizes information about stock-based
compensation for options which is recognized in general and
administrative expense in the accompanying consolidated
statement of operations for the years ended December 31,
2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Grant date fair value for awards during the period:
|
|
|
|
|
|
|
|
|
|
|
|
|
Time Vesting options(a)
|
|
$
|
580
|
|
|
$
|
87
|
|
|
$
|
1,931
|
|
Performance Vesting options:
|
|
|
|
|
|
|
|
|
|
|
|
|
Officers(b)
|
|
|
|
|
|
|
|
|
|
|
531
|
|
Non-officers(c)
|
|
|
|
|
|
|
|
|
|
|
142
|
|
Stock option grants under the Plan(d)
|
|
|
5,675
|
|
|
|
1,921
|
|
|
|
3,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
6,255
|
|
|
$
|
2,008
|
|
|
$
|
6,159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense from stock
options:
|
|
|
|
|
|
|
|
|
|
|
|
|
Time Vesting options(a)
|
|
$
|
181
|
|
|
$
|
17
|
|
|
$
|
5,085
|
|
Performance Vesting options:
|
|
|
|
|
|
|
|
|
|
|
|
|
Officers(b)
|
|
|
253
|
|
|
|
602
|
|
|
|
511
|
|
Non-officers(c)
|
|
|
|
|
|
|
|
|
|
|
505
|
|
Stock option grants under the Plan(d)
|
|
|
2,667
|
|
|
|
1,844
|
|
|
|
1,024
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,101
|
|
|
$
|
2,463
|
|
|
$
|
7,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes and other information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit related to stock options
|
|
$
|
1,990
|
|
|
$
|
953
|
|
|
$
|
2,779
|
|
Deductions in current taxable income related to stock options
exercised
|
|
$
|
10,756
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
(a) |
|
Options granted prior to February 27, 2006, vested
immediately as of the date of the Combination, as a result of a
change of control. Options granted thereafter vest using a four
year graded vesting schedule by approval from the Board of
Directors. |
|
(b) |
|
Options granted prior to February 27, 2006, vest using a
three year cliff vesting schedule by approval from CEHCs
Board of Directors. |
|
(c) |
|
Vested as of the date of the Combination by approval from
CEHCs Board of Directors. |
|
(d) |
|
Vest using a three or four year graded vesting schedule by
approval from the Board of Directors. The 2007 grant date fair
value includes an adjustment of $765,000 from a change in fair
value due to the Code Section 409A (defined later) option
modification. |
In calculating the compensation expense for options, the Company
has estimated the fair value of each grant using the
Black-Scholes option-pricing model. Assumptions utilized in the
model are shown below. Amounts shown are assumptions under the
Plan for options exercisable for Resources common stock at a
rate of 1:1:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Risk-free interest rate
|
|
|
3.18
|
%
|
|
|
4.47
|
%
|
|
|
4.81
|
%
|
Expected term (years)
|
|
|
6.21
|
|
|
|
6.25
|
|
|
|
2.87
|
|
Expected volatility
|
|
|
38.88
|
%
|
|
|
37.33
|
%
|
|
|
37.12
|
%
|
Expected dividend yield
|
|
|
|
|
|
|
|
|
|
|
|
|
F-26
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Stock option modifications. On
November 8, 2007, the compensation committee of the
Companys board of directors authorized and approved
amendments to certain outstanding agreements related to options
to purchase the Companys common stock that were previously
awarded to certain of the Companys executive officers and
employees in order to amend such award agreements so that the
subject stock option award would constitute deferred
compensation that is compliant with Section 409A of the
Internal Revenue Code of 1986, as amended (the
Code), or exempt from the application of Code
Section 409A. As the offer to amend outstanding stock
option agreements previously issued to certain of the
Companys employees may constitute a tender offer under the
Securities Exchange Act of 1934, on November 8, 2007, the
board of directors of the Company authorized commencement of a
tender offer to amend the applicable outstanding stock option
award agreements in the form approved by the compensation
committee.
Generally, the amendments provide that the employee stock
options, which had previously vested in connection with the
Combination, will become exercisable in 25 percent
increments over a four year period beginning in 2008 and
continuing through 2011 or upon the occurrence of certain
specified events. Employees who decided to amend their stock
option award agreement received a cash payment equal to $0.50
for each share of common stock subject to the amendment on
January 2, 2008. The Company made aggregate cash payments
of approximately $192,000 to such employees. The Companys
affected executive officers received and accepted a similar
offer to amend their stock option awards issued prior to the
Combination on substantially the same terms, except such
officers were not offered the $0.50 per share payment.
In addition, the Companys named executive officers
received stock option awards in June 2006 to purchase
450,000 shares of common stock, in the aggregate, at a
purchase price of $12.00 per share. The Company subsequently
determined that the fair market value of a share of common stock
as of the date of the award was $15.40. As a result, the
compensation committee of the Companys board of directors
authorized and approved an amendment to these stock option award
agreements pursuant to which the exercise price of such stock
options would be increased from $12.00 per share to $15.40 per
share. The Company agreed to issue to the executive officer an
award of the number of shares of restricted stock equal to
(i) the product of $3.40 and the number of shares of common
stock subject to the stock option award, divided by
(ii) the Fair Market Value of a share of common stock on
the date of the award of restricted stock.
The Company has determined that its aggregate compensation
expense resulting from these modifications of approximately
$0.8 million will be recorded during the period from
November 8, 2007 to December 31, 2007 and during the
years ending December 31, 2008, 2009 and 2010.
Future stock-based compensation expense. The
following table reflects the future stock-based compensation
expense to be recorded for all the stock-based compensation
awards that are outstanding at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted
|
|
|
Stock
|
|
|
|
|
|
|
Stock
|
|
|
Options
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
2009
|
|
$
|
2,470
|
|
|
$
|
2,701
|
|
|
$
|
5,171
|
|
2010
|
|
|
1,393
|
|
|
|
1,242
|
|
|
|
2,635
|
|
2011
|
|
|
475
|
|
|
|
466
|
|
|
|
941
|
|
2012
|
|
|
40
|
|
|
|
55
|
|
|
|
95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,378
|
|
|
$
|
4,464
|
|
|
$
|
8,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note H. Disclosures
about fair value of financial instruments
The Company adopted SFAS No. 157, Fair Value
Measurements, (SFAS No. 157)
effective January 1, 2008 for financial assets and
liabilities measured on a recurring basis.
SFAS No. 157 applies to all financial assets and
financial liabilities that are being measured and reported on a
fair value basis. In February 2008, the FASB issued FSP
No. 157-2,
which delayed the effective date of SFAS No. 157 by
one year for nonfinancial assets and
F-27
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
liabilities. As defined in SFAS No. 157, fair value is
the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market
participants at the measurement date. SFAS No. 157
requires disclosure that establishes a framework for measuring
fair value and expands disclosure about fair value measurements.
The statement requires fair value measurements be classified and
disclosed in one of the following categories:
|
|
|
|
Level 1:
|
Unadjusted quoted prices in active markets that are accessible
at the measurement date for identical, unrestricted assets or
liabilities. The Company considers active markets to be those in
which transactions for the assets or liabilities occur in
sufficient frequency and volume to provide pricing information
on an ongoing basis.
|
|
|
Level 2:
|
Quoted prices in markets that are not active, or inputs which
are observable, either directly or indirectly, for substantially
the full term of the asset or liability. This category includes
those derivative instruments that the Company values using
observable market data. Substantially all of these inputs are
observable in the marketplace throughout the full term of the
derivative instrument, can be derived from observable data, or
supported by observable levels at which transactions are
executed in the marketplace. Level 2 instruments primarily
include non-exchange traded derivatives such as over-the-counter
commodity price swaps, investments and interest rate swaps. The
Companys valuation models are primarily industry-standard
models that consider various inputs including: (i) quoted
forward prices for commodities, (ii) time value and
(iii) current market and contractual prices for the
underlying instruments, as well as other relevant economic
measures. The Company utilizes our counterparties
valuations to assess the reasonableness of our prices and
valuation techniques.
|
|
|
Level 3:
|
Measured based on prices or valuation models that require inputs
that are both significant to the fair value measurement and less
observable from objective sources (i.e., supported by
little or no market activity). Level 3 instruments
primarily include derivative instruments, such as basis swaps,
commodity price collars and floors, as well as investments. The
Companys valuation models are primarily industry-standard
models that consider various inputs including: (i) quoted
forward prices for commodities, (ii) time value,
(iii) volatility factors and (iv) current market and
contractual prices for the underlying instruments, as well as
other relevant economic measures. Although the Company utilizes
our counterparties valuations to assess the reasonableness
of our prices and valuation techniques, the Company does not
have sufficient corroborating market evidence to support
classifying these assets and liabilities as Level 2.
|
The following represents information about the estimated fair
values of the Companys financial instruments:
Cash and cash equivalents, accounts receivable, other current
assets, accounts payable, interest payable and other current
liabilities. The carrying amounts approximate
fair value due to the short maturity of these instruments.
Notes receivable officers and
employees. The carrying amounts approximate fair
value due to the comparability of the interest rate to
risk-adjusted rates for similar financial instruments.
Line of credit and term note. The carrying
amount of borrowings outstanding under the Companys
revolving credit facility and term note (see
Note J) approximate fair value because the instruments
bear interest at variable market rates.
