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 fiscal year ended
December 31,
2010
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or
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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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. 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 whether the registrant has submitted
electronically and posted on its corporate website, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§ 229.405 of this chapter) 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. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o (Do
not check if a smaller reporting company)
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Smaller reporting
company o
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes o No þ
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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:
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$4,936,190,591
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Number of shares of registrants common stock outstanding
as of February 23, 2011:
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103,020,570
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Documents
Incorporated by Reference:
Portions of the registrants definitive proxy statement for
its 2010 Annual Meeting of Stockholders, which will be filed
with the Securities and Exchange Commission within 120 days
of December 31, 2010, are incorporated by reference into
Part III of this report for the year ended
December 31, 2010.
Table of
Contents
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1
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3
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3
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4
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5
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7
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8
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10
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10
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11
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11
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12
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17
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17
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18
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20
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20
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34
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35
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35
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35
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39
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39
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40
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40
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41
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41
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41
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41
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41
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42
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42
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45
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45
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45
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46
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47
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49
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i
Table of
Contents continued
ii
CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Various statements contained in or incorporated by reference
into this report that express a belief, expectation, or
intention, or that are not statements of historical fact, are
forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933 (the
Securities Act) and Section 21E of the
Securities Exchange Act of 1934 (the Exchange Act).
These forward-looking statements include statements, projections
and estimates concerning our operations, performance, business
strategy, oil and natural gas reserves, drilling program capital
expenditures, liquidity and capital resources, the timing and
success of specific projects, outcomes and effects of
litigation, claims and disputes, derivative activities and
potential financing. Forward-looking statements are generally
accompanied by words such as estimate,
project, predict, believe,
expect, anticipate,
potential, could, may,
foresee, plan, goal or other
words that convey the uncertainty of future events or outcomes.
Forward-looking statements are not guarantees of performance. We
have based these forward-looking statements on our current
expectations and assumptions about future events. These
statements are based on certain assumptions and analyses made by
us in light of our experience and our perception of historical
trends, current conditions and expected future developments as
well as other factors we believe are appropriate under the
circumstances. Actual results may differ materially from those
implied or expressed by the forward-looking statements. These
forward-looking statements speak only as of the date of this
report, or if earlier, as of the date they were made. We
disclaim any obligation to update or revise these statements
unless required by securities law, and we caution you not to
rely on them unduly. While our management considers these
expectations and assumptions to be reasonable, they are
inherently subject to significant business, economic,
competitive, regulatory and other risks, contingencies and
uncertainties relating to, among other matters, the risks
discussed in Item 1A. Risk Factors, as well as
those factors summarized below:
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sustained or further declines in the prices we receive for our
oil and natural gas;
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uncertainties about the estimated quantities of oil and natural
gas reserves;
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risks related to the integration of the assets of Marbob Energy
Corporation and affiliates (Marbob) and its former
employees, along with other recently acquired assets, with our
operations;
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drilling and operating risks, including risks related to
properties where we do not serve as the operator;
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the adequacy of our capital resources and liquidity including,
but not limited to, access to additional borrowing capacity
under our credit facility;
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the effects of government regulation, permitting and other legal
requirements, including new legislation or regulation of
hydraulic fracturing;
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difficult and adverse conditions in the domestic and global
capital and credit markets;
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risks related to the concentration of our operations in the
Permian Basin of Southeast New Mexico and West Texas;
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potential financial losses or earnings reductions from our
commodity price and interest rate risk management programs;
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shortages of oilfield equipment, supplies, services and
qualified personnel and increased costs for such equipment,
supplies, services and personnel;
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risks and liabilities associated with acquired properties or
businesses, including the assets acquired in connection with
each of our recent acquisitions;
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uncertainties about our ability to successfully execute our
business and financial plans and strategies;
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uncertainties about our ability to replace reserves and
economically develop our current reserves;
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general economic and business conditions, either internationally
or domestically or in the jurisdictions in which we operate;
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1
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competition in the oil and natural gas industry;
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uncertainty concerning our assumed or possible future results of
operations; and
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our substantial existing indebtedness, as well as the increase
in our indebtedness as a result of our recent acquisitions.
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Reserve engineering is a process of estimating underground
accumulations of oil and natural gas that cannot be measured in
an exact way. The accuracy of any reserve estimate depends on
the quality of available data, the interpretation of such data
and price and cost assumptions made by our reserve engineers. In
addition, the results of drilling, testing and production
activities may justify revisions of estimates that were made
previously. If significant, such revisions would change the
schedule of any further production and development drilling.
Accordingly, reserve estimates may differ from the quantities of
oil and natural gas that are ultimately recovered.
2
PART I
General
Concho Resources Inc., a Delaware corporation
(Concho, Company, we,
us and our), formed in February 2006, is
an independent oil and natural gas company engaged in the
acquisition, development and exploration of oil and natural gas
properties. Our core operating areas are located in the Permian
Basin region of Southeast New Mexico and West Texas, a large
onshore oil and natural gas basin in the United States. The
Permian Basin is one of the most prolific oil and natural gas
producing regions in the United States and is characterized by
an extensive production history, mature infrastructure, long
reserve life, multiple producing horizons and enhanced recovery
potential. We refer to our three core operating areas as the
(i) New Mexico Shelf, where we primarily target the Yeso
and Lower Abo formations, (ii) Delaware Basin, where we
primarily target the Bone Spring formation, and (iii) Texas
Permian, where we primarily target the Wolfberry, a term applied
to the combined Wolfcamp and Spraberry horizons. We intend to
grow our reserves and production through development drilling
and exploration activities on our multi-year project inventory
and through acquisitions that meet our strategic and financial
objectives.
Acquisitions
Marbob
and Settlement Acquisitions
In July 2010, we entered into an asset purchase agreement to
acquire certain of the oil and natural gas leases, interests,
properties and related assets owned by Marbob Energy Corporation
and its affiliates (collectively, Marbob) for
aggregate consideration of (i) cash in the amount of
$1.45 billion, (ii) the issuance to Marbob of a
$150 million 8% unsecured senior note due 2018 and
(iii) the issuance to Marbob of approximately
1.1 million shares of our common stock, subject to purchase
price adjustments, which included downward purchase price
adjustments based on the exercise of third parties of
contractual preferential purchase rights in properties to be
acquired from Marbob (the Marbob Acquisition).
On October 7, 2010, we closed the Marbob Acquisition. At
closing, we paid approximately $1.1 billion in cash plus
the unsecured senior note and common stock described above for a
total purchase price of approximately $1.4 billion. The
total purchase price as originally announced was reduced due to
third party contractual preferential purchase rights in the
Marbob properties. Certain of the third parties
contractual preferential purchase rights became subject to
litigation, as discussed below.
We funded the cash consideration in the Marbob Acquisition with
(a) borrowings under our credit facility and (b) net
proceeds of $292.7 million from a private placement of
approximately 6.6 million shares of our common stock at a
price of $45.30 per share that closed on October 7, 2010.
Certain of the Marbob interests in properties contained
contractual preferential purchase rights by third parties if
Marbob were to sell them. Marbob informed us of its receipt of a
notice from BP America Production Company (BP)
electing to exercise its contractual preferential purchase
rights.
On July 20, 2010, BP announced it was selling all its
assets in the Permian Basin to a subsidiary of Apache
Corporation (Apache). Marbob and BP owned common
interests in certain properties subject to contractual
preferential purchase rights. BP and Apache contested
Marbobs ability to exercise its contractual preferential
purchase rights in this situation. As a result, we and Marbob
filed suit against BP and Apache seeking declaratory judgment
and injunctive relief to protect Marbobs contractual right
to have the option to purchase the interests in these common
properties.
On October 15, 2010, we and Marbob resolved the litigation
with BP and Apache related to the disputed contractual
preferential purchase rights. As a result of the settlement, we
acquired a non-operated interest in substantially all of the oil
and natural gas assets subject to the litigation for
approximately $286 million in cash (the Settlement
Acquisition). We funded the Settlement Acquisition with
borrowings under our credit facility.
3
The properties acquired in the Marbob and Settlement
Acquisitions are primarily located in the Permian Basin of
Southeast New Mexico, including a large acreage position
contiguous to our core Yeso play on the southeast New Mexico
Shelf and a significant acreage position in the Bone Spring play
in the Delaware Basin. The assets acquired in the Marbob and
Settlement Acquisitions contained approximately 72.4 MMBoe
of proved reserves at closing. The results of operations prior
to October 2010 do not include results from the Marbob and
Settlement Acquisitions.
Wolfberry
Acquisitions
In December 2009, together with the acquisition of related
additional interests that closed in early 2010, we closed two
acquisitions of interests in producing and non-producing assets
in the Wolfberry play in Texas for approximately
$270.7 million in cash (the Wolfberry
Acquisitions). The Wolfberry Acquisitions contained
approximately 19.9 MMBoe of proved reserves. The Wolfberry
Acquisitions were primarily funded with borrowings under our
credit facility. The results of operations prior to 2010 do not
include results from the Wolfberry Acquisitions.
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 natural gas properties from persons
affiliated with the Henry Entities. In August 2008 and September
2008, we acquired additional non-operated interests in oil and
natural gas properties from persons affiliated with the Henry
Entities (known as along-side interests). The 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
proved reserves at closing. The Henry Properties are primarily
located in the Wolfberry play of the Permian Basin. We paid
approximately $583.7 million in net cash for the Henry
Properties, which was funded with (i) borrowings under our
credit facility and (ii) net proceeds of approximately
$242.4 million from our private placement of
8.3 million shares of our common stock. The results of
operations prior to August 2008 do not include results from the
Henry Properties acquisition.
Divestiture
In December 2010, we sold certain of our non-core Permian Basin
assets for cash consideration of $103.3 million. For 2010,
these assets produced 1,393 Boe per day, of which approximately
46 percent was oil. The proved reserves of these assets
were approximately 6.0 MMBoe at closing.
Business
and Properties
Our core operations are focused in the Permian Basin of
Southeast New Mexico and West Texas. It underlies an area of
Southeast 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. At December 31, 2010, 97.5 percent
of our total estimated proved reserves were located in our core
operating areas and consisted of approximately 65 percent
oil and 35 percent natural gas. We have assembled a
multi-year inventory of development drilling and exploration
projects, including projects to further evaluate (i) the
aerial extent of the Yeso formation and the Wolfberry play and
(ii) the exploration potential in the Bone Spring and
Wolfcamp formations in the Delaware Basin and the Lower Abo
horizontal oil play, which we believe will allow us to grow
proved reserves and production.
We continually evaluate opportunities that could develop into an
emerging play. We view an emerging play as an area where we can
acquire large undeveloped acreage positions and apply horizontal
drilling
and/or
advanced fracture stimulation technologies to achieve economic
and repeatable production results.
4
The following table sets forth information with respect to
drilling of wells commenced during the periods indicated:
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Years Ended December 31,
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2010
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2009
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Gross wells
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662
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361
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Net wells
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402
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230
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Percent of gross wells:
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Producers
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76.0
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%
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81.7
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Unsuccessful
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0.2
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%
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0.6
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%
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Awaiting completion at year-end
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23.8
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17.7
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100.0
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%
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100.0
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%
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We produced approximately 15.6 MMBoe and 10.9 MMBoe of
oil and natural gas during 2010 and 2009, respectively. In
addition, we increased our average daily production from
30.6 MBoe during the fourth quarter of 2009 to
54.4 MBoe during the fourth quarter of 2010, of which the
fourth quarter of 2010 included daily production of
12.4 MBoe from the Marbob and Settlement Acquisitions.
During 2010, we increased our total estimated proved reserves by
approximately 111.9 MMBoe, including acquisitions of
74.8 MMBoe.
Summary
of Core Operating Areas and Other Plays
The following is a summary of information regarding our core
operating areas and other plays that are further described below:
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Year Ended
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December 31, 2010
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December 31,
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Total
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Gross
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2010 Average
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Proved
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Identified
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Total
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Total
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Daily
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Reserves
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% Proved
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Drilling
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Gross
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Net
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Production
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Areas
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(Mboe)
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PV-10
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% Oil
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Developed
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Locations
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Acreage
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Acreage
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(Boe per Day)
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($ in millions)
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Core Operating Areas:
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New Mexico Shelf
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192,934
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$
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3,979.4
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65.0
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%
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62.4
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%
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2,897
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219,825
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114,210
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26,904
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Delaware Basin
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22,093
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355.7
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40.5
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%
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72.2
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%
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1,101
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266,962
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148,457
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2,721
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Texas Permian
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100,498
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1,594.8
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70.5
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%
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45.2
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%
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1,800
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210,666
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65,855
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11,606
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Other
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7,927
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131.3
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78.4
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%
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34.4
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%
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455
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90,914
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46,221
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1,412
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Total
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323,452
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$
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6,061.2
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(a)
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65.4
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%
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57.0
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%
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6,253
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(b)
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788,367
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374,743
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42,643
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(c)
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(a) |
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Our Standardized Measure at December 31, 2010 was
$4,176.1 million. The present value of estimated future net
revenues discounted at an annual rate of 10 percent
(PV-10)
is not a GAAP financial measure and 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 percent. 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
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
assets. 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 assets.
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. See
Item 1. Business Non-GAAP Financial
Measures and Reconciliations. |
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(b) |
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Of the 6,253 gross identified drilling locations, 2,042
locations were associated with proved reserves. |
5
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(c) |
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Includes production, from the respective close dates in October
2010, from the Marbob and Settlement Acquisitions of
1,139 MBoe (3,120 Boe of daily production for 2010). Also,
includes production of 508 MBoe (1,393 Boe of daily
production for 2010) for the assets divested in December
2010. |
Core
operating areas
New Mexico Shelf. This area represents
our most significant concentration of assets and, at
December 31, 2010, we had estimated proved reserves in this
area of 192.9 MMBoe, or 59.6 percent of our total
proved reserves and 65.6 percent of our
PV-10.
Within this area we target two distinct producing areas, which
we refer to as the shelf assets and the Lower Abo assets. The
shelf assets generally produce out of vertical wells from the
Yeso, San Andres and Grayburg formations, with producing
depths ranging from approximately 900 feet to
7,500 feet. The Lower Abo is a horizontal oil play just
north and northeast of the shelf assets in Lea, Eddy and Chaves
Counties, New Mexico. The Lower Abo play is found at vertical
depths ranging from 6,500 feet to 10,000 feet and is
being developed utilizing horizontal drilling techniques and
advanced fracture and stimulation technology.
During the year ended December 31, 2010, we commenced
drilling or participated in the drilling of 270 (220 net)
wells in this area, of which 227 (189 net) wells were completed
as producers and 43 (32 net) wells were in various stages of
drilling and completion at December 31, 2010. Additionally,
at December 31, 2010, we had 6 (5 net) wells that were
pending completion which were drilled prior to the closing of
the Marbob Acquisition. During 2010, we continued our
development of the Yeso formation on 10 acre spacing.
At December 31, 2010, we had 219,825 gross (114,210
net) acres in this area. At December 31, 2010, on our
assets in this area, we had identified 2,897 (1,889 net)
drilling locations, with proved undeveloped reserves attributed
to 742 (580 net) of such locations. Of these drilling locations,
we identified 2,156 (1,287 net) drilling locations intended to
evaluate the Yeso formation.
Delaware Basin. This area represents a
new core area for us as a result of the Marbob Acquisition. At
December 31, 2010, we had estimated proved reserves in this
area of 22.1 MMBoe, or 6.8 percent of our total proved
reserves and 5.9 percent of our
PV-10.
Within this area we utilize horizontal drilling and fracturing
technologies to target the oil prone Bone Spring formation that
includes three Bone Spring sandstone members and the Avalon
Shale member. Additionally, we utilize vertical drilling and
multistage fracturing to target the oil prone Wolfbone
formation, a new emerging opportunity that is a
combination of stacked unconventional reservoir intervals of the
Bone Spring formation and the Wolfcamp formation. These
formations produce from 4,700 feet to 13,500 feet for
our currently targeted activity. Traditionally, the greater
Delaware Basin has produced from the deeper, natural gas prone
Morrow, Atoka and Strawn formations, as well as from the oil
prone Bone Spring and Delaware formations, with producing depths
ranging from 5,000 feet to 15,000 feet.
During the year ended December 31, 2010, we commenced
drilling or participated in the drilling of 25 (13 net) wells in
this area, of which 8 (2 net) wells were completed as producers
and 17 (11 net) wells were in various stages of drilling and
completion at December 31, 2010. Additionally, at
December 31, 2010, we had 15 (8 net) wells that were
pending completion that were drilled prior to the closing of the
Marbob Acquisition. During 2010, we (i) continued
Marbobs and our development and step-out activity on the
Avalon Shale and Bone Spring formations, (ii) implemented
and evaluated larger fracture stimulation procedures in the
completion of certain horizontal wells, and (iii) drilled
the first well to evaluate the effectiveness of modern fracture
stimulation procedures in the Wolfbone formation.
At December 31, 2010, we had 266,962 gross (148,457
net) acres in this area. At December 31, 2010, on our
assets in this area, we had identified 1,101 (497 net) drilling
locations, with proved undeveloped reserves attributed to 83 (33
net) of such locations. Of these locations, we identified 968
(442 net) locations intended to evaluate the Bone Spring
formation.
Texas Permian. At December 31,
2010, our estimated proved reserves of 100.5 MMBoe in this
area accounted for 31.1 percent of our total proved
reserves and 26.3 percent of our
PV-10 value.
6
Our primary objective in the Texas Permian area is the Wolfberry
in the Midland Basin. Wolfberry is the term applied
to the combined production from the Spraberry and Wolfcamp
horizons out of vertical wellbores, which are typically
encountered at depths of 7,500 feet to 10,500 feet.
These formations are comprised of a sequence of basinal,
interbedded sands, shales and carbonates. We also operate and
develop properties on the Central Basin Platform targeting the
Grayburg, San Andres and Clearfork formations, which are
shallower, and are typically encountered at depths of
4,500 feet to 7,500 feet. The reservoirs in these
formations are largely carbonates, limestones and dolomites.
At December 31, 2010, we had 210,666 gross (65,855
net) acres in this area. In addition, at December 31, 2010,
we had identified 1,800 (893 net) drilling locations, with
proved undeveloped reserves attributed to 1,094 (502 net) of
such drilling locations.
During 2010, we commenced drilling or participated in the
drilling of 313 (162 net) wells in this area, of which 225 (118
net) wells were completed as producers, 1 (0.25 net) well was
unsuccessful and 87 (44 net) wells were in various stages of
drilling and completion at December 31, 2010.
Other
We are involved in other areas in which we had 7.9 MMBoe of
proved reserves at December 31, 2010. The significant other
area we are involved is the Bakken/Three Forks Play.
At December 31, 2010, we held interests in
90,914 gross (46,221 net) acres in these areas. During
2010, we commenced participation in the drilling of 54 (6 net)
wells, which 43 (5 net) wells were producing and 11 (1 net)
wells were in various stages of drilling and completion at
December 31, 2010. At December 31, 2010, we had
7.9 MMBoe of proved reserves in these other areas. At
December 31, 2010, on our properties in these areas, we had
identified 455 (54 net) drilling locations with proved
undeveloped reserves associated with 121 (14 net) of these
drilling locations.
Bakken/Three Forks play. Our acreage in
the Bakken/Three Forks play is in the Williston Basin in
North Dakota, primarily in Mountrail and McKenzie Counties
and represents 42,130 gross (11,180 net) acres which are
included in the 90,914 gross (46,221 net) acres discussed
above. These Mississippian/Devonian age horizons consist of
siltstones encased within and below a highly organic oil-rich
shale package. These horizons are found at vertical depths
ranging from 9,000 feet to 11,000 feet and are being
developed utilizing horizontal drilling techniques and advanced
fracture and stimulation technology.
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
402
|
|
|
|
253
|
|
|
|
211
|
|
|
|
139
|
|
|
|
118
|
|
|
|
77
|
|
Dry
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
164
|
|
|
|
91
|
|
|
|
125
|
|
|
|
83
|
|
|
|
93
|
|
|
|
63
|
|
Dry
|
|
|
1
|
|
|
|
|
|
|
|
3
|
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
Total wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
566
|
|
|
|
344
|
|
|
|
336
|
|
|
|
222
|
|
|
|
211
|
|
|
|
140
|
|
Dry
|
|
|
2
|
|
|
|
|
|
|
|
3
|
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
568
|
|
|
|
344
|
|
|
|
339
|
|
|
|
223
|
|
|
|
212
|
|
|
|
141
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
The following table sets forth information about our wells for
which drilling was in-progress or are pending completion at
December 31, 2010, which are not included in the above
table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling In-Progress
|
|
|
Pending Completion(a)
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development wells
|
|
|
23
|
|
|
|
11
|
|
|
|
82
|
|
|
|
47
|
|
Exploratory wells
|
|
|
19
|
|
|
|
9
|
|
|
|
34
|
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
42
|
|
|
|
20
|
|
|
|
116
|
|
|
|
68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Does not include 21 (13 net) wells pending completion which were
drilled prior to the closing of the Marbob Acquisition. |
Our
Production, Prices and Expenses
The following table sets forth summary information concerning
our production and operating data from continuing operations for
the years ended December 31, 2010, 2009 and 2008. The table
below excludes production and operating data that we have
classified as discontinued operations, which is more fully
described in Note O of the Notes to Consolidated Financial
Statements included in Item 8. Financial Statements
and Supplementary Data. The actual historical data in this
table excludes results from the (i) Marbob and Settlement
Acquisitions for periods prior to their respective close dates
in October 2010, (ii) Wolfberry Acquisitions for periods
prior to 2010 and (iii) Henry Properties acquisition for
periods prior to August 2008. Because of normal production
declines, increased or decreased drilling activities and the
effects of acquisitions or divestitures, the historical
information presented below should not be interpreted as being
indicative of future results.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
10,078
|
|
|
|
7,035
|
|
|
|
4,152
|
|
Natural gas (MMcf)
|
|
|
29,867
|
|
|
|
19,847
|
|
|
|
10,796
|
|
Total (MBoe)
|
|
|
15,056
|
|
|
|
10,343
|
|
|
|
5,951
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
27,611
|
|
|
|
19,274
|
|
|
|
11,344
|
|
Natural gas (Mcf)
|
|
|
81,827
|
|
|
|
54,375
|
|
|
|
29,497
|
|
Total (Boe)
|
|
|
41,249
|
|
|
|
28,337
|
|
|
|
16,260
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl)
|
|
$
|
76.12
|
|
|
$
|
57.97
|
|
|
$
|
95.93
|
|
Oil, with derivatives (Bbl)(a)
|
|
$
|
73.51
|
|
|
$
|
68.60
|
|
|
$
|
86.69
|
|
Natural gas, without derivatives (Mcf)
|
|
$
|
6.88
|
|
|
$
|
5.63
|
|
|
$
|
12.14
|
|
Natural gas, with derivatives (Mcf)(a)
|
|
$
|
7.46
|
|
|
$
|
6.19
|
|
|
$
|
12.21
|
|
Total, without derivatives (Boe)
|
|
$
|
64.60
|
|
|
$
|
50.24
|
|
|
$
|
88.96
|
|
Total, with derivatives (Boe)(a)
|
|
$
|
64.01
|
|
|
$
|
58.53
|
|
|
$
|
82.63
|
|
Operating costs and expenses per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses and workover costs
|
|
$
|
5.83
|
|
|
$
|
5.45
|
|
|
$
|
6.44
|
|
Oil and natural gas taxes
|
|
$
|
5.52
|
|
|
$
|
4.10
|
|
|
$
|
7.32
|
|
General and administrative
|
|
$
|
4.23
|
|
|
$
|
5.13
|
|
|
$
|
6.92
|
|
Depreciation, depletion and amortization
|
|
$
|
16.60
|
|
|
$
|
19.02
|
|
|
$
|
19.73
|
|
|
|
|
(a) |
|
Includes the effect of (i) commodity derivatives designated
as hedges and reported in oil and natural gas sales and
(ii) includes the cash payments/receipts from commodity
derivatives not designated as hedges and reported |
8
|
|
|
|
|
in operating costs and expenses. The following table reflects
the amounts of cash payments/receipts from commodity derivatives
not designated as hedges that were included in computing average
prices with derivatives and reconciles to the amount in gain
(loss) on derivatives not designated as hedges as reported in
the statements of operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Oil and natural gas sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments on oil derivatives
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(30,591
|
)
|
Designated natural gas cash flow hedges reclassified from
accumulated other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
(696
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total effect on oil and natural gas sales
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(31,287
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash (payments on) receipts from oil derivatives
|
|
$
|
(26,281
|
)
|
|
$
|
74,796
|
|
|
$
|
(7,780
|
)
|
Cash receipts from natural gas derivatives
|
|
|
17,414
|
|
|
|
10,955
|
|
|
|
1,426
|
|
Cash payments on interest rate derivatives
|
|
|
(4,957
|
)
|
|
|
(3,335
|
)
|
|
|
|
|
Unrealized
mark-to-market
gain (loss) on commodity and interest rate derivatives
|
|
|
(73,501
|
)
|
|
|
(239,273
|
)
|
|
|
256,224
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as hedges
|
|
$
|
(87,325
|
)
|
|
$
|
(156,857
|
)
|
|
$
|
249,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The presentation of average prices with derivatives is a
non-GAAP measure as a result of including the cash payments
on/receipts from commodity derivatives that are presented in
gain (loss) on derivatives not designated as hedges in the
statements of operations. This presentation of average prices
with derivatives is a means by which to reflect the actual cash
performance of our commodity derivatives for the respective
periods and presents oil and natural gas prices with derivatives
in a manner consistent with the presentation generally used by
the investment community.
9
Productive
Wells
The following table sets forth the number of productive oil and
natural gas wells on our properties at December 31, 2010,
2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Productive Wells
|
|
|
Net Productive Wells
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Core Operating Areas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Mexico Shelf
|
|
|
2,353
|
|
|
|
80
|
|
|
|
2,433
|
|
|
|
1,845
|
|
|
|
36
|
|
|
|
1,881
|
|
Delaware Basin
|
|
|
702
|
|
|
|
308
|
|
|
|
1,010
|
|
|
|
230
|
|
|
|
106
|
|
|
|
336
|
|
Texas Permian
|
|
|
1,463
|
|
|
|
14
|
|
|
|
1,477
|
|
|
|
513
|
|
|
|
2
|
|
|
|
515
|
|
Other
|
|
|
237
|
|
|
|
39
|
|
|
|
276
|
|
|
|
11
|
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
4,755
|
|
|
|
441
|
|
|
|
5,196
|
|
|
|
2,599
|
|
|
|
144
|
|
|
|
2,743
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Core Operating Areas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Mexico Shelf
|
|
|
1,464
|
|
|
|
68
|
|
|
|
1,532
|
|
|
|
1,047
|
|
|
|
30
|
|
|
|
1,077
|
|
Delaware Basin
|
|
|
300
|
|
|
|
123
|
|
|
|
423
|
|
|
|
133
|
|
|
|
25
|
|
|
|
158
|
|
Texas Permian
|
|
|
1,740
|
|
|
|
69
|
|
|
|
1,809
|
|
|
|
464
|
|
|
|
11
|
|
|
|
475
|
|
Other
|
|
|
65
|
|
|
|
131
|
|
|
|
196
|
|
|
|
6
|
|
|
|
6
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
3,569
|
|
|
|
391
|
|
|
|
3,960
|
|
|
|
1,650
|
|
|
|
72
|
|
|
|
1,722
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Core Operating Areas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Mexico Shelf
|
|
|
1,227
|
|
|
|
70
|
|
|
|
1,297
|
|
|
|
837
|
|
|
|
31
|
|
|
|
868
|
|
Delaware Basin
|
|
|
300
|
|
|
|
122
|
|
|
|
422
|
|
|
|
135
|
|
|
|
25
|
|
|
|
160
|
|
Texas Permian
|
|
|
1,625
|
|
|
|
71
|
|
|
|
1,696
|
|
|
|
381
|
|
|
|
14
|
|
|
|
395
|
|
Other
|
|
|
49
|
|
|
|
89
|
|
|
|
138
|
|
|
|
4
|
|
|
|
5
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
3,201
|
|
|
|
352
|
|
|
|
3,553
|
|
|
|
1,357
|
|
|
|
75
|
|
|
|
1,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing
Arrangements
General. We market our 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 products group, asset managers and our
corporate reservoir 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.
Oil. We do not transport, refine or
process the oil we produce. A significant portion of our oil in
Southeast New Mexico is connected directly to oil gathering
pipelines. Most of our gathered oil in this area is utilized in
a two-refinery complex in Southeast New Mexico. In 2010, we
placed a significant portion of our West Texas production on
pipeline. Most of this production is sweet crude and is
transported by third parties to the Cushing, Oklahoma hub. The
balance of our oil in these areas that is not directly connected
to pipeline is trucked to unloading stations on those same
pipelines. We sell the majority of the oil we produce under
contracts using market-based pricing. This price is then
adjusted for differentials based upon delivery location and oil
quality.
Natural Gas. We consider all natural
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 natural gas under individually negotiated
natural gas purchase contracts using market-based pricing.
10
The majority of our natural gas is subject to term agreements
that extend at least three years from the date of the subject
contract.
The majority of the natural gas we sell is casinghead gas sold
at the lease under a percentage of proceeds processing contract.
The purchaser gathers our casinghead natural gas in the field
where it is produced and transports it via pipeline to a natural
gas processing plant where the natural gas liquid products are
extracted and sold by the processor. The remaining natural gas
product is residue gas, or dry gas, which is placed on residue
pipeline systems available in the area. Under our percentage of
proceeds contracts, 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.
In a limited number of cases (typically dry gas production), the
natural 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 2010, revenues from oil and natural gas sales to Navajo
Refining Company, L.P., ConocoPhillips Company, DCP Midstream,
LP and Plains Marketing and Transportation Inc. accounted for
approximately 32 percent, 14 percent, 12 percent
and 11 percent, respectively, of our total operating
revenues. While the loss of any 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 any 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 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.
In addition to the competition for drilling and workover
equipment we are also affected by the availability of related
equipment and materials. 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 exploration activities and
cause significant price increases. The past shortages of
personnel made it difficult to attract and retain personnel with
experience in the oil and natural gas industry and 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 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 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 (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,
without making a cost of service filing. Every five years, the
FERC reviews the appropriateness of the index in relation to
industry costs. On March 21, 2006, FERC issued a decision
setting the index for the period July 1, 2006 through
July 1, 2011 at the Producer Price Index for Finished Goods
(the PPI-FG) plus 1.3 percent. Most recently,
on December 16, 2010, the FERC established a new price
index of PPI-FG plus 2.65 percent for the five-year period
beginning July 1, 2011. 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.