Derivative instruments. The fair value of the
derivative instruments are estimated by management considering
various factors, including closing exchange and over-the-counter
quotations and the time value of the underlying commitments. As
required by SFAS No. 157, financial assets and
liabilities are classified based on the lowest level of input
that is significant to the fair value measurement. The
Companys assessment of the significance of a particular
input to the fair value measurement requires judgment, and may
affect the valuation of the fair value
F-28
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
of assets and liabilities and their placement within the fair
value hierarchy levels. The following table summarizes the
valuation of the Companys financial instruments by
SFAS No. 157 pricing levels at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements using
|
|
|
|
|
|
|
|
|
|
Quoted
|
|
|
Significant
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
prices
|
|
|
other
|
|
|
Significant
|
|
|
carrying value
|
|
|
|
|
|
|
in active
|
|
|
observable
|
|
|
unobservable
|
|
|
at
|
|
|
|
|
|
|
markets
|
|
|
inputs
|
|
|
inputs
|
|
|
December 31,
|
|
|
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
2008
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
$
|
|
|
|
$
|
124,641
|
|
|
$
|
|
|
|
$
|
124,641
|
|
|
|
|
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
(680
|
)
|
|
|
|
|
|
|
(680
|
)
|
|
|
|
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
(1,083
|
)
|
|
|
|
|
|
|
(1,083
|
)
|
|
|
|
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
49,562
|
|
|
|
49,562
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial assets (liabilities)
|
|
$
|
|
|
|
$
|
122,878
|
|
|
$
|
49,562
|
|
|
$
|
172,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth a reconciliation of changes in
the fair value of financial assets and liabilities classified as
Level 3 in the fair value hierarchy:
|
|
|
|
|
|
|
(In Thousands)
|
|
|
Balance at January 1, 2008
|
|
$
|
1,866
|
|
Realized and unrealized gains
|
|
|
49,122
|
|
Purchases, issuances, and settlements
|
|
|
(1,426
|
)
|
|
|
|
|
|
Balance at December 31, 2008
|
|
$
|
49,562
|
|
|
|
|
|
|
Total gains for the period included in earnings attributable to
the change in unrealized gains relating to assets still held at
the reporting date
|
|
$
|
47,696
|
|
|
|
|
|
|
For additional information on the Companys derivative
instruments see Note I.
|
|
Note I.
|
Derivative
financial instruments
|
The Company uses financial derivative contracts to manage
exposures to commodity price and interest rate. Commodity hedges
are used to (i) reduce the effect of the volatility of
price changes on the natural gas and crude oil the Company
produces and sells, (ii) support the Companys annual
capital budget and expenditure plans and (iii) support the
economics associated with acquisitions. Interest rate hedges are
used to hedge our mitigate the cash flow risk associated with
rising interest rates. The Company does not enter into
derivative financial instruments for speculative or trading
purposes. The Company also may enter physical delivery contracts
to effectively provide commodity price hedges. Because these
contracts are not expected to be net cash settled, they are
considered to be normal sales contracts and not derivatives.
Therefore, these contracts are not recorded in the financial
statements.
Currently, the Company does not designate its derivative
instruments to qualify for hedge accounting. Accordingly, the
Company reflects the changes in the fair value of its derivative
instruments in the statements of operations.
A key requirement for designation of derivative instruments to
qualify for hedge accounting is that at both the inception of
the hedge and on an ongoing basis, the hedging relationship is
expected to be highly effective in achieving offsetting cash
flows attributable to the hedged risk during the term of the
hedge. Generally, the hedging relationship can be considered to
be highly effective if there is a high degree of historical
correlation between the hedging instrument and the forecasted
transaction. For all quarters ended prior to July 1, 2007,
prices received for
F-29
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
the Companys natural gas were highly correlated with the
Inside FERC El Paso Natural Gas index (the
Index) the Index referenced in all of
the Companys natural gas derivative instruments. However,
during the quarter ended September 30, 2007, this
historical relationship did not meet the criteria as being
highly correlated. Natural gas produced from the Companys
New Mexico shelf assets has a substantial component of natural
gas liquids. Prices received for natural gas liquids are not
highly correlated to the price of natural gas, but are more
closely correlated to the price of oil. During the third quarter
of 2007, the price of oil and natural gas liquids, and
therefore, the prices the Company received for its natural gas
(including natural gas liquids) rose substantially and at a
significantly higher rate than the corresponding change in the
Index. This resulted in a decrease in correlation between the
prices received and the Index below the level required for cash
flow hedge accounting. According to SFAS No. 133, an
entity shall discontinue hedge accounting prospectively for an
existing hedge if the hedge is no longer highly effective. Hedge
accounting must be discontinued regardless of whether the
Company believes the hedge will be prospectively highly
effective. The hedge must be discontinued during the period the
hedges became ineffective. As a result, any changes in fair
value must be recorded in earnings. Because the natural gas and
natural gas liquids prices fluctuate at different rates over
time, the loss of effectiveness does not relate to any single
date.
During the three months ended June 30, 2007, the Company
determined that all of its natural gas commodity contracts no
longer qualified as hedges under the requirements of
SFAS No. 133 for the reason stated in the above
paragraph. These contracts are referred to as dedesignated
hedges.
Therefore, June 30, 2007, was considered the last date the
Companys natural gas hedges were highly effective, and the
Company discontinued hedge accounting during the three months
ended September 30, 2007 and all periods thereafter.
Mark-to-market adjustments related to these dedesignated hedges
are recorded each period to earnings. Effective portions of
dedesignated hedges, previously recorded in AOCI at
June 30, 2007, remain in AOCI and are being reclassified
into earnings under natural gas revenues, during the periods
which the hedged forecasted transaction affects earnings.
2008 commodity derivative contracts. During
the year ended December 31, 2008, the Company entered into
additional commodity derivative contracts to hedge a portion of
its estimated future production. The following table summarizes
information about these additional commodity derivative
contracts at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
|
Remaining
|
|
|
|
Remaining
|
|
|
Daily
|
|
|
Index
|
|
|
Contract
|
|
|
|
Volume
|
|
|
Volume
|
|
|
Price
|
|
|
Period
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar
|
|
|
768,000
|
|
|
|
2,104
|
|
|
$
|
120.00 - $134.60
|
(a)
|
|
|
1/1/09-12/31/09
|
|
Price swap
|
|
|
292,000
|
|
|
|
800
|
|
|
$
|
98.35
|
(a)
|
|
|
1/1/09-12/31/09
|
|
Price swap
|
|
|
348,000
|
|
|
|
953
|
|
|
$
|
125.10
|
(a)
|
|
|
1/1/09-12/31/09
|
|
Price swap
|
|
|
240,000
|
|
|
|
658
|
|
|
$
|
128.80
|
(a)
|
|
|
1/1/10-12/31/10
|
|
Price swap
|
|
|
336,000
|
|
|
|
921
|
|
|
$
|
128.66
|
(a)
|
|
|
1/1/11-12/31/11
|
|
Price swap
|
|
|
504,000
|
|
|
|
1,377
|
|
|
$
|
127.80
|
(a)
|
|
|
1/1/12-12/31/12
|
|
Natural gas (volumes in MMBtus):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
1,825,000
|
|
|
|
5,000
|
|
|
$
|
8.44
|
(b)
|
|
|
1/1/09-12/31/09
|
|
Index basis swap
|
|
|
6,022,500
|
|
|
|
16,500
|
|
|
$
|
1.08
|
(c)
|
|
|
1/1/09-12/31/09
|
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the
NYMEX-West Texas Intermediate monthly average futures price. |
|
(b) |
|
The index price for the natural gas price collar is based on the
Inside FERC-El Paso Permian Basin first-of-the-month spot
price. |
|
(c) |
|
The basis differential between the El Paso Permian delivery
point and NYMEX Henry Hub delivery point. |
F-30
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Commodity derivative contracts assumed in the Henry Entities
acquisition. As part of the Henry Entities
acquisition, the Company assumed the following commodity
derivative contracts on July 31, 2008. The following table
summarizes information about the remaining portion of these
assumed derivative contracts at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
|
Remaining
|
|
|
|
Remaining
|
|
|
Daily
|
|
|
Index
|
|
|
Contract
|
|
|
|
Volume
|
|
|
Volume
|
|
|
Price
|
|
|
Period
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
443,491
|
|
|
|
1,215
|
|
|
$
|
73.59
|
(a)
|
|
|
1/1/09 - 12/31/09
|
|
Price swap
|
|
|
401,746
|
|
|
|
1,101
|
|
|
$
|
72.03
|
(a)
|
|
|
1/1/10 - 12/31/10
|
|
Price swap
|
|
|
221,746
|
|
|
|
608
|
|
|
$
|
68.92
|
(a)
|
|
|
1/1/11 - 12/31/11
|
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the
NYMEX-West Texas Intermediate monthly average futures price and
the prices represent weighted average prices. |
2008 interest rate derivative
contracts. During 2008, the Company entered into
interest rate derivative contracts to hedge a portion of its
future interest rate exposure. The Company hedged its LIBOR
interest rate on the Companys bank debt by fixing the rate
at 1.90 percent for three years beginning in May of 2009 on
$300 million of the Companys bank debt. The interest
rate derivative contracts were not designated as cash flow
hedges.
The following table sets forth the Companys outstanding
derivative contracts at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume /
|
|
|
|
|
|
Index
|
|
Remaining
|
|
|
|
Fair Value
|
|
|
Notional
|
|
|
Daily
|
|
|
Price /
|
|
Contract
|
|
|
|
Asset (Liability)
|
|
|
Amount
|
|
|
Volume
|
|
|
Rate
|
|
Period
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar
|
|
$
|
49,562
|
|
|
|
768,000
|
|
|
|
2,104
|
|
|
$120.00 - $134.60(a)
|
|
|
1/1/09 - 12/31/09
|
|
Price swap
|
|
|
58,269
|
|
|
|
1,813,491
|
|
|
|
4,968
|
|
|
$87.16(a)(c)
|
|
|
1/1/09 - 12/31/09
|
|
Price swap
|
|
|
17,948
|
|
|
|
641,746
|
|
|
|
1,758
|
|
|
$93.26(a)(c)
|
|
|
1/1/10 - 12/31/10
|
|
Price swap
|
|
|
18,191
|
|
|
|
557,746
|
|
|
|
1,528
|
|
|
$104.91(a)(c)
|
|
|
1/1/11 - 12/31/11
|
|
Price swap
|
|
|
24,339
|
|
|
|
504,000
|
|
|
|
1,377
|
|
|
$127.80(a)
|
|
|
1/1/12 - 12/31/12
|
|
Natural gas (volumes in MMBtus):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
5,894
|
|
|
|
1,825,000
|
|
|
|
5,000
|
|
|
$8.44(b)
|
|
|
1/1/09 - 12/31/09
|
|
Basis swap
|
|
|
(680
|
)
|
|
|
6,022,500
|
|
|
|
16,500
|
|
|
$1.08(d)
|
|
|
1/1/09 - 12/31/09
|
|
Interest rate (notional amount in dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rate swap
|
|
|
(1,083
|
)
|
|
$
|
300,000,000
|
|
|
|
|
|
|
1.90%(e)
|
|
|
5/1/09 - 4/30/12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net asset
|
|
$
|
172,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the
NYMEX-West Texas Intermediate monthly average futures price. |
|
(b) |
|
The index price for the natural gas price collar is based on the
Inside FERC-El Paso Permian Basin first-of-the-month spot
price. |
|
(c) |
|
Prices represent weighted average prices. |
F-31
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
(d) |
|
The basis differential between the El Paso Permian delivery
point and NYMEX Henry Hub delivery point. |
|
(e) |
|
The index rate is based on the one-month LIBOR. |
The Companys reported oil and gas revenue and average oil
and gas prices includes the effects of oil quality and Btu
content, gathering and transportation costs, gas processing and
shrinkage, and the net effect of the commodity hedges that
qualified for cash flow hedge accounting. The following table
summarizes the gains and losses reported in earnings related to
the commodity and interest rate derivative instruments and the
net change in AOCI:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Increase (decrease) in oil and gas revenue from derivative
activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments on cash flow hedges in oil sales
|
|
$
|
(30,591
|
)
|
|
$
|
(11,091
|
)
|
|
$
|
(7,000
|
)
|
Cash receipts from cash flow hedges in gas sales
|
|
|
|
|
|
|
188
|
|
|
|
1,232
|
|
Dedesignated cash flow hedges reclassified from AOCI in gas sales
|
|
|
(696
|
)
|
|
|
1,103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total decrease in oil and gas revenue from derivative activity
|
|
$
|
(31,287
|
)
|
|
$
|
(9,800
|
)
|
|
$
|
(5,768
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as
hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market gain (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
257,307
|
|
|
$
|
(22,089
|
)
|
|
$
|
|
|
Interest rate derivatives
|
|
|
(1,083
|
)
|
|
|
|
|
|
|
|
|
Cash (payments) receipts on derivatives not designated as
hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
(6,354
|
)
|
|
|
1,815
|
|
|
|
|
|
Interest rate derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivatives not designated as hedges
|
|
$
|
249,870
|
|
|
$
|
(20,274
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) from ineffective portion of cash flow
hedges:
|
|
$
|
1,336
|
|
|
$
|
(821
|
)
|
|
$
|
1,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market gain (loss) of cash flow hedges
|
|
$
|
(7,985
|
)
|
|
$
|
(33,783
|
)
|
|
$
|
11,936
|
|
Reclassification adjustment of losses to earnings
|
|
|
30,591
|
|
|
|
10,903
|
|
|
|
5,768
|
|
Net AOCI upon dedesignation at June 30, 2007
|
|
|
|
|
|
|
(407
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change, before income taxes
|
|
|
22,606
|
|
|
|
(23,287
|
)
|
|
|
17,704
|
|
Income tax effect
|
|
|
(8,835
|
)
|
|
|
9,102
|
|
|
|
(6,230
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change, net of income taxes
|
|
$
|
13,771
|
|
|
$
|
(14,185
|
)
|
|
$
|
11,474
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dedesignated cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net AOCI upon dedesignation at June 30, 2007
|
|
$
|
|
|
|
$
|
407
|
|
|
$
|
|
|
Reclassification adjustment of (gains) losses to earnings
|
|
|
696
|
|
|
|
(1,103
|
)
|
|
|
|
|
Income tax effect
|
|
|
(272
|
)
|
|
|
272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change, net of income taxes
|
|
$
|
424
|
|
|
$
|
(424
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-32
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
All of the Companys commodity derivative contracts are
expected to settle by December 31, 2012. All the
Companys commodity derivative contracts previously
accounted for as cash flow hedges and dedesignated as hedges
were settled on December 31, 2008.
Post 2008 commodity derivative
contracts. After December 31, 2008 and
through February 19, 2009, the Company entered into the
following additional commodity derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
Remaining
|
|
|
|
|
|
|
Remaining
|
|
|
Daily
|
|
|
Index
|
|
Contract
|
|
|
|
|
|
|
Volume
|
|
|
Volume
|
|
|
Price
|
|
Period
|
|
|
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
600,000
|
|
|
|
1,644
|
|
|
$57.55(a)
|
|
|
1/1/10 - 12/31/10
|
|
|
|
|
|
Price collar
|
|
|
600,000
|
|
|
|
6,522
|
|
|
$45.00 - $49.00(a)
|
|
|
3/1/09 - 5/31/09
|
|
|
|
|
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the
NYMEX-West Texas Intermediate monthly average futures price. |
The Companys debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Senior Credit Facility
|
|
$
|
630,000
|
|
|
$
|
216,000
|
|
2nd Lien Credit Facility
|
|
|
|
|
|
|
109,900
|
|
Unamortized original issue discount on 2nd Lien Credit Facility
|
|
|
|
|
|
|
(496
|
)
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
630,000
|
|
|
|
325,404
|
|
Current portion of 2nd Lien Credit Facility
|
|
|
|
|
|
|
2,000
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
$
|
630,000
|
|
|
$
|
327,404
|
|
|
|
|
|
|
|
|
|
|
Senior credit facility. On July 31, 2008,
the Company amended and restated its senior credit facility in
various respects, including increasing the borrowing base to
$960 million, subject to scheduled semiannual
redeterminations, and extending the maturity date to
July 31, 2013 (the Senior Credit Facility). The
Company paid an arrangement fee of $14.4 million upon
closing the Senior Credit Facility. At December 31, 2008,
the Company had letters of credit outstanding under the Senior
Credit Facility of approximately $275,000 and its availability
to borrow additional funds was $329.7 million. In October
2008, the Companys $960 million borrowing base was
reaffirmed until the next scheduled borrowing base
redetermination in April 2009. Between scheduled borrowing base
redeterminations the Company and, if requested by
662/3 percent
of the lenders, the lenders may each request one special
redetermination.
Advances on the Senior Credit Facility bear interest, at the
Companys option, based on (i) the prime rate of
JPMorgan Chase Bank (JPM Prime Rate)
(3.25 percent at December 31, 2008) or
(ii) a Eurodollar rate (substantially equal to the London
Interbank Offered Rate). The interest rates of Eurodollar rate
advances and JPM Prime Rate advances vary, with interest margins
ranging from 125 to 275 basis points and zero to
125 basis points, respectively, per annum depending on the
balance outstanding. The Company pays commitment fees on the
unused portion of the available borrowing base ranging from 25
to 50 basis points per annum.
The Senior Credit Facility also includes a
same-day
advance facility under which the Company may borrow funds on a
daily basis from the administrative agent. Same day advances
cannot exceed $25 million and the maturity dates cannot
exceed fourteen days. The interest rate on this facility is the
JPM Prime Rate plus the applicable interest margin.
F-33
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The Companys obligations under the Senior Credit Facility
are secured by a first lien on substantially all of the
Companys oil and gas properties. In addition, all of the
Companys subsidiaries are guarantors and all general
partner, limited partner and membership interests in the
Companys subsidiaries owned by the Company have been
pledged to secure borrowings under the Senior Credit Facility.
The credit agreement contains various restrictive covenants and
compliance requirements which include (a) maintenance of
certain financial ratios including (i) maintenance of a
quarterly ratio of total debt to consolidated earnings before
interest expense, income taxes, depletion, depreciation, and
amortization, exploration expense and other noncash income and
expenses to be no greater than 4.0 to 1.0, and
(ii) maintenance of a ratio of current assets to current
liabilities, excluding noncash assets and liabilities related to
financial derivatives and asset retirement obligations and
including the unfunded amounts under the Senior Credit Facility,
to be no less than 1.0 to 1.0; (b) limits on the incurrence
of additional indebtedness and certain types of liens;
(c) restrictions as to mergers and sales or transfer of
assets; and (d) a restriction on the payment of cash
dividends. At December 31, 2008, the Company was in
compliance with its debt covenants.
2nd lien credit facility. On
March 27, 2007, the Company entered into a second lien
credit facility (the 2nd Lien Credit Facility),
for a term loan facility in the amount of $200 million. The
2nd Lien Credit Facility was fully paid on July 31,
2008 from proceeds from the Companys Senior Credit
Facility and the facility was terminated.