Effective November 4, 2009, pursuant to the Energy
Independence and Security Act of 2007, the Federal Trade
Commission (FTC) issued a rule prohibiting market
manipulation in the petroleum industry. The FTC rule prohibits
any person, directly or indirectly, in connection with the
purchase or sale of oil, gasoline or petroleum distillates at
wholesale from knowingly engaging in any act, practice or course
of business, including the making of any untrue statement of
material fact, that operates or would operate as a fraud or
deceit upon any person, or intentionally failing to state a
material fact that under the circumstances renders a statement
made by such person misleading, provided that such omission
distorts or is likely to distort market conditions for any such
product. A violation of this rule may result in civil penalties
of up to $1 million per day per violation, in addition to
any applicable penalty under the Federal Trade Commission Act.
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 Act), the Natural Gas Policy Act of 1978
(the Natural Gas Policy Act) 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
12
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.
In August 2005, Congress enacted the Energy Policy Act of 2005
(the 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 or Natural Gas Policy 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 natural gas sales,
purchases or transportation subject to FERC jurisdiction, which
now includes the annual reporting requirements under Order
No. 704, described below. 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 a rule (Order
No. 704), as clarified in orders on rehearing,
requiring that any market participant, including a producer such
as us, 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 natural 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 (the Competition Bill)
and H.B. 1920 (the LUG Bill). The Competition Bill
gives the Railroad Commission of Texas 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 Railroad Commission 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
13
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 Railroad Commission with procedures unique to
lost and unaccounted for natural gas issues. It extends the
types of information that can be requested, provides producers
with an annual audit right, and provides the Railroad Commission
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, and the Railroad
Commission rules implementing the Railroad Commissions
authority pursuant to the bills became effective on
April 28, 2008. We note that the Railroad Commission is
subject to a sunset condition. If the Texas Legislature does not
continue the Railroad Commission, the Railroad Commission will
be abolished effective September 1, 2011, and will begin a
one-year wind-down process. The Sunset Advisory Commission has
recommended certain organizational changes be made to the
Railroad Commission. We cannot tell what, if any, changes will
be made to the Railroad Commission as a result of the pending
regular session or any called sessions of the Texas Legislature
in 2011, but we do not believe that any such changes would
affect our business in a way that would be materially different
from the way such changes would affect our competitors.
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 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;
|
|
|
|
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;
|
|
|
|
limit or prohibit drilling activities on certain lands lying
within wilderness, wetlands and other protected areas; and
|
|
|
|
require remedial measures to mitigate pollution from former and
ongoing operations, such as requirements to close pits and plug
abandoned wells.
|
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
natural gas industry increases the cost of doing business in the
industry and consequently affects profitability. Additionally,
environmental laws and regulations are
14
revised frequently, and any changes that result in more
stringent and costly waste handling, disposal and cleanup
requirements for the oil and natural 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 (the 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 (the 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 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 (the
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 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 operations to prevent future contamination.
Water discharges. The federal Water
Pollution Control Act (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.
Climate change. In December 2009 EPA
determined that emissions of carbon dioxide, methane and other
greenhouse gases, or GHGs, present an endangerment
to public health and the environment because emissions of such
gases are, according to the EPA, contributing to warming of the
earths atmosphere and other climatic changes. Based on
these findings, the EPA has begun adopting and implementing
regulations to restrict emissions of GHGs
15
under existing provisions of the Clean Air Act
(CAA). The EPA recently adopted two sets of rules
regulating GHG emissions under the CAA, one of which requires a
reduction in emissions of GHGs from motor vehicles and the other
of which regulates emissions of GHGs from certain large
stationary sources, effective January 2, 2011. The
EPAs rules relating to emissions of GHGs from large
stationary sources of emissions are currently subject to a
number of legal challenges, but the federal courts have thus far
declined to issue any injunctions to prevent EPA from
implementing, or requiring state environmental agencies to
implement, the rules. The EPA has also adopted rules requiring
the reporting of GHG emissions from specified large GHG emission
sources in the United States, including petroleum refineries, on
an annual basis beginning in 2011 for emissions occurring after
January 1, 2010, as well as certain onshore oil and natural
gas facilities, on an annual basis beginning in 2012 for
emissions occurring in 2011.
In addition, Congress has from time to time considered adopting
legislation to reduce emissions of GHGs and almost one-half of
the states have already taken legal measures to reduce emissions
of GHGs gases primarily through the planned development of GHG
emission inventories
and/or
regional GHG cap and trade programs. Most of these cap and trade
programs work by requiring major sources of emissions, such as
electric power plants, or major producers of fuels, such as
refineries and natural gas processing plants, to acquire and
surrender emission allowances. The number of allowances
available for purchase is reduced each year in an effort to
achieve the overall GHG emission reduction goal.
The adoption of legislation or regulatory programs to reduce
emissions of GHGs could require us to incur increased operating
costs, such as costs to purchase and operate emissions control
systems, to acquire emissions allowances, or to comply with new
regulatory or reporting requirements. Any such legislation or
regulatory programs could also increase the cost of consuming,
and thereby reduce demand for, the oil and natural gas we
produce. Consequently, legislation and regulatory programs to
reduce emissions of GHGs could have an adverse effect on our
business, financial condition and results of operations.
Finally, it should be noted that some scientists have concluded
that increasing concentrations of GHGs in the earths
atmosphere may produce climate changes that have significant
physical effects, such as increased frequency and severity of
storms, droughts, and floods and other climatic events. If any
such effects were to occur, they could have an adverse effect on
our financial condition and results of operations.
Hydraulic fracturing. Hydraulic
fracturing is an important and common practice that is used to
stimulate production of hydrocarbons from tight formations. We
routinely utilize hydraulic fracturing techniques in many of our
drilling and completion programs. The process involves the
injection of water, sand and chemicals under pressure into the
formation to fracture the surrounding rock and stimulate
production. The process is typically regulated by state oil and
natural gas commissions. However, the EPA recently asserted
federal regulatory authority over hydraulic fracturing involving
diesel additives under the Safe Drinking Water Acts
Underground Injection Control Program. While the EPA has yet to
take any action to enforce or implement this newly asserted
regulatory authority, industry groups have filed suit
challenging the EPAs recent decision. At the same time,
the EPA has commenced a study of the potential environmental
impacts of hydraulic fracturing activities, and a committee of
the United States House of Representatives is also conducting an
investigation of hydraulic fracturing practices. Legislation has
been introduced before Congress to provide for federal
regulation of hydraulic fracturing and to require disclosure of
the chemicals used in the fracturing process. In addition, some
states have adopted, and other states are considering adopting,
regulations that could impose more stringent permitting,
disclosure and well construction requirements on hydraulic
fracturing operations. For example, Colorado, Pennsylvania, and
Wyoming have each adopted a variety of well construction, set
back, and disclosure regulations limiting how fracturing can be
performed and requiring various degrees of chemical disclosure.
If new laws or regulations that significantly restrict hydraulic
fracturing are adopted, such laws could make it more difficult
or costly for us to perform fracturing to stimulate production
from tight formations. In addition, if hydraulic fracturing
becomes regulated at the federal level as a result of federal
legislation or regulatory initiatives by the EPA, our fracturing
activities could become subject to additional permitting
requirements, and also to attendant permitting delays and
potential increases in costs. Restrictions on hydraulic
fracturing could also reduce the amount of oil and natural gas
that we are ultimately able to produce from our reserves.
Endangered species. The federal
Endangered Species Act and analogous state laws regulate
activities that could have an adverse effect on threatened or
endangered species. Some of our well drilling operations are
16
conducted in areas where protected species are known to exist.
In these areas, we may be obligated to develop and implement
plans to avoid potential adverse impacts to protected species,
and we may be prohibited from conducting drilling operations in
certain locations or during certain seasons, such as breeding
and nesting seasons, when our operations could have an adverse
effect on the species. It is also possible that a federal or
state agency could order a complete halt to drilling activities
in certain locations if it is determined that such activities
may have a serious adverse effect on a protected species. The
presence of a protected species in areas where we perform
drilling activities could impair our ability to timely complete
well drilling and development and could adversely affect our
future production from those areas.
National Environmental Policy Act. Oil
and natural gas exploration and production activities on federal
lands are subject to the National Environmental Policy Act (the
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 development of some of our 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 (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. Also, pursuant to OSHA, the Occupational
Safety and Health Administration has established a variety of
standards relating to workplace exposure to hazardous substances
and employee health and safety. We believe that we are in
substantial compliance with the applicable requirements of OSHA
and comparable laws.
We believe that we are in substantial compliance with 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 during 2010. 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 2011. 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, 2010, we employed 443 persons. Of
these, 332 worked at our Midland, Texas headquarters and our
Texas field operations and 111 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 good. 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 a 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 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.
17
Non-GAAP Financial
Measures and Reconciliations
PV-10
PV-10 is
derived from the standardized measure of discounted future net
cash flows, which is the most directly comparable GAAP financial
measure.
PV-10 is a
computation of the standardized measure of discounted future net
cash flows on a pre-tax basis.
PV-10 is
equal to the standardized measure of discounted future net cash
flows at the applicable date, before deducting future income
taxes, discounted at 10 percent. 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
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
assets. 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 assets.
PV-10,
however, is not a substitute for the standardized measure of
discounted future net cash flows. Our
PV-10
measure and the standardized measure of discounted future net
cash flows do not purport to present the fair value of our oil
and natural gas reserves.
The following table provides a reconciliation of
PV-10 to the
standardized measure of discounted future net cash flows at
December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
PV-10
|
|
$
|
6,061.2
|
|
|
$
|
2,764.8
|
|
|
$
|
1,663.2
|
|
Present value of future income taxes discounted at 10%
|
|
|
(1,885.1
|
)
|
|
|
(842.8
|
)
|
|
|
(464.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
4,176.1
|
|
|
$
|
1,922.0
|
|
|
$
|
1,199.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX
We define EBITDAX as net income (loss), plus
(1) exploration and abandonments expense,
(2) depreciation, depletion and amortization expense,
(3) accretion expense, (4) impairments of long-lived
assets, (5) non-cash stock-based compensation expense,
(6) bad debt expense, (7) ineffective portion of cash
flow hedges, (8) unrealized (gain) loss on derivatives not
designated as hedges, (9) (gain) loss on sale of assets, net,
(10) interest expense, (11) federal and state income
taxes and (12) similar items listed above that are
presented in discontinued operations. EBITDAX is not a measure
of net income or cash flow as determined by GAAP.
Our EBITDAX measure provides additional information which may be
used to better understand our operations, and it is also a
material component of one of the financial covenants under our
credit facility. EBITDAX is one of several metrics that we use
as a supplemental financial measurement in the evaluation of our
business and should not be considered as an alternative to, or
more meaningful than, net income, as an indicator of our
operating performance. Certain items excluded from EBITDAX are
significant components in understanding and assessing a
companys financial performance, such as a companys
cost of capital and tax structure, as well as the historic cost
of depreciable and depletable assets. EBITDAX, as used by us,
may not be comparable to similarly titled measures reported by
other companies. We believe that EBITDAX is a widely followed
measure of operating performance and is one of many metrics used
by our management team and by other users of our consolidated
financial statements, including by lenders pursuant to a
covenant in our credit facility. For example, EBITDAX can be
used to assess our operating performance and return on capital
in comparison to other independent exploration and production
companies without regard to financial or capital structure, and
to assess the financial performance of our assets and our
company without regard to capital structure or historical cost
basis. Further, under our credit facility, an event of default
could arise if we were not able to satisfy and remain in
compliance with specified financial ratios, including the
maintenance of a quarterly ratio of total debt to consolidated
last twelve months EBITDAX of no greater than 4.0 to 1.0.
Non-compliance with this ratio could trigger an event of default
under our credit facility, which then could trigger an event of
default under our indentures.
18
The following table provides a reconciliation of net income
(loss) to EBITDAX:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Net income (loss)
|
|
$
|
204,370
|
|
|
$
|
(9,802
|
)
|
|
$
|
278,702
|
|
|
$
|
25,360
|
|
|
$
|
19,668
|
|
Exploration and abandonments
|
|
|
10,324
|
|
|
|
10,632
|
|
|
|
38,468
|
|
|
|
29,097
|
|
|
|
5,610
|
|
Depreciation, depletion and amortization
|
|
|
249,850
|
|
|
|
196,736
|
|
|
|
117,406
|
|
|
|
69,360
|
|
|
|
53,009
|
|
Accretion of discount on asset retirement obligations
|
|
|
1,503
|
|
|
|
917
|
|
|
|
761
|
|
|
|
360
|
|
|
|
270
|
|
Impairments of long-lived assets
|
|
|
11,614
|
|
|
|
7,880
|
|
|
|
11,522
|
|
|
|
4,777
|
|
|
|
7,913
|
|
Non-cash stock-based compensation
|
|
|
12,931
|
|
|
|
9,040
|
|
|
|
5,223
|
|
|
|
3,841
|
|
|
|
9,144
|
|
Bad debt expense
|
|
|
870
|
|
|
|
(1,035
|
)
|
|
|
2,905
|
|
|
|
|
|
|
|
|
|
Ineffective portion of cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
(1,336
|
)
|
|
|
821
|
|
|
|
(1,193
|
)
|
Unrealized (gain) loss on derivatives not designated as hedges
|
|
|
73,501
|
|
|
|
239,273
|
|
|
|
(256,224
|
)
|
|
|
22,089
|
|
|
|
|
|
(Gain) loss on sale of assets, net
|
|
|
58
|
|
|
|
114
|
|
|
|
(777
|
)
|
|
|
(368
|
)
|
|
|
(3
|
)
|
Interest expense
|
|
|
60,087
|
|
|
|
28,292
|
|
|
|
29,039
|
|
|
|
36,042
|
|
|
|
30,567
|
|
Income tax expense (benefit)
|
|
|
122,649
|
|
|
|
(21,510
|
)
|
|
|
157,434
|
|
|
|
12,709
|
|
|
|
12,467
|
|
Discontinued operations
|
|
|
(4,763
|
)
|
|
|
14,671
|
|
|
|
18,180
|
|
|
|
13,304
|
|
|
|
11,622
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX
|
|
$
|
742,994
|
|
|
$
|
475,208
|
|
|
$
|
401,303
|
|
|
$
|
217,392
|
|
|
$
|
149,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
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
Oil
and natural gas prices are volatile. A decline in 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 natural gas
properties depend primarily upon the prices we receive for our
oil and natural gas production and the prices prevailing from
time to time for oil and natural gas. 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
cash flow we have available for capital expenditures and our
ability to borrow money or raise additional capital. The prices
for oil and natural gas are subject to a variety of factors
beyond our control, including:
|
|
|
|
|
the level of consumer demand for oil and natural gas;
|
|
|
|
the domestic and foreign supply of oil and natural gas;
|
|
|
|
commodity processing, gathering and transportation availability,
and the availability of refining capacity;
|
|
|
|
the price and level of imports of foreign oil and natural gas;
|
|
|
|
the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls;
|
|
|
|
domestic and foreign governmental regulations and taxes;
|
|
|
|
the price and availability of alternative fuel sources;
|
|
|
|
weather conditions;
|
|
|
|
political conditions or hostilities in oil and natural gas
producing regions, including the Middle East, Africa and South
America;
|
|
|
|
technological advances affecting energy consumption;
|
|
|
|
variations between product prices at sales points and applicable
index prices; and
|
|
|
|
worldwide economic conditions.
|
Furthermore, oil and natural gas prices were volatile in 2010.
For example, the NYMEX oil prices in 2010 ranged from a high of
$91.51 to a low of $68.01 per Bbl and the NYMEX natural gas
prices in 2010 ranged from a high of $6.01 to a low of $3.29 per
MMBtu. Further, the NYMEX oil prices and NYMEX natural gas
prices reached lows of $84.32 per Bbl and $3.87 per MMBtu,
respectively, during the period from January 1, 2011 to
February 23, 2011.
Declines in oil and natural gas prices would not only reduce our
revenue, but could also reduce the amount of 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 natural gas industry
experiences 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.
.
20
Our
estimates of proved reserves have been prepared under SEC rules
which went into effect for fiscal years ending on or after
December 31, 2009, which may make comparisons to prior to
December 31, 2009 difficult and could limit our ability to book
additional proved undeveloped reserves in the
future.
This report presents estimates of our proved reserves as of
December 31, 2010, which have been prepared and presented
under the recently changed SEC rules that are effective for
fiscal years ending on or after December 31, 2009, and
require SEC reporting companies to prepare their reserves
estimates using revised reserve definitions and revised pricing
based on a
12-month
unweighted average of the
first-day-of-the-month
pricing. The previous rules required that reserve estimates be
calculated using
last-day-of-the-year
pricing. The pricing that was used for estimates of our reserves
as of December 31, 2010 was based on an unweighted average
twelve month West Texas Intermediate posted price of $75.96 per
Bbl for oil and a Henry Hub spot natural gas price of $4.38 per
MMBtu for natural gas. As a result of this change in pricing
methodology, direct comparisons of our reported reserves amounts
under the rules prior to December 31, 2009 may be more
difficult.
Another impact of the SEC rules is a general requirement that,
subject to limited exceptions, proved undeveloped reserves may
only be booked if they relate to wells scheduled to be drilled
within five years of the date of booking. This rule has limited
and may continue to limit our potential to book additional
proved undeveloped reserves as we pursue our drilling program,
particularly as we develop our significant acreage in West Texas
and Southeast New Mexico. Moreover, we may be required to write
down our proved undeveloped reserves if we do not drill on those
reserves within the required five-year timeframe.
Drilling
for and producing 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 exploration, development and
production activities. Our oil and natural gas exploration and
production activities are subject to numerous risks, including
the risk that drilling will not result in commercially viable
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:
|
|
|
|
|
delays imposed by or resulting from compliance with regulatory
and contractual requirements;
|
|
|
|
pressure or irregularities in geological formations;
|
|
|
|
shortages of or delays in obtaining equipment and qualified
personnel;
|
|
|
|
equipment failures or accidents;
|
|
|
|
adverse weather conditions;
|
|
|
|
reductions in oil and natural gas prices;
|
|
|
|
surface access restrictions;
|
|
|
|
loss of title or other title related issues;
|
|
|
|
oil, natural gas liquids or natural gas gathering,
transportation and processing availability restrictions or
limitations; and
|
|
|
|
limitations in the market for oil and natural gas.
|
21
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 oil
and/or
natural gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and natural gas
reserves and of future net cash flows depend upon a number of
variable factors and assumptions, including the following:
|
|
|
|
|
historical production from the area compared with production
from other producing areas;
|
|
|
|
the assumed effects of regulations by governmental agencies;
|
|
|
|
the quality, quantity and interpretation of available relevant
data;
|
|
|
|
assumptions concerning future commodity prices; and
|
|
|
|
assumptions concerning future operating costs; severance, ad
valorem and excise taxes; development costs; and workover and
remedial costs.
|
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:
|
|
|
|
|
the quantities of oil and natural gas that are ultimately
recovered;
|
|
|
|
the production and operating costs incurred;
|
|
|
|
the amount and timing of future development
expenditures; and
|
|
|
|
future commodity prices.
|
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.
The
Standardized Measure of our estimated reserves is not an
accurate estimate of the current fair value of our estimated
proved oil and natural gas reserves.
Standardized Measure is a reporting convention that provides a
common basis for comparing oil and natural gas companies subject
to the rules and regulations of the SEC. Our non-GAAP financial
measure,
PV-10, is a
similar reporting convention that we have disclosed in this
report. Both measures require the use of operating and
development costs prevailing as of the date of computation.
Consequently, they will not reflect the prices ordinarily
received or that will be received for oil and natural gas
production because of varying market conditions, nor may it
reflect the actual costs that will be required to produce or
develop the oil and natural 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 10 percent discount
factor, which is required by the rules and regulations of 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 natural gas
industry in general. Therefore, Standardized Measure or
PV-10
included or incorporated by reference in this report should not
be construed as accurate estimates of the current fair value of
our proved reserves. 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.
If average oil prices were $10.00 per Bbl lower than the average
price we used, our
PV-10 at
December 31, 2010, would have decreased from
$6,061.2 million to $5,182.5 million. If average
natural gas prices were $1.00 per Mcf lower than the average
price we used, our
PV-10 at
December 31, 2010, would have decreased from
$6,061.2 million to $5,635.9 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.
22
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 oil and
natural gas reserves.
The oil and natural gas industry is capital intensive. We make
and expect to continue to make substantial capital expenditures
for the acquisition, exploration and development of oil and
natural gas reserves. At December 31, 2010, total debt
outstanding under our credit facility was $613.5 million
(total debt at December 31, 2010 was $1.7 billion),
and approximately $1.4 billion was available to be borrowed
under our credit facility. Expenditures for exploration and
development of oil and natural gas properties are the primary
use of our capital resources. We incurred approximately
$2.4 billion in acquisition, exploration and development
activities (excluding asset retirement obligations) during the
year ended December 31, 2010 on our properties
($1.7 billion related to acquisitions), and under our 2011
capital budget, we intend to invest approximately
$1.1 billion for exploration and development activities and
acquisition of leasehold acreage, dependent on our cash flow and
our commodity price outlook.
We intend to finance our future capital expenditures, other than
significant acquisitions, 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 common stock.
Additional borrowings under our credit facility or the issuance
of additional debt securities 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. If
we incur certain additional indebtedness, our borrowing base
under our credit facility may be reduced. 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:
|
|
|
|
|
our proved reserves;
|
|
|
|
the level of oil and natural gas we are able to produce from
existing wells;
|
|
|
|
the prices at which our oil and natural gas are sold;
|
|
|
|
global credit and securities markets;
|
|
|
|
the ability and willingness of lenders and investors to provide
capital and the cost of the capital; and
|
|
|
|
our ability to acquire, locate and produce new reserves.
|
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 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 the 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
have substantial indebtedness and may incur substantially more
debt. Higher levels of indebtedness make us more vulnerable to
economic downturns and adverse developments in our
business.
We have incurred debt amounting to approximately
$1.7 billion at December 31, 2010. At
December 31, 2010, the borrowing base under our credit
facility was $2.0 billion, of which approximately
$1.4 billion was available to be borrowed.
23
As a result of our indebtedness, we will need to use a portion
of our cash flow to pay interest, which will reduce the amount
we will have available to finance our operations and other
business activities and could limit our flexibility in planning
for or reacting to changes in our business and the industry in
which we operate. Our indebtedness under our credit facility is
at a variable interest rate, and so a rise in interest rates
will generate greater interest expense to the extent we do not
have applicable interest rate fluctuation hedges. The amount of
our debt may also cause us to be more vulnerable to economic
downturns and adverse developments in our business.
We may incur substantially more debt in the future. The
indentures governing certain of our outstanding senior notes
contain restrictions on our incurrence of additional
indebtedness. These restrictions, however, are subject to a
number of qualifications and exceptions, and under certain
circumstances, we could incur substantial additional
indebtedness in compliance with these restrictions. Moreover,
these restrictions do not prevent us from incurring obligations
that do not constitute indebtedness under the indentures.
Our ability to meet our debt obligations and other expenses will
depend on our future performance, which will be affected by
financial, business, economic, regulatory and other factors,
many of which we are unable to control. If our cash flow is not
sufficient to service our debt, we may be required to refinance
debt, sell assets or sell additional shares of common stock on
terms that we may not find attractive if it may be done at all.
Further, our failure to comply with the financial and other
restrictive covenants relating to our indebtedness could result
in a default under that indebtedness, which could adversely
affect our business, financial condition and results of
operations.
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 oil and natural gas exploration, development and production,
and related 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 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, 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.
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 oil and natural gas exploration, development
and production, and related 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, in some instances, issuance of
orders or injunctions limiting or requiring discontinuation of
certain 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 for a variety of
environmental costs 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
24
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.
We may
not be able to obtain funding at all, or to obtain funding on
acceptable terms, because of the deterioration of the credit and
capital markets. This may hinder or prevent us from meeting our
future capital needs and from refinancing our existing
indebtedness.
In recent years, global financial markets and economic
conditions experienced disruptions and volatility, which caused
a deterioration in the credit and capital markets. A recurrence
of similar conditions in the future could make it difficult for
us to obtain funding for our ongoing capital needs.
In volatile financial markets, the cost of raising money in the
debt and equity capital markets can fluctuate widely and the
availability of funds from those markets may diminish
significantly. Due to these factors, we cannot be certain that
funding will be available if needed and to the extent required,
on acceptable terms. In addition, we may be unable to refinance
our existing indebtedness as it comes due on terms that are
acceptable to us or at all. If we cannot meet our capital needs
or refinance our existing indebtedness, 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, 2010, we had approximately
$613.5 million of outstanding debt under our credit
facility, and our borrowing base was $2.0 billion. 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, between redeterminations we
and, if requested by
662/3 percent
of our lenders, our lenders, may each request one special
redetermination. 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. If we incur certain
additional indebtedness, our borrowing base under our credit
facility may be reduced. We expect to utilize cash flow from
operations, bank borrowings, equity financings and asset sales
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 primarily in the Permian Basin
of Southeast 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 Southeast
New Mexico and West Texas. At December 31, 2010,
approximately 97.5 percent of our proved reserves were
attributable to properties located in this area. 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 oil, natural gas or natural gas
liquids.
In addition to the geographic concentration of our producing
properties described above, at December 31, 2010,
approximately (i) 43.2 percent of our proved reserves
were attributable to the Yeso formation, which includes both the
Paddock and Blinebry intervals, underlying our oil and natural
gas properties located in Southeast New Mexico; and
(ii) 27.4 percent of our proved reserves were
attributable to the Wolfberry play in West Texas. This
25
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 natural 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 proved oil and natural 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 natural gas properties. To the extent such
tests indicate a reduction of the estimated useful life or
estimated future cash flows of our oil and natural 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.
We
periodically evaluate our unproved oil and natural gas
properties for impairment, and could be required to recognize
noncash charges to earnings of future periods.
At December 31, 2010, we carried unproved property costs of
$633.9 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.
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 plays
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 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.
Commodity price risk management arrangements expose us to the
risk of financial loss and may limit our ability to benefit from
increases in 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, 2010, the net unrealized loss
on our commodity price risk
26
management contracts was approximately $135 million. An
average increase in the commodity price of $10.00 per barrel of
oil and $1.00 per MMBtu for natural gas from the commodity
prices at December 31, 2010, would have increased the net
unrealized loss on our commodity price risk management
contracts, as reflected on our balance sheet at
December 31, 2010, by $208 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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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 identified and scheduled the drilling of certain of our
drilling locations as an estimation of our future multi-year
development activities on our existing acreage. At
December 31, 2010, we had identified 6,253 gross
drilling locations with proved reserves attributable to 2,042 of
such locations. These identified locations represent a
significant part of our growth strategy. Our ability to drill
and develop these locations depends on a number of
uncertainties, including (i) our ability to timely drill
wells on lands subject to complex development terms and
circumstances; (ii) the availability of capital, equipment,
services and personnel; (iii) seasonal conditions;
(iv) regulatory and third party approvals; (v) oil and
natural gas prices; and (vi) drilling and recompletion
costs and results. Because of these uncertainties, we may never
drill the numerous potential locations we have identified or
produce oil or natural gas from these or any other potential
locations. 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
43 percent of our total estimated proved reserves at
December 31, 2010, were undeveloped, and those reserves may
not ultimately be developed.
At December 31, 2010, approximately 43 percent of our
total estimated 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 assumptions, however, may not prove correct.
Our reserve report at December 31, 2010 includes estimates
of total future development costs over the next five years
associated with our proved undeveloped reserves of approximately
$1.7 billion. If we choose not to spend the capital to
develop these reserves, or if we are not otherwise able to
successfully develop these reserves, we will be required to
write-off these reserves. In addition, under the SECs
reserve rules, because proved undeveloped reserves may be booked
only if they relate to wells scheduled to be drilled within five
years of the date of booking, we may be required to write off
any proved undeveloped reserves
27
that are not developed within this five year timeframe. Any such
write-offs of our reserves could reduce our ability to borrow
money and could reduce the value of our securities.
Unless
we replace our 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 and exploration
activities or acquire properties containing proved reserves, our
proved reserves will decline as those reserves are produced.
Producing oil and natural gas reservoirs generally are
characterized by declining production rates that vary depending
upon reservoir characteristics and other factors. Our future 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 or assets 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 and the indentures governing
certain of our senior notes impose certain limitations on our
ability to enter into mergers or combination transactions. Our
credit facility and the indentures governing certain of our
senior notes also limit our ability to incur certain
indebtedness, which could indirectly limit our ability to engage
in acquisitions of businesses or assets. If we desire to engage
in an acquisition that is otherwise prohibited by our credit
facility or the indentures governing certain of our senior
notes, we will be required to seek the consent of our lenders or
the holders of the senior notes in accordance with the
requirements of the facility or the indentures, which consent
may be withheld by the lenders under our credit facility or such
holders of senior notes in their sole 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 or assets, 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 may incur additional debt
or issue additional equity to pay for any future acquisitions,
subject to the limitations described above.
Our
acquisitions may prove to be worth less than what we paid
because of uncertainties in evaluating recoverable reserves and
could expose us to potentially significant
liabilities.
We obtained the majority of our current reserve base through
acquisitions of producing properties and undeveloped acreage. We
expect that acquisitions will continue to contribute to our
future growth. In connection with these and potential future
acquisitions, we are often only able to perform limited due
diligence.
Successful acquisitions of oil and natural gas properties
require an assessment of a number of factors, including
estimates of recoverable reserves, the timing of recovering
reserves, exploration potential, future oil and natural gas
prices, operating costs and potential environmental, regulatory
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.
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There may be threatened, contemplated, asserted or other claims
against the acquired assets related to environmental, title,
regulatory, tax, contract, litigation or other matters of which
we are unaware, which could materially and adversely affect our
production, revenues and results of operations. We are sometimes
able to obtain contractual indemnification for preclosing
liabilities, including environmental liabilities, but we
generally acquire interests in properties on an as
is basis with limited remedies for breaches of
representations and warranties. In addition, even when we are
able to obtain such indemnification from the sellers, these
indemnification obligations usually expire over time and expose
us to potential unindemnified liabilities, which could
materially adversely affect our production, revenues and results
of operations.