Principal maturities of long-term
debt. Principal maturities of long-term debt
outstanding at December 31, 2008 are as follows:
|
|
|
|
|
|
|
(In thousands)
|
|
|
2009
|
|
$
|
|
|
2010
|
|
|
|
|
2011
|
|
|
|
|
2012
|
|
|
|
|
2013
|
|
|
630,000
|
|
|
|
|
|
|
Total
|
|
$
|
630,000
|
|
|
|
|
|
|
Interest expense. The following amounts have
been incurred and charged to interest expense for the years
ended December 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Cash payments for interest
|
|
$
|
27,747
|
|
|
$
|
41,036
|
|
|
$
|
23,882
|
|
Amortization of original issue discount
|
|
|
58
|
|
|
|
98
|
|
|
|
|
|
Amortization of deferred loan origination costs
|
|
|
2,157
|
|
|
|
1,338
|
|
|
|
1,494
|
|
Write-off of deferred loan origination costs and original issue
discount
|
|
|
1,547
|
|
|
|
2,631
|
|
|
|
|
|
Net changes in accruals
|
|
|
(1,237
|
)
|
|
|
(6,414
|
)
|
|
|
7,320
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest costs incurred
|
|
|
30,272
|
|
|
|
38,689
|
|
|
|
32,696
|
|
Less: capitalized interest
|
|
|
(1,233
|
)
|
|
|
(2,647
|
)
|
|
|
(2,129
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest expense
|
|
$
|
29,039
|
|
|
$
|
36,042
|
|
|
$
|
30,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-34
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
Note K.
|
Commitments
and contingencies
|
Severance agreements. The Company has entered
into severance and change in control agreements with all of its
officers. The current annual salaries for the Companys
officers covered under such agreements total approximately
$2.4 million.
Indemnifications. The Company has agreed to
indemnify its directors and officers, employees and agents with
respect to claims and damages arising from acts or omissions
taken in such capacity, as well as with respect to certain
litigation.
Legal actions. The Company is a party to
proceedings and claims incidental to its business. While many of
these matters involve inherent uncertainty, the Company believes
that the amount of the liability, if any, ultimately incurred
with respect to such proceedings and claims will not have a
material adverse effect on the Companys consolidated
financial position as a whole or on its liquidity, capital
resources or future annual results of operations. The Company
will continue to evaluate litigation against the Company on a
quarter-by-quarter
basis and will establish and adjust any reserves as appropriate
to reflect its assessment of the then current status of the
matters.
Acquisition commitments. In connection with
the Acquisition, the Company agreed to pay certain employees of
the Henry Entities bonuses of approximately $11.0 million
in the aggregate at each of the first and second anniversaries
of the closing of the Acquisition, respectively. Except as
described below, these employees must remain employed with the
Company to receive the bonus. A Henry Entities employee who is
otherwise entitled to a full bonus will receive the full bonus
(i) if the Company terminates the employee without cause,
(ii) upon death or disability of such employee or
(iii) upon a change in control of the Company. If such
employee resigns or is terminated for cause the employee will
not receive the bonus and the Company will be required to pay
the sellers in the Acquisition 65 percent of the bonus
amount not paid to the employee. The Company will reflect the
bonus amounts to be paid to these employees as a period cost
which will be included in the Companys results of
operations over the period earned. Amounts that ultimately are
determined to be paid to the sellers will be treated as a
contingent purchase price and reflected as an
adjustment to the purchase price. During 2008, the Company
recognized $4.3 million of the obligation in its results of
operations and $0.7 million as contingent purchase price.
Daywork commitments. The Company periodically
enters into contractual arrangements under which the Company is
committed to expend funds to drill wells in the future,
including agreements to secure drilling rig services, which
require the Company to make future minimum payments to the rig
operators. The Company records drilling commitments in the
periods in which well capital is incurred or rig services are
provided. The following table summarizes the Companys
future drilling commitments at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due By Period
|
|
|
|
|
|
|
Less Than
|
|
|
1 - 3
|
|
|
3 - 5
|
|
|
More Than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
|
(In thousands)
|
|
|
Daywork drilling contracts
|
|
$
|
5,584
|
|
|
$
|
5,584
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Daywork drilling contracts with related parties(a)
|
|
|
12,296
|
|
|
|
12,296
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daywork drilling contracts assumed in the Henry Properties
acquisition(b)
|
|
|
10,850
|
|
|
|
7,978
|
|
|
|
2,872
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual drilling commitments
|
|
$
|
28,730
|
|
|
$
|
25,858
|
|
|
$
|
2,872
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Consists of daywork drilling contracts with Silver Oak Drilling,
LLC, an affiliate of the Chase Group. |
|
(b) |
|
A major oil and gas company which owns an interest in the wells
being drilled and the Company are parties to these contracts.
Only the Companys 25% share of the contract obligation has
been reflected above. |
F-35
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Operating leases. The Company leases vehicles,
equipment and office facilities under non-cancellable operating
leases. Lease payments associated with these operating leases
for the years ended December 31, 2008, 2007 and 2006 were
approximately $720,000, $288,000 and $685,000, respectively.
Future minimum lease commitments under non-cancellable operating
leases at December 31, 2008 are as follows:
|
|
|
|
|
|
|
(In thousands)
|
|
|
2009
|
|
$
|
970
|
|
2010
|
|
|
985
|
|
2011
|
|
|
989
|
|
2012
|
|
|
981
|
|
2013
|
|
|
818
|
|
|
|
|
|
|
Total
|
|
$
|
4,743
|
|
|
|
|
|
|
The Company accounts for income taxes in accordance with the
provisions of SFAS No. 109. The Company and its
subsidiaries file federal corporate income tax returns on a
consolidated basis. The tax returns and the amount of taxable
income or loss are subject to examination by United States
federal and state taxing authorities.
The Companys provision for income taxes differed from the
U.S. statutory rate of 35 percent primarily due to
state income taxes and non-deductible expenses. The effective
income tax rate for the years ended December 31, 2008, 2007
and 2006 was 36.8 percent, 38.7 percent and
42.2 percent, respectively.
SFAS No. 109 requires that the Company continually
assess both positive and negative evidence to determine whether
it is more likely than not that deferred tax assets can be
realized prior to their expiration. Management monitors
Company-specific, oil and gas industry and worldwide economic
factors and assesses the likelihood that the Companys net
operating loss carryforwards (NOLs) and other
deferred tax attributes in the United States, state, and local
tax jurisdictions will be utilized prior to their expiration. At
December 31, 2008 and 2007, the Company had no valuation
allowances related to its deferred tax assets.
The Company adopted the provisions of FASB Interpretation
No. 48 Accounting for Uncertainty in Income
Taxes (FIN No. 48) an
interpretation of FASB Statement No. 109
Accounting for Income Taxes, on
January 1, 2007. At the time of adoption and at
December 31, 2008, the Company did not have any significant
uncertain tax positions requiring recognition in the financial
statements. The tax years 2004 through 2008 remain subject to
examination by major tax jurisdictions.
The FASB issued
FIN No. 48-1,
Definition of Settlement in FASB Interpretation
No. 48,
(FIN No. 48-1)
to clarify when a tax position is effectively settled.
FIN No. 48-1
provides guidance in determining the proper timing for
recognizing tax benefits and applying the new information
relevant to the technical merits of a tax position obtained
during a tax authority examination. FIN No.
48-1
provides criteria to determine whether a tax position is
effectively settled after completion of a tax authority
examination, even if the potential legal obligation remains
under the statute of limitations. The Companys adoption of
this pronouncement did not have a significant effect on its
consolidated financial statements.
Texas margins tax. On May 18, 2006, the
Governor of Texas signed into law House Bill 3
(HB-3) which modifies the existing franchise tax
law. The modified franchise tax will be computed by subtracting
either costs of goods sold or compensation expense, as defined
in HB-3, from gross revenue to arrive at a gross margin. The
resulting gross margin will be taxed at a one percent rate. HB-3
has also expanded the definition of tax-paying entities to
include limited partnerships. HB-3 became effective for
activities occurring on or after January 1, 2007.
F-36
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The portion of tax expense attributable to the enactment of the
Texas margin tax was $226,000 and $113,000 for the years ended
December 31, 2008 and 2007, respectively.
Income tax provision. The Companys
income tax provision and amounts separately allocated were
attributable to the following items for the years ended
December 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Income from operations
|
|
$
|
162,085
|
|
|
$
|
16,019
|
|
|
$
|
14,379
|
|
Changes in stockholders equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred hedge gains (losses)
|
|
|
(3,121
|
)
|
|
|
(13,204
|
)
|
|
|
4,200
|
|
Net settlement losses included in earnings
|
|
|
12,228
|
|
|
|
3,830
|
|
|
|
2,030
|
|
Tax benefits related to stock-based compensation
|
|
|
(3,614
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
167,578
|
|
|
$
|
6,645
|
|
|
$
|
20,609
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys income tax provision attributable to income
from operations consisted of the following for the years ended
December 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
$
|
8,080
|
|
|
$
|
1,902
|
|
|
$
|
1,527
|
|
U.S. state and local
|
|
|
521
|
|
|
|
401
|
|
|
|
234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,601
|
|
|
|
2,303
|
|
|
|
1,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
|
141,668
|
|
|
|
10,069
|
|
|
|
10,777
|
|
U.S. state and local
|
|
|
11,816
|
|
|
|
3,647
|
|
|
|
1,841
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
153,484
|
|
|
|
13,716
|
|
|
|
12,618
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
162,085
|
|
|
$
|
16,019
|
|
|
$
|
14,379
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The reconciliation between the tax expense computed by
multiplying pretax income by the U.S. federal statutory
rate and the reported amounts of income tax expense is as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Income at U.S. federal statutory rate
|
|
$
|
154,276
|
|
|
$
|
14,483
|
|
|
$
|
11,916
|
|
State income taxes (net of federal tax effect)
|
|
|
13,372
|
|
|
|
2,631
|
|
|
|
2,083
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
380
|
|
Statutory depletion carryover
|
|
|
|
|
|
|
(613
|
)
|
|
|
|
|
Change in tax rate
|
|
|
(5,671
|
)
|
|
|
|
|
|
|
|
|
Nondeductible expense & other
|
|
|
108
|
|
|
|
(482
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expense for income taxes
|
|
$
|
162,085
|
|
|
$
|
16,019
|
|
|
$
|
14,379
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-37
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and deferred tax
liabilities were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Deferred tax asset:
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
$
|
5,569
|
|
|
$
|
4,440
|
|
Derivative instruments
|
|
|
|
|
|
|
17,612
|
|
Statutory depletion carryover
|
|
|
1,635
|
|
|
|
613
|
|
Federal tax credit carryovers
|
|
|
8,525
|
|
|
|
1,195
|
|
Other
|
|
|
10,625
|
|
|
|
564
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
26,354
|
|
|
|
24,424
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liability:
|
|
|
|
|
|
|
|
|
Oil and gas properties, principally due to differences in basis
and depletion and the deduction of intangible drilling costs for
tax purposes
|
|
|
(557,011
|
)
|
|
|
(269,938
|
)
|
Intangible asset operating rights
|
|
|
(14,387
|
)
|
|
|
|
|
Derivative instruments
|
|
|
(65,689
|
)
|
|
|
|
|
Other
|
|
|
(235
|
)
|
|
|
(54
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(637,322
|
)
|
|
|
(269,992
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(610,968
|
)
|
|
$
|
(245,568
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Note M.
|
Major
customers and derivative counterparties
|
Sales to major customers. The Companys
share of oil and gas production is sold to various purchasers.
The Company is of the opinion that the loss of any one purchaser
would not have a material adverse effect on the ability of the
Company to sell its oil and gas production.
The following purchasers individually accounted for ten percent
or more of the consolidated oil and natural gas revenues,
including the results of commodity hedges, during the years
ended December 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2008
|
|
2007
|
|
2006
|
|
Navajo Refining Company, L.P.
|
|
|
59%
|
|
|
|
60%
|
|
|
|
52%
|
|
DCP Midstream LP
|
|
|
18%
|
|
|
|
23%
|
|
|
|
17%
|
|
At December 31, 2008, the Company had receivables from
Navajo Refining Company, L.P. and DCP Midstream LP of $16.2
million and $3.7 million, respectively, which are reflected
in Accounts receivable oil and gas in the
accompanying consolidated balance sheet.
Derivative counterparties. The Company uses
credit and other financial criteria to evaluate the credit
standing of, and to select, counterparties to its derivative
instruments. The Companys credit facility agreements
require that the senior unsecured debt ratings of the
Companys derivative counterparties be not less than either
A- by Standard & Poors Rating Group rating
system or A3 by Moodys Investors Service, Inc. rating
system. At December 31, 2008 and 2007, the counterparties
with whom the Company had outstanding derivative contracts met
or exceeded the required ratings. Although the Company does not
obtain collateral or otherwise secure the fair value of its
derivative instruments, management believes the associated
credit risk is mitigated by the Companys credit risk
policies and procedures and by the credit rating requirements of
the Companys credit facility agreements.
F-38
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Contract Operator Agreement and Transition Services
Agreement. On February 27, 2006, the Company
signed a Contract Operator Agreement with Mack Energy
Corporation (MEC), an affiliate of the Chase Group,
whereby the Company engaged MEC as its contract operator to
provide certain services with respect to the Chase Group
Properties. The initial term of the Contract Operator Agreement
was five years commencing on March 1, 2006 and ending on
February 28, 2011. The Company and MEC entered into a
Transition Services Agreement on April 23, 2007, which
terminated the Contract Operator Agreement and under which MEC
continued to provide certain field level operating services on
the Chase Group Properties. The Transition Services Agreement
was terminated automatically on August 7, 2007 upon the
Companys completion of the Companys initial public
offering. Upon termination of such agreement, the Companys
employees along with third party contractors assumed the
operation of the subject properties.
The Company incurred charges from MEC of approximately
$1.9 million and $18.2 million for the year ended
December 31, 2008 and from the termination dates of the
respective agreements through December 31, 2007,
respectively, in the ordinary course of business. The Company
incurred charges from MEC of approximately $18.2 million
and $10.3 million during 2007 for services rendered under
the Contract Operator Agreement and Transition Services
Agreement through the termination dates of the respective
agreements and the year ended December 31, 2006,
respectively.
The Company had outstanding invoices payable to MEC of
approximately zero and $0.4 million at December 31,
2008 and 2007, respectively, which are reflected in accounts
payable related parties in the accompanying
consolidated balance sheet.
Other related party transactions. The Company
also has engaged in transactions with certain other affiliates
of the Chase Group, including Silver Oak, an oilfield services
company, a supply company, a drilling fluids supply company, a
pipe and tubing supplier, a fixed base operator of aircraft
services and a software company.
The Company incurred charges from these related party vendors of
approximately $23.2 million, $43.8 million and
$32.4 million for the years ended December 31, 2008,
2007 and 2006, respectively, for services rendered.
At December 31, 2008 and 2007, the Company had outstanding
invoices payable to the other related party vendors identified
above of approximately $21,000 and $1.7 million,
respectively, which are reflected in accounts
payable related parties in the accompanying
consolidated balance sheets.
Overriding royalty and royalty
interests. Certain members of the Chase Group own
overriding royalty interests in certain of the Chase Group
Properties. The amount paid attributable to such interests was
approximately $3.1 million, $2.4 million and
$1.2 million for the years ended December 31, 2008,
2007 and 2006, respectively. The Company owed royalty payments
of approximately $146,000 and $315,000 to these members of the
Chase Group at December 31, 2008 and 2007, respectively.
Royalties are paid on certain properties located in Andrews
County, Texas to a partnership of which one of the
Companys directors is the General Partner, and who also
owns a 3.5 percent partnership interest. The Company paid
approximately $332,000, $205,000 and $72,000 for the years ended
December 31, 2008, 2007 and 2006, respectively. The Company
owed this partnership royalty payments of approximately $13,000
and $29,000 at December 31, 2008 and 2007, respectively.
In April 2005, the Company acquired certain working interests in
46,861 gross (26,908 net) acres located in Culberson
County, Texas from an entity partially owned by a person who
became an executive officer of the Company immediately following
such acquisition. In connection with this acquisition, such
entity retained a 2 percent overriding royalty interest in
the acquired properties, which overriding royalty interest is
now owned equally by such officer and a non-officer employee of
the Company. The amount attributable to such interest was
approximately $3,000 during the year ended December 31,
2007. During the year ended December 31, 2008, no payments
were made related to this overriding royalty interest.
F-39
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Prospect participation. Subsequent to the
closing of the Combination, the Company acquired working
interests from Caza in certain lands in New Mexico in which Caza
owns an interest. The Company paid Caza approximately zero,
$3,000 and $2.1 million for the years ended
December 31, 2008, 2007 and 2006 for these interests. At
December 31, 2008 and 2007, the Company had no outstanding
invoices owed to Caza.
Working interests owned by employees. As part
of the Henry Properties acquisition, the Company purchased oil
and gas properties in which employees owned a working interest.
The Company distributed revenues to these employees of
approximately $155,000 and received joint interest payments from
these employees of $635,000 for the year ended December 31,
2008. At December 31, 2008, the Company was owed by these
employees approximately $300,000, which is reflected in accounts
receivable related parties.
|
|
Note O.
|
Net
income per share
|
Basic net income per share is computed by dividing net income
applicable to common shareholders by the weighted average number
of common shares treated as outstanding for the period. As
discussed in Note F, agreements to sell stock to the
Companys officers and certain employees subject to
Purchase Notes are accounted for as options (Bundled
Capital Options and Capital Options,
respectively). As a result, Bundled Capital Options and Capital
Options are excluded from the weighted average number of common
shares treated as outstanding during each period until the
Purchase Notes are paid in full, thus exercising the options.
All Bundled Capital Options were exercised prior to
September 30, 2007. All Capital Options were exercised
prior to March 31, 2008.
The computation of diluted income per share reflects the
potential dilution that could occur if securities or other
contracts to issue common stock that are dilutive to income were
exercised or converted into common stock or resulted in the
issuance of common stock that would then share in the earnings
of the Company. These amounts include unexercised Bundled
Capital Options, Capital Options, stock options and restricted
stock (as issued under the Plan and described in Note G).
Potentially dilutive effects are calculated using the treasury
stock method.
The CEHC 6% Series A Preferred Stock were entitled to
receive an amount equal to its stated value ($9.00) plus any
unpaid dividends upon occurrence of a liquidation event, as
defined. In connection with the Combination on February 24,
2006, a liquidation event occurred. Instead of receiving the
stated value, the holders of the CEHC 6% Series A Preferred
Stock agreed to accept 0.75 shares of Resources common
stock in exchange for each share of CEHC 6% Series A
Preferred Stock. This was considered to be an induced
conversion, as defined in the FASB Emerging Issues Task Force
Topic D-42, The Effect on the Calculation of Earnings per
Share for the Redemption or Induced Conversion of Preferred
Stock. The excess of the carrying amount of the CEHC 6%
Series A Preferred Stock over the fair value of the
Resources common stock issued is required to be added to
2006 net income to arrive at 2006 net income
applicable to common shareholders for the year ended
December 31, 2006.