Competition
in the oil and natural gas industry is intense, making it more
difficult for us to acquire properties, market oil and natural
gas and secure trained personnel.
We operate in a highly competitive environment for acquiring
properties, marketing 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 natural 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 natural 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 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.
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
natural gas industry can fluctuate significantly, often in
correlation with 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
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 oil
or natural gas is present or may be produced economically.
Drilling for oil and natural gas often involves unprofitable
results, 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
29
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 may
incur substantial losses and be subject to substantial liability
claims as a result of our 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 oil and natural gas exploration and
production activities are subject to all of the operating risks
associated with drilling for and producing oil and natural gas,
including the possibility of:
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environmental hazards, such as uncontrollable flows of 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.
30
Market
conditions or operational impediments may hinder our access to
oil and natural gas markets or delay our
production.
Market conditions or the unavailability of satisfactory oil and
natural gas processing or transportation arrangements may hinder
our access to oil and natural gas markets or delay our
production. The availability of a ready market for our oil and
natural gas production depends on a number of factors, including
the demand for and supply of 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 or otherwise curtail
production from wells due to lack of a market or inadequacy or
unavailability of 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.
Certain
federal income tax deductions currently available with respect
to oil and natural gas exploration and development may be
eliminated as a result of future legislation.
President Obamas budget proposal for the fiscal year 2012
recommended the elimination of certain key United States federal
income tax preferences currently available to oil and natural
gas exploration and production companies. These changes include,
but are not limited to, (i) the repeal of the percentage
depletion allowance for oil and natural gas properties,
(ii) the elimination of current deductions for intangible
drilling and development costs and (iii) the increase in
the amortization period from two years to seven years for
geophysical costs paid or incurred in connection with the
exploration for, or development of, oil or natural gas within
the United States.
It is unclear whether any such changes will actually be enacted
or, if enacted, how soon any such changes could become
effective. The passage of any legislation as a result of the
budget proposal or any other similar change in United States
federal income tax law could affect certain tax deductions that
are currently available with respect to oil and natural gas
exploration and production.
Climate
change legislation or regulations restricting emissions of
greenhouse gases could result in increased operating
costs and reduced demand for the crude oil and natural gas that
we produce.
In December 2009, the EPA determined that emissions of carbon
dioxide, methane and other greenhouse gases present
an endangerment to public health and the environment because
emissions of such gases are, according to the EPA, contributing
to warming of the earths atmosphere and other climatic
changes. Based on these findings, the EPA has begun adopting and
implementing regulations to restrict emissions of greenhouse
gases under existing provisions of the federal Clean Air Act.
The EPA recently adopted two sets of rules regulating greenhouse
gas emissions under the Clean Air Act, one of which requires a
reduction in emissions of greenhouse gases from motor vehicles
and the other of which regulates emissions of greenhouse gases
from certain large stationary sources, effective January 2,
2011. The EPAs rules relating to emissions of greenhouse
gases from large stationary sources of emissions are currently
subject to a number of legal challenges, but the federal courts
have thus far declined to issue any injunctions to prevent EPA
from implementing, or requiring state environmental agencies to
implement, the rules. The EPA has also adopted rules requiring
the reporting of greenhouse gas emissions from specified large
greenhouse gas emission sources in the United States, including
petroleum refineries, on an annual basis, beginning in 2011 for
emissions occurring after January 1, 2010, as well as
certain onshore oil and natural gas production facilities, on an
annual basis, beginning in 2012 for emissions occurring in 2011.
In addition, Congress has from time to time considered adopting
legislation to reduce emissions of greenhouse gases and almost
one-half of the states have already taken legal measures to
reduce emissions of greenhouse gases primarily through the
planned development of greenhouse gas emission inventories
and/or
regional greenhouse gas cap and trade programs. Most of these
cap and trade programs work by requiring major sources of
emissions, such as electric power plants, or major producers of
fuels, such as refineries and gas processing plants, to acquire
and
31
surrender emission allowances. The number of allowances
available for purchase is reduced each year in an effort to
achieve the overall greenhouse gas emission reduction goal.
The adoption of legislation or regulatory programs to reduce
emissions of greenhouse gases could require us to incur
increased operating costs, such as costs to purchase and operate
emissions control systems, to acquire emissions allowances or
comply with new regulatory or reporting requirements. Any such
legislation or regulatory programs could also increase the cost
of consuming, and thereby reduce demand for, the oil and natural
gas we produced. Consequently, legislation and regulatory
programs to reduce emissions of greenhouse gases could have an
adverse effect on our business, financial condition and results
of operations. Finally, it should be noted that some scientists
have concluded that increasing concentrations of greenhouse
gases in the earths atmosphere may produce climate changes
that have significant physical effects, such as increased
frequency and severity of storms, droughts, and floods and other
climatic events. If any such effects were to occur, they could
have an adverse effect on our financial condition and results of
operations.
The
recent adoption of derivatives legislation by Congress could
have an adverse effect on our ability to use derivative
instruments to reduce the effect of commodity price, interest
rate and other risks associated with our business.
Congress recently adopted comprehensive financial reform
legislation that establishes federal oversight and regulation of
the
over-the-counter
derivatives market and entities, including us, that participate
in that market. The new legislation, known as the Dodd-Frank
Wall Street Reform and Consumer Protection Act (the
Dodd-Frank Act), was signed into law by the
President on July 21, 2010 and requires the Commodities
Futures Trading Commission (the CFTC) and the SEC to
promulgate rules and regulations implementing the new
legislation within 360 days from the date of enactment. In
its rulemaking under the Act, the CFTC has proposed regulations
to set position limits for certain futures and option contracts
in the major energy markets and for swaps that are their
economic equivalents. Certain bona fide hedging
transactions or positions would be exempt from these position
limits. It is not possible at this time to predict when the CFTC
will finalize these regulations. The financial reform
legislation may also require us to comply with margin
requirements and with certain clearing and trade-execution
requirements in connection with our derivative activities,
although the application of those provisions to us is uncertain
at this time. The financial reform legislation may also require
the counterparties to our derivative instruments to spin off
some of their derivatives activities to a separate entity, which
may not be as creditworthy as the current counterparty. The new
legislation and any new regulations could significantly increase
the cost of derivative contracts (including through requirements
to post collateral which could adversely affect our available
liquidity), materially alter the terms of derivative contracts,
reduce the availability of derivatives to protect against risks
we encounter, reduce our ability to monetize or restructure our
existing derivative contracts, and increase our exposure to less
creditworthy counterparties. If we reduce our use of derivatives
as a result of the legislation and regulations, our results of
operations may become more volatile and our cash flows may be
less predictable, which could adversely affect our ability to
plan for and fund capital expenditures. Finally, the legislation
was intended, in part, to reduce the volatility of oil and
natural gas prices, which some legislators attributed to
speculative trading in derivatives and commodity instruments
related to oil and natural gas. Our revenues could therefore be
adversely affected if a consequence of the legislation and
regulations is to lower commodity prices. Any of these
consequences could have a material adverse effect on us, our
financial condition and our results of operations.
Federal
and state legislation and regulatory initiatives relating to
hydraulic fracturing could result in increased costs and
additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is
used to stimulate production of hydrocarbons from tight
formations. We routinely utilize hydraulic fracturing techniques
in many of our drilling and completion programs. The process
involves the injection of water, sand and chemicals under
pressure into the formation to fracture the surrounding rock and
stimulate production. The process is typically regulated by
state oil and gas commissions. However, the EPA recently
asserted federal regulatory authority over hydraulic fracturing
involving diesel additives under the Safe Drinking Water
Acts Underground Injection Control Program. While the EPA
has yet to take any action to enforce or implement this newly
asserted regulatory authority, industry groups have filed suit
challenging the EPAs recent decision. At the same time,
the EPA has commenced a study of the potential
32
environmental impacts of hydraulic fracturing activities, and a
committee of the United States House of Representatives is also
conducting an investigation of hydraulic fracturing practices.
Legislation has been introduced before Congress to provide for
federal regulation of hydraulic fracturing and to require
disclosure of the chemicals used in the fracturing process. In
addition, some states have adopted, and other states are
considering adopting, regulations that could impose more
stringent permitting, disclosure and well construction
requirements on hydraulic fracturing operations. For example,
Colorado, Pennsylvania and Wyoming have each adopted a variety
of well construction, set back, and disclosure regulations
limiting how fracturing can be performed and requiring various
degrees of chemical disclosure. If new laws or regulations that
significantly restrict hydraulic fracturing are adopted, such
laws could make it more difficult or costly for us to perform
fracturing to stimulate production from tight formations. In
addition, if hydraulic fracturing becomes regulated at the
federal level as a result of federal legislation or regulatory
initiatives by the EPA, our fracturing activities could become
subject to additional permitting requirements, and also to
attendant permitting delays and potential increases in costs.
Restrictions on hydraulic fracturing could also reduce the
amount of oil and natural gas that we are ultimately able to
produce from our reserves.
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 officers and key employees who have
extensive experience and expertise in evaluating and analyzing
producing oil and natural gas properties and drilling prospects,
maximizing production from oil and natural gas properties,
marketing oil and natural 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.
Because
we do not control the development of certain 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, 2010, approximately 10.4 percent of
our proved reserves were 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;
|
|
|
|
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 and application of suitable technology.
|
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 or we will be required to write-off the reserves
attributable thereto, which may adversely affect our production,
revenues and results of operations. Any such write-offs of our
reserves could reduce our ability to borrow money and could
reduce the value of our securities
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 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 recovery methods are inherently difficult to
predict. If our enhanced recovery methods do not allow for the
extraction of 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
33
projects. In addition, if proposed legislation and regulatory
initiatives relating to hydraulic fracturing become law, the
cost of some of these enhanced recovery methods could increase
substantially.
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 oil and
natural gas, potentially putting downward pressure on demand for
our services and causing a reduction in our revenue. 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 used for
the production, transportation, processing or marketing of 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, our 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 certificate of
incorporation, our 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:
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|
|
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
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|
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, investors
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.
Covenants contained in our credit facility and the indentures
governing certain of our senior notes restrict the payment of
dividends. Investors 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. Investors seeking cash
dividends should not purchase our common stock.
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. We may also acquire interests in other companies
by using a combination of cash and our common stock or just our
common stock. We may also issue securities convertible into, or
exchangeable for, or that represent the right to receive, our
common stock. Any of
34
these events may dilute your ownership interest in our company,
reduce our earnings per share 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.
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|
Item 1B.
|
Unresolved
Staff Comments
|
There are no unresolved staff comments.
Our Oil
and Natural Gas Reserves
The estimates of our proved reserves at December 31, 2010,
all of which were located in the United States, were based on
evaluations prepared by the independent petroleum engineering
firms of Cawley, Gillespie & Associates, Inc.
(CGA) and Netherland, Sewell & Associates,
Inc. (NSAI) (or collectively external
engineers). Reserves were estimated in accordance with
guidelines established by the SEC and the Financial Accounting
Standards Board (the FASB).
Internal controls. Our proved reserves
are estimated at the property level and compiled for reporting
purposes by our corporate reservoir engineering staff, all of
whom are independent of our operating teams. We maintain our
internal evaluations of our reserves in a secure reserve
engineering database. The corporate reservoir engineering staff
interact with our internal staff of petroleum engineers and
geoscience professionals in each of our operating areas and with
accounting and marketing employees to obtain the necessary data
for the reserves estimation process. Reserves are reviewed and
approved internally by our senior management and audit committee.
Our internal professional staff works closely with our external
engineers to ensure the integrity, accuracy and timeliness of
data that is furnished to them for their reserve estimation
process. All of the reserve information maintained in our secure
reserve engineering database is provided to the external
engineers. In addition, other pertinent data is provided such as
seismic information, geologic maps, well logs, production tests,
material balance calculations, well performance data, operating
procedures and relevant economic criteria. We make available all
information requested, including our pertinent personnel, to the
external engineers as part of their evaluation of our reserves.
Qualifications
of responsible technical persons.
E. Joseph Wright has been our Senior Vice President and
Chief Operating Officer since November 2010. Mr. Wright
previously served as the Vice President Engineering
and Operations from our formation in February 2004 to October
2010. Previously, Mr. Wright served as Vice
President Operations/Engineering of Concho
Oil & Gas Corp. from its formation in January 2001
until its sale in January 2004, and as Vice
President Operations for Concho Resources Inc.
(which was a different company from the current company). He has
also worked in several operations, engineering and capital
markets positions at Mewbourne Oil Company. Mr. Wright is a
graduate of Texas A&M University with a Bachelor of Science
degree in Petroleum Engineering.
Gayle Burleson has been our Vice President
Engineering, since September 2010. Ms. Burleson was our
Manager of Corporate Engineering from July 2008 until September
2010. Ms. Burleson was Senior Reservoir Engineer for us
from January 2006 until July 2008. From 1999 until 2006,
Ms. Burleson was employed by BTA Oil Producers as a Senior
Engineer responsible for Reservoir and Operations engineering
duties in the Permian Basin, Oklahoma and North Dakota. From
1998 until 1999, Ms. Burleson was employed as a Staff
Reservoir Engineer for Mobil Oil Corporation responsible for
tertiary floods in Utah. From 1996 until 1998, Ms. Burleson
was employed as a Senior Reservoir Engineer for
Parker & Parsley Petroleum Company (now Pioneer
Natural Resources Company) overseeing development in the Permian
Basin, and she began her career in 1988 until 1996 with Exxon
Corporation in various reservoir engineering capacities
responsible for primary oil and natural gas fields, waterfloods
and tertiary recovery floods in the Permian Basin and North
Dakota. Ms. Burleson is a graduate of Texas Tech University
with a Bachelor of Science in Chemical Engineering
35
CGA. Approximately 66.3 percent of
the reserves estimates shown herein at December 31, 2010,
have been independently prepared by CGA, a worldwide leader of
petroleum property analysis for industry and financial
organizations and government agencies. CGA was founded in 1961
and performs consulting petroleum engineering services under
Texas Board of Professional Engineers Registration
No. F-693.
Within CGA, the technical person primarily responsible for
preparing the estimates set forth in the CGA letter dated
January 24, 2011, filed as part of this report, was
Mr. Zane Meekins. Mr. Meekins has been a practicing
consulting petroleum engineer at CGA since 1989.
Mr. Meekins is a Registered Professional Engineer in the
State of Texas (License No. 71055) and has over
22 years of practical experience in petroleum engineering,
with over 20 years of experience in the estimation and
evaluation of reserves. He graduated from Texas A&M
University in 1987 with a Bachelor of Science in Petroleum
Engineering. Mr. Meekins meets or exceeds the education,
training, and experience requirements set forth in the Standards
Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information promulgated by the Society of Petroleum
Engineers; he is proficient in judiciously applying industry
standard practices to engineering and geoscience evaluations as
well as applying SEC and other industry reserves definitions and
guidelines.
NSAI. Approximately 33.7 percent
of the reserves estimates shown herein at December 31,
2010, have been independently prepared by NSAI, a worldwide
leader of petroleum property analysis for industry and financial
organizations and government agencies. NSAI was founded in 1961
and performs consulting petroleum engineering services under
Texas Board of Professional Engineers Registration
No. F-002699.
Within NSAI, the technical person primarily responsible for
preparing the estimates set forth in the NSAI letter dated
January 20, 2011, filed as part of this report, was
Mr. G. Lance Binder. Mr. Binder has been a practicing
consulting petroleum engineer at NSAI since 1983.
Mr. Binder is a Registered Professional Engineer in the
State of Texas (License No. 61794) and has over
30 years of practical experience in petroleum engineering,
with over 29 years of experience in the estimation and
evaluation of reserves. He graduated from Purdue University in
1978 with a Bachelor of Science Degree in Chemical Engineering.
Mr. Binder meets or exceeds the education, training, and
experience requirements set forth in the Standards Pertaining to
the Estimating and Auditing of Oil and Gas Reserves Information
promulgated by the Society of Petroleum Engineers; he is
proficient in judiciously applying industry standard practices
to engineering and geoscience evaluations as well as applying
SEC and other industry reserves definitions and guidelines.
Our oil and natural gas reserves. The
following table sets forth our estimated proved oil and natural
gas reserves,
PV-10 and
Standardized Measure at December 31, 2010.
PV-10 and
Standardized Measure include 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
and our computation of future net cash flows are based on a
12-month
unweighted average of the
first-day-of-the-month
pricing of $75.96 per Bbl West Texas Intermediate posted oil
price and on a
12-month
unweighted average of the
first-day-of-the-month
pricing of $4.38 per MMBtu Henry Hub spot natural gas price,
adjusted for location and quality by property.
The following table sets forth certain proved reserve
information by area at December 31, 2010:
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Natural
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Oil (MBbl)
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Gas (MMcf)
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Total (MBoe)
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PV-10(a)
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(In millions)
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Core Operating Areas:
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New Mexico Shelf
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125,394
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405,239
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192,934
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$
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3,979.4
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Delaware Basin
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8,949
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78,865
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22,093
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355.7
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Texas Permian
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70,866
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177,791
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100,498
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1,594.8
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Other
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6,214
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10,279
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7,927
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131.3
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Total
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211,423
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672,174
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323,452
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6,061.2
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Present value of future income tax discounted at 10%
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(1,885.1
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)
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Standardized Measure
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$
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4,176.1
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36
The following table sets forth our estimated proved reserves by
category at December 31, 2010:
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Natural
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Oil (MBbl)
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Gas (MMcf)
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Total (MBoe)
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Percent of Total
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|
PV-10(a)
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(In millions)
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Proved developed producing
|
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101,981
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|
|
|
378,618
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|
|
|
165,084
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|
51.0
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%
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|
$
|
3,824.0
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Proved developed non-producing
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13,458
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35,873
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|
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19,437
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6.0
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%
|
|
|
417.4
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Proved undeveloped
|
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95,984
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|
|
|
257,683
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|
|
|
138,931
|
|
|
|
43.0
|
%
|
|
|
1,819.8
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|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
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Total proved
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|
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211,423
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|
|
|
672,174
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|
|
|
323,452
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|
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100.0
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%
|
|
$
|
6,061.2
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|
|
|
|
|
|
|
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|
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|
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|
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|
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(a) |
|
Our Standardized Measure at December 31, 2010 was
$4,176.1 million.
PV-10 is a
Non-GAAP financial measure and 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 percent. 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
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
assets. 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 assets.
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. See
Item 1. Business Non-GAAP Financial
Measures and Reconciliations. |
Changes to proved reserves. The
following table sets forth the changes in our proved reserve
volumes by area during the year ended December 31, 2010 (in
MBoe):
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Purchases of
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Sales of
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Revisions of
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Extensions and
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Minerals-in-
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Minerals-in-
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Previous
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Production
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Discoveries
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Place
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Place
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Estimates
|
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Core Operating Areas:
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New Mexico Shelf
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(9,820
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)
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23,879
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|
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52,241
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|
|
|
(471
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)
|
|
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1,034
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Delaware Basin
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(993
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)
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2,129
|
|
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|
20,140
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|
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|
(1,248
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)
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|
|
(3,175
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)
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Texas Permian
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|
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(4,236
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)
|
|
|
28,556
|
|
|
|
2,387
|
|
|
|
(3,897
|
)
|
|
|
516
|
|
Other
|
|
|
(515
|
)
|
|
|
5,074
|
|
|
|
|
|
|
|
(389
|
)
|
|
|
737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
(15,564
|
)
|
|
|
59,638
|
|
|
|
74,768
|
|
|
|
(6,005
|
)
|
|
|
(888
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production. Production volumes of
15.6 MMBoe includes (i) 0.5 MMBoe of production
related to the assets divested as noted below and
(ii) 1.1 MMBoe of production from the Marbob and
Settlement Acquisitions for periods after their respective close
date in October 2010.
Extensions and discoveries. Extensions and
discoveries are primarily the result of our continued success
from our extension and infill drilling in the Yeso of Southeast
New Mexico and the Wolfberry in West Texas. Extensions and
discoveries in Other are primarily attributable to the success
of our exploratory drilling activities in the Bakken/Three Forks
play.
Purchases of
minerals-in-place. Purchases
of
minerals-in-place
are primarily attributable to the Marbob and Settlement
Acquisitions that closed in October 2010.
Sales of
minerals-in-place. In
December 2010, we sold certain of our non-core Permian Basin
assets for cash consideration of $103.3 million.
Revisions of previous estimates. Revisions of
previous estimates are comprised of 4.5 MMBoe of positive
revisions resulting from an increase in oil and natural gas
price and 5.4 MMBoe of negative revisions resulting from
technical and performance evaluations. The Companys proved
reserves at December 31, 2010 were determined using the
twelve month average equivalent prices of $75.96 per Bbl of oil
for West Texas Intermediate and $4.38 per
37
MMBtu of natural gas for Henry Hub spot, compared to
corresponding prices of $57.65 per Bbl of oil and $3.87 per
MMBtu of natural gas at December 31, 2009.
Proved undeveloped reserves. At
December 31, 2010, we had approximately 138.9 MMBoe of
proved undeveloped reserves as compared to 107.8 MMBoe at
December 31, 2009.
The following table summarizes the changes in our proved
undeveloped reserves during 2010 (in MBoe):
|
|
|
|
|
At December 31, 2009
|
|
|
107,796
|
|
Extensions and discoveries
|
|
|
38,754
|
|
Purchases of
minerals-in-place
|
|
|
26,754
|
|
Sales of
minerals-in-place
|
|
|
(879
|
)
|
Revisions of previous estimates
|
|
|
(4,658
|
)
|
Conversion to proved developed reserves
|
|
|
(28,836
|
)
|
|
|
|
|
|
At December 31, 2010
|
|
|
138,931
|
|
|
|
|
|
|
Our purchases of
minerals-in-place
are primarily attributable to our October 2010 Marbob and
Settlement Acquisitions. Our extensions and discoveries are
primarily the result of our continued success from our extension
and infill drilling in the Yeso of Southeast New Mexico and the
Wolfberry in West Texas.
The following table sets forth, since 2008, proved undeveloped
reserves converted to proved developed reserves during the
respective year and the investment required to convert proved
undeveloped reserves to proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
Converted to
|
|
|
|
|
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Investment in Conversion
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
of Proved Undeveloped Reserves
|
|
Year Ended December 31,
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBoe)
|
|
|
to Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
2008(a)
|
|
|
4,378
|
|
|
|
15,681
|
|
|
|
6,992
|
|
|
$
|
114,067
|
|
2009
|
|
|
7,453
|
|
|
|
19,860
|
|
|
|
10,763
|
|
|
|
131,773
|
|
2010
|
|
|
20,117
|
|
|
|
52,318
|
|
|
|
28,836
|
|
|
|
309,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
31,948
|
|
|
|
87,859
|
|
|
|
46,591
|
|
|
$
|
555,279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Our initial disclosures of our reserves occurred in our initial
public offering in August 2007. |
The following table sets forth the estimated timing and cash
flows of developing our proved undeveloped reserves at
December 31, 2010 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future
|
|
|
Future
|
|
|
Future
|
|
|
Future
|
|
|
|
|
|
|
Production
|
|
|
Cash
|
|
|
Production
|
|
|
Development
|
|
|
Future Net
|
|
Years Ended December 31,(a)
|
|
(MBoe)
|
|
|
Inflows
|
|
|
Costs
|
|
|
Costs
|
|
|
Cash Flows
|
|
|
2011
|
|
|
3,005
|
|
|
$
|
203,214
|
|
|
$
|
23,232
|
|
|
$
|
461,171
|
|
|
$
|
(281,189
|
)
|
2012
|
|
|
7,241
|
|
|
|
487,153
|
|
|
|
59,940
|
|
|
|
461,405
|
|
|
|
(34,192
|
)
|
2013
|
|
|
9,354
|
|
|
|
628,058
|
|
|
|
82,084
|
|
|
|
309,362
|
|
|
|
236,612
|
|
2014
|
|
|
10,157
|
|
|
|
682,025
|
|
|
|
93,746
|
|
|
|
315,567
|
|
|
|
272,712
|
|
2015
|
|
|
10,185
|
|
|
|
680,339
|
|
|
|
98,837
|
|
|
|
159,472
|
|
|
|
422,030
|
|
Thereafter
|
|
|
98,989
|
|
|
|
6,454,520
|
|
|
|
1,882,503
|
|
|
|
33,377
|
|
|
|
4,538,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
138,931
|
|
|
$
|
9,135,309
|
|
|
$
|
2,240,342
|
|
|
$
|
1,740,354
|
|
|
$
|
5,154,613
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Beginning in 2012 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 2011. |
38
Historically, our drilling programs were substantially funded
from our cash flow and were weighted towards drilling unproven
locations. Our expectation in the future is to continue to fund
our drilling programs primarily from our cash flows. Based on
our current expectations of our cash flows and drilling
programs, which includes drilling of proved undeveloped and
unproven locations, we believe that we can substantially fund
from our cash flow and, if needed, our credit facility, the
drilling of our current inventory of proved undeveloped
locations in the next 5 years.
Developed
and Undeveloped Acreage
The following table presents our total gross and net developed
and undeveloped acreage by area at December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acres
|
|
|
Undeveloped Acres
|
|
|
Total Acres
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Core Operating Areas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Mexico Shelf
|
|
|
86,285
|
|
|
|
44,935
|
|
|
|
133,540
|
|
|
|
69,275
|
|
|
|
219,825
|
|
|
|
114,210
|
|
Delaware Basin
|
|
|
151,040
|
|
|
|
69,978
|
|
|
|
115,922
|
|
|
|
78,479
|
|
|
|
266,962
|
|
|
|
148,457
|
|
Texas Permian
|
|
|
164,820
|
|
|
|
41,617
|
|
|
|
45,846
|
|
|
|
24,238
|
|
|
|
210,666
|
|
|
|
65,855
|
|
Other
|
|
|
23,867
|
|
|
|
6,337
|
|
|
|
67,047
|
|
|
|
39,884
|
|
|
|
90,914
|
|
|
|
46,221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
426,012
|
|
|
|
162,867
|
|
|
|
362,355
|
|
|
|
211,876
|
|
|
|
788,367
|
|
|
|
374,743
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth the future expiration amounts of
our gross and net undeveloped acreage at December 31, 2010
by area. Expirations may be less if production is established
and/or
continuous development activities are undertaken beyond the
primary term of the lease.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
Thereafter
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Core Operating Areas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Mexico Shelf
|
|
|
5,912
|
|
|
|
3,972
|
|
|
|
6,746
|
|
|
|
3,498
|
|
|
|
7,999
|
|
|
|
4,798
|
|
|
|
38,502
|
|
|
|
23,074
|
|
Delaware Basin
|
|
|
4,409
|
|
|
|
2,993
|
|
|
|
24,622
|
|
|
|
8,585
|
|
|
|
2,195
|
|
|
|
881
|
|
|
|
33,011
|
|
|
|
28,283
|
|
Texas Permian
|
|
|
5,962
|
|
|
|
2,251
|
|
|
|
805
|
|
|
|
1,164
|
|
|
|
|
|
|
|
97
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
1,920
|
|
|
|
1,440
|
|
|
|
9,991
|
|
|
|
7,494
|
|
|
|
26,407
|
|
|
|
16,366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
16,283
|
|
|
|
9,216
|
|
|
|
34,093
|
|
|
|
14,687
|
|
|
|
20,185
|
|
|
|
13,270
|
|
|
|
97,920
|
|
|
|
67,723
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Title to
Our Properties
As is customary in the oil and natural 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
natural 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.
39
|
|
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.
|
Removed
and Reserved.
|
40
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
|
|
2009:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
28.10
|
|
|
$
|
17.29
|
|
Second Quarter
|
|
$
|
33.57
|
|
|
$
|
23.50
|
|
Third Quarter
|
|
$
|
38.70
|
|
|
$
|
25.17
|
|
Fourth Quarter
|
|
$
|
47.00
|
|
|
$
|
33.71
|
|
2010:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
51.62
|
|
|
$
|
42.60
|
|
Second Quarter
|
|
$
|
61.65
|
|
|
$
|
44.30
|
|
Third Quarter
|
|
$
|
66.49
|
|
|
$
|
51.51
|
|
Fourth Quarter
|
|
$
|
89.87
|
|
|
$
|
65.95
|
|
On February 23, 2011, the last sales price of our common
stock as reported on the New York Stock Exchange was $108.20 per
share.
As of February 23, 2011, there were 467 holders of record
of our common stock.
Dividend
Policy
We have not paid, and do not intend to pay in the foreseeable
future, cash dividends on our common stock. Covenants contained
in our credit facility and the indentures governing certain of
our senior notes restrict the payment of dividends on our common
stock. 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.
Repurchase
of Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum
|
|
|
|
|
|
|
|
|
|
Total Number
|
|
|
Number of Shares
|
|
|
|
|
|
|
|
|
|
of Shares
|
|
|
That May
|
|
|
|
Total Number
|
|
|
|
|
|
Purchased as
|
|
|
Yet be Purchased
|
|
|
|
of Shares
|
|
|
Average Price
|
|
|
Part of Publicly
|
|
|
Under
|
|
Period
|
|
Withheld(a)
|
|
|
per Share
|
|
|
Announced Plans
|
|
|
the Plan
|
|
|
October 1, 2010 October 31, 2010
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
November 1, 2010 November 30, 2010
|
|
|
2,192
|
|
|
$
|
77.04
|
|
|
|
|
|
|
|
|
|
December 1, 2010 December 31, 2010
|
|
|
2,727
|
|
|
$
|
86.80
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Represents shares that were withheld by us to satisfy tax
withholding obligations of certain of our directors, officers
and key employees that arose upon the lapse of restrictions on
restricted stock. |
41
|
|
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 Item 7. 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
Our results of operations for the periods presented below may
not be comparable either from period to period or going forward
for the following reasons:
|
|
|
|
|
on February 24, 2006, we entered into a combination
agreement in which we agreed to purchase certain oil and gas
properties owned by Chase Oil Corporation (Chase
Oil), Caza Energy LLC and certain other 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 received approximately
35 million shares of our common stock and approximately
$409 million in cash. The executive officers of Concho
Equity Holdings Corp. became the executive officers of our
company at the closing of the combination transaction. We
accounted for the combination transaction as a reorganization of
our company, such that Concho Equity Holdings Corp. became our
wholly owned subsidiary, and a simultaneous acquisition by our
company of the assets contributed by the Chase Group;
|
|
|
|
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;
|
|
|
|
in July 2008, we closed the Henry Entities acquisition. In
August 2008 and September 2008, we acquired additional
non-operated interests in oil and natural gas properties from
persons affiliated with the Henry Entities. We paid
approximately $583.7 million in net cash for the Henry
Properties acquisition, which was funded with borrowings under
our credit facility and net proceeds of approximately
$242.4 million from our private placement of
8.3 million shares of our common stock. The results of
operations prior to August 2008 do not include results from the
Henry Properties acquisition;
|
|
|
|
in September 2009, we issued $300 million of 8.625%
unsecured senior notes at a discount, resulting in a
yield-to-maturity
of 8.875 percent. The net proceeds from this offering was
used to repay a portion of the borrowings under our credit
facility;
|
|
|
|
in December 2009, together with the acquisition of related
additional interests that closed in 2010, we closed the
Wolfberry Acquisitions for approximately $270.7 million in
cash. The results of operations prior to 2010 do not include
results from the Wolfberry Acquisitions;
|
|
|
|
in February 2010, we issued approximately 5.3 million
shares of our common stock at $42.75 per share in a secondary
public offering resulting in net proceeds of approximately
$219.3 million. The net proceeds from this offering were
used to repay a portion of the borrowings under our credit
facility;
|
|
|
|
in October 2010, we closed the Marbob and Settlement
Acquisitions for aggregate consideration of approximately
$1.6 billion. The Marbob Acquisition consideration was
comprised of (i) approximately $1.1 billion in cash
which was funded with borrowings under our credit facility and
with net proceeds of a $292.7 million private placement of
6.6 million shares of our common stock, (ii) issuance
of 1.1 million shares of our common stock to the sellers
and (iii) issuance of a $150 million 8.0% unsecured
senior note due 2018 to the sellers. The Settlement Acquisition
cash consideration of $286 million was primarily funded
with borrowings under our credit facility. The results of
operations prior to October 2010 do not include results from the
Marbob and Settlement Acquisitions;
|
42
|
|
|
|
|
in December 2010, we issued in a secondary public offering
2.9 million shares of our common stock at $82.50 per share
and we received net proceeds of approximately
$227.4 million. We used the net proceeds from this offering
to repay a portion of the borrowings under our credit
facility; and
|
|
|
|
in December 2010, we issued $600 million in principal
amount of 7.0% unsecured senior notes due 2021 at par and we
received net proceeds of approximately $587.4 million. We
used the net proceeds from this offering to repay a portion of
the borrowings under our credit facility.
|
Our financial data below is derived from (i) our audited
consolidated financial statements included in this report and
(ii) other audited consolidated financial statements of
ours not included in this report after taking into account the
necessary reclassifications to present the discontinued
operations related to the divestiture of certain of our non-core
Permian Basin assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010(a)
|
|
|
2009(b)
|
|
|
2008(c)
|
|
|
2007
|
|
|
2006(d)
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Statement of operations data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
972,576
|
|
|
$
|
519,601
|
|
|
$
|
498,085
|
|
|
$
|
267,295
|
|
|
$
|
176,326
|
|
Total operating costs and expenses
|
|
|
(596,528
|
)
|
|
|
(523,932
|
)
|
|
|
(42,822
|
)
|
|
|
(200,012
|
)
|
|
|
(118,061
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
$
|
376,048
|
|
|
$
|
(4,331
|
)
|
|
$
|
455,263
|
|
|
$
|
67,283
|
|
|
$
|
58,265
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations, net of tax
|
|
$
|
183,034
|
|
|
$
|
(11,527
|
)
|
|
$
|
270,222
|
|
|
$
|
20,016
|
|
|
$
|
16,417
|
|
Income from discontinued operations, net of tax
|
|
$
|
21,336
|
|
|
$
|
1,725
|
|
|
$
|
8,480
|
|
|
$
|
5,344
|
|
|
$
|
3,251
|
|
Net income (loss) attributable to common shareholders
|
|
$
|
204,370
|
|
|
$
|
(9,802
|
)
|
|
$
|
278,702
|
|
|
$
|
25,315
|
|
|
$
|
30,025
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
$
|
1.98
|
|
|
$
|
(0.14
|
)
|
|
$
|
3.41
|
|
|
$
|
0.31
|
|
|
$
|
0.57
|
|
Income from discontinued operations, net of tax
|
|
|
0.23
|
|
|
|
0.02
|
|
|
|
0.11
|
|
|
|
0.07
|
|
|
|
0.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to common shareholders
|
|
$
|
2.21
|
|
|
$
|
(0.12
|
)
|
|
$
|
3.52
|
|
|
$
|
0.38
|
|
|
$
|
0.63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
$
|
1.95
|
|
|
$
|
(0.14
|
)
|
|
$
|
3.35
|
|
|
$
|
0.30
|
|
|
$
|
0.53
|
|
Income from discontinued operations, net of tax
|
|
|
0.23
|
|
|
|
0.02
|
|
|
|
0.11
|
|
|
|
0.07
|
|
|
|
0.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to common shareholders
|
|
$
|
2.18
|
|
|
$
|
(0.12
|
)
|
|
$
|
3.46
|
|
|
$
|
0.37
|
|
|
$
|
0.59
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operations
|
|
$
|
651,582
|
|
|
$
|
359,546
|
|
|
$
|
397,841
|
|
|
$
|
169,769
|
|
|
$
|
112,181
|
|
Net cash used in investing activities
|
|
$
|
2,043,457
|
|
|
$
|
586,148
|
|
|
$
|
946,050
|
|
|
$
|
160,353
|
|
|
$
|
596,852
|
|
Net cash provided by financing activities
|
|
$
|
1,389,025
|
|
|
$
|
212,084
|
|
|
$
|
541,981
|
|
|
$
|
19,886
|
|
|
$
|
476,611
|
|
EBITDAX(e)
|
|
$
|
742,994
|
|
|
$
|
475,208
|
|
|
$
|
401,303
|
|
|
$
|
217,392
|
|
|
$
|
149,074
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2010(a)
|
|
2009(b)
|
|
2008(c)
|
|
2007
|
|
2006(d)
|
|
|
(In thousands)
|
|
Balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
384
|
|
|
$
|
3,234
|
|
|
$
|
17,752
|
|
|
$
|
30,424
|
|
|
$
|
1,122
|
|
Property and equipment, net
|
|
|
4,913,787
|
|
|
|
2,856,289
|
|
|
|
2,401,404
|
|
|
|
1,394,994
|
|
|
|
1,320,655
|
|
Total assets
|
|
|
5,368,494
|
|
|
|
3,171,085
|
|
|
|
2,815,203
|
|
|
|
1,508,229
|
|
|
|
1,390,072
|
|
Long-term debt, including current maturities
|
|
|
1,668,521
|
|
|
|
845,836
|
|
|
|
630,000
|
|
|
|
327,404
|
|
|
|
495,500
|
|
Stockholders equity
|
|
|
2,383,874
|
|
|
|
1,335,428
|
|
|
|
1,325,154
|
|
|
|
775,398
|
|
|
|
575,156
|
|
|
|
|
(a) |
|
The Marbob and Settlement Acquisitions closed in October 2010.
See Note D of the Notes to Consolidated Financial
Statements included in Item 8. Financial Statements
and Supplementary Data. |
|
(b) |
|
The Wolfberry Acquisitions closed in December 2009. See
Note D of the Notes to Consolidated Financial Statements
included in Item 8. Financial Statements and
Supplementary Data. |
|
(c) |
|
The Henry Entities acquisition closed in July 2008. See
Note D of the Notes to Consolidated Financial Statements
included in Item 8. Financial Statements and
Supplementary Data. |
|
(d) |
|
The acquisition of the Chase Group Properties was substantially
consummated on February 27, 2006, as a result of the
combination of assets owned by Chase Oil and certain of its
affiliates and Concho Equity Holdings Corp. |
|
(e) |
|
EBITDAX is defined as net income (loss), plus
(1) exploration and abandonments expense,
(2) depreciation, depletion and amortization expense,
(3) accretion expense, (4) impairments of long-lived
assets, (5) non-cash stock-based compensation expense,
(6) bad debt expense, (7) ineffective portion of cash
flow hedges and unrealized (gain) loss on derivatives not
designated as hedges, (8) unrealized (gain) loss on
derivatives not designated as hedges, (9) (gain) loss on sale of
assets, net, (10) interest expense, (11) federal and
state income taxes and (12) similar items listed above that
are presented in discontinued operations. See Item 1.
Business Non-GAAP Financial Measures and
Reconciliations. |
44
|
|
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.
In October 2010, we closed the Marbob and Settlement
Acquisitions, as discussed below. The results of these
acquisitions are included in our results of operations for
periods after their respective closing dates in October 2010. As
a result, many comparisons between periods will be difficult or
impossible.
In December 2009, we closed the Wolfberry Acquisitions. The
results of these acquisitions are included in our results of
operations beginning January 1, 2010. As a result, many
comparisons between periods will be difficult or impossible.
In July 2008, we closed the Henry Entities acquisition. In
August 2008 and September 2008, we acquired additional
non-operated interests in oil and natural gas properties from
persons affiliated with the Henry Entities (known as
along-side interests). The results of operations are
included in our consolidated statements of operations from
August 1, 2008 forward.
Certain statements in our discussion below are forward-looking
statements. These forward-looking statements involve risks and
uncertainties. We caution that a number of factors could cause
actual results to differ materially from these implied or
expressed by the forward-looking statements. Please see
Cautionary Statement Regarding Forward-Looking
Statements.
Overview
We are an independent oil and natural gas company engaged in the
acquisition, development and exploration of producing oil and
natural gas properties. Our core operations are primarily
focused in the Permian Basin of Southeast New Mexico and West
Texas. We refer to our three core operating areas as the
(i) New Mexico Shelf, where we primarily target the Yeso
and Lower Abo formations, (ii) Delaware Basin, where we
primarily target the Bone Spring formation, and (iii) Texas
Permian, where we primarily target the Wolfberry, a term applied
to the combined Wolfcamp and Spraberry horizons. We also have
significant acreage positions in the Bakken/Three Forks play in
North Dakota. Oil comprised 65 percent of our
323.5 MMBoe of estimated proved reserves at
December 31, 2010, and 66 percent of our
15.6 MMBoe of production for 2010. We seek to operate the
wells in which we own an interest, and we operated wells that
accounted for 92.3 percent of our proved developed
producing
PV-10 and
69.8 percent of our 5,196 gross wells at
December 31, 2010. By controlling operations, we are able
to more effectively manage the cost and timing of exploration
and development of our properties, including the drilling and
stimulation methods used.
Financial
and Operating Performance
Our financial and operating performance for 2010 included the
following highlights:
|
|
|
|
|
Net income was $204.4 million ($2.18 per diluted share), as
compared to a net loss of $9.8 million ($0.12 per diluted
share) in 2009. The increase in earnings is primarily due to:
|
|
|
|
|
|
$453.0 million increase in oil and natural gas revenues as
a result of commodity price increases and a 45.6 percent
increase in production;
|
|
|
|
$69.5 million decrease in net losses on derivatives not
designated as hedges;
|
|
|
|
$29.1 million gain from the divestiture of certain non-core
Permian Basin assets, included in discontinued operations,
offset by;
|
|
|
|
$53.1 million increase in depreciation, depletion and
amortization (DD&A) expense, significantly due
in part to the increase in production in 2010;
|
45
|
|
|
|
|
$72.0 million increase in oil and natural gas production
costs due in part to (i) increases in production in 2010,
and (ii) the increase in oil and natural gas revenues in
2010 directly increases our oil and natural production taxes,
and;
|
|
|
|
$31.8 million increase in interest expense due to
(i) increased borrowings during 2010 primarily related to
acquisitions and (ii) an increase in our overall interest
rate in 2010 primarily as a result of the 2009 senior note
issuance.
|
|
|
|
|
|
Average daily sales volumes from continuing operations increased
during 2010 by 45.6 percent from 28,377 Boe per day during
2009 to 41,249 Boe per day during 2010. The increase is
primarily the attributable to (i) our successful drilling
efforts during 2009 and 2010 and (ii) our acquisitions in
2010.
|
|
|
|
Net cash provided by operating activities increased by
$292.1 million to $651.6 million for 2010, as compared
to $359.5 million in 2009, primarily due to the increase in
oil and gas revenue, offset by increases in related oil and
natural gas production costs and other cash related costs.
|
|
|
|
In 2010, we sold approximately 14.8 million shares of our
common stock for net proceeds of approximately
$739.5 million in a combination of secondary public
offerings and a private placement. The proceeds were primarily
utilized to fund acquisitions and repay amounts outstanding
under our credit facility to increase our (i) availability
under our credit facility and (ii) liquidity for future
activities.
|
|
|
|
In December 2010, we issued $600 million of
7.0% senior notes due 2021. The proceeds were primarily
utilized to repay amounts outstanding under our credit facility
to increase our (i) availability under our credit facility
and (ii) liquidity for future activities.
|
|
|
|
Long-term debt was increased by $822.7 million during 2010
primarily as a result of acquisitions.
|
|
|
|
At December 31, 2010 our availability under our credit
facility was approximately $1.4 billion.
|
Commodity
Prices
Our results of operations are heavily influenced by commodity
prices. Factors that may impact future commodity prices,
including the price of oil and natural gas, include:
|
|
|
|
|
developments generally impacting the Middle East, including Iraq
and Iran;
|
|
|
|
the extent to which members of the Organization of Petroleum
Exporting Countries and other oil exporting nations are able to
continue to manage oil supply through export quotas;
|
|
|
|
the overall global demand for oil; and
|
|
|
|
overall North American natural gas supply and demand
fundamentals, including:
|
|
|
|
|
|
the United States economy impact,
|
|
|
|
weather conditions, and
|
|
|
|
liquefied natural gas deliveries to the United States.
|
Although we cannot predict the occurrence of events that may
affect future commodity prices or the degree to which these
prices will be affected, the prices for any commodity that we
produce will generally approximate current market prices in the
geographic region of the production. From time to time, we
expect that we may economically hedge a portion of our commodity
price risk to mitigate the impact of price volatility on our
business. See Note I of the Notes to Consolidated Financial
Statements included in Item 8. Financial Statements
and Supplementary Data for additional information
regarding our commodity derivative positions at
December 31, 2010.
Oil and natural gas prices have been subject to significant
fluctuations during the past several years. In general, oil
prices were significantly higher during 2010 measured against
2009, while natural gas prices were moderately
46
higher. The following table sets forth the average NYMEX oil and
natural gas prices for the years ended December 31, 2010,
2009 and 2008, as well as the high and low NYMEX price for the
same periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
Average NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
$
|
79.50
|
|
|
$
|
61.95
|
|
|
$
|
99.75
|
|
Natural gas (MMBtu)
|
|
$
|
4.40
|
|
|
$
|
4.16
|
|
|
$
|
8.89
|
|
High and low NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
91.51
|
|
|
$
|
81.37
|
|
|
$
|
145.29
|
|
Low
|
|
$
|
68.01
|
|
|
$
|
33.98
|
|
|
$
|
33.87
|
|
Natural gas (MMBtu):
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
6.01
|
|
|
$
|
6.07
|
|
|
$
|
13.58
|
|
Low
|
|
$
|
3.29
|
|
|
$
|
2.51
|
|
|
$
|
5.29
|
|
Further, the NYMEX oil price and NYMEX natural gas price reached
highs and lows of $98.10 and $84.32 per Bbl and $4.74 and $3.87
per MMBtu, respectively, during the period from January 1,
2011 to February 23, 2011. At February 23, 2011, the
NYMEX oil price and NYMEX natural gas price were $98.10 per Bbl
and $3.90 per MMBtu, respectively.
Recent
Events
Marbob and Settlement acquisitions. In
July 2010, we entered into an asset purchase agreement to
acquire certain of the oil and natural gas leases, interests,
properties and related assets owned by Marbob for aggregate
consideration of (i) cash in the amount of
$1.45 billion, (ii) the issuance to Marbob of a
$150 million 8.0% unsecured senior note due 2018 and
(iii) the issuance to Marbob of approximately
1.1 million shares of our common stock, subject to purchase
price adjustments, which included downward purchase price
adjustments based on the exercise of third parties of
contractual preferential purchase rights.
On October 7, 2010, we closed the Marbob Acquisition. At
closing, we paid approximately $1.1 billion in cash plus
the unsecured senior note and common stock described above for a
total purchase price of approximately $1.4 billion. The
total purchase price as originally announced was reduced due to
third party contractual preferential purchase rights. Certain of
the third parties contractual preferential purchase rights
became subject to litigation, as discussed below.
We funded the cash consideration in the Marbob Acquisition with
(a) borrowings under our credit facility and (b) net
proceeds of $292.7 million from a private placement of
approximately 6.6 million shares of our common stock at a
price of $45.30 per share that closed on October 7, 2010.
Certain of the Marbob interests in properties contained
contractual preferential purchase rights by third parties if
Marbob were to sell them. Marbob informed us of its receipt of a
notice from BP electing to exercise its contractual preferential
purchase rights.
On July 20, 2010, BP announced it was selling all its
assets in the Permian Basin to a subsidiary of Apache. Marbob
and BP owned common interests in certain properties subject to
contractual preferential purchase rights. BP and Apache
contested Marbobs ability to exercise its contractual
preferential purchase rights in this situation. As a result, we
and Marbob filed suit against BP and Apache seeking declaratory
judgment and injunctive relief to protect Marbobs
contractual right to have the option to purchase these interests
in these common properties.
On October 15, 2010, we and Marbob resolved the litigation
with BP and Apache related to the disputed contractual
preferential purchase rights. As a result of the settlement, we
acquired a non-operated interest in substantially all of the oil
and natural gas assets subject to the litigation for
approximately $286 million in cash (the Settlement
Acquisition). We funded the Settlement Acquisition with
borrowings under our credit facility.
47
The properties acquired in the Marbob and Settlement
Acquisitions contained approximately 72.4 MMBoe of proved
reserves at closing. The results of operations prior to October
2010 do not include results from the Marbob and Settlement
Acquisitions.
Borrowing base increase. In October
2010, we and our bank lenders entered into an amendment to our
credit agreement simultaneously with the closing of the Marbob
Acquisition. The amendment increased each of the borrowing base
and the lenders aggregate commitment from
$1.2 billion to $2.0 billion.
Private placement of equity. In October
2010, we closed the private placement of our common stock,
simultaneously with the closing of the Marbob Acquisition, on
6.6 million shares of our common stock at a price of $45.30
per share for net proceeds of approximately $292.7 million.
Senior notes issuance. In December
2010, we issued $600 million in principal amount of 7.0%
unsecured senior notes due 2021 at par and we received net
proceeds of approximately $587.4 million. We used the net
proceeds from this offering to repay a portion of the borrowings
under our credit facility to increase our liquidity for future
activities.
Common stock offering. In December
2010, we issued in a secondary public offering 2.9 million
shares of our common stock at $82.50 per share and we received
net proceeds of approximately $227.4 million. We used the
net proceeds from this offering to repay a portion of the
borrowings under our credit facility to increase our liquidity
for future activities.
Permian asset divestiture. In December
2010, we sold certain of our non-core Permian Basin assets for
cash consideration of $103.3 million. For 2010, these
assets produced 1,393 Boe per day, of which approximately
46 percent was oil. The proved reserves of these assets
were approximately 6.0 MMBoe at closing.
North Dakota divestiture. In February
2011, we entered into a purchase and sale agreement to sell our
North Dakota assets for cash consideration of approximately
$196.0 million, subject to customary purchase price
adjustments, and expect to close the divestiture prior to
March 31, 2011. We expect to recognize a gain on this sale
in excess of $140.0 million.
2011 capital budget. In November 2010,
we announced our 2011 capital budget of approximately
$1.1 billion, which we expect can be funded substantially
within our cash flow, based on current commodity prices and our
expectations. As our size and financial flexibility have grown,
we now take a longer-term view on spending substantially within
our cash flow, and our spending during any specific period may
exceed our cash flow for that period. However, our capital
budget is largely discretionary, and if we experience sustained
oil and natural gas prices significantly below the current
levels or substantial increases in our drilling and completion
costs, we may reduce our capital spending program to be
substantially within our cash flow.
Our capital budget does not include acquisitions (other than the
customary purchase of leasehold acreage). The following is a
summary of our 2011 capital budget:
|
|
|
|
|
|
|
Capital Budget
|
|
|
|
2011
|
|
|
|
(In millions)
|
|
|
Core Operating Areas:
|
|
|
|
|
New Mexico Shelf
|
|
$
|
579
|
|
Delaware Basin
|
|
|
145
|
|
Texas Permian
|
|
|
219
|
|
Acquisition of leasehold acreage and other property interests,
geological and geophysical and other
|
|
|
61
|
|
Facilities and other capital in our core operating areas
|
|
|
100
|
|
|
|
|
|
|
Total
|
|
$
|
1,104
|
|
|
|
|
|
|
48
Derivative
Financial Instruments
Derivative financial instrument
exposure. At December 31, 2010, the fair
value of our financial derivatives was a net liability of
$140.3 million. All of our counterparties to these
financial derivatives are a party to our credit facility and
have their outstanding debt commitments and derivative exposures
collateralized pursuant to our credit facility. Under the terms
of our financial derivative instruments and their
collateralization under our credit facility, we do not have
exposure to potential margin calls on our financial
derivative instruments. We currently have no reason to believe
that our counterparties to these commodity derivative contracts
are not financially viable. Our credit facility does not allow
us to offset amounts we may owe a lender against amounts we may
be owed related to our financial instruments with such party.
New commodity derivative
contracts. During 2010, we entered into
additional commodity derivative contracts to hedge a portion of
our estimated future production. The following table summarizes
information about these additional commodity derivative
contracts for the year ended December 31, 2010. When
aggregating multiple contracts, the weighted average contract
price is disclosed.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
Index
|
|
Contract
|
|
|
Volume
|
|
Price
|
|
Period
|
|
Oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
670,000
|
|
|
$83.72(a)
|
|
|
1/1/10
|
- 12/31/10
|
|
Price swap
|
|
|
195,000
|
|
|
$76.85(a)
|
|
|
3/1/10
|
- 12/31/10
|
|
Price swap
|
|
|
1,463,000
|
|
|
$88.63(a)
|
|
|
5/1/10
|
- 12/31/10
|
|
Price swap
|
|
|
378,000
|
|
|
$85.62(a)
|
|
|
1/1/11
|
- 6/30/11
|
|
Price swap
|
|
|
200,000
|
|
|
$83.47(a)
|
|
|
1/1/11
|
- 11/30/11
|
|
Price swap
|
|
|
6,282,000
|
|
|
$85.49(a)
|
|
|
1/1/11
|
- 12/31/11
|
|
Price swap
|
|
|
96,000
|
|
|
$86.80(a)
|
|
|
7/1/11
|
- 12/31/11
|
|
Price swap
|
|
|
540,000
|
|
|
$86.84(a)
|
|
|
1/1/12
|
- 6/30/12
|
|
Price swap
|
|
|
389,000
|
|
|
$86.95(a)
|
|
|
1/1/12
|
- 11/30/12
|
|
Price swap
|
|
|
5,487,000
|
|
|
$88.21(a)
|
|
|
1/1/12
|
- 12/31/12
|
|
Price swap
|
|
|
261,000
|
|
|
$82.50(a)
|
|
|
7/1/12
|
- 12/31/12
|
|
Price swap
|
|
|
1,380,000
|
|
|
$82.58(a)
|
|
|
1/1/13
|
- 12/31/13
|
|
Price swap
|
|
|
1,248,000
|
|
|
$83.94(a)
|
|
|
1/1/14
|
- 12/31/14
|
|
Price swap
|
|
|
600,000
|
|
|
$84.50(a)
|
|
|
1/1/15
|
- 6/30/15
|
|
Natural gas (volumes in MMBtus):
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
418,000
|
|
|
$5.99(b)
|
|
|
2/1/10
|
- 12/31/10
|
|
Price swap
|
|
|
1,250,000
|
|
|
$5.55(b)
|
|
|
3/1/10
|
- 12/31/10
|
|
Price swap
|
|
|
5,076,000
|
|
|
$6.14(b)
|
|
|
1/1/11
|
- 12/31/11
|
|
Price swap
|
|
|
300,000
|
|
|
$6.54(b)
|
|
|
1/1/12
|
- 12/31/12
|
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the
NYMEX-West Texas Intermediate monthly average futures price. |
|
(b) |
|
The index prices for the natural gas price swaps are based on
the NYMEX-Henry Hub last trading day futures price. |
Post-2010 commodity derivative
contracts. After December 31, 2010 and
through February 23, 2011, we entered into the following
oil price commodity derivative contracts to hedge an additional
portion of our estimated future production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
Index
|
|
Contract
|
|
|
Volume
|
|
Price
|
|
Period
|
|
Oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
115,000
|
|
|
$
|
96.65(a
|
)
|
|
|
3/1/11 - 11/30/11
|
|
Price swap
|
|
|
200,000
|
|
|
$
|
97.20(a
|
)
|
|
|
3/1/11 - 12/31/11
|
|
Price swap
|
|
|
45,000
|
|
|
$
|
99.35(a
|
)
|
|
|
1/1/12 - 3/31/12
|
|
Price swap
|
|
|
180,000
|
|
|
$
|
99.00(a
|
)
|
|
|
1/1/12 - 12/31/12
|
|
Price swap
|
|
|
300,000
|
|
|
$
|
99.00(a
|
)
|
|
|
7/1/12 - 9/30/12
|
|
Price swap
|
|
|
255,000
|
|
|
$
|
99.00(a
|
)
|
|
|
10/1/12 - 12/31/12
|
|
Price swap
|
|
|
1,080,000
|
|
|
$
|
99.88(a
|
)
|
|
|
1/1/13 - 12/31/13
|
|
|
|
|
(a) |
|
The index price for the oil price swap is based on the
NYMEX-West Texas Intermediate monthly average futures price. |
49
Results
of Operations
The following table sets forth summary information from our
continuing operations concerning our production and operating
data for the years ended December 31, 2010, 2009 and 2008.
The data in this table excludes results from the (i) Marbob
and Settlement Acquisitions for periods prior to their
respective close dates in October 2010, (ii) Wolfberry
Acquisitions for periods prior to December 2009 and
(iii) Henry Properties acquisition for periods prior to
August 1, 2008. Also, the table below excludes production
and operating data that we have classified as discontinued
operations, which is more fully described in Note O of the
Notes to Consolidated Financial Statements included in
Item 8. Financial Statements and Supplementary
Data.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
10,078
|
|
|
|
7,035
|
|
|
|
4,152
|
|
Natural gas (MMcf)
|
|
|
29,867
|
|
|
|
19,847
|
|
|
|
10,796
|
|
Total (MBoe)
|
|
|
15,056
|
|
|
|
10,343
|
|
|
|
5,951
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
27,611
|
|
|
|
19,274
|
|
|
|
11,344
|
|
Natural gas (Mcf)
|
|
|
81,827
|
|
|
|
54,375
|
|
|
|
29,497
|
|
Total (Boe)
|
|
|
41,249
|
|
|
|
28,337
|
|
|
|
16,260
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl)
|
|
$
|
76.12
|
|
|
$
|
57.97
|
|
|
$
|
95.93
|
|
Oil, with derivatives (Bbl)(a)
|
|
$
|
73.51
|
|
|
$
|
68.60
|
|
|
$
|
86.69
|
|
Natural gas, without derivatives (Mcf)
|
|
$
|
6.88
|
|
|
$
|
5.63
|
|
|
$
|
12.14
|
|
Natural gas, with derivatives (Mcf)(a)
|
|
$
|
7.46
|
|
|
$
|
6.19
|
|
|
$
|
12.21
|
|
Total, without derivatives (Boe)
|
|
$
|
64.60
|
|
|
$
|
50.24
|
|
|
$
|
88.96
|
|
Total, with derivatives (Boe)(a)
|
|
$
|
64.01
|
|
|
$
|
58.53
|
|
|
$
|
82.63
|
|
Operating costs and expenses per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses and workover costs
|
|
$
|
5.83
|
|
|
$
|
5.45
|
|
|
$
|
6.44
|
|
Oil and natural gas taxes
|
|
$
|
5.52
|
|
|
$
|
4.10
|
|
|
$
|
7.32
|
|
General and administrative
|
|
$
|
4.23
|
|
|
$
|
5.13
|
|
|
$
|
6.92
|
|
Depreciation, depletion and amortization
|
|
$
|
16.60
|
|
|
$
|
19.02
|
|
|
$
|
19.73
|
|
|
|
|
(a) |
|
Includes the effect of (i) commodity derivatives designated
as hedges and reported in oil and natural gas sales and
(ii) includes the cash payments/receipts from commodity
derivatives not designated as hedges and reported in operating
costs and expenses. See the table that reflects the amounts of
cash payments/receipts from commodity derivatives not designated
as hedges that were included in computing average prices with
derivatives and reconciles to the amount in gain (loss) on
derivatives not designated as hedges as reported in the
statements of operations in Item 1.
Business Our Production, Prices and Expenses. |
50
The following table sets forth summary information from our
discontinued operations concerning our production and operating
data for the years ended December 31, 2010, 2009 and 2008.