The following table is a reconciliation of the basic weighted
average common shares outstanding to diluted weighted average
common shares outstanding for the years ended December 31,
2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
(In thousands)
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
79,206
|
|
|
|
64,316
|
|
|
|
47,287
|
|
Dilutive Bundled Capital Options
|
|
|
|
|
|
|
847
|
|
|
|
2,516
|
|
Dilutive Capital Options
|
|
|
6
|
|
|
|
154
|
|
|
|
192
|
|
Dilutive common stock options
|
|
|
1,134
|
|
|
|
901
|
|
|
|
714
|
|
Dilutive restricted stock
|
|
|
241
|
|
|
|
91
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
80,587
|
|
|
|
66,309
|
|
|
|
50,729
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-40
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Since the Company had net income applicable to common
shareholders, the effects of all potentially dilutive securities
including Bundled Capital Options, Capital Options, incentive
stock options and unvested restricted stock were considered in
the computation of diluted earnings per share. Because the
exercise prices of certain incentive stock options were greater
than the average market price of the common shares and would be
anti-dilutive, incentive stock options to purchase
313,354 shares, 366,250 shares and 450,000 of common
stock for the years ended December 31, 2008, 2007 and 2006,
respectively, were outstanding but not included in the
computations of diluted income per share from continuing
operations. Also excluded from the computation of diluted income
per share for the year ended December 31, 2008, were
56,086 shares of restricted stock because the effect would
be anti-dilutive.
|
|
Note P.
|
Other
current liabilities
|
The following table provides the components of the
Companys other current liabilities at December 31,
2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Other current liabilities:
|
|
|
|
|
|
|
|
|
Accrued production costs
|
|
$
|
15,489
|
|
|
$
|
4,135
|
|
Payroll related matters
|
|
|
11,290
|
|
|
|
3,821
|
|
Accrued interest
|
|
|
353
|
|
|
|
1,590
|
|
Asset retirement obligations
|
|
|
2,611
|
|
|
|
912
|
|
Other
|
|
|
8,314
|
|
|
|
4,008
|
|
|
|
|
|
|
|
|
|
|
Other current liabilities
|
|
$
|
38,057
|
|
|
$
|
14,466
|
|
|
|
|
|
|
|
|
|
|
F-41
CONCHO
RESOURCES INC.
December 31,
2008, 2007 and 2006
Capitalized
Costs
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Oil and gas properties:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
2,316,330
|
|
|
$
|
1,303,665
|
|
Unproved
|
|
|
377,244
|
|
|
|
251,353
|
|
Less: accumulated depletion
|
|
|
(306,990
|
)
|
|
|
(167,109
|
)
|
|
|
|
|
|
|
|
|
|
Net capitalized costs for oil and gas properties
|
|
$
|
2,386,584
|
|
|
$
|
1,387,909
|
|
|
|
|
|
|
|
|
|
|
Costs
Incurred for Oil and Gas Producing Activities(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
597,713
|
|
|
$
|
|
|
|
$
|
830,537
|
|
Unproved
|
|
|
240,294
|
|
|
|
7,293
|
|
|
|
220,295
|
|
Exploration
|
|
|
160,174
|
|
|
|
116,004
|
|
|
|
49,297
|
|
Development
|
|
|
178,842
|
|
|
|
64,524
|
|
|
|
124,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred for oil and gas properties
|
|
$
|
1,177,023
|
|
|
$
|
187,821
|
|
|
$
|
1,224,946
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The costs incurred for oil and gas producing activities includes
the following amounts of asset retirement obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Proved property acquisition costs
|
|
$
|
7,062
|
|
|
$
|
|
|
|
$
|
6,155
|
|
Exploration costs
|
|
|
563
|
|
|
|
(15
|
)
|
|
|
43
|
|
Development costs
|
|
|
(1,123
|
)
|
|
|
315
|
|
|
|
1,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
6,502
|
|
|
$
|
300
|
|
|
$
|
7,293
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve
Quantity Information
The estimates of proved oil and gas reserves, which are all
located in the United States primarily in the Permian Basin
region of Southeastern New Mexico and West Texas, were prepared
by the Companys engineers. These reserve estimates were
reviewed and confirmed by Netherland, Sewell &
Associates, Inc. and Cawley, Gillespie & Associates,
Inc. Reserves were estimated in accordance with guidelines
established by the United States Securities and Exchange
Commission (SEC) and the FASB, which require that
reserve estimates be prepared under existing economic and
operating conditions with no provision for price and cost
escalations except by contractual arrangements except that
future production costs exclude overhead charges for Company
operated properties.
F-42
CONCHO
RESOURCES INC.
UNAUDITED
SUPPLEMENTARY INFORMATION (Continued)
The following table summarizes the prices utilized in the
reserve estimates for 2008, 2007 and 2006. Commodity prices
utilized for the reserve estimates were adjusted for location,
grade and quality are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2008
|
|
2007
|
|
2006
|
|
Prices utilitzed in the reserve estimates before adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-end West Texas Intermediate posted oil price per Bbl
|
|
$
|
41.00
|
|
|
$
|
92.50
|
|
|
$
|
57.75
|
|
Year-end Henry Hub spot market natural gas price per MMBtu
|
|
$
|
5.71
|
|
|
$
|
6.80
|
|
|
$
|
5.64
|
|
Oil and gas reserve quantity estimates are subject to 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. The accuracy of such
estimates is a function of the quality of available data and of
engineering and geological interpretation and judgment. Results
of subsequent drilling, testing and production may cause either
upward or downward revision of previous estimates. Further, the
volumes considered to be commercially recoverable fluctuate with
changes in prices and operating costs. The Company emphasizes
that reserve estimates are inherently imprecise and that
estimates of new discoveries are more imprecise than those of
currently producing oil and gas properties. Accordingly, these
estimates are expected to change as additional information
becomes available in the future.
The following table provides a rollforward of the total proved
reserves for the years ended December 31, 2008, 2007 and
2006, as well as proved developed reserves at the beginning and
end of each respective year. Oil and condensate volumes are
expressed in MBbls and natural gas volumes are expressed in MMcf.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
Oil and
|
|
Natural
|
|
|
|
Oil and
|
|
Natural
|
|
|
|
Oil and
|
|
Natural
|
|
|
|
|
Condensate
|
|
Gas
|
|
Total
|
|
Condensate
|
|
Gas
|
|
Total
|
|
Condensate
|
|
Gas
|
|
Total
|
|
|
(MBbls)
|
|
(MMcf)
|
|
(MBoe)
|
|
(MBbls)
|
|
(MMcf)
|
|
(MBoe)
|
|
(MBbls)
|
|
(MMcf)
|
|
(MBoe)
|
|
Total Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, January 1
|
|
|
53,361
|
|
|
|
225,837
|
|
|
|
91,000
|
|
|
|
44,322
|
|
|
|
200,818
|
|
|
|
77,792
|
|
|
|
9,658
|
|
|
|
49,530
|
|
|
|
17,913
|
|
Purchase of
minerals-in-place
|
|
|
20,837
|
|
|
|
56,022
|
|
|
|
30,174
|
|
|
|
105
|
|
|
|
354
|
|
|
|
164
|
|
|
|
27,163
|
|
|
|
137,963
|
|
|
|
50,157
|
|
Sales of
minerals-in-place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Discoveries and extensions(a)
|
|
|
24,194
|
|
|
|
73,380
|
|
|
|
36,424
|
|
|
|
13,140
|
|
|
|
48,751
|
|
|
|
21,265
|
|
|
|
10,226
|
|
|
|
39,427
|
|
|
|
16,797
|
|
Revisions of previous estimates
|
|
|
(7,521
|
)
|
|
|
(34,323
|
)
|
|
|
(13,242
|
)
|
|
|
(1,191
|
)
|
|
|
(12,022
|
)
|
|
|
(3,195
|
)
|
|
|
(430
|
)
|
|
|
(16,595
|
)
|
|
|
(3,196
|
)
|
Production
|
|
|
(4,586
|
)
|
|
|
(14,968
|
)
|
|
|
(7,081
|
)
|
|
|
(3,014
|
)
|
|
|
(12,064
|
)
|
|
|
(5,025
|
)
|
|
|
(2,295
|
)
|
|
|
(9,507
|
)
|
|
|
(3,880
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31
|
|
|
86,285
|
|
|
|
305,948
|
|
|
|
137,275
|
|
|
|
53,361
|
|
|
|
225,837
|
|
|
|
91,000
|
|
|
|
44,322
|
|
|
|
200,818
|
|
|
|
77,791
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
|
|
|
27,617
|
|
|
|
128,872
|
|
|
|
49,096
|
|
|
|
23,443
|
|
|
|
112,423
|
|
|
|
42,180
|
|
|
|
6,502
|
|
|
|
34,160
|
|
|
|
12,195
|
|
December 31
|
|
|
46,661
|
|
|
|
179,124
|
|
|
|
76,515
|
|
|
|
27,617
|
|
|
|
128,872
|
|
|
|
49,096
|
|
|
|
23,443
|
|
|
|
112,423
|
|
|
|
42,180
|
|
|
|
|
(a) |
|
The 2008, 2007 and 2006 discoveries and extensions included
14,533, 9,601 and 5,211 net MBoe, respectively, related to
additions from the Companys infill drilling activities. |
Standardized
Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is
computed by applying year-end prices of oil and gas (with
consideration of price changes only to the extent provided by
contractual arrangements) to the estimated future production of
proved oil and gas reserves less estimated future expenditures
(based on year-end costs) to be incurred in developing and
producing the proved reserves, discounted using a rate of
10 percent per year to reflect the estimated timing of the
future cash flows. Future income taxes are calculated by
comparing undiscounted future cash flows to the tax basis of oil
and gas properties plus available carryforwards and credits and
applying the current tax rates to the difference.