The discontinued operations is the result of reclassifying the
results of operations from our December 2010 Permian divestiture
from continuing operations for GAAP purposes, which is more
fully described in Note O of the Notes to Consolidated
Financial Statements included in Item 8. Financial
Statements and Supplementary Data.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
252
|
|
|
|
301
|
|
|
|
434
|
|
Natural gas (MMcf)
|
|
|
1,538
|
|
|
|
1,721
|
|
|
|
4,172
|
|
Total (MBoe)
|
|
|
508
|
|
|
|
588
|
|
|
|
1,129
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
690
|
|
|
|
825
|
|
|
|
1,189
|
|
Natural gas (Mcf)
|
|
|
4,214
|
|
|
|
4,715
|
|
|
|
11,430
|
|
Total (Boe)
|
|
|
1,392
|
|
|
|
1,611
|
|
|
|
3,094
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl)
|
|
$
|
73.34
|
|
|
$
|
58.39
|
|
|
$
|
53.57
|
|
Natural gas, without derivatives (Mcf)
|
|
$
|
4.61
|
|
|
$
|
4.22
|
|
|
$
|
2.99
|
|
Total, without derivatives (Boe)
|
|
$
|
50.33
|
|
|
$
|
42.26
|
|
|
$
|
31.62
|
|
Operating costs and expenses per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses and workover costs
|
|
$
|
14.90
|
|
|
$
|
12.30
|
|
|
$
|
5.70
|
|
Oil and natural gas taxes
|
|
$
|
4.74
|
|
|
$
|
3.58
|
|
|
$
|
2.62
|
|
General and administrative(a)
|
|
$
|
(1.94
|
)
|
|
$
|
(1.51
|
)
|
|
$
|
(0.31
|
)
|
Depreciation, depletion and amortization
|
|
$
|
14.69
|
|
|
$
|
16.00
|
|
|
$
|
5.76
|
|
|
|
|
(a) |
|
Represents the fees received from third-parties for operating
oil and natural gas properties that were sold. We reflect these
fees as a reduction of general and administrative expenses. |
The following table presents selected production and operating
data for the fields which represent greater than 15 percent
of our total proved reserves for the years ended
December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
West
|
|
Grayburg
|
|
West
|
|
Grayburg
|
|
Grayburg
|
|
|
Wolfberry(a)
|
|
Jackson
|
|
Wolfberry(a)
|
|
Jackson
|
|
Jackson
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
1,643
|
|
|
|
1,680
|
|
|
|
1,320
|
|
|
|
1,429
|
|
|
|
1,045
|
|
Natural gas (MMcf)
|
|
|
4,679
|
|
|
|
4,696
|
|
|
|
3,361
|
|
|
|
4,108
|
|
|
|
3,407
|
|
Total (MBoe)
|
|
|
2,423
|
|
|
|
2,463
|
|
|
|
1,880
|
|
|
|
2,114
|
|
|
|
1,613
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl)
|
|
$
|
77.74
|
|
|
$
|
75.72
|
|
|
$
|
58.30
|
|
|
$
|
58.87
|
|
|
$
|
94.35
|
|
Natural gas, without derivatives (Mcf)
|
|
$
|
7.37
|
|
|
$
|
7.59
|
|
|
$
|
6.03
|
|
|
$
|
5.76
|
|
|
$
|
10.67
|
|
Total, without derivatives (Boe)
|
|
$
|
66.95
|
|
|
$
|
66.12
|
|
|
$
|
51.72
|
|
|
$
|
51.00
|
|
|
$
|
83.68
|
|
Production costs per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses including workovers
|
|
$
|
4.51
|
|
|
$
|
6.24
|
|
|
$
|
4.86
|
|
|
$
|
4.47
|
|
|
$
|
4.55
|
|
Oil and natural gas taxes
|
|
$
|
4.32
|
|
|
$
|
5.70
|
|
|
$
|
3.77
|
|
|
$
|
4.42
|
|
|
$
|
7.20
|
|
|
|
|
(a) |
|
This field was acquired as part of the Henry Properties
acquisition in July 2008. |
51
Year
Ended December 31, 2010 Compared to Year Ended
December 31, 2009
Oil and natural gas revenues. Revenue
from oil and natural gas operations was $972.6 million for
the year ended December 31, 2010, an increase of
$453.0 million (87 percent) from $519.6 million
for the year ended December 31, 2009. This increase was
primarily due to increases in realized oil and natural gas
prices and increased production (i) as a result of the
Wolfberry Acquisitions, (ii) the Marbob and Settlement
Acquisitions which closed in October 2010 and (iii) due to
successful drilling efforts during 2009 and 2010. Specifically
the:
|
|
|
|
|
average realized oil price (excluding the effects of derivative
activities) was $76.12 per Bbl during the year ended
December 31, 2010, an increase of 31 percent from
$57.97 per Bbl during the year ended December 31, 2009;
|
|
|
|
total oil production was 10,078 MBbl for the year ended
December 31, 2010, an increase of 3,043 MBbl
(43 percent) from 7,035 MBbl for the year ended
December 31, 2009;
|
|
|
|
average realized natural gas price (excluding the effects of
derivative activities) was $6.88 per Mcf during the year ended
December 31, 2010, an increase of 22 percent from
$5.63 per Mcf during the year ended December 31, 2009. Our
natural gas prices have been significantly higher than the
related NYMEX prices primarily due to the value of the natural
gas liquids in our liquids-rich natural gas stream; and
|
|
|
|
total natural gas production was 29,867 MMcf for the year
ended December 31, 2010, an increase of 10,020 MMcf
(50 percent) from 19,847 MMcf for the year ended
December 31, 2009.
|
Production expenses. The following
table provides the components of our total oil and natural gas
production costs for the years ended December 31, 2010 and
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
Lease operating expenses
|
|
$
|
84,907
|
|
|
$
|
5.64
|
|
|
$
|
55,421
|
|
|
$
|
5.36
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem
|
|
|
8,708
|
|
|
|
0.58
|
|
|
|
4,912
|
|
|
|
0.47
|
|
Production
|
|
|
74,327
|
|
|
|
4.94
|
|
|
|
37,495
|
|
|
|
3.63
|
|
Workover costs
|
|
|
2,825
|
|
|
|
0.19
|
|
|
|
954
|
|
|
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas production expenses
|
|
$
|
170,767
|
|
|
$
|
11.35
|
|
|
$
|
98,782
|
|
|
$
|
9.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, we have some
control over lease operating expenses and workover costs on
properties we operate, but production and ad valorem taxes are
directly related to commodity price changes.
Lease operating expenses were $84.9 million ($5.64 per Boe)
for the year ended December 31, 2010 which was an increase
of $29.5 million (53 percent) from $55.4 million
($5.36 per Boe) for the year ended December 31, 2009. The
increase in lease operating expenses was primarily due to
(i) our wells successfully drilled and completed in 2009
and 2010, (ii) additional interests acquired in the
Wolfberry Acquisitions in December 2009 and (iii) the
Marbob and Settlement Acquisitions which closed in October 2010.
The increase in lease operating expenses per Boe was primarily
due to (i) cost increases in services and supplies
primarily related to increase in commodity prices and
(ii) a reduction in our third-party income from utilization
of our salt water disposal systems, in part due to our use of
those systems, offset in part by additional production from our
wells successfully drilled and completed in 2009 and 2010 where
we are receiving benefits from economies of scale.
Ad valorem taxes have increased primarily as a result of
increased valuations of our Texas properties and the increase in
our number of wells primarily associated with the Wolfberry
Acquisitions and 2009 and 2010 drilling activity.
Production taxes per unit of production were $4.94 per Boe
during the year ended December 31, 2010, an increase of
36 percent from $3.63 per Boe during the year ended
December 31, 2009. The increase was directly
52
related to the increase in commodity prices and our increase in
oil and natural gas revenues related to increased volumes
coupled with a $2.2 million ($0.21 per Boe) increase in
production taxes in 2010 related to prior years taxes on one of
our assets in our New Mexico Shelf area. Over the same period,
our per Boe prices (excluding the effects of derivatives)
increased 29 percent.
Workover expenses were approximately $2.8 million and
$1.0 million for the years ended December 31, 2010 and
2009, respectively. The 2010 amounts related primarily to
increased workovers during the first two quarters of 2010 in our
New Mexico Shelf area due to work performed to restore
production, whereas the 2009 amounts related primarily to
workovers in our Texas Permian area.
Exploration and abandonments
expense. The following table provides a
breakdown of our exploration and abandonments expense for the
years ended December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Geological and geophysical
|
|
$
|
2,712
|
|
|
$
|
3,635
|
|
Exploratory dry holes
|
|
|
37
|
|
|
|
1,941
|
|
Leasehold abandonments and other
|
|
|
7,575
|
|
|
|
5,056
|
|
|
|
|
|
|
|
|
|
|
Total exploration and abandonments
|
|
$
|
10,324
|
|
|
$
|
10,632
|
|
|
|
|
|
|
|
|
|
|
Our geological and geophysical expense, which primarily consists
of the costs of acquiring and processing seismic data,
geophysical data and core analysis, was approximately
$2.7 million and $3.7 million for the years ended
December 31, 2010 and 2009, respectively.
Our exploratory dry hole expense during the year ended
December 31, 2009 was primarily attributable to an
unsuccessful exploratory well located on our Arkansas acreage
and two unsuccessful exploratory wells in our Texas Permian area.
For the year ended December 31, 2010, we recorded
approximately $7.6 million of leasehold abandonments, which
related to non-core prospects in our New Mexico Basin and Texas
Permian areas and abandonment costs related to specific wells in
our New Mexico Shelf and Texas Permian areas. For the year ended
December 31, 2009, we recorded $5.1 million of
leasehold abandonments, which related primarily to the write-off
of four prospects in our New Mexico Shelf area and three
prospects in our Texas Permian area.
Depreciation, depletion and amortization
expense. The following table provides
components of our depreciation, depletion and amortization
expense for the years ended December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
245,197
|
|
|
$
|
16.29
|
|
|
$
|
192,501
|
|
|
$
|
18.61
|
|
Depreciation of other property and equipment
|
|
|
3,104
|
|
|
|
0.21
|
|
|
|
2,680
|
|
|
|
0.26
|
|
Amortization of intangible asset operating rights
|
|
|
1,549
|
|
|
|
0.10
|
|
|
|
1,555
|
|
|
|
0.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depletion, depreciation and amortization
|
|
$
|
249,850
|
|
|
$
|
16.60
|
|
|
$
|
196,736
|
|
|
$
|
19.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period end
|
|
$
|
75.96
|
|
|
|
|
|
|
$
|
57.65
|
|
|
|
|
|
Natural gas price used to estimate proved natural gas reserves
at period end
|
|
$
|
4.38
|
|
|
|
|
|
|
$
|
3.87
|
|
|
|
|
|
Depletion of proved oil and natural gas properties was
$245.2 million ($16.29 per Boe) for the year ended
December 31, 2010, an increase of $52.7 million
(27 percent) from $192.5 million ($18.61 per Boe) for
the year ended December 31, 2009. The increase in depletion
expense was primarily due to (i) capitalized costs
associated with new wells that were successfully drilled and
completed in 2009 and 2010, (ii) the Wolfberry Acquisitions
and (iii) the Marbob and Settlement Acquisitions, offset in
part by the increase in the oil and natural gas prices between
53
the periods utilized to determine proved reserves. The decrease
in depletion expense per Boe was primarily due to (i) the
increase in the oil and natural gas prices between the periods
utilized to determine proved reserves, (ii) the increase in
proved reserves from the successful 2009 and 2010 drilling of
unproved properties, (iii) the proved finding costs
associated with the Marbob and Settlement Acquisitions and
(iv) the increase in total proved reserves due to the SEC
rules adopted at the end of 2009 related to disclosures of oil
and natural gas reserves.
On December 31, 2009, we adopted the SEC rules related to
disclosures of oil and natural gas reserves. As a result of
these SEC rules we recorded an additional 13.6 MMBoe of
proved reserves. We utilized the additional proved reserves
beginning in our depletion computation in the fourth quarter of
2009. Our fourth quarter of 2009 depletion expense rate was
$17.19 per Boe, which was lower than past quarters in part due
to the these additional proved reserves. Comparisons between
years as it relates to our depletion rate is difficult as a
result of these rules.
The amortization of the intangible asset is a result of the
value assigned to the operating rights that we acquired in the
Henry Properties acquisition. The intangible asset is currently
being amortized over an estimated life of approximately
25 years.
Impairment of long-lived assets. We
periodically review our long-lived assets to be held and used,
including proved oil and natural gas properties accounted for
under the successful efforts method of accounting. Due primarily
to downward adjustments to the economically recoverable proved
reserves associated with well performance, we recognized a
non-cash charge against earnings of $11.6 million during
the year ended December 31, 2010, which was primarily
attributable to natural gas related properties in our New Mexico
Shelf area and to a lesser extent impairment in value of certain
of our inventoried tubular goods. For the year ended
December 31, 2009, we recognized a non-cash charge against
earnings of $7.9 million, which was comprised primarily of
natural gas related properties in our New Mexico Shelf area.
General and administrative
expenses. The following table provides
components of our general and administrative expenses for the
years ended December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
General and administrative expenses recurring
|
|
$
|
59,704
|
|
|
$
|
3.96
|
|
|
$
|
44,476
|
|
|
$
|
4.30
|
|
Non-recurring bonus paid to Henry Entities employees
|
|
|
5,059
|
|
|
|
0.33
|
|
|
|
10,150
|
|
|
|
0.98
|
|
Non-cash stock-based compensation stock options
|
|
|
2,653
|
|
|
|
0.17
|
|
|
|
4,285
|
|
|
|
0.41
|
|
Non-cash stock-based compensation restricted stock
|
|
|
10,278
|
|
|
|
0.67
|
|
|
|
4,755
|
|
|
|
0.46
|
|
Less: Third-party operating fee reimbursements
|
|
|
(13,419
|
)
|
|
|
(0.90
|
)
|
|
|
(10,502
|
)
|
|
|
(1.02
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses
|
|
$
|
64,275
|
|
|
$
|
4.23
|
|
|
$
|
53,164
|
|
|
$
|
5.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were $64.3 million
($4.23 per Boe) for year ended December 31, 2010, an
increase of $11.1 million (21 percent) from
$53.2 million ($5.13 per Boe) for the year ended
December 31, 2009. The increase in general and
administrative expenses was primarily due to (i) an
increase in non-cash stock-based compensation for stock-based
compensation awards, (ii) additional personnel and related
costs associated with the Marbob Acquisition and (iii) an
increase in the number of employees and related personnel
expenses to handle our increased activities, partially offset by
(i) a decrease in the non-recurring bonus due to the Henry
Entities employees (discussed in the next paragraph) and
(ii) an increase in third-party operating fee
reimbursements. The decrease in total general and administrative
expenses per Boe was primarily due to increased production
associated with (i) additional production from our wells
successfully drilled and completed in 2009 and 2010,
(ii) additional production from our Wolfberry Acquisitions
for which we added no administrative personnel and
(iii) the production from our the Marbob and Settlement
Acquisitions.
In connection with the Henry Entities acquisition in July 2008,
we agreed to pay certain of the Henry Entities former
employees a predetermined bonus amount, in addition to the
compensation we pay these employees, at each of the first and
second anniversaries of the closing of the acquisition. Since
these employees earned this bonus over
54
the two years following the acquisition and it is outside of our
control, we are reflecting the cost in our general and
administrative costs as non-recurring. The final payment of the
Henry Entities bonuses occurred in July 2010.
We earn reimbursements as operator of certain oil and natural
gas properties in which we own interests. As such, we earned
reimbursements of $13.4 million and $10.5 million
during the years ended December 31, 2010 and 2009,
respectively, which increased primarily as a result of
additional operated properties from our drilling and
acquisitions. This reimbursement is reflected as a reduction of
general and administrative expenses in the consolidated
statements of operations.
Bad debt expense. In May 2008, we
entered into a short-term purchase agreement with an oil
purchaser to buy a portion of our oil affected as a result of a
New Mexico refinery shut down due to repairs. In July 2008, this
purchaser declared bankruptcy. We fully reserved the receivable
amount due from this purchaser of approximately
$2.9 million as of December 31, 2008, and pursued a
claim in the bankruptcy proceedings. In December 2009, we
recovered approximately $1.0 million and accordingly
reduced our allowance for bad debts and bad debt expense.
Loss on derivatives not designated as
hedges. The following table sets forth the
cash settlements and the non-cash
mark-to-market
adjustment for the derivative contracts not designated as hedges
for the years ended December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Cash payments (receipts):
|
|
|
|
|
|
|
|
|
Commodity derivatives oil
|
|
$
|
26,281
|
|
|
$
|
(74,796
|
)
|
Commodity derivatives natural gas
|
|
|
(17,414
|
)
|
|
|
(10,955
|
)
|
Financial derivatives interest rate
|
|
|
4,957
|
|
|
|
3,335
|
|
Mark-to-market
(gain) loss:
|
|
|
|
|
|
|
|
|
Commodity derivatives oil
|
|
|
93,595
|
|
|
|
229,896
|
|
Commodity derivatives natural gas
|
|
|
(23,347
|
)
|
|
|
7,959
|
|
Financial derivatives interest rate
|
|
|
3,253
|
|
|
|
1,418
|
|
|
|
|
|
|
|
|
|
|
Loss on derivatives not designated as hedges
|
|
$
|
87,325
|
|
|
$
|
156,857
|
|
|
|
|
|
|
|
|
|
|
Interest expense. The following table
sets forth interest expense, weighted average interest rates and
weighted average debt balances for the years ended
December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2010
|
|
2009
|
|
|
(Dollars in thousands)
|
|
Interest expense
|
|
$
|
60,087
|
|
|
$
|
28,292
|
|
Weighted average interest rate
|
|
|
5.1
|
%
|
|
|
3.4
|
%
|
Weighted average debt balance
|
|
$
|
979,093
|
|
|
$
|
667,993
|
|
The increase in weighted average debt balance during the year
ended December 31, 2010, was due primarily to borrowings in
October 2010 for the Marbob and Settlement Acquisitions. The
increase in interest expense is due to an increase in the
weighted average debt balance. The increase in the weighted
average interest rate is primarily due to the issuance of our
senior notes.
In September 2009, we issued $300 million of
8.625% senior notes at a discount, resulting in a
yield-to-maturity
of 8.875 percent. Currently, the interest rate associated
with the senior notes is higher than the credit facility, which
results in us, currently, having higher absolute interest rates.
Income tax provisions. We recorded
income tax expense of $122.6 million and an income tax
benefit of $21.5 million for the years ended
December 31, 2010 and 2009, respectively. The effective
income tax rate for the years ended December 31, 2010 and
2009 was 40.1 percent and 65.1 percent, respectively,
between periods.
55
We recorded an $8.3 million charge to income tax expense in
the fourth quarter of 2010 to increase our estimated overall
state tax rate utilized to record our net deferred tax
liability. This increase in the tax rate is due to an increase
in our overall blended state income tax rate, a result of the
assets acquired in the Marbob and Settlement Acquisitions being
located in New Mexico where the state income tax rate is higher
than in Texas. Also, in 2010, we recorded a benefit of
approximately $1.6 million associated with revisions to our
2009 income tax provision.
In 2009, we recorded a tax benefit of approximately
$6.6 million associated with a reduction in our estimated
overall state tax rate and the related effect on our net
deferred tax liability. In 2009, we made the Wolfberry
Acquisitions, the assets of which were primarily in the state of
Texas. The state income tax rate is lower in Texas compared to
New Mexico (the location of our other significant concentration
of assets). Accordingly, this has caused a reduction of our
overall estimated state income tax rate due to the addition of
Texas assets. Also, in 2009, we recorded a benefit of
approximately $1.6 million associated with revisions to our
2008 tax provision.
Excluding the effect of these two items our effective income tax
rate would have been 37.9 percent and 40.5 percent in
2010 and 2009, respectively, which would approximate a more
normalized effective income tax rate.
Income (loss) from discontinued operations, net of
tax. In December 2010, we closed the sale of
certain of our non-core Permian Basin assets for cash
consideration of $103.3 million.
The results of operations of these assets and the related gain
on disposition are reported as discontinued operations in the
accompanying consolidated statements of operations, described in
more detail in Note O of the Notes to Consolidated
Financial Statements included in Item 8. Financial
Statements and Supplementary Data. The Company recognized
income from discontinued operations of $21.3 million and
$1.7 million for the years ended December 31, 2010 and
2009, respectively. In 2010, income from discontinued operations
included a pre-tax gain of the sale of these assets of
$29.1 million.
Year
Ended December 31, 2009 Compared to Year Ended
December 31, 2008
Oil and natural gas revenues. Revenue
from oil and natural gas operations was $519.6 million for
the year ended December 31, 2009, an increase of
$21.5 million (4 percent) from $498.1 million for
the year ended December 31, 2008. This increase was due to
increased production (i) as a result of the inclusion of a
full year of production in 2009 from the Henry Properties
acquisition and (ii) due to successful drilling efforts
during 2008 and 2009, partially offset by substantial decreases
in realized oil and natural gas prices. Specifically, the:
|
|
|
|
|
average realized oil price (excluding the effects of derivative
activities) was $57.97 per Bbl during the year ended
December 31, 2009, a decrease of 40 percent from
$95.93 per Bbl during the year ended December 31, 2008;
|
|
|
|
total oil production was 7,035 MBbl for the year ended
December 31, 2009, an increase of 2,883 MBbl
(69 percent) from 4,152 MBbl for the year ended
December 31, 2008;
|
|
|
|
average realized natural gas price (excluding the effects of
derivative activities) was $5.63 per Mcf during the year ended
December 31, 2009, a decrease of 54 percent from
$12.14 per Mcf during the year ended December 31, 2008. Our
natural gas prices have been significantly higher than the
related NYMEX prices primarily due to the value of the natural
gas liquids in our liquids-rich natural gas stream; and
|
|
|
|
total natural gas production was 19,847 MMcf for the year
ended December 31, 2009, an increase of 9,051 MMcf
(84 percent) from 10,796 MMcf for the year ended
December 31, 2008.
|
Hedging activities. We utilize
commodity derivative instruments in order to (i) reduce the
effect of the volatility of price changes on the commodities we
produce and sell, (ii) support our capital budget and
expenditure plans and (iii) support the economics
associated with acquisitions.
Currently, we do not designate our derivative instruments to
qualify for hedge accounting. Accordingly, we reflect the
changes in the fair value and settlements of our derivative
instruments in the statements of operations as (gain) loss on
derivatives not designated as hedges. All of our remaining
hedges that historically qualified or were dedesignated from
hedge accounting were settled in 2008. For further discussion
and information see (Gain) loss
56
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.
The following is a summary of the effects of commodity hedges
that qualified for hedge accounting treatment for the year ended
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
Oil Hedges
|
|
Natural Gas Hedges
|
|
|
Years Ended
|
|
Years Ended
|
|
|
December 31, 2008
|
|
December 31, 2008
|
|
|
(Dollars in thousands)
|
|
Decrease in oil and natural gas revenues
|
|
$
|
(30,591
|
)
|
|
$
|
(696
|
)
|
Hedged volumes (Bbls and MMBtus, respectively)
|
|
|
951,000
|
|
|
|
4,941,000
|
|
Production expenses. The following
table provides the components of our total oil and natural gas
production costs for the years ended December 31, 2009 and
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
Lease operating expenses
|
|
$
|
55,421
|
|
|
$
|
5.36
|
|
|
$
|
37,293
|
|
|
$
|
6.27
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem
|
|
|
4,912
|
|
|
|
0.47
|
|
|
|
2,101
|
|
|
|
0.35
|
|
Production
|
|
|
37,495
|
|
|
|
3.63
|
|
|
|
41,450
|
|
|
|
6.97
|
|
Workover costs
|
|
|
954
|
|
|
|
0.09
|
|
|
|
992
|
|
|
|
0.17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas production expenses
|
|
$
|
98,782
|
|
|
$
|
9.55
|
|
|
$
|
81,836
|
|
|
$
|
13.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, we have some
control over lease operating expenses and workover costs on
properties we operate, but production and ad valorem taxes are
directly related to commodity price changes.
Lease operating expenses were $55.4 million ($5.36 per Boe)
for the year ended December 31, 2009, an increase of
$18.1 million (49 percent) from $37.3 million
($6.27 per Boe) for the year ended December 31, 2008. The
total increase in absolute amounts in lease operating expenses
was due to (i) the inclusion of a full year of expenses
from the wells acquired in the Henry Properties acquisition and
(ii) our wells successfully drilled and completed in 2008
and 2009. The decrease in lease operating expenses on a per unit
basis is due to (i) increased volumes from our successful
drilling program in 2008 and 2009 that has allowed economies of
scale in our cost structure and (ii) cost reductions in
services and supplies, primarily as a result of the recently
lower commodity prices, offset by the wells acquired in the
Henry Properties acquisition, which have a higher per unit cost
as compared to our historical per unit cost.
Ad valorem taxes have increased primarily as a result of the
Henry Properties acquisition, which were highly concentrated in
Texas, a state which has a higher ad valorem tax rate than New
Mexico, where substantially all of our properties prior to the
Henry Properties acquisition were located.
Production taxes per unit of production were $3.63 per Boe
during the year ended December 31, 2009, a decrease of
48 percent from $6.97 per Boe during the year ended
December 31, 2008. The decrease was directly related to the
decrease in commodity prices offset by the increase in oil and
natural gas revenues related to increased volumes. Over the same
period, our Boe prices (excluding the effects of derivatives)
decreased 44 percent.
57
Exploration and abandonments
expense. The following table provides a
breakdown of our exploration and abandonments expense for the
years ended December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Geological and geophysical
|
|
$
|
3,635
|
|
|
$
|
3,140
|
|
Exploratory dry holes
|
|
|
1,941
|
|
|
|
3,722
|
|
Leasehold abandonments and other
|
|
|
5,056
|
|
|
|
31,606
|
|
|
|
|
|
|
|
|
|
|
Total exploration and abandonments
|
|
$
|
10,632
|
|
|
$
|
38,468
|
|
|
|
|
|
|
|
|
|
|
Our geological and geophysical expense during the year ended
December 31, 2009 was primarily attributable to continued
seismic activity in our Lower Abo assets in our New Mexico Shelf
area. During the year ended December 31, 2008, our
geological and geophysical expense was primarily attributable to
a comprehensive seismic survey on our New Mexico Shelf area
which was initiated in December 2007 and completed in 2008.
During the year ended December 31, 2009, we wrote-off an
unsuccessful exploratory well on our Arkansas acreage and two
unsuccessful exploratory wells in Texas Permian area. Our
exploratory dry hole expense during the year ended
December 31, 2008 was primarily attributable to an
unsuccessful operated exploratory well located in our Texas
Permian area.
For the year ended December 31, 2009, we recorded
approximately $5.1 million of leasehold abandonments, which
relate primarily to the write-off of four prospects in our New
Mexico Shelf area and three prospects in our Texas Permian area.
For the year ended December 31, 2008, we recorded
$31.6 million of leasehold abandonments, which were
primarily related to two prospects in our Texas Permian area and
on our Arkansas acreage.
Depreciation, depletion and amortization
expense. The following table provides
components of our depreciation, depletion and amortization
expense for the years ended December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
192,501
|
|
|
$
|
18.61
|
|
|
$
|
114,958
|
|
|
$
|
19.32
|
|
Depreciation of other property and equipment
|
|
|
2,680
|
|
|
|
0.26
|
|
|
|
1,808
|
|
|
|
0.30
|
|
Amortization of intangible asset operating rights
|
|
|
1,555
|
|
|
|
0.15
|
|
|
|
640
|
|
|
|
0.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depletion, depreciation and amortization
|
|
$
|
196,736
|
|
|
$
|
19.02
|
|
|
$
|
117,406
|
|
|
$
|
19.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period end
|
|
$
|
57.65
|
|
|
|
|
|
|
$
|
41.00
|
|
|
|
|
|
Natural gas price used to estimate proved natural gas reserves
at period end
|
|
$
|
3.87
|
|
|
|
|
|
|
$
|
5.71
|
|
|
|
|
|
Depletion of proved oil and natural gas properties was
$192.5 million ($18.61 per Boe) for the year ended
December 31, 2009, an increase of $77.5 million
(67 percent) from $115.0 million ($19.32 per Boe) for
the year ended December 31, 2008. The increase in depletion
expense, on an absolute basis, was primarily due to (i) a
full year effect of the Henry Properties acquisition,
(ii) capitalized costs associated with new wells that were
successfully drilled and completed in 2008 and 2009 and
(iii) to a lesser extent the Wolfberry Acquisitions in
December 2009. The decrease in the per Boe depletion expense was
primarily due to the increase in the oil prices between the
years utilized to determine proved reserves partially offset by
(i) the Henry Properties acquisition, for which the
depletion rate was higher than that of our historical assets and
(ii) capitalized costs associated with the drilling of
proved undeveloped locations which generally do not add any
incremental proved reserves.
On December 31, 2009, we adopted the SEC rules related to
disclosures of oil and natural gas reserves. As a result of
these SEC rules we recorded an additional 13.6 MMBoe of
proved reserves. We utilized the additional proved reserves
beginning in our depletion computation in the fourth quarter of
2009. Our fourth quarter of 2009
58
depletion expense rate was $17.19 per Boe, which was lower than
past quarters in part due to the these additional proved
reserves. Comparisons between years as it relates to our
depletion rate is difficult as a result of these rules.
The amortization of the intangible asset is a result of the
value assigned to the operating rights that we acquired in the
Henry Properties acquisition. The intangible asset is currently
being amortized over an estimated life of approximately
25 years.
Impairment of long-lived assets. We
periodically review our long-lived assets to be held and used,
including proved oil and natural gas properties accounted for
under the successful efforts method of accounting. Due primarily
to downward adjustments to the economically recoverable proved
reserves associated with declines in commodity prices and well
performance, we recognized a non-cash charge against earnings of
$7.9 million during the year ended December 31, 2009,
which was primarily attributable to natural gas related
properties in our New Mexico Shelf area. For the year ended
December 31, 2008, we recognized a non-cash charge against
earnings of $11.5 million, which was comprised primarily of
fields in our non-core areas.
General and administrative
expenses. The following table provides
components of our general and administrative expenses for the
years ended December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
Amount
|
|
|
Per Boe
|
|
|
Amount
|
|
|
Per Boe
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
General and administrative expenses recurring
|
|
$
|
44,476
|
|
|
$
|
4.30
|
|
|
$
|
36,170
|
|
|
$
|
6.08
|
|
Non-recurring bonus paid to Henry Entities employees
|
|
|
10,150
|
|
|
|
0.98
|
|
|
|
4,328
|
|
|
|
0.73
|
|
Non-cash stock-based compensation stock options
|
|
|
4,285
|
|
|
|
0.41
|
|
|
|
3,101
|
|
|
|
0.52
|
|
Non-cash stock-based compensation restricted stock
|
|
|
4,755
|
|
|
|
0.46
|
|
|
|
2,122
|
|
|
|
0.36
|
|
Less: Third-party operating fee reimbursements
|
|
|
(10,502
|
)
|
|
|
(1.02
|
)
|
|
|
(4,591
|
)
|
|
|
(0.77
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses
|
|
$
|
53,164
|
|
|
$
|
5.13
|
|
|
$
|
41,130
|
|
|
$
|
6.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were $53.2 million
($5.13 per Boe) for the year ended December 31, 2009, an
increase of $12.1 million (29 percent) from
$41.1 million ($6.92 per Boe) for the year ended
December 31, 2008. The increase in general and
administrative expenses during the year ended December 31,
2009 over 2008 was primarily due to (i) a full year effect
of the non-recurring bonus paid to former Henry Entities
employees, (ii) an increase in non-cash stock-based
compensation and (iii) an increase in the number of
employees and related personnel expenses, partially offset by an
increase in third-party operating fee reimbursements.
In connection with the Henry Entities acquisition, we agreed to
pay certain of our employees, who were formerly Henry
Entities employees, a predetermined bonus amount, in
addition to the compensation we pay these employees, over the
two years following the acquisition. Since these employees will
earn this bonus over the two years, we are reflecting the cost
in our general and administrative costs as non-recurring, as it
is not controlled by us.
We earn reimbursements as operator of certain oil and natural
gas properties in which we own interests. As such, we earned
reimbursements of $10.5 million and $4.6 million
during the year ended December 31, 2009 and 2008,
respectively. This reimbursement is reflected as a reduction of
general and administrative expenses in the consolidated
statements of operations. The increase in this reimbursement is
primarily related to the Henry Properties acquisition, as we own
a lower working interest in these operated properties compared
to our historical property base, so we receive a larger
third-party reimbursement as compared to our historical property
base and 2009 reflects a full year effect of owning the Henry
Properties.
Bad debt expense. In May 2008, we
entered into a short-term purchase agreement with an oil
purchaser to buy a portion of our oil affected as a result of a
New Mexico refinery shut down due to repairs. In July 2008, this
purchaser declared bankruptcy. We fully reserved the receivable
amount due from this purchaser of approximately
$2.9 million as of December 31, 2008, and pursued a
claim in the bankruptcy proceedings. In December 2009, we
recovered approximately $1.0 million and accordingly
reduced our allowance for bad debts and bad debt expense.
59
(Gain) loss on derivatives not designated as
hedges. In 2007, we discontinued designating
our derivative instruments to qualify for hedge accounting; see
Note I of the Notes to Consolidated Financial Statements
included in Item 8. Financial Statements and
Supplementary Data for additional information related to
our derivative instruments. Accordingly, we reflect changes in
the fair value and settlements of our derivative instruments in
our consolidated statements of operations.
The following table sets forth the cash settlements and the
non-cash
mark-to-market
adjustment for the derivative contracts not designated as hedges
for the years ended December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Cash payments (receipts):
|
|
|
|
|
|
|
|
|
Commodity derivatives oil
|
|
$
|
(74,796
|
)
|
|
$
|
7,780
|
|
Commodity derivatives natural gas
|
|
|
(10,955
|
)
|
|
|
(1,426
|
)
|
Financial derivatives interest rate
|
|
|
3,335
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market
(gain) loss:
|
|
|
|
|
|
|
|
|
Commodity derivatives oil
|
|
|
229,896
|
|
|
|
(253,960
|
)
|
Commodity derivatives natural gas
|
|
|
7,959
|
|
|
|
(3,347
|
)
|
Financial derivatives interest rate
|
|
|
1,418
|
|
|
|
1,083
|
|
|
|
|
|
|
|
|
|
|
(Gain) loss on derivatives not designated as hedges
|
|
$
|
156,857
|
|
|
$
|
(249,870
|
)
|
|
|
|
|
|
|
|
|
|
Interest expense. The following table
sets forth interest expense, weighted average interest rates and
weighted average debt balances for the years ended
December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2009
|
|
2008
|
|
|
(dollars in thousands)
|
|
Interest expense
|
|
$
|
28,292
|
|
|
$
|
29,039
|
|
Weighted average interest rate
|
|
|
3.4
|
%
|
|
|
5.1
|
%
|
Weighted average debt balance
|
|
$
|
667,993
|
|
|
$
|
450,654
|
|
In September 2009, we issued $300 million of
8.625% senior notes at a discount, resulting in a
yield-to-maturity
of 8.875 percent. Currently, the interest rate associated
with the senior notes is higher than the credit facility, which
will result in us having higher absolute interest rates in the
foreseeable future.
The increase in weighted average debt balance during the year
ended December 31, 2009 was due primarily to borrowings in
2008 for the Henry Properties acquisition. The decrease in
interest expense is due to a decrease in the weighted average
interest rate offset by an increase in the weighted average debt
balance. The decrease in the weighted average interest rate is
primarily due to an improvement in market interest rates, offset
by the issuance of our senior notes.
Income tax provisions. We recorded an
income tax benefit of $21.5 million and income tax expense
of $157.4 million for the years ended December 31,
2009 and 2008, respectively. The effective income tax rate for
the year ended December 31, 2009 and 2008 was
65.1 percent and 36.8 percent, respectively.
In 2009 and 2008, we recorded a tax benefit of approximately
$6.6 million and $5.7 million associated with a
reduction in our estimated overall state tax rate and the
related effect on our net deferred tax liability. In 2008, we
closed the Henry Properties acquisition and in 2009 we closed
the Wolfberry Acquisitions, the assets of which were primarily
in the state of Texas. The state income tax rate is lower in
Texas compared to New Mexico (the location of our other
significant concentration of assets). Accordingly, this has
caused a reduction of our overall estimated state income tax
rate due to the addition of Texas assets. Also, in 2009, we
recorded a benefit of approximately $1.6 million associated
with revisions to our 2008 tax provision. Excluding the effect
of these two items our
60
effective income tax rate would have been 40.5 percent and
38.1 percent in 2009 and 2008, respectively, which would
approximate a more normalized effective income tax
rate.
Income (loss) from discontinued operations, net of
tax. In December 2010, we closed the sale of
certain of our Permian Basin assets for cash consideration of
$103.3 million.
The results of operations of these assets and the related gain
on disposition are reported as discontinued operations in the
accompanying consolidated statements of operations described in
more detail in Note O of the Notes to Consolidated
Financial Statements included in Item 8. Financial
Statements and Supplementary Data. The Company recognized
income from discontinued operations of $1.7 million and
$8.5 million during 2009 and 2008, respectively.
Capital
Commitments, Capital Resources and Liquidity
Capital commitments. Our primary needs
for cash are development, exploration and acquisition of oil and
natural gas assets, payment of contractual obligations and
working capital obligations. Funding for these cash needs may be
provided by any combination of internally-generated cash flow,
financing under our credit facility, proceeds from the
disposition of assets or alternative financing sources, as
discussed in Capital resources below.
Oil and natural gas properties. Our costs
incurred on oil and natural gas properties, excluding
acquisitions and asset retirement obligations, during the years
ended December 31, 2010, 2009 and 2008 totaled
$682.0 million, $394.0 million and
$339.6 million, respectively. The primary reason for the
differences in the costs incurred and cash flow expenditures is
the timing of payments. These 2010 expenditures were
significantly funded by cash flow from operations (including
effects of cash settlements received from (paid on) derivatives
not designated as hedges) and to a lesser extent from borrowings
under our credit facility.
In October 2010, we closed the Marbob and Settlement
Acquisitions which was the primary reason for the increase in
our costs incurred on oil and natural gas properties during
2010. For additional information see Acquisitions
below and Item 7. Managements Discussion
and Analysis of Financial Condition and Results of
Operations Recent events.
In November 2010, we announced our 2011 capital budget of
approximately $1.1 billion, which we expect can be funded
substantially within our cash flow, based on current commodity
prices and our expectations. As our size and financial
flexibility have grown, we now take a longer-term view on
spending substantially within our cash flow, and our spending
during any specific period may exceed our cash flow for that
period. However, our capital budget is largely discretionary,
and if we experience sustained oil and natural gas prices
significantly below the current levels or substantial increases
in our drilling and completion costs, we may reduce our capital
spending program to be substantially within our cash flow.
Although we cannot provide any assurance, we generally attempt
to fund our non-acquisition expenditures with our available cash
and cash flow as adjusted from time to time; however, we may
also use our credit facility, or other alternative financing
sources, to fund such expenditures. The actual amount and timing
of our expenditures may differ materially from our estimates as
a result of, among other things, actual drilling results, the
timing of expenditures by third parties on projects that we do
not operate, the availability of drilling rigs and other
services and equipment, regulatory, technological and
competitive developments and market conditions. In addition,
under certain circumstances we would consider increasing or
reallocating our capital spending plans.
Other than the purchase of leasehold acreage, our 2011 capital
budget is exclusive of acquisitions. We do not have a specific
acquisition budget, since the timing and size of acquisitions
are difficult to forecast. We evaluate opportunities to purchase
or sell oil and natural gas properties in the marketplace and
could participate as a buyer or seller of properties at various
times. We seek to acquire oil and natural gas properties that
provide opportunities for the addition of reserves and
production through a combination of development, high-potential
exploration and control of operations that will allow us to
apply our operating expertise.
Acquisitions. Our expenditures for
acquisitions of proved and unproved properties during the years
ended December 31, 2010, 2009 and 2008 totaled
$1.7 billion, $280.5 million and $838.0 million,
respectively. The Marbob Acquisition consideration was comprised
of (i) approximately $1.1 billion in cash which was
funded with
61
borrowings under our credit facility and with net proceeds of a
$292.7 million private placement of 6.6 million shares
of our common stock, (ii) issuance of 1.1 million
shares of our common stock to the sellers and
(iii) issuance of a $150 million 8.0% unsecured senior
note due 2018 to the sellers. The Settlement Acquisition, also
in October 2010, was primarily funded with borrowings under our
credit facility. The Wolfberry Acquisitions in December 2009
were funded by borrowings under our credit facility, and the
Henry Properties acquisition in 2008 was primarily funded by a
private placement of our common stock and borrowings under our
credit facility.
Divestitures. In December 2010, we sold
certain of our non-core Permian Basin assets for cash
consideration of $103.3 million. For 2010, these assets
produced 1,393 Boe per day, of which approximately
46 percent was oil. The proved reserves of these assets
were approximately 6.0 MMBoe at closing. We used the net
proceeds from this divestiture to repay a portion of the
outstanding borrowings under our credit facility.
In February 2011, we entered into a purchase and sale agreement
to sell our North Dakota assets for cash consideration of
approximately $196.0 million, subject to customary purchase
price adjustments, and expect to close the divestiture prior to
March 31, 2011. We expect to recognize a gain on this sale
in excess of $140.0 million.
Contractual obligations. Our
contractual obligations include long-term debt, cash interest
expense on debt, operating lease obligations, drilling
commitments, employment agreements with executive officers,
derivative liabilities and other obligations.
We had the following contractual obligations at
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
$
|
1,663,500
|
|
|
$
|
|
|
|
$
|
613,500
|
|
|
$
|
|
|
|
$
|
1,050,000
|
|
Cash interest expense on debt(b)
|
|
|
726,261
|
|
|
|
95,369
|
|
|
|
159,750
|
|
|
|
159,750
|
|
|
|
311,392
|
|
Operating lease obligations(c)
|
|
|
15,242
|
|
|
|
3,471
|
|
|
|
8,082
|
|
|
|
3,689
|
|
|
|
|
|
Drilling commitments(d)
|
|
|
2,400
|
|
|
|
2,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employment agreements with senior officers(e)
|
|
|
2,701
|
|
|
|
2,430
|
|
|
|
271
|
|
|
|
|
|
|
|
|
|
Derivative liabilities(f)
|
|
|
149,422
|
|
|
|
97,775
|
|
|
|
51,647
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations(g)
|
|
|
43,326
|
|
|
|
7,378
|
|
|
|
1,034
|
|
|
|
2,083
|
|
|
|
32,831
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations
|
|
$
|
2,602,852
|
|
|
$
|
208,823
|
|
|
$
|
834,284
|
|
|
$
|
165,522
|
|
|
$
|
1,394,223
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
See Note J of the Notes to Consolidated Financial
Statements included in Item 8. Financial Statements
and Supplementary Data for information regarding future
interest payment obligations on our senior notes. The amounts
included in the table above represent principal maturities only. |
|
(b) |
|
Cash interest expense on the our unsecured senior notes is
estimated assuming no principal repayment until their maturity
dates. Cash interest expense on our credit facility is estimated
assuming (i) a principal balance outstanding equal to the
balance at December 31, 2010 of $613.5 million with no
principal repayment until the instrument due date of
July 31, 2013 and (ii) a fixed interest rate of
4.6 percent, which was our interest rate at
December 31, 2010. Also included in the Less than
1 year column is accrued interest at
December 31, 2010, for our unsecured senior notes and the
credit facility of approximately $15.5 million. |
|
(c) |
|
See Note K of the Notes to Consolidated Financial
Statements included in Item 8. Financial Statements
and Supplementary Data. |
|
(d) |
|
Consists of daywork drilling contracts related to drilling rigs
contracted through December 31, 2011. See Note K of
the Notes to Consolidated Financial Statements included in
Item 8. Financial Statements and Supplementary
Data. |
62
|
|
|
(e) |
|
Represents amounts of cash compensation we are obligated to pay
to our senior officers under employment agreements assuming such
employees continue to serve the entire term of their employment
agreement and their cash compensation is not adjusted. |
|
(f) |
|
Derivative obligations represent commodity and interest rate
derivatives that were valued at December 31, 2010. 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 natural gas
property abandonments related to proved reserves by period, net
of any future accretion. See Note E of the Notes to
Consolidated Financial Statements included in Item 8.
Financial Statements and Supplementary Data. |
Off-balance sheet
arrangements. Currently, we do not have any
material off-balance sheet arrangements.
Capital resources. Our primary sources
of liquidity have been cash flows generated from operating
activities (including the cash settlements received from (paid
on) derivatives not designated as hedges presented in our
investing activities) and financing provided by our credit
facility. We currently believe that our cash flows will
substantially meet both our short-term working capital
requirements and our current 2011 capital expenditure plans. We
believe we have adequate availability under our credit facility
to fund any cash flow deficits, though we could reduce our
capital spending program to remain substantially within our cash
flow.
The following table summarizes our net decrease in cash and cash
equivalents for the years ended December 31, 2010, 2009 and
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Net cash provided by operating activities
|
|
$
|
651,582
|
|
|
$
|
359,546
|
|
|
$
|
391,397
|
|
Net cash used in investing activities
|
|
|
(2,043,457
|
)
|
|
|
(586,148
|
)
|
|
|
(946,050
|
)
|
Net cash provided by financing activities
|
|
|
1,389,025
|
|
|
|
212,084
|
|
|
|
541,981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
$
|
(2,850
|
)
|
|
$
|
(14,518
|
)
|
|
$
|
(12,672
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operating activities. The
increase in operating cash flows during the year ended
December 31, 2010 over 2009 was principally due to
increases in our oil and natural gas production as a result of
our (i) exploration and development program,
(ii) Wolfberry Acquisitions in December 2009 and
(iii) Marbob and Settlement Acquisitions in October 2010,
and increases in average realized oil and natural gas prices.
The decrease in operating cash flows during the year ended
December 31, 2009 over 2008 was principally due to
increases in oil and natural gas production costs and general
and administrative expenses, partially offset by increased oil
and natural gas revenues.
Cash flow used in investing activities. During
the years ended December 31, 2010, 2009 and 2008, we
invested $2.1 billion, $669.3 million and
$931.9 million, respectively, for additions to, and
acquisitions of, oil and natural gas properties. Cash flows used
in investing activities were substantially higher during the
year ended December 31, 2010 over 2009, primarily due to
the Marbob and Settlement Acquisitions in October 2010 and
increased drilling activity in 2010, offset by
$104.3 million of proceeds from the sale of assets, which
is primarily from our December 2010 non-core Permian
divestiture. Cash flows used in investing activities were
substantially lower during the year ended December 31, 2009
over 2008, due to (i) the Henry Properties acquisition in
2008 being larger than the Wolfberry Acquisitions in 2009 and
(ii) our receipts from, in 2009, compared to our payments
on, in 2008, associated with derivatives not designated as
hedges, offset by increased exploration and development
activities in 2009.
Cash flow from financing activities. Below is
a description of our financing activities. During 2010, 2009 and
2008 we completed the following significant capital markets
activities:
|
|
|
|
|
in December 2010, we issued in a secondary public offering
2.9 million shares of our common stock at $82.50 per share
and we received net proceeds of approximately
$227.4 million. We used the net proceeds
|
63
|
|
|
|
|
from this offering to repay a portion of the borrowings under
our credit facility to increase our liquidity for future
activities;
|
|
|
|
|
|
in December 2010, we issued $600 million in principal
amount of 7.0% unsecured senior notes due 2021 at par and we
received net proceeds of approximately $587.4 million. We
used the net proceeds from this offering to repay a portion of
the borrowings under our credit facility to increase our
liquidity for future activities;
|
|
|
|
in October 2010, we closed the private placement of our common
stock, simultaneously with the closing of the Marbob
Acquisition, on 6.6 million shares of our common stock at a
price of $45.30 per share for net proceeds of approximately
$292.7 million;
|
|
|
|
in February 2010, we issued approximately 5.3 million
shares of our common stock at $42.75 per share in a secondary
public offering and we received net proceeds of approximately
$219.3 million. The net proceeds from this offering were
used to repay a portion of the borrowing under our credit
facility;
|
|
|
|
in September 2009, we issued $300 million of
8.625% senior notes at a discount, resulting in a
yield-to-maturity
of 8.875 percent. The net proceeds from this offering were
used to repay a portion of the borrowing under our credit
facility; and
|
|
|
|
in July 2008, we closed the private placement of our common
stock, simultaneously with the closing of the Henry Entities
acquisition, on 8.3 million shares of our common stock at a
negotiated price of $30.11 per share for net proceeds of
approximately $242.4 million.
|
Our credit facility, as amended, has a maturity date of
July 31, 2013. At December 31, 2010, we had no letters
of credit outstanding under the credit facility, and our
availability to borrow additional funds was approximately
$1.4 billion based on the borrowing base of
$2.0 billion. The next scheduled borrowing base
redetermination will be in April 2011. 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) (3.25 percent at
December 31, 2010) or (ii) a Eurodollar rate
(substantially equal to the London Interbank Offered Rate). At
December 31, 2010, the interest rates of Eurodollar rate
advances and JPM Prime Rate advances varied, with interest
margins ranging from 200 to 300 basis points and 112.5 to
212.5 basis points, respectively, per annum depending on
the debt balance outstanding. At December 31, 2010, we paid
commitment fees on the unused portion of the available borrowing
base of 50 basis points per annum.
In conducting our business, we may utilize various financing
sources, including the issuance of (i) fixed and floating
rate debt, (ii) convertible securities,
(iii) preferred stock, (iv) common stock and
(v) other securities. Over the last three years, we have
demonstrated our use of the capital markets by issuing common
stock in public offerings and private placements and issuing
senior unsecured debt. However, there are no assurances that we
can access the capital markets to obtain additional funding, if
needed, and at what cost and terms. We may also sell assets and
issue securities in exchange for oil and natural gas assets or
interests in oil and natural gas companies. Additional
securities may be of a class senior to common stock with respect
to such matters as dividends and liquidation rights and may also
have other rights and preferences as determined from time to
time by our board of directors. Utilization of some of these
financing sources may require approval from the lenders under
our credit facility.
Liquidity. Our principal sources of
short-term liquidity are cash on hand and available borrowing
capacity under our credit facility. At December 31, 2010,
we had $0.4 million of cash on hand.
At December 31, 2010, the borrowing base under our credit
facility was $2.0 billion, which provided us with
approximately $1.4 billion of available borrowing capacity.
Our borrowing base is redetermined semi-annually, with the next
redetermination occurring in April 2011. Between scheduled
borrowing base redeterminations, we and, if requested by
662/3 percent
of the lenders, the lenders, may each request one special
redetermination. In general, redeterminations are based upon a
number of factors, including commodity prices and reserve
levels. Upon a redetermination, our borrowing base could be
substantially reduced. There is no assurance that our borrowing
base will not be reduced.
64
Our credit facility matures in July 2013, and we do not expect
to seek refinancing or the extension of the maturity in the near
term. There are no assurances that if we seek (i) to
refinance our credit facility that we could do so with
comparable terms or (ii) extension of maturity of our
credit facility that we could obtain an extension from our
lenders. Our ability to refinance our credit facility or obtain
extension of our maturity could affect our liquidity.
Debt ratings. We receive debt credit
ratings from Standard & Poors Ratings Group,
Inc. (S&P) and Moodys Investors Service,
Inc. (Moodys), which are subject to regular
reviews. S&Ps corporate rating for us is
BB with a stable outlook. Moodys corporate
rating for us is B1 with a negative outlook.
S&P and Moodys consider many factors in determining
our ratings including: production growth opportunities,
liquidity, debt levels and asset and reserve mix. A reduction in
our debt ratings could negatively affect our ability to obtain
additional financing or the interest rate, fees and other terms
associated with such additional financing.
Book capitalization and current
ratio. Our book capitalization at
December 31, 2010 was $4,052.4 million, consisting of
debt of $1,668.5 million and stockholders equity of
$2,383.9 million. Our debt to book capitalization was
41 percent and 39 percent at December 31, 2010 and
2009, respectively. Our ratio of current assets to current
liabilities was 0.65 to 1.00 at December 31, 2010 as
compared to 0.64 to 1.00 at December 31, 2009.
Inflation and changes in prices. Our
revenues, the value of our assets, and our ability to obtain
bank financing or additional capital on attractive terms have
been and will continue to be affected by changes in commodity
prices and the costs to produce our reserves. Commodity prices
are subject to significant fluctuations that are beyond our
ability to control or predict. During the year ended
December 31, 2010, we received, from continuing operations,
an average of $76.12 per barrel of oil and $6.88 per Mcf of
natural gas before consideration of commodity derivative
contracts compared to $57.97 per barrel of oil and $5.63 per Mcf
of natural gas in the year ended December 31, 2009.
Although certain of our costs are affected by general inflation,
inflation does not normally have a significant effect on our
business. In a trend that began in 2004 and continued through
the first six months of 2008, commodity prices for oil and
natural gas increased significantly. The higher prices led to
increased activity in the industry and, consequently, rising
costs. These cost trends have put pressure not only on our
operating costs but also on capital costs. We expect these costs
to reflect upward pressure during 2011 as a result of the recent
improvements in oil prices in 2010.
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,
valuation of stock-based compensation, valuation of business
combinations and valuation of financial derivative instruments.
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. Exploratory
drilling costs are initially capitalized, but are charged to
expense if and when the well is determined not to have found
proved
65
reserves. Generally, a gain or loss is recognized when producing
properties are sold. This accounting method may yield
significantly different results than the full cost method of
accounting.
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 natural 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 or projects are periodically assessed for impairment
of value 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.
Depletion of capitalized drilling and development costs of oil
and natural gas properties is computed using the
unit-of-production
method on a field 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 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.
Oil
and Natural Gas Reserves and Standardized Measure of Discounted
Net Future Cash Flows
This report presents estimates of our proved reserves as of
December 31, 2010, which have been prepared and presented
under the SEC rules which became effective December 31,
2009. These rules are effective for fiscal years ending on or
after December 31, 2009, and require SEC reporting
companies to prepare their reserves estimates using revised
reserve definitions and revised pricing based on a
12-month
unweighted average of the
first-day-of-the-month
pricing. The previous rules required that reserve estimates be
calculated using
last-day-of-the-year
pricing. The pricing that was used for estimates of our reserves
as of December 31, 2010 was based on an unweighted average
twelve month West Texas Intermediate posted price of $75.96 per
Bbl for oil and a Henry Hub spot natural gas price of $4.38 per
MMBtu for natural gas. As a result of this change in pricing
methodology, direct comparisons to our reported reserves amounts
prior to 2009 may be more difficult.
Another impact of the SEC rules is a general requirement that,
subject to limited exceptions, proved undeveloped reserves may
only be booked if they relate to wells scheduled to be drilled
within five years of the date of booking. This rule has limited
and may continue to limit our potential to book additional
proved undeveloped reserves as we pursue our drilling program,
particularly as we develop our significant acreage in the
Permian Basin of Southeast New Mexico and West Texas. Moreover,
we may be required to write down our proved undeveloped reserves
if we do not drill on those reserves with the required five-year
time-frame.
Our independent engineers and technical staff prepare the
estimates of our oil and natural gas reserves and associated
future net cash flows. 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 net 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.
66
Asset
Retirement Obligations
There are 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 relates to oil and
natural gas wells on which we have a legal obligation to plug
and abandon. We record the fair value of a liability for an
asset retirement obligation in the period in which it is
incurred and, generally, 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 in 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
Under the modified prospective accounting 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 average of the
high and low stock price on the date of grant for the fair value
of restricted stock awards.
Valuation
of Business Combinations
In connection with a purchase business combination, the
acquiring company must allocate the cost of the acquisition to
assets acquired and liabilities assumed based on fair values as
of the acquisition date. Deferred taxes must be recorded for any
differences between the assigned values and tax bases of assets
and liabilities. Any excess of purchase price over amounts
assigned to assets and liabilities is recorded as goodwill. The
amount of goodwill recorded in any particular business
combination can vary significantly depending upon the value
attributed to assets acquired and liabilities assumed.
In estimating the fair values of assets acquired and liabilities
assumed, we make various assumptions. The most significant
assumptions related to the estimated fair values assigned to
proved and unproved oil and natural gas properties. To estimate
the fair values of these properties, we utilize estimates of oil
and natural gas reserves. We make future price assumption to
apply to the estimated reserves quantities acquired and estimate
future operating and development costs to arrive at estimates of
future net cash flows. For estimated proved reserves, the future
net cash flows were discounted using a market-based weighted
average cost of capital rates determined appropriate at the time
of the acquisition. The market-based weighted average cost of
capital rates are subject to additional project-specific risking
factors. To compensate for the inherent risk of estimating and
valuing unproved reserves, the discounted future net cash flows
of the unproved reserves were reduced by additional
risk-weighting factors.
Estimated fair values assigned to assets acquired can have a
significant effect on results of operations in the future. A
higher fair value assigned to a property results in a higher
depletion expense, which results in lower net earnings. Fair
values are based on estimates of future commodity prices,
reserves quantities, operating expenses and development costs.
This increases the likelihood of impairment if future commodity
prices or reserves quantities are lower than those originally
used to determine fair value, or if future operating expenses or
development costs are
67
higher than those originally used to determine fair value.
Impairment would have no effect on cash flows but would result
in a decrease in net income for the period in which the
impairment is recorded.
Valuation
of Financial Derivative Instruments
In order to reduce commodity price uncertainty and increase cash
flow predictability relating to the marketing of our oil and
natural gas, we enter into oil and natural gas price hedging
arrangements with respect to a portion of our expected
production. In addition, we have used derivative instruments in
connection with acquisitions and certain price-sensitive
projects. Management exercises significant judgment in
determining the types of instruments to be used, production
volumes to be hedged, prices at which to hedge and the
counterparties creditworthiness. All derivative
instruments are reflected at fair value in our consolidated
balance sheets.
Our open commodity derivative instruments were in a net
liability position with a fair value of $134.6 million at
December 31, 2010. In order to determine the fair value at
the end of each reporting period, we compute discounted cash
flows for the duration of each commodity derivative instrument
using the terms of the related contract. Inputs consist of
published forward commodity price curves as of the date of the
estimate. We compare these prices to the price parameters
contained in our hedge contracts to determine estimated future
cash inflows or outflows. We then discount the cash inflows or
outflows using a combination of published LIBOR rates,
Eurodollar futures rates and interest swap rates. The fair
values of our commodity derivative assets and liabilities
include a measure of credit risk based on current published
credit default swap rates. In addition, for collars, we estimate
the option value of the contract floors and ceilings using an
option pricing model which takes into account market volatility,
market prices and contract parameters.
Changes in the fair values of our commodity derivative
instruments have a significant impact on our net income because
we follow
mark-to-market
accounting and recognize all gains and losses on such
instruments in earnings in the period in which they occur. For
the year ended December 31, 2010, we reported a
$70.2 million non-cash
mark-to-market
loss on commodity derivative instruments.
We also use derivative instruments to manage interest rate risk
by entering into forward contracts or swap agreements to
minimize the impact of interest rate fluctuations associated
with fixed or floating rate borrowings. The interest rate
derivative contracts were not designated as cash flow hedges.
Our interest rate derivative instruments were in a liability
position with a fair value of $5.8 million at
December 31, 2010. In order to determine the fair value at
the end of each reporting period, we compute discounted cash
flows for the duration of the instrument using the terms of the
related contract. Inputs consist of published interest rate
yield curves as of the date of the estimate and a measure of our
own nonperformance risk, based on the current published credit
default swap rates.
We compare our estimates of the fair values of our commodity and
interest rate derivative instruments with those provided by our
counterparties. There have been no significant differences.
Recent
Accounting Pronouncements
Business combinations. In December
2010, the FASB issued an update in order to address diversity in
practice about the interpretation of the pro forma revenue and
earnings disclosure requirements for business combinations.
The update requires a public entity to disclose pro forma
information for business combinations that occurred in the
current reporting period. The disclosures include pro forma
revenue and earnings of the combined entity for the current
reporting period as though the acquisition date for all business
combinations that occurred during the year had been as of the
beginning of the annual reporting period. If comparative
financial statements are presented, the pro forma revenue and
earnings of the combined entity for the comparable prior
reporting period should be reported as though the acquisition
date for all business combinations that occurred during the
current year had been as of the beginning of the comparable
prior annual reporting period.
In practice, some preparers have presented the pro forma
information in their comparative financial statements as if the
business combination that occurred in the current reporting
period had occurred as of the beginning of each
68
of the current and prior annual reporting periods. Other
preparers have disclosed the pro forma information as if the
business combination occurred at the beginning of the prior
annual reporting period only, and carried forward the related
adjustments, if applicable, through the current reporting
period. We early adopted the update effective January 1, 2010,
and the adoption did not have a significant impact on our
consolidated financial statements.
Various topics. In February 2010, the
FASB issued an update to various topics, which eliminated
outdated provisions and inconsistencies in the Accounting
Standards Codification (the Codification), and
clarified certain guidance to reflect the FASBs original
intent. The update is effective for the first reporting period,
including interim periods, beginning after issuance of the
update, except for the amendments affecting embedded derivatives
and reorganizations. In addition to amending the Codification,
the FASB made corresponding changes to the legacy accounting
literature to facilitate historical research. These changes are
included in an appendix to the update. We adopted the update
effective January 1, 2010, and the adoption did not have a
significant impact on our consolidated financial statements.
Accounting for extractive
activities. In April 2010, the FASB issued an
amendment to a paragraph in the accounting standard for oil and
natural gas extractive activities accounting. The standard adds
to the Codification the SECs Modernization of Oil and
Gas Reporting release. We adopted the update effective
April 20, 2010, and the adoption did not have a significant
impact on our consolidated financial statements.
|
|
Item 7A.
|
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, 2010,
and from which we may incur future gains or losses from changes
in market interest rates or commodity prices and losses from
extension of credit. We do not enter into derivative or other
financial instruments for speculative or trading purposes.