Discounted future cash flow estimates like those shown below are
not intended to represent estimates of the fair value of oil and
gas properties. Estimates of fair value would also consider
probable and possible reserves,
F-43
CONCHO
RESOURCES INC.
UNAUDITED
SUPPLEMENTARY INFORMATION (Continued)
anticipated future oil and gas prices, interest rates, changes
in development and production costs and risks associated with
future production. Because of these and other considerations,
any estimate of fair value is necessarily subjective and
imprecise.
The following table provides the standardized measure of
discounted future cash flows at December 31, 2008, 2007 and
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Oil and gas producing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
5,785,109
|
|
|
$
|
6,507,955
|
|
|
$
|
3,560,326
|
|
Future production costs
|
|
|
(1,666,380
|
)
|
|
|
(1,517,415
|
)
|
|
|
(995,335
|
)
|
Future development and abandonment costs(a)
|
|
|
(668,005
|
)
|
|
|
(484,140
|
)
|
|
|
(484,462
|
)
|
Future income tax expense
|
|
|
(919,251
|
)
|
|
|
(1,482,633
|
)
|
|
|
(530,212
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,531,473
|
|
|
|
3,023,767
|
|
|
|
1,550,317
|
|
10% annual discount factor
|
|
|
(1,332,488
|
)
|
|
|
(1,591,993
|
)
|
|
|
(839,968
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
$
|
1,198,985
|
|
|
$
|
1,431,774
|
|
|
$
|
710,349
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes $28.8 million, $19.5 million and
$25.3 million of undiscounted asset retirement cash inflow
estimated at December 31, 2008, 2007 and 2006,
respectively, using current estimates of future salvage values
less future abandonment costs. See Note E for corresponding
information regarding the Companys discounted asset
retirement obligations. |
Changes
in Standardized Measure of Discounted Future Net Cash
Flows
The following table provides a rollforward of the standardized
measure of discounted future cash flows for the years ended
December 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Oil and gas producing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of
minerals-in-place
|
|
$
|
1,014,689
|
|
|
$
|
4,054
|
|
|
$
|
795,072
|
|
Sales of
minerals-in-place
|
|
|
(24
|
)
|
|
|
(54
|
)
|
|
|
|
|
Extensions and discoveries
|
|
|
426,208
|
|
|
|
511,519
|
|
|
|
156,266
|
|
Net changes in prices and production costs
|
|
|
(1,622,800
|
)
|
|
|
802,584
|
|
|
|
(109,264
|
)
|
Oil and gas sales, net of production costs
|
|
|
(473,841
|
)
|
|
|
(249,866
|
)
|
|
|
(166,236
|
)
|
Changes in future development costs
|
|
|
74,160
|
|
|
|
72,441
|
|
|
|
(6,085
|
)
|
Revisions of previous quantity estimates
|
|
|
(283,557
|
)
|
|
|
(82,299
|
)
|
|
|
(51,147
|
)
|
Accretion of discount
|
|
|
255,660
|
|
|
|
85,533
|
|
|
|
23,085
|
|
Changes in production rates, timing and other
|
|
|
104,137
|
|
|
|
35,834
|
|
|
|
(10,119
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in present value of future net revenues
|
|
|
(505,368
|
)
|
|
|
1,179,746
|
|
|
|
631,572
|
|
Net change in present value of future income taxes
|
|
|
272,579
|
|
|
|
(458,321
|
)
|
|
|
(144,985
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(232,789
|
)
|
|
|
721,425
|
|
|
|
486,587
|
|
Balance, beginning of year
|
|
|
1,431,774
|
|
|
|
710,349
|
|
|
|
223,762
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
$
|
1,198,985
|
|
|
$
|
1,431,774
|
|
|
$
|
710,349
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-44
CONCHO
RESOURCES INC.
UNAUDITED
SUPPLEMENTARY INFORMATION (Continued)
Selected
Quarterly Financial Results
The following table provides selected quarterly financial
results for the years ended December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
(In thousands, except per share data)
|
|
|
Year ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
106,711
|
|
|
$
|
137,383
|
|
|
$
|
170,457
|
|
|
$
|
119,238
|
|
Operating costs and expenses (excluding gains (losses) on
derivatives not designated as hedges)
|
|
|
(48,205
|
)
|
|
|
(54,942
|
)
|
|
|
(90,889
|
)
|
|
|
(121,229
|
)
|
Gains (losses) on derivatives not designated as hedges
|
|
|
(17,178
|
)
|
|
|
(102,456
|
)
|
|
|
163,312
|
|
|
|
206,192
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
41,328
|
|
|
|
(20,015
|
)
|
|
|
242,880
|
|
|
|
204,201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
22,365
|
|
|
$
|
(14,420
|
)
|
|
$
|
141,928
|
|
|
$
|
128,829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$
|
22,365
|
|
|
$
|
(14,420
|
)
|
|
$
|
141,928
|
|
|
$
|
128,829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share Basic
|
|
$
|
0.30
|
|
|
$
|
(0.19
|
)
|
|
$
|
1.75
|
|
|
$
|
1.53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share Diluted
|
|
$
|
0.29
|
|
|
$
|
(0.19
|
)
|
|
$
|
1.72
|
|
|
$
|
1.51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
60,346
|
|
|
$
|
66,103
|
|
|
$
|
69,098
|
|
|
$
|
98,786
|
|
Operating costs and expenses (excluding gains (losses) on
derivatives not designated as hedges)
|
|
|
(41,938
|
)
|
|
|
(46,324
|
)
|
|
|
(49,690
|
)
|
|
|
(60,170
|
)
|
Gains (losses) on derivatives not designated as hedges
|
|
|
|
|
|
|
|
|
|
|
3,088
|
|
|
|
(23,362
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
18,408
|
|
|
|
19,779
|
|
|
|
22,496
|
|
|
|
15,254
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
4,623
|
|
|
$
|
5,925
|
|
|
$
|
7,954
|
|
|
$
|
6,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
4,589
|
|
|
$
|
5,914
|
|
|
$
|
7,954
|
|
|
$
|
6,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share Basic
|
|
$
|
0.08
|
|
|
$
|
0.10
|
|
|
$
|
0.12
|
|
|
$
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share Diluted
|
|
$
|
0.08
|
|
|
$
|
0.10
|
|
|
$
|
0.11
|
|
|
$
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-45
Index of
Exhibits
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
2
|
.1
|
|
Purchase Agreement, dated June 5, 2008, by and among Concho
Resources Inc., James C. Henry and Paula Henry, Henry Securities
Ltd., Henchild LLC, Henry Family Investment Group, Henry Holding
LP, Henry Energy LP, Aguasal Holding, HELP Investment LLC, Henry
Capital LLC, Henry Operating LLC, Henry Petroleum LP, Quail
Ranch LLC, Aguasal Management LLC, and Aguasal LP (filed as
Exhibit 2.1 to the Companys Current Report on
Form 8-K on June 9, 2008, and incorporated herein by
reference).
|
|
3
|
.1
|
|
Restated Certificate of Incorporation (filed as Exhibit 3.1
to the Companys Current Report on Form 8-K on
August 6, 2007, and incorporated herein by reference).
|
|
3
|
.2
|
|
Amended and Restated Bylaws of Concho Resources Inc., as amended
March 25, 2008 (filed as Exhibit 3.1 to the
Companys Current Report on Form 8-K on March 26,
2008, and incorporated herein by reference).
|
|
4
|
.1
|
|
Specimen Common Stock Certificate (filed as Exhibit 4.1 to
the Companys Current Report on
Form S-1/A
on July 5, 2007, and incorporated herein by reference).
|
|
10
|
.1
|
|
Credit Agreement, dated as of February 24, 2006, by and
among Concho Resources Inc., JPMorgan Chase Bank, N.A., as
administrative agent, Bank of America, N.A., as syndication
agent, Wachovia Bank, National Association, and BNP Paribas, as
documentation agents, and other lenders party thereto(filed as
Exhibit 10.1 to the Companys Current Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
|
10
|
.2
|
|
Second Lien Credit Agreement, dated as of March 23, 2007,
among Concho Resources Inc., Bank of America, N.A., as
administrative agent, and Banc of America LLC, as sole lead
arranger and sole booking manager (filed as Exhibit 10.2 to
the Companys Current Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
|
10
|
.3
|
|
Form of Drilling Agreement with Silver Oak Drilling, LLC (filed
as Exhibit 10.4 to the Companys Current Report on
Form S-1/A
on July 5, 2007, and incorporated herein by reference).
|
|
10
|
.4
|
|
Salt Water Disposal System Ownership and Operating Agreement
dated February 24, 2006, among COG Operating LLC, Chase Oil
Corporation, Caza Energy LLC and Mack Energy Corporation (filed
as Exhibit 10.5 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10
|
.5
|
|
Transition Services Agreement dated April 23, 2007, between
COG Operating LLC and Mack Energy Corporation (filed as
Exhibit 10.3 to the Companys Current Report on
Form S-1 on April 24, 2007, and incorporated herein by
reference).
|
|
10
|
.6
|
|
Combination Agreement dated February 24, 2006, among Concho
Resources Inc., Concho Equity Holdings Corp., Chase Oil
Corporation, Caza Energy LLC and the other signatories thereto
(filed as Exhibit 2.1 to the Companys Current Report
on
Form S-1
on April 24, 2007, and incorporated herein by reference).