Hypothetical changes in interest rates and commodity prices
chosen for the following estimated sensitivity analysis are
considered to be reasonably possible near-term changes generally
based on consideration of past fluctuations for each risk
category. However, since it is not possible to accurately
predict future changes in interest rates and commodity prices,
these hypothetical changes may not necessarily be an indicator
of probable future fluctuations.
Credit risk. We
monitor our risk of loss due to non-performance by
counterparties of their contractual obligations. Our principal
exposure to credit risk is through the sale of our oil and
natural gas production, which we market to energy marketing
companies and refineries and to a lesser extent our derivative
counterparties. We monitor our exposure to these counterparties
primarily by reviewing credit ratings, financial statements and
payment history. We extend credit terms based on our evaluation
of each counterpartys creditworthiness. Although we have
not generally required our counterparties to provide collateral
to support their obligation to us, we may, if circumstances
dictate, require collateral in the future. In this manner, we
reduce credit risk.
Commodity price
risk. We are exposed to market risk as
the prices of oil and natural gas are subject to fluctuations
resulting from changes in supply and demand. To reduce our
exposure to changes in the prices of oil and natural gas we have
entered into, and may in the future enter into additional
commodity price risk management arrangements for a portion of
our oil and natural gas production. The agreements that we have
entered into generally have the effect of providing us with a
fixed price for a portion of our expected future oil and natural
gas production over a fixed period of time. Our commodity price
risk management activities could have the effect of reducing net
income and the value of our common stock. An average increase in
the commodity price of $10.00 per barrel of oil and $1.00 per
MMBtu for natural gas from the commodity prices at
December 31, 2010, would have increased the net unrealized
loss on our commodity price risk management contracts by
approximately $208 million.
At December 31, 2010, we had (i) oil price swaps that
settle on a monthly basis covering future oil production from
January 1, 2011 through June 30, 2015 and
(ii) natural gas price swaps, natural gas price collars and
natural gas basis swaps covering future natural gas production
from January 1, 2011 to December 31, 2012, 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 instruments. The average NYMEX oil price
and average NYMEX natural gas prices for the year ended
December 31, 2010, was $79.50 per Bbl and $4.40 per MMBtu,
69
respectively. At February 23, 2011, the NYMEX oil price and
NYMEX natural gas price were $98.10 per Bbl and $3.90 per MMBtu,
respectively. A decrease in oil and natural gas prices, would
decrease the fair value liability of our commodity derivative
contracts from their recorded balance at December 31, 2010.
Changes in the recorded fair value of the undesignated commodity
derivative contracts are marked to market through earnings as
unrealized gains or losses. The potential decrease in our fair
value liability would be recorded in earnings as an unrealized
gain. However, an increase in the average NYMEX oil and natural
gas price above those at December 31, 2010, would result in
an increase in our fair value liability and be recorded as an
unrealized loss in earnings. We are currently unable to estimate
the effects on the earnings of future periods resulting from
changes in the market value of our commodity derivative
contracts.
Interest rate
risk. Our exposure to changes in interest
rates relates primarily to debt obligations. We manage our
interest rate exposure by limiting our variable-rate debt to a
certain percentage of total capitalization and by monitoring the
effects of market changes in interest rates. To reduce our
exposure to changes in interest rates we have entered into, and
may in the future enter into additional interest rate risk
management arrangements for a portion of our outstanding debt.
The agreements that we have entered into generally have the
effect of providing us with a fixed interest rate for a portion
of our variable rate debt. We may utilize interest rate
derivatives to alter interest rate exposure in an attempt to
reduce interest rate expense related to existing debt issues.
Interest rate derivatives are used solely to modify interest
rate exposure and not to modify the overall leverage of the debt
portfolio. We are exposed to changes in interest rates as a
result of our credit facility, and the terms of our credit
facility require us to pay higher interest rate margins as we
utilize a larger percentage of our available borrowing base.
At December 31, 2010, we had interest rate swaps on
$300 million of notional principal that fixed the LIBOR
interest rate (not including the interest rate margins discussed
above) at 1.90 percent for the three years beginning in May
2009. An average decrease in future interest rates of
25 basis points from the future rate at December 31,
2010, would have decreased our net unrealized value on our
interest rate risk management contracts by approximately
$1.0 million.
We had total indebtedness of $613.5 million outstanding
under our credit facility at December 31, 2010. The impact
of a 1 percent increase in interest rates on this amount of
debt would result in increased annual interest expense of
approximately $6.1 million.
The fair value of our derivative instruments is determined based
on our valuation models. We did not change our valuation method
during 2010. During 2010, we were party to commodity and
interest rate derivative instruments. See Note I of the
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
the year ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Instruments Net Assets (Liabilities)(a)
|
|
|
|
Commodities
|
|
|
Interest Rate
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Fair value of contracts outstanding at December 31, 2009
|
|
$
|
(64,332
|
)
|
|
$
|
(2,501
|
)
|
|
$
|
(66,833
|
)
|
Changes in fair values(b)
|
|
|
(79,115
|
)
|
|
|
(8,210
|
)
|
|
|
(87,325
|
)
|
Contract maturities
|
|
|
8,867
|
|
|
|
4,957
|
|
|
|
13,824
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts outstanding at December 31, 2010
|
|
$
|
(134,580
|
)
|
|
$
|
(5,754
|
)
|
|
$
|
(140,334
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Represents the fair values of open derivative contracts subject
to market risk. |
|
(b) |
|
At inception, new derivative contracts entered into by us have
no intrinsic value. |
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
Our consolidated financial statements and supplementary
financial data are included in this report beginning on
page F-1.
70
|
|
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.
|
|
Item 9A.
|
Controls
and Procedures
|
Evaluation of Disclosure Controls and
Procedures. As required by
Rule 13a-15(b)
of the Exchange Act, we have evaluated, under the supervision
and with the participation of our management, including our
principal executive officer and principal financial officer, the
effectiveness of the design and operation of our disclosure
controls and procedures (as defined in
Rules 13a-15(e)
and
15d-15(e)
under the Exchange Act) as of the end of the period covered by
this report. Our disclosure controls and procedures are designed
to provide reasonable assurance that the information required to
be disclosed by us in reports that we file under the Exchange
Act is accumulated and communicated to our management, including
our principal executive officer and principal financial officer,
as appropriate, to allow timely decisions regarding required
disclosure and is recorded, processed, summarized and reported
within the time periods specified in the rules and forms of the
SEC. Based upon the evaluation, our principal executive officer
and principal financial officer have concluded that our
disclosure controls and procedures were effective at
December 31, 2010 at the reasonable assurance level.
Changes in Internal Control over Financial
Reporting. There have been no changes in
our internal controls over financial reporting (as defined in
Rule 13a-15(f)
under the Exchange Act) that occurred during our last fiscal
quarter that have materially affected or are reasonably likely
to materially affect our internal controls over financial
reporting.
Marbob and Settlement
Acquisitions. Because the Marbob and
Settlement Acquisitions were completed in the fourth quarter of
2010, management did not include the internal control processes
for these related assets in its assessment of internal control
over financial reporting at December 31, 2010. See more
details below relating to the exclusion of these acquisitions
from Managements Report on Internal Control Over Financial
Reporting. Additionally, these acquisitions are 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 these acquisitions in its 2011 assessment. The
Marbob and Settlement acquisitions represent 31 percent of
our total assets at December 31, 2010 and 6 percent of
our total revenues for the year ended December 31, 2010.
71
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, 2010, 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 Marbob and Settlement
acquisitions, which closed in the fourth quarter of 2010 and
constitute 31 percent of total assets and 6 percent of
revenues of the consolidated financial statement amounts as of
and for the year ended December 31, 2010. Based on our
assessment and those criteria, management determined that the
Company maintained effective internal control over financial
reporting at December 31, 2010.
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 their report on the effectiveness of the
Companys internal control over financial reporting at
December 31, 2010. The report, which expresses an
unqualified opinion on the effectiveness of the Companys
internal control over financial reporting at December 31,
2010, is included in this Item under the heading Report of
Independent Registered Public Accounting Firm.
72
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2010, 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 the Marbob and Settlement Acquisitions, which
reflect total assets and revenues constituting 31 percent
and 6 percent, respectively, of the related consolidated
financial statement amounts as of and for the year ended
December 31, 2010. As indicated in Managements
Report, the Marbob and Settlement Acquisitions were acquired
during the fourth quarter of 2010 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 Marbob
and Settlement Acquisitions.
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, 2010, 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, 2010 and 2009 and the
related consolidated statements of operations,
stockholders equity and cash flows for each of the three
years in the period ended December 31, 2010, and our report
dated February 25, 2011 expressed an unqualified opinion
thereon.
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
February 25, 2011
73
|
|
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. We expect to file a
definitive proxy statement with the SEC within 120 days
after the close of the year ended December 31, 2010.
|
|
Item 11.
|
Executive
Compensation
|
Item 11 will be incorporated by reference pursuant to
Regulation 14A under the Exchange Act. We expect to file a
definitive proxy statement with the SEC within 120 days
after the close of the year ended December 31, 2010.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
Equity
Compensation Plans
At December 31, 2010, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
(2)
|
|
(3)
|
|
|
|
|
|
|
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 (1))
|
|
Equity compensation plan approved by security holders(a)
|
|
|
1,597,003
|
|
|
$
|
15.43
|
|
|
|
1,063,339
|
|
Equity compensation plan not approved by security holders(b)
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,597,003
|
|
|
|
|
|
|
|
1,063,339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. We expect to file a definitive proxy statement
with the SEC within 120 days after the close of the year
ended December 31, 2010.
|
|
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. We expect to file a
definitive proxy statement with the SEC within 120 days
after the close of the year ended December 31, 2010.
|
|
Item 14.
|
Principal
Accounting Fees and Services
|
Item 14 will be incorporated by reference pursuant to
Regulation 14A under the Exchange Act. We expect to file a
definitive proxy statement with the SEC within 120 days
after the close of the year ended December 31, 2010.
74
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 ours are
included in Financial Statements and Supplementary
Data:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2010 and 2009
Consolidated Statements of Operations for the Years Ended
December 31, 2010, 2009 and 2008
Consolidated Statements of Stockholders Equity for the
Years Ended December 31, 2010, 2009 and 2008
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2010, 2009 and 2008
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 this report or they are inapplicable.
Exhibits
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
2.1
|
|
|
Asset Purchase Agreement, dated July 19, 2010, by and among
Concho Resources Inc., Marbob Energy Corporation, Pitch Energy
Corporation, Costaplenty Energy Corporation and John R. Gray,
LLC (filed as Exhibit 2.1 to the Companys Current Report
on Form 8-K on July 20, 2010, and incorporated herein by
reference).
|
|
2.2
|
|
|
Purchase and Sale Agreement, dated November 20, 2009, between
Terrace Petroleum Corporation, et al., as Seller, and COG
Operating LLC, as Buyer, (filed as Exhibit 2.1 to the
Companys Current Report on Form 8-K on November 25, 2009,
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 Registration Statement on Form S-1/A on July 5,
2007, and incorporated herein by reference).
|
|
4.2
|
|
|
Indenture, dated September 18, 2009, between Concho Resources
Inc., the subsidiary guarantors named therein, and Wells Fargo
Bank, National Association, as trustee (filed as Exhibit 4.1 to
the Companys Current Report on Form 8-K on September 22,
2009, and incorporated herein by reference).
|
75
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
4.3
|
|
|
First Supplemental Indenture, dated September 18, 2009, between
Concho Resources Inc., the subsidiary guarantors named therein,
and Wells Fargo Bank, National Association, as trustee (filed as
Exhibit 4.2 to the Companys Current Report on Form 8-K on
September 22, 2009, and incorporated herein by reference).
|
|
4.4
|
|
|
Form of 8.625% Senior Notes due 2017 (included in Exhibit
4.2 to the Companys Current Report on Form 8-K on
September 22, 2009, and incorporated herein by reference).
|
|
4.5
|
|
|
Second Supplemental Indenture, dated November 3, 2010, between
Concho Resources Inc., the subsidiary guarantors named therein,
and Wells Fargo Bank, National Association, as trustee (filed as
Exhibit 4.4 to the Post-Effective Amendment to the
Companys Registration Statement on Form S-3 on
December 7, 2010, and incorporated herein by reference).
|
|
4.6
|
|
|
Third Supplemental Indenture, dated December 14, 2010, between
Concho Resources Inc., the subsidiary guarantors named therein,
and Wells Fargo Bank, National Association, as trustee (filed as
Exhibit 4.1 to the Companys Current Report on Form 8-K on
December 14, 2010, and incorporated herein by reference).
|
|
4.7
|
|
|
Form of 7.0% Senior Notes due 2021 (included in Exhibit 4.1
to the Companys Current Report on Form 8-K on December 14,
2010, and incorporated herein by reference).
|
|
10.1
|
|
|
Form of Drilling Agreement with Silver Oak Drilling, LLC (filed
as Exhibit 10.4 to the Companys Registration Statement on
Form S-1/A on July 5, 2007, and incorporated herein by
reference).
|
|
10.2
|
|
|
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 Registration Statement on
Form S-1 on April 24, 2007, and incorporated herein by
reference).
|
|
10.3
|
|
|
Software License Agreement dated March 2, 2006, between Enertia
Software Systems and Concho Resources Inc. (filed as Exhibit
10.6 to the Companys Registration Statement on Form S-1 on
April 24, 2007, and incorporated herein by reference).
|
|
10.4
|
|
|
Transfer of Operating Rights (Sublease) in a Lease for Oil and
Gas for Valhalla properties (filed as Exhibit 10.8 to the
Companys Registration Statement on Form S-1 on April 24,
2007, and incorporated herein by reference).
|
|
10.5
|
|
|
Business Opportunities Agreement dated February 27, 2006, among
Concho Resources Inc. and the other signatories thereto (filed
as Exhibit 10.11 to the Companys Registration Statement on
Form S-1 on April 24, 2007, and incorporated herein by
reference).
|
|
10.6
|
|
|
Registration Rights Agreement dated February 27, 2006, among
Concho Resources Inc. and the other signatories thereto (filed
as Exhibit 10.12 to the Companys Registration Statement on
Form S-1 on April 24, 2007, and incorporated herein by
reference).
|
|
10.7**
|
|
|
Concho Resources Inc. 2006 Stock Incentive Plan (filed as
Exhibit 10.13 to the Companys Registration Statement on
Form S-1 on April 24, 2007, and incorporated herein by
reference).
|
|
10.8**
|
|
|
Form of Nonstatutory Stock Option Agreement (filed as Exhibit
10.16 to the Companys Annual Report on Form 10-K on
March 28, 2008, and incorporated herein by reference).
|
|
10.9**
|
|
|
Form of Restricted Stock Agreement (for employees) (filed as
Exhibit 10.16 to the Companys Registration Statement on
Form S-1 on April 24, 2007, and incorporated herein by
reference).
|
|
10.10**
|
|
|
Form of Restricted Stock Agreement (for non-employee directors)
(filed as Exhibit 10.18 to the Companys Annual Report on
Form 10-K on March 28, 2008, and incorporated herein by
reference).
|
|
10.11**
|
|
|
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).
|
|
10.12**
|
|
|
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).
|
76
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
10.13**
|
|
|
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).
|
|
10.14**
|
|
|
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).
|
|
10.15**
|
|
|
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).
|
|
10.16**
|
|
|
Employment Agreement dated November 5, 2009, between Concho
Resources Inc. and C. William Giraud (filed as Exhibit 10.18 to
the Companys Annual Report on From 10-K on February 26,
2010, and incorporated herein by reference).
|
|
10.17**
|
|
|
Form of Indemnification Agreement between Concho Resources Inc.
and each of the officers and directors thereof (filed as Exhibit
10.23 to the Companys Registration Statement on Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10.18**
|
|
|
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).
|
|
10.19**
|
|
|
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).
|
|
10.20**
|
|
|
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).
|
|
10.21**
|
|
|
Indemnification Agreement, dated November 5, 2009, by and
between Concho Resources, Inc. and Mark B. Puckett (filed as
Exhibit 10.1 to the Companys Current Report on Form 8-K on
November 12, 2009, and incorporated herein by reference).
|
|
10.22**
|
|
|
Indemnification Agreement, dated November 5, 2009, by and
between Concho Resources, Inc. and C. William Giraud (filed as
Exhibit 10.2 to the Companys Current Report on Form 8-K on
November 12, 2009, and incorporated herein by reference).
|
|
10.23**
|
|
|
Indemnification Agreement, dated September 24, 2010, between
Concho Resources Inc. and Don McCormack (filed as Exhibit 10.1
to the Companys Current Report on Form 8-K on September
29, 2010, and incorporated herein by reference).
|
|
10.24**
|
|
|
Consulting Agreement dated June 9, 2009, by and between Concho
Resources Inc. and Steven L. Beal (filed as Exhibit 10.1 to the
Companys Current Report on Form 8-K on June 12, 2009, and
incorporated herein by reference).
|
|
10.25
|
|
|
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).
|
|
10.26
|
|
|
First Amendment to Amended and Restated Credit Agreement dated
as of April 7, 2009, to the 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 4.1 to the
Companys Current Report on Form 8-K on April 9, 2009, and
incorporated herein by reference).
|
|
10.27
|
|
|
Limited Consent and Waiver, dated September 4, 2009, to the
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 10.1 to the Companys Current Report on
Form 8-K on September 22, 2009, and incorporated herein by
reference).
|
77
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
10.28
|
|
|
Common Stock Purchase Agreement, dated July 19, 2010, by and
among Concho Resources Inc. and the purchasers named therein
(filed as Exhibit 10.1 to the Companys Current Report on
Form 8-K on July 20, 2010, and incorporated herein by
reference).
|
|
10.29
|
|
|
Promissory Note in the principal amount of $150,000,000 between
Concho Resources Inc. and Pitch Energy Corporation, dated
October 7, 2010 (filed as Exhibit 10.5 to the Companys
Quarterly Report on Form 10-Q on November 4, 2010, and
incorporated herein by reference).
|
|
10.30
|
|
|
Registration Rights Agreement, dated October 7, 2010, 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 October 13, 2010, and incorporated herein by
reference).
|
|
10.31
|
|
|
Second Amendment to Amended and Restated Credit Agreement, dated
April 26, 2010, by and among Concho Resources Inc., JP Morgan
Chase Bank, N.A., as Administrative Agent (filed as Exhibit 4.1
to the Companys Current Report on Form 8-K on April 29,
2010, and incorporated herein by reference).
|
|
10.32
|
|
|
Third Amendment to Amended and Restated Credit Agreement and
Limited Waiver, dated June 16, 2010, among Concho Resources Inc.
and the lenders party thereto and JPMorgan Chase Bank, N.A., as
Administrative Agent (filed as Exhibit 10.1 to the
Companys Current Report on Form 8-K on June 18, 2010, and
incorporated herein by reference).
|
|
10.33
|
|
|
Fourth Amendment to Amended and Restated Credit Agreement, dated
October 7, 2010, among Concho Resources Inc. and the lenders
party thereto and JPMorgan Chase Bank, N.A., as administrative
agent (filed as Exhibit 10.2 to the Companys Current
Report on Form 8-K on October 13, 2010, and incorporated herein
by reference).
|
|
10.34
|
|
|
Fifth Amendment to Amended and Restated Credit Agreement and
Limited Waiver, dated as of December 7, 2010, among Concho
Resources Inc. and the lenders party thereto and JPMorgan Chase
Bank, N.A., as administrative agent (filed as Exhibit 10.1 to
the Companys Current Report on Form 8-K on December 10,
2010, and incorporated herein by reference).
|
|
10.35(a)**
|
|
|
Form of Restricted Stock Agreement (for officers).
|
|
10.36(a)**
|
|
|
Form of Restricted Stock Agreement (for non-officer employees).
|
|
12.1(a)
|
|
|
Ratio of Earnings to Fixed Charges and Ratio of Earnings to
Fixed Charges and Preferred Stock Dividends.
|
|
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)
|
|
|
Netherland, Sewell & Associates, Inc. Reserve Report.
|
|
23.4(a)
|
|
|
Consent of Cawley, Gillespie & Associates, Inc.
|
|
23.5(a)
|
|
|
Cawley, Gillespie & Associates, Inc. Reserve Report.
|
|
31.1(a)
|
|
|
Certification of Chief Executive Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
|
|
31.2(a)
|
|
|
Certification of Chief Financial Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
|
|
32.1(b)
|
|
|
Certification of Chief Executive Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
|
|
32.2(b)
|
|
|
Certification of Chief Financial Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
|
|
101.INS(a)
|
|
|
XBRL Instance Document.
|
|
101.SCH(a)
|
|
|
XBRL Schema Document.
|
|
101.CAL(a)
|
|
|
XBRL Calculation Linkbase Document.
|
|
101.DEF(a)
|
|
|
XBRL Definition Linkbase Document.
|
|
101.LAB(a)
|
|
|
XBRL Labels Linkbase Document.
|
|
101.PRE(a)
|
|
|
XBRL Presentation Linkbase Document.
|
|
|
|
(a) |
|
Filed herewith. |
|
(b) |
|
Furnished herewith. |
|
** |
|
Management contract or compensatory plan or arrangement. |
78
GLOSSARY
OF TERMS
The following terms are used throughout this report:
|
|
|
Bbl |
|
One stock tank barrel, of 42 United States gallons liquid
volume, used herein in reference to oil, condensate or natural
gas liquids. |
|
Boe |
|
One barrel of 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 natural gas to 1.0 Bbl of oil or condensate. |
|
Basin |
|
A large natural depression on the earths surface in which
sediments accumulate. |
|
Development wells |
|
Wells drilled within the proved area of an oil or natural gas
reservoir to the depth of a stratigraphic horizon known to be
productive. |
|
Dry hole |
|
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. |
|
Exploratory wells |
|
Wells drilled to find and produce oil or natural gas in an
unproved area, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another
reservoir, or to extend a known reservoir. |
|
Field |
|
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. |
|
GAAP |
|
Generally accepted accounting principles in the United States of
America. |
|
Gross wells |
|
The number of wells in which a working interest is owned. |
|
Horizontal drilling |
|
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. |
|
Infill wells |
|
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. |
|
LIBOR |
|
London Interbank Offered Rate, which is a market rate of
interest. |
|
MBbl |
|
One thousand barrels of oil, condensate or natural gas liquids. |
|
MBoe |
|
One thousand Boe. |
|
Mcf |
|
One thousand cubic feet of natural gas. |
|
MMBbl |
|
One million barrels of oil, condensate or natural gas liquids. |
|
MMBoe |
|
One million Boe. |
|
MMBtu |
|
One million British thermal units. |
|
MMcf |
|
One million cubic feet of natural gas. |
|
NYMEX |
|
The New York Mercantile Exchange. |
79
|
|
|
NYSE |
|
The New York Stock Exchange. |
|
Net acres |
|
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. |
|
Net wells |
|
The total of fractional working interests owned in gross wells. |
|
PV-10 |
|
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. |
|
Primary recovery |
|
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
natural gas injection. |
|
Productive wells |
|
Wells that produce commercial quantities of hydrocarbons,
exclusive of their capacity to produce at a reasonable rate of
return. |
|
Proved developed reserves |
|
Has the meaning given to such term in Release
No. 33-8995:
Modernization of Oil and Gas Reporting, which defines
proved reserves as: |
|
|
|
Proved developed reserves are reserves of any category that can
be expected to be recovered: |
|
|
|
(i) through existing wells with existing equipment and
operating methods or in which the cost of the required equipment
is relatively minor compared to the cost of a new well; and
|
|
|
|
(ii) through installed extraction equipment and
infrastructure operational at the time of the reserve estimate
if the extraction is by means not involving a well.
|
|
|
|
Supplemental definitions from the 2007 Petroleum Resources
Management System: |
|
|
|
Proved Developed Producing Reserves Developed
Producing Reserves are expected to be recovered from completion
intervals that are open and producing at the time of the
estimate. Improved recovery reserves are considered producing
only after the improved recovery project is in operation. |
|
|
|
Proved Developed Non-Producing Reserves Developed
Non-Producing Reserves include shut-in and behind-pipe Reserves. |
|
|
|
Shut-in Reserves are expected to be recovered from
(1) completion intervals which are open at the time of the
estimate but which have not yet started producing,
(2) wells which were shut-in for market conditions or
pipeline connections, or (3) wells not capable of
production for mechanical reasons. Behind-pipe Reserves are
expected to be recovered from zones in existing wells which will
require additional completion work or future recompletion prior
to start of production. In |
80
|
|
|
|
|
all cases, production can be initiated or restored with
relatively low expenditure compared to the cost of drilling a
new well. |
|
Proved reserves |
|
Has the meaning given to such term in Release
No. 33-8995:
Modernization of Oil and Gas Reporting, which defines
proved reserves as: |
|
|
|
Proved reserves are those quantities of oil and natural gas,
which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically
producible from a given date forward, from known
reservoirs, and under existing economic conditions, operating
methods, and government regulations prior to the
time at which contracts providing the right to operate expire,
unless evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are
used for the estimation. The project to extract the hydrocarbons
must have commenced or the operator must be reasonably certain
that it will commence the project within a reasonable time. |
|
|
|
(i) The area of the reservoir considered as proved includes:
|
|
|
|
(A) the area identified by
drilling and limited by fluid contacts, if any, and
|
|
|
|
(B) adjacent undrilled
portions of the reservoir that can, with reasonable certainty,
be judged to be continuous with it and to contain economically
producible oil or natural gas on the basis of available
geoscience and engineering data.
|
|
|
|
(ii) In the absence of data on fluid contacts, proved
quantities in a reservoir are limited by the lowest known
hydrocarbons (LKH) as seen in a well penetration
unless geoscience, engineering, or performance data and reliable
technology establishes a lower contact with reasonable certainty.
|
|
|
|
(iii) Where direct observation from well penetrations has
defined a highest known oil (HKO) elevation and the
potential exists for an associated natural gas cap, proved oil
reserves may be assigned in the structurally higher portions of
the reservoir only if geoscience, engineering, or performance
data and reliable technology establish the higher contact with
reasonable certainty.
|
|
|
|
(iv) Reserves which can be produced economically through
application of improved recovery techniques (including, but not
limited to, fluid injection) are included in the proved
classification when:
|
|
|
|
(A) successful testing by a
pilot project in an area of the reservoir with properties no
more favorable than in the reservoir as a whole, the operation
of an installed program in the reservoir or an analogous
reservoir, or other evidence using reliable technology
establishes the reasonable certainty of the engineering analysis
on which the project or program was based; and
|
|
|
|
(B) the project has been
approved for development by all necessary parties and entities,
including governmental entities.
|
81
|
|
|
|
|
(v) Existing economic conditions include prices and costs
at which economic producibility from a reservoir is to be
determined. The price shall be the average price during the
12-month
period prior to the ending date of the period covered by the
report, determined as an unweighted arithmetic average of the
first-day-of-the-month
price for each month within such period, unless prices are
defined by contractual arrangements, excluding escalations based
upon future conditions.
|
|
Proved undeveloped reserves |
|
Has the meaning given to such term in Release
No. 33-8995:
Modernization of Oil and Gas Reporting, which defines
proved reserves as: |
|
|
|
Proved undeveloped oil and natural gas reserves are reserves of
any category 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. |
|
|
|
(i) Reserves on undrilled acreage shall be limited to those
directly offsetting development spacing areas that are
reasonably certain of production when drilled, unless evidence
using reliable technology exists that establishes reasonable
certainty of economic producibility at greater distances.
|
|
|
|
(ii) Undrilled locations can be classified as having
undeveloped reserves only if a development plan has been adopted
indicating that they are scheduled to be drilled within five
years, unless the specific circumstances, justify a longer time.
|
|
Recompletion |
|
The addition of production from another interval or formation in
an existing wellbore. |
|
Reservoir |
|
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. |
|
SEC |
|
The United States Securities and Exchange Commission. |
|
Seismic survey |
|
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. |
|
Spacing |
|
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. |
|
Standardized measure |
|
The present value (discounted at an annual rate of
10 percent) 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 Financial Accounting Standards
Board guidelines, 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. |
82
|
|
|
Undeveloped acreage |
|
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. |
|
Wellbore |
|
The hole drilled by the bit that is equipped for oil or natural
gas production on a completed well. Also called a well or
borehole. |
|
Working interest |
|
The right granted to the lessee of a property to explore for and
to produce and own oil, natural gas, or other minerals. The
working interest owners bear the exploration, development, and
operating costs on either a cash, penalty, or carried basis. |
|
Workover |
|
Operations on a producing well to restore or increase production. |
83
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,
Chief Executive Officer and President (Principal Executive
Officer)
Date: February 25, 2011
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.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ TIMOTHY
A. LEACH
Timothy
A. Leach
|
|
Director, Chairman of the Board of Directors, Chief Executive
Officer and President (Principal Executive Officer)
|
|
February 25, 2011
|
|
|
|
|
|
/s/ DARIN
G. HOLDERNESS
Darin
G. Holderness
|
|
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
|
|
February 25, 2011
|
|
|
|
|
|
/s/ DON
O. McCORMACK
Don
O. McCormack
|
|
Vice President and Chief Accounting Officer (Principal
Accounting Officer)
|
|
February 25, 2011
|
|
|
|
|
|
/s/ STEVEN
L. BEAL
Steven
L. Beal
|
|
Director
|
|
February 25, 2011
|
|
|
|
|
|
/s/ TUCKER
S. BRIDWELL
Tucker
S. Bridwell
|
|
Director
|
|
February 25, 2011
|
|
|
|
|
|
/s/ WILLIAM
H. EASTER III
William
H. Easter III
|
|
Director
|
|
February 25, 2011
|
|
|
|
|
|
/s/ W.
HOWARD KEENAN, JR.
W.
Howard Keenan, Jr.
|
|
Director
|
|
February 25, 2011
|
|
|
|
|
|
/s/ RAY
M. POAGE
Ray
M. Poage
|
|
Director
|
|
February 25, 2011
|
|
|
|
|
|
/s/ MARK
B. PUCKETT
Mark
B. Puckett
|
|
Director
|
|
February 25, 2011
|
|
|
|
|
|
/s/ A.
WELLFORD TABOR
A.
Wellford Tabor
|
|
Director
|
|
February 25, 2011
|
84
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, 2010 and 2009, and the related
consolidated statements of operations, stockholders equity
and cash flows for each of the three years in the period ended
December 31, 2010. 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, 2010 and 2009, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2010, 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, 2010, 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 25, 2011, expressed an unqualified opinion
thereon.