The Combination Agreement filed as Exhibit 2.1 omits
certain of the schedules and exhibits to the Combination
Agreement in accordance with Item 601 (b)(2) of
Regulation S-K.
A list briefly identifying the contents of all omitted schedules
and exhibits is included with the Combination Agreement filed as
Exhibit 2.1. Concho Resources agrees to furnish
supplementally a copy of any omitted schedule or exhibit to the
Securities and Exchange Commission upon request.
|
|
10
|
.7
|
|
Software License Agreement dated March 2, 2006, between
Enertia Software Systems and Concho Resources Inc. (filed as
Exhibit 10.6 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10
|
.8
|
|
Leasehold Acquisition Agreement dated April 1, 2005, by and
between Trey Resources, Inc. and COG Oil and Gas LP (filed as
Exhibit 10.7 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10
|
.9
|
|
Transfer of Operating Rights (Sublease) in a Lease for Oil and
Gas for Valhalla properties (filed as Exhibit 10.8 to the
Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10
|
.10
|
|
Assignment of Oil and Gas Leases from Caza Energy LLC (filed as
Exhibit 10.9 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10
|
.11**
|
|
Escrow Agreement dated February 27, 2006, among Concho
Resources Inc., Timothy A. Leach, Steven L. Beal, David W.
Copeland, Curt F. Kamradt and E. Joseph Wright and the other
signatories thereto (filed as Exhibit 10.10 to the
Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
10
|
.12
|
|
Business Opportunities Agreement dated February 27, 2006,
among Concho Resources Inc. and the other signatories thereto
(filed as Exhibit 10.11 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10
|
.13
|
|
Registration Rights Agreement dated February 27, 2006,
among Concho Resources Inc. and the other signatories thereto
(filed as Exhibit 10.12 to the Companys Current
Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10
|
.14**
|
|
Concho Resources Inc. 2006 Stock Incentive Plan (filed as
Exhibit 10.13 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10
|
.15**
|
|
Concho Resources Inc. Summary of Executive Officer Compensation
Program (filed as Exhibit 10.15 to the Companys Current
Report on
Form 10-K
on March 28, 2008, and incorporated herein by reference).
|
|
10
|
.16**
|
|
Form of Nonstatutory Stock Option Agreement (filed as
Exhibit 10.16 to the Companys Current Report on
Form 10-K
on March 28, 2008, and incorporated herein by reference).
|
|
10
|
.17**
|
|
Form of Restricted Stock Agreement (for employees) (filed as
Exhibit 10.16 to the Companys Current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10
|
.18**
|
|
Form of Restricted Stock Agreement (for non-employee directors)
(filed as Exhibit 10.18 to the Companys Current
Report on
Form 10-K
on March 28, 2008, and incorporated herein by reference).
|
|
10
|
.19**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and Timothy A. Leach (filed as
Exhibit 10.1 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10
|
.20**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and Steven L. Beal (filed as
Exhibit 10.2 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10
|
.21**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and E. Joseph Wright (filed as
Exhibit 10.3 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10
|
.22**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and Darin G. Holderness (filed as
Exhibit 10.4 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10
|
.23**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and David W. Copeland (filed as
Exhibit 10.5 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10
|
.24**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and Matthew G. Hyde (filed as
Exhibit 10.6 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10
|
.25**
|
|
Employment Agreement dated December 19, 2008, between
Concho Resources Inc. and Jack F. Harper (filed as
Exhibit 10.7 to the Companys current Report on
Form 8-K
on December 19, 2008, and incorporated herein by reference).
|
|
10
|
.26**
|
|
Form of Indemnification Agreement between Concho Resources Inc.
and each of the officers and directors thereof (filed as
Exhibit 10.23 to the Companys current Report on
Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10
|
.27**
|
|
Indemnification Agreement, dated May 21, 2008, by and
between Concho Resources, Inc. and Matthew G. Hyde (filed as
Exhibit 10.1 to the Companys current Report on
Form 8-K
on May 28, 2008, and incorporated herein by reference).
|
|
10
|
.28**
|
|
Indemnification Agreement, dated August 25, 2008, by and
between Concho Resources, Inc. and Darin G. Holderness (filed as
Exhibit 10.1 to the Companys current Report on
Form 8-K on August 29, 2008, and incorporated herein
by reference).
|
|
10
|
.29**
|
|
Indemnification Agreement, dated February 27, 2008, by and
between Concho Resources, Inc. and William H. Easter III
(filed as Exhibit 10.1 to the Companys current Report
on
Form 8-K
on March 4, 2008, and incorporated herein by reference).
|
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
10
|
.30
|
|
Gas Purchase Contract between COG Oil & Gas LP and Duke
Energy Field Services, LP dated November 1, 2006 (filed as
Exhibit 10.25 to the Companys current Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
Confidential treatment of certain provisions of this exhibit has
previously been granted by the Securities and Exchange
Commission. Omitted material for which confidential treatment
has been granted has been filed separately with the Securities
and Exchange Commission.
|
|
10
|
.31
|
|
Letter Agreement between COG Operating LLC and Navajo Refining
Company, L.P. dated January 15, 2007 (filed as
Exhibit 10.26 to the Companys current Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
|
10
|
.32
|
|
First Amendment to Credit Agreement, dated as of July 6,
2006, among Concho Resources Inc., certain of its subsidiaries,
JPMorgan Chase Bank, N.A. and the other leaders party thereto
(filed as Exhibit 10.27 to the Companys current
Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
|
10
|
.33
|
|
Second Amendment to Credit Agreement, dated as of March 7,
2007, among Concho Resources Inc., certain of its subsidiaries,
JPMorgan Chase Bank, N.A. and the other leaders party thereto
(filed as Exhibit 10.28 to the Companys current
Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
|
10
|
.34**
|
|
Third Amendment to Credit Agreement, dated as of May 19,
2008, by and among Concho Resources Inc., certain of its
subsidiaries, JPMorgan Chase Bank, N.A. and the other leaders
party thereto (filed as Exhibit 10.1 to the Companys
Current Report on
Form 8-K
on May 23, 2008, and incorporated herein by reference).
|
|
10
|
.35**
|
|
Form of option letter agreement among Concho Resources Inc.,
Concho Equity Holdings Corp. and each of Messrs. Leach and Beal
(filed as Exhibit 10.29 to the Companys current
Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
|
10
|
.36**
|
|
Form of option letter agreement among Concho Resources Inc.,
Concho Equity Holdings Corp. and each of Messrs. Copeland,
Kamradt, Thomas and Wright (filed as Exhibit 10.30 to the
Companys current Report on
Form S-1
on June 6, 2007, and incorporated herein by reference).
|
|
10
|
.37**
|
|
Form of Amendment to Stock Option Award Agreement with executive
officers related to the Pre-Combination Options (filed as
Exhibit 10.1 to the Companys current Report on
Form 8-K
on November 20, 2007, and incorporated herein by reference).
|
|
10
|
.38**
|
|
Form of Amendment to Nonstatutory Stock Option Agreement with
executive officers related to the June 2006 Options (filed as
Exhibit 10.2 to the Companys current Report on
Form 8-K
on November 20, 2007, and incorporated herein by reference).
|
|
10
|
.39**
|
|
Form of Restricted Stock Agreement with executive officers
related to the June 2006 Options (filed as Exhibit 10.3 to
the Companys current Report on
Form 8-K
on November 20, 2007, and incorporated herein by reference).
|
|
10
|
.40
|
|
Summary of Director Compensation Program (filed as
Exhibit 10.41 to the Companys Current Report on
Form 10-K
on March 28, 2008, and incorporated herein by reference).
|
|
10
|
.41
|
|
Common Stock Purchase Agreement, dated June 5, 2008, by and
among Concho Resources Inc. and the purchasers named therein
(filed as Exhibit 10.1 to the Companys Current Report
on
Form 8-K
on June 9, 2008, and incorporated herein by reference).
|
|
10
|
.42
|
|
Registration Rights Agreement, dated July 31, 2008, by and
between Concho Resources Inc. and the purchasers named therein
(filed as Exhibit 10.1 to the Companys Current Report
on
Form 8-K
on August 6, 2008, and incorporated herein by reference).
|
|
10
|
.43
|
|
Amended and Restated Credit Agreement, dated July 31, 2008,
by and among Concho Resources Inc., JP Morgan Chase Bank, N.A.,
Bank of America, N.A., Calyon New York Branch, ING Capital LLC
and BNP Paribas and certain other lenders party thereto (filed
as Exhibit 10.2 to the Companys Current Report on
Form 8-K
on August 6, 2008, and incorporated herein by reference).
|
|
21
|
.1(a)
|
|
Subsidiaries of Concho Resources Inc.
|
|
23
|
.1(a)
|
|
Consent of Grant Thornton LLP
|
|
23
|
.2(a)
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
23
|
.3(a)
|
|
Consent of Cawley, Gillespie & Associates, Inc.
|
|
31
|
.1(a)
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
31
|
.2(a)
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1(b)
|
|
Certification of Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2(b)
|
|
Certification of Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
(a) |
|
Filed herewith. |
|
(b) |
|
Furnished herewith. |
|
** |
|
Management contract or compensatory plan or arrangement. |