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
February 25, 2011
F-2
CONCHO
RESOURCES INC.
|
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|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
|
(In thousands, except
|
|
|
|
|
|
|
share and per share data)
|
|
|
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
384
|
|
|
$
|
3,234
|
|
|
|
|
|
Accounts receivable, net of allowance for doubtful accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
|
136,471
|
|
|
|
69,199
|
|
|
|
|
|
Joint operations and other
|
|
|
131,912
|
|
|
|
100,120
|
|
|
|
|
|
Related parties
|
|
|
169
|
|
|
|
216
|
|
|
|
|
|
Derivative instruments
|
|
|
6,855
|
|
|
|
1,309
|
|
|
|
|
|
Deferred income taxes
|
|
|
42,716
|
|
|
|
29,284
|
|
|
|
|
|
Prepaid costs and other
|
|
|
12,126
|
|
|
|
13,896
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
330,633
|
|
|
|
217,258
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, at cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method
|
|
|
5,616,249
|
|
|
|
3,358,004
|
|
|
|
|
|
Accumulated depletion and depreciation
|
|
|
(730,509
|
)
|
|
|
(517,421
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas properties, net
|
|
|
4,885,740
|
|
|
|
2,840,583
|
|
|
|
|
|
Other property and equipment, net
|
|
|
28,047
|
|
|
|
15,706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
4,913,787
|
|
|
|
2,856,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred loan costs, net
|
|
|
52,828
|
|
|
|
20,676
|
|
|
|
|
|
Intangible asset operating rights, net
|
|
|
34,973
|
|
|
|
36,522
|
|
|
|
|
|
Inventory
|
|
|
28,342
|
|
|
|
16,255
|
|
|
|
|
|
Noncurrent derivative instruments
|
|
|
2,233
|
|
|
|
23,614
|
|
|
|
|
|
Other assets
|
|
|
5,698
|
|
|
|
471
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
5,368,494
|
|
|
$
|
3,171,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
39,943
|
|
|
$
|
15,443
|
|
|
|
|
|
Related parties
|
|
|
1,197
|
|
|
|
291
|
|
|
|
|
|
Bank overdrafts
|
|
|
12,314
|
|
|
|
3,415
|
|
|
|
|
|
Revenue payable
|
|
|
57,406
|
|
|
|
31,069
|
|
|
|
|
|
Accrued and prepaid drilling costs
|
|
|
215,079
|
|
|
|
164,282
|
|
|
|
|
|
Derivative instruments
|
|
|
97,775
|
|
|
|
62,419
|
|
|
|
|
|
Other current liabilities
|
|
|
83,275
|
|
|
|
60,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
506,989
|
|
|
|
337,014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
1,668,521
|
|
|
|
845,836
|
|
|
|
|
|
Deferred income taxes
|
|
|
720,889
|
|
|
|
603,286
|
|
|
|
|
|
Noncurrent derivative instruments
|
|
|
51,647
|
|
|
|
29,337
|
|
|
|
|
|
Asset retirement obligations and other long-term liabilities
|
|
|
36,574
|
|
|
|
20,184
|
|
|
|
|
|
Commitments and contingencies (Note K)
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock, $0.001 par value; 300,000,000 authorized;
102,842,082 and 85,815,926 shares issued at December 31,
2010 and 2009, respectively
|
|
|
103
|
|
|
|
86
|
|
|
|
|
|
Additional paid-in capital
|
|
|
1,874,649
|
|
|
|
1,029,392
|
|
|
|
|
|
Retained earnings
|
|
|
510,737
|
|
|
|
306,367
|
|
|
|
|
|
Treasury stock, at cost; 31,963 and 12,380 shares at
December 31, 2010 and 2009, respectively
|
|
|
(1,615
|
)
|
|
|
(417
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
2,383,874
|
|
|
|
1,335,428
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
5,368,494
|
|
|
$
|
3,171,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-3
CONCHO
RESOURCES INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009(a)
|
|
|
2008(a)
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
767,153
|
|
|
$
|
407,785
|
|
|
$
|
367,697
|
|
Natural gas sales
|
|
|
205,423
|
|
|
|
111,816
|
|
|
|
130,388
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
972,576
|
|
|
|
519,601
|
|
|
|
498,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
|
170,767
|
|
|
|
98,782
|
|
|
|
81,836
|
|
Exploration and abandonments
|
|
|
10,324
|
|
|
|
10,632
|
|
|
|
38,468
|
|
Depreciation, depletion and amortization
|
|
|
249,850
|
|
|
|
196,736
|
|
|
|
117,406
|
|
Accretion of discount on asset retirement obligations
|
|
|
1,503
|
|
|
|
917
|
|
|
|
761
|
|
Impairments of long-lived assets
|
|
|
11,614
|
|
|
|
7,880
|
|
|
|
11,522
|
|
General and administrative (including non-cash stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation of $12,931, $9,040 and $5,223 for the years ended
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010, 2009 and 2008, respectively)
|
|
|
64,275
|
|
|
|
53,163
|
|
|
|
41,130
|
|
Bad debt expense
|
|
|
870
|
|
|
|
(1,035
|
)
|
|
|
2,905
|
|
Ineffective portion of cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
(1,336
|
)
|
(Gain) loss on derivatives not designated as hedges
|
|
|
87,325
|
|
|
|
156,857
|
|
|
|
(249,870
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
596,528
|
|
|
|
523,932
|
|
|
|
42,822
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
376,048
|
|
|
|
(4,331
|
)
|
|
|
455,263
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(60,087
|
)
|
|
|
(28,292
|
)
|
|
|
(29,039
|
)
|
Other, net
|
|
|
(10,278
|
)
|
|
|
(414
|
)
|
|
|
1,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(70,365
|
)
|
|
|
(28,706
|
)
|
|
|
(27,607
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
305,683
|
|
|
|
(33,037
|
)
|
|
|
427,656
|
|
Income tax benefit (expense)
|
|
|
(122,649
|
)
|
|
|
21,510
|
|
|
|
(157,434
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
183,034
|
|
|
|
(11,527
|
)
|
|
|
270,222
|
|
Income from discontinued operations, net of tax
|
|
|
21,336
|
|
|
|
1,725
|
|
|
|
8,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
204,370
|
|
|
$
|
(9,802
|
)
|
|
$
|
278,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
$
|
1.98
|
|
|
$
|
(0.14
|
)
|
|
$
|
3.41
|
|
Income from discontinued operations, net of tax
|
|
|
0.23
|
|
|
|
0.02
|
|
|
|
0.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
2.21
|
|
|
$
|
(0.12
|
)
|
|
$
|
3.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares used in basic earnings per share
|
|
|
92,542
|
|
|
|
84,912
|
|
|
|
79,206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
$
|
1.95
|
|
|
$
|
(0.14
|
)
|
|
$
|
3.35
|
|
Income from discontinued operations, net of tax
|
|
|
0.23
|
|
|
|
0.02
|
|
|
|
0.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
2.18
|
|
|
$
|
(0.12
|
)
|
|
$
|
3.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares used in diluted earnings per share
|
|
|
93,837
|
|
|
|
84,912
|
|
|
|
80,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Retrospectively adjusted for presentation of discontinued
operations as described in Note B. |
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
CONCHO
RESOURCES INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivable
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
from
|
|
|
|
|
|
Comprehensive
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Common Stock
|
|
|
Paid-in
|
|
|
Officers and
|
|
|
Retained
|
|
|
Income
|
|
|
Treasury Stock
|
|
|
Stockholders
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Employees
|
|
|
Earnings
|
|
|
(Loss)
|
|
|
Shares
|
|
|
Amount
|
|
|
Equity
|
|
|
|
(In thousands)
|
|
|
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
|
|
|
128
|
|
|
|
|
|
|
|
5,223
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,223
|
|
Cancellation of restricted stock
|
|
|
(46
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
Net loss and total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,802
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,802
|
)
|
Stock options exercised
|
|
|
695
|
|
|
|
1
|
|
|
|
6,115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,116
|
|
Stock-based compensation
|
|
|
300
|
|
|
|
|
|
|
|
9,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,040
|
|
Cancellation of restricted stock
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess tax benefits related to stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
5,212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,212
|
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
|
|
(292
|
)
|
|
|
(292
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2009
|
|
|
85,816
|
|
|
|
86
|
|
|
|
1,029,392
|
|
|
|
|
|
|
|
306,367
|
|
|
|
|
|
|
|
12
|
|
|
|
(417
|
)
|
|
|
1,335,428
|
|
Net income and total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
204,370
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
204,370
|
|
Issuance of common stock
|
|
|
14,845
|
|
|
|
15
|
|
|
|
739,431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
739,446
|
|
Common stock issued in acquisition
|
|
|
1,104
|
|
|
|
1
|
|
|
|
75,772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75,773
|
|
Stock options exercised
|
|
|
560
|
|
|
|
1
|
|
|
|
5,777
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,778
|
|
Stock-based compensation
|
|
|
537
|
|
|
|
|
|
|
|
12,931
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,931
|
|
Cancellation of restricted stock
|
|
|
(20
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess tax benefits related to stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
11,346
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,346
|
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
|
|
|
|
(1,198
|
)
|
|
|
(1,198
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2010
|
|
|
102,842
|
|
|
$
|
103
|
|
|
$
|
1,874,649
|
|
|
$
|
|
|
|
$
|
510,737
|
|
|
$
|
|
|
|
|
32
|
|
|
$
|
(1,615
|
)
|
|
$
|
2,383,874
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
CONCHO
RESOURCES INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009(a)
|
|
|
2008(a)
|
|
|
|
(In thousands)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
204,370
|
|
|
$
|
(9,802
|
)
|
|
$
|
278,702
|
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
249,850
|
|
|
|
196,736
|
|
|
|
117,406
|
|
Accretion of discount on asset retirement obligations
|
|
|
1,503
|
|
|
|
917
|
|
|
|
761
|
|
Impairments of long-lived assets
|
|
|
11,614
|
|
|
|
7,880
|
|
|
|
11,522
|
|
Exploration and abandonments, including dry holes
|
|
|
7,612
|
|
|
|
6,997
|
|
|
|
35,328
|
|
Non-cash compensation expense
|
|
|
12,931
|
|
|
|
9,040
|
|
|
|
5,223
|
|
Bad debt expense
|
|
|
870
|
|
|
|
(1,035
|
)
|
|
|
2,905
|
|
Deferred income taxes
|
|
|
104,930
|
|
|
|
(29,142
|
)
|
|
|
154,254
|
|
(Gain) loss on sale of assets, net
|
|
|
58
|
|
|
|
114
|
|
|
|
(777
|
)
|
Ineffective portion of cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
(1,336
|
)
|
(Gain) loss on derivatives not designated as hedges
|
|
|
87,325
|
|
|
|
156,857
|
|
|
|
(249,870
|
)
|
Dedesignated cash flow hedges reclassified from accumulated
other comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
696
|
|
Discontinued operations
|
|
|
(7,157
|
)
|
|
|
12,088
|
|
|
|
12,759
|
|
Other non-cash items
|
|
|
6,837
|
|
|
|
3,870
|
|
|
|
6,517
|
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(92,957
|
)
|
|
|
(26,217
|
)
|
|
|
39,609
|
|
Prepaid costs and other
|
|
|
3,255
|
|
|
|
(7,952
|
)
|
|
|
(5,542
|
)
|
Inventory
|
|
|
(2,321
|
)
|
|
|
4,117
|
|
|
|
(16,819
|
)
|
Accounts payable
|
|
|
24,373
|
|
|
|
7,960
|
|
|
|
(25,234
|
)
|
Revenue payable
|
|
|
26,337
|
|
|
|
8,118
|
|
|
|
7,074
|
|
Other current liabilities
|
|
|
12,152
|
|
|
|
19,000
|
|
|
|
18,219
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
651,582
|
|
|
|
359,546
|
|
|
|
391,397
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures on oil and natural gas properties
|
|
|
(684,347
|
)
|
|
|
(403,798
|
)
|
|
|
(347,702
|
)
|
Acquisition of oil and natural gas properties and other assets
|
|
|
(1,442,700
|
)
|
|
|
(265,469
|
)
|
|
|
(584,220
|
)
|
Additions to other property and equipment
|
|
|
(6,935
|
)
|
|
|
(4,396
|
)
|
|
|
(8,808
|
)
|
Proceeds from the sale of assets
|
|
|
104,349
|
|
|
|
5,099
|
|
|
|
1,034
|
|
Settlements received from (paid on) derivatives not designated
as hedges
|
|
|
(13,824
|
)
|
|
|
82,416
|
|
|
|
(6,354
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(2,043,457
|
)
|
|
|
(586,148
|
)
|
|
|
(946,050
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt
|
|
|
2,946,748
|
|
|
|
1,158,650
|
|
|
|
767,800
|
|
Payments of long-term debt
|
|
|
(2,283,248
|
)
|
|
|
(942,916
|
)
|
|
|
(465,700
|
)
|
Exercise of stock options
|
|
|
5,778
|
|
|
|
6,116
|
|
|
|
5,391
|
|
Excess tax benefit from stock-based compensation
|
|
|
11,346
|
|
|
|
5,212
|
|
|
|
3,614
|
|
Net proceeds from issuance of common stock
|
|
|
739,446
|
|
|
|
|
|
|
|
242,426
|
|
Proceeds from repayment of officer and employee notes
|
|
|
|
|
|
|
|
|
|
|
333
|
|
Payments for loan costs
|
|
|
(38,746
|
)
|
|
|
(8,667
|
)
|
|
|
(15,541
|
)
|
Purchase of treasury stock
|
|
|
(1,198
|
)
|
|
|
(292
|
)
|
|
|
(125
|
)
|
Bank overdrafts
|
|
|
8,899
|
|
|
|
(6,019
|
)
|
|
|
3,783
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
1,389,025
|
|
|
|
212,084
|
|
|
|
541,981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(2,850
|
)
|
|
|
(14,518
|
)
|
|
|
(12,672
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
3,234
|
|
|
|
17,752
|
|
|
|
30,424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
384
|
|
|
$
|
3,234
|
|
|
$
|
17,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL CASH FLOWS:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest and fees, net of $184, $66 and $1,233
capitalized interest
|
|
$
|
48,052
|
|
|
$
|
14,862
|
|
|
$
|
27,747
|
|
Cash paid for income taxes
|
|
$
|
19,885
|
|
|
$
|
7,299
|
|
|
$
|
11,304
|
|
NON-CASH INVESTING AND FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock in acquisition of oil and natural gas
properties and other assets
|
|
$
|
75,773
|
|
|
$
|
|
|
|
$
|
|
|
Issuance of debt in acquisition of oil and natural gas
properties and other assets
|
|
$
|
159,000
|
|
|
$
|
|
|
|
$
|
|
|
Deferred tax effect of acquired oil and natural gas properties
and other assets
|
|
$
|
|
|
|
$
|
(835
|
)
|
|
$
|
206,497
|
|
|
|
|
(a) |
|
Retrospectively adjusted for presentation of discontinued
operations as described in Note B. |
The accompanying notes are an integral part of these
consolidated financial statements.
F-6
CONCHO
RESOURCES INC.
December 31,
2010, 2009 and 2008
|
|
Note A.
|
Organization
and nature of operations
|
Concho Resources Inc. (the Company) is a Delaware
corporation formed on February 22, 2006. The Companys
principal business is the acquisition, development and
exploration of oil and natural gas properties primarily located
in the Permian Basin region of Southeast New Mexico and West
Texas.
|
|
Note B.
|
Summary
of significant accounting policies
|
Principles of consolidation. The
consolidated financial statements of the Company include the
accounts of the Company and its wholly-owned subsidiaries. A
third-party formed an entity to effectuate a tax-free exchange
of assets for the Company. The Company has 100 percent
control over the decisions of the entity, but has no current
direct ownership. The third-party will convey ownership to the
Company upon completion of the tax-free exchange process. As a
result of the Companys control over the entity it has been
consolidated in the Companys financial statements. All
material intercompany balances and transactions have been
eliminated.
Discontinued operations. In December
2010, the Company sold its interests in certain non-core,
Permian Basin assets. As a result, the Company has reflected the
results of operations of these divested assets as discontinued
operations, rather than as a component of continuing operations.
See Note O for additional information regarding this
divestiture and its discontinued operations.
Use of estimates in the preparation of financial
statements. Preparation of financial
statements in conformity with generally accepted accounting
principles in the United States of America requires management
to make estimates and assumptions that affect the reported
amounts of assets and liabilities, the disclosure of contingent
assets and liabilities at the date of the financial statements
and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from these
estimates. Depletion of oil and natural gas properties are
determined using estimates of proved oil and natural gas
reserves. There are numerous uncertainties inherent in the
estimation of quantities of proved reserves and in the
projection of future rates of production and the timing of
development expenditures. Similarly, evaluations for impairment
of proved and unproved oil and natural gas properties are
subject to numerous uncertainties including, among others,
estimates of future recoverable reserves and commodity price
outlooks. Other significant estimates include, but are not
limited to, the asset retirement obligations, fair value of
derivative financial instruments, purchase price allocations for
business and oil and natural gas property acquisitions and fair
value of stock-based compensation.
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 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 natural gas to various customers and participates with
other parties in the drilling, completion and operation of oil
and natural gas wells. Joint interest and oil and natural 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 $1.3 million and $2.4 million at
December 31, 2010 and 2009, respectively. The Company wrote
off $2.0 million in receivables against the allowance for
doubtful accounts and allowed for additional bed debt of
approximately $0.9 million during 2010.
F-7
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Inventory. Inventory consists primarily
of tubular goods and other oilfield 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 $52.8 million and
$20.7 million, net of accumulated amortization of
$15.2 million and $8.6 million, at December 31,
2010 and December 31, 2009, respectively.
Future amortization expense of deferred loan costs at
December 31, 2010 is as follows:
|
|
|
|
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
2011
|
|
$
|
14,221
|
|
2012
|
|
|
14,368
|
|
2013
|
|
|
9,308
|
|
2014
|
|
|
2,173
|
|
2015
|
|
|
2,362
|
|
Thereafter
|
|
|
10,396
|
|
|
|
|
|
|
Total
|
|
$
|
52,828
|
|
|
|
|
|
|
Oil and natural gas properties. The
Company utilizes the successful efforts method of accounting for
its oil and natural gas properties. 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.
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 natural 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; and
(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
F-8
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 completed 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, 2010 and 2009 the Company had excluded
$80.6 million and $30.9 million, respectively, of
capitalized costs from depletion and had capitalized interest of
$0.2 million, $0.07 million and $1.2 million,
during 2010, 2009 and 2008, respectively.
The Company reviews its long-lived assets to be held and used,
including proved oil and natural gas properties, whenever events
or circumstances indicate that the carrying value of those
assets may not be recoverable. An impairment loss is indicated
if the sum of the expected 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 natural gas
properties by amortization base or by individual well for those
wells not constituting part of an amortization base. For each
property determined to be impaired, an impairment loss equal to
the difference between the carrying value of the properties and
the estimated fair value (discounted future cash flows) of the
properties would be recognized at that time. Estimating future
cash flows involves the use of judgments, including estimation
of the proved and unproved oil and natural gas reserve
quantities, timing of development and production, expected
future commodity prices, capital expenditures and production
costs. The Company recognized impairment expense from continuing
and discontinued operations of $15.2 million,
$12.2 million and $18.4 million during the years ended
December 31, 2010, 2009 and 2008, respectively, primarily
related to its proved oil and natural gas properties.
Unproved oil and natural 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, 2010, 2009
and 2008, the Company recognized expense from continuing and
discontinued operations of $7.6 million, $5.1 million
and $31.6 million, respectively, related to abandoned
prospects, which is included in exploration and abandonments
expense in the accompanying consolidated statements of
operations.
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, or fair value if acquired, and are depreciated
using the straight-line method based on expected lives of the
individual assets or group of assets ranging from two to
31 years.
Intangible assets. The Company has
capitalized certain operating rights acquired in an acquisition.
The gross operating rights of approximately $38.7 million
and related accumulated amortization of $3.7 million at
December 31, 2010, 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
years ended December 31, 2010, 2009 and
F-9
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2008 was approximately $1.5 million, $1.6 million and
$0.6 million, respectively. The following table reflects
the estimated aggregate amortization expense for each of the
periods presented below:
|
|
|
|
|
|
|
(In thousands)
|
|
|
2011
|
|
$
|
1,549
|
|
2012
|
|
|
1,549
|
|
2013
|
|
|
1,549
|
|
2014
|
|
|
1,549
|
|
2015
|
|
|
1,549
|
|
Thereafter
|
|
|
27,228
|
|
|
|
|
|
|
Total
|
|
$
|
34,973
|
|
|
|
|
|
|
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.
At December 31, 2010 and 2009, the Company has accrued
approximately $1.4 million and $0.8 million,
respectively, related to environmental liabilities. During the
years ended December 31, 2010, 2009 and 2008, the Company
has recognized environmental charges of $3.0 million,
$2.3 million and $0.5 million, respectively.
Oil and natural gas sales and
imbalances. Oil and natural gas revenues are
recorded at the time of delivery of such products to pipelines
for the account of the purchaser or at the time of physical
transfer of such products to the purchaser. The Company follows
the sales method of accounting for oil and natural gas sales,
recognizing revenues based on the Companys share of actual
proceeds from the oil and natural gas sold to purchasers. Oil
and natural gas imbalances are generated on properties for which
two or more owners have the right to take production
in-kind and, in doing so, take more or less than
their respective entitled percentage. Imbalances are tracked by
well, but the Company does not record any receivable from or
payable to the other owners unless the imbalance has reached a
level at which it exceeds the remaining reserves in the
respective well. If reserves are insufficient to offset the
imbalance and the Company is in an overtake position, a
liability is recorded for the amount of shortfall in reserves
valued at a contract price or the market price in effect at the
time the imbalance is generated. If the Company is in an
undertake position, a receivable is recorded for an amount that
is reasonably expected to be received, not to exceed the current
market value of such imbalance.
The following table reflects the Companys natural gas
imbalance positions at December 31, 2010 and 2009 as well
as amounts reflected in oil and natural gas production expense
for the years ended December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Natural gas imbalance liability (included in asset retirement
obligations and other long-term liabilities)
|
|
$
|
403
|
|
|
$
|
533
|
|
Overtake position (Mcf)
|
|
|
71,153
|
|
|
|
101,278
|
|
Natural gas imbalance receivable (included in other assets)
|
|
$
|
100
|
|
|
$
|
444
|
|
Undertake position (Mcf)
|
|
|
22,240
|
|
|
|
98,584
|
|
F-10
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Value of net overtake (undertake) arising during the year
increasing (decreasing) oil and natural gas production expense
|
|
$
|
(38
|
)
|
|
$
|
23
|
|
|
$
|
(189
|
)
|
Net overtake (undertake) position arising during the year (Mcf)
|
|
|
(8,695
|
)
|
|
|
7,317
|
|
|
|
(19,269
|
)
|
Value of net (undertake) related to divested natural gas
properties
|
|
$
|
(252
|
)
|
|
$
|
|
|
|
$
|
|
|
Net (undertake) position related to divested natural gas
properties (Mcf)
|
|
|
(54,914
|
)
|
|
|
|
|
|
|
|
|
Derivative instruments and hedging. The
Company recognizes 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.
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.
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 earnings. The
Company did not have any derivatives designated as fair value or
cash flow hedges during the years ended December 31, 2010
or 2009.
Asset retirement obligations. The
Company records 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 is
allocated to expense through depreciation of the asset. Changes
in the liability due to passage of time are generally 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
natural gas properties and records such reimbursements as
reductions of general and administrative expense. Such fees from
continuing and discontinued operations totaled approximately
$14.4 million, $11.4 million and $4.9 million for
the years ended December 31, 2010, 2009 and 2008,
respectively.
Stock-based compensation. From time to
time, the Company exchanges its equity instruments for services
provided by employees and directors 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 the services. The cost of the services
F-11
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
received in exchange for equity instruments, including 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 recognizes
deferred tax assets and liabilities 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. 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 evaluates uncertain tax positions for recognition
and measurement in the consolidated financial statements. To
recognize a tax position, the Company determines whether it is
more likely than not that the tax positions will be sustained
upon examination, including resolution of any related appeals or
litigation, based on the technical merits of the position. A tax
position that meets the more likely than not threshold is
measured to determine the amount of benefit to be recognized in
the consolidated financial statements. The amount of tax benefit
recognized with respect to any tax position is measured as the
largest amount of benefit that is greater than 50 percent
likely of being realized upon settlement. The Company had no
uncertain tax positions that required recognition in the
consolidated financial statements at December 31, 2010 and
2009. Any interest or penalties would be recognized as a
component of income tax expense.
Recent
accounting pronouncements.
Business combinations. In December
2010, the Financial Accounting Standards Board (the
FASB) issued an update in order to address diversity
in practice about the interpretation of the pro forma revenue
and earnings disclosure requirements for business combinations.
The update requires a public entity to disclose pro forma
information for business combinations that occurred in the
current reporting period. The disclosures include pro forma
revenue and earnings of the combined entity for the current
reporting period as though the acquisition date for all business
combinations that occurred during the year had been as of the
beginning of the annual reporting period. If comparative
financial statements are presented, the pro forma revenue and
earnings of the combined entity for the comparable prior
reporting period should be reported as though the acquisition
date for all business combinations that occurred during the
current year had been as of the beginning of the comparable
prior annual reporting period.
In practice, some preparers have presented the pro forma
information in their comparative financial statements as if the
business combination that occurred in the current reporting
period had occurred as of the beginning of each of the current
and prior annual reporting periods. Other preparers have
disclosed the pro forma information as if the business
combination occurred at the beginning of the prior annual
reporting period only, and carried forward the related
adjustments, if applicable, through the current reporting
period. The Company early adopted the update effective January
1, 2010, and the adoption did not have a significant impact on
its consolidated financial statements.
Various topics. In February 2010, the
FASB issued an update to various topics, which eliminated
outdated provisions and inconsistencies in the Accounting
Standards Codification (the Codification), and
clarified certain guidance to reflect the FASBs original
intent. The update is effective for the first reporting period,
including interim periods, beginning after issuance of the
update, except for the amendments affecting embedded derivatives
and reorganizations. In addition to amending the Codification,
the FASB made corresponding changes to the legacy accounting
literature to facilitate historical research. These changes are
included in an appendix to the update. The Company adopted the
update effective January 1, 2010, and the adoption did not
have a significant impact on its consolidated financial
statements.
F-12
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Accounting for extractive
activities. In April 2010, the FASB issued an
amendment to a paragraph in the accounting standard for oil and
natural gas extractive activities accounting. The standard adds
to the Codification the SECs Modernization of Oil and
Gas Reporting release. The Company adopted the update
effective April 20, 2010, and the adoption did not have a
significant impact on 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, 2010, 2009, and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Beginning capitalized exploratory well costs
|
|
$
|
8,668
|
|
|
$
|
25,553
|
|
|
$
|
21,056
|
|
Additions to exploratory well costs pending the determination of
proved reserves
|
|
|
175,343
|
|
|
|
135,656
|
|
|
|
25,621
|
|
Reclassifications due to determination of proved reserves
|
|
|
(137,185
|
)
|
|
|
(152,200
|
)
|
|
|
(18,327
|
)
|
Exploratory well costs charged to expense
|
|
|
|
|
|
|
(341
|
)
|
|
|
(2,797
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending capitalized exploratory well costs
|
|
$
|
46,826
|
|
|
$
|
8,668
|
|
|
$
|
25,553
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table provides an aging at December 31, 2010
and 2009 of capitalized exploratory well costs based on the date
the drilling was completed:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Wells in drilling progress
|
|
$
|
19,190
|
|
|
$
|
1,767
|
|
Capitalized exploratory well costs that have been capitalized
for a period of one year or less
|
|
|
27,636
|
|
|
|
6,901
|
|
Capitalized exploratory well costs that have been capitalized
for a period greater than one year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalized exploratory well costs
|
|
$
|
46,826
|
|
|
$
|
8,668
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2010, the Company had 48 gross
exploratory wells either drilling or waiting on results from
completion. There were 10 wells in the New Mexico Shelf
area, 12 wells in Delaware Basin area, 23 wells in the
Texas Permian area and 3 wells in our other non-core areas.
|
|
Note D.
|
Acquisitions
and business combinations
|
Marbob and Settlement Acquisitions. In
July 2010, the Company entered into an asset purchase agreement
to acquire certain of the oil and natural gas leases, interests,
properties and related assets owned by Marbob Energy Corporation
and its affiliates (collectively, Marbob) for
aggregate consideration of (i) cash in the amount of
$1.45 billion, (ii) the issuance to Marbob of
$150 million 8.0% unsecured senior note due 2018 and
(iii) the issuance to Marbob of approximately
1.1 million shares of the Companys common stock,
subject to purchase price adjustments, which included downward
purchase price adjustments based on the exercise of third
parties of contractual preferential purchase rights in
properties to be acquired from Marbob (Marbob
Acquisition).
F-13
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
On October 7, 2010, the Company closed the Marbob
Acquisition. At closing, the Company paid approximately
$1.1 billion in cash plus the unsecured senior note and
common stock described above for a total purchase price of
approximately $1.4 billion. The total purchase price as
originally announced was reduced due to third party contractual
preferential purchase rights in the Marbob properties. Certain
of the third parties contractual preferential purchase rights
became subject to litigation, as discussed below.
The Company funded the cash consideration in the Marbob
Acquisition with (a) borrowings under its credit facility
and (b) net proceeds of $292.7 million from a private
placement of approximately 6.6 million shares of the
Companys common stock at a price of $45.30 per share that
closed on October 7, 2010.
Certain of the Marbob interests in properties contained
contractual preferential purchase rights by third parties if
Marbob were to sell them. Marbob informed the Company of its
receipt of a notice from BP America Production Company
(BP) electing to exercise its contractual
preferential purchase rights in certain of Marbobs
properties as a result of the Marbob Acquisition.
On July 20, 2010, BP announced it was selling all its
assets in the Permian Basin to a subsidiary of Apache
Corporation (Apache). Marbob and BP owned common
interests in certain properties subject to contractual
preferential purchase rights. BP and Apache contested
Marbobs ability to exercise its contractual preferential
purchase rights in this situation. As a result, Marbob and the
Company filed suit against BP and Apache seeking declaratory
judgment and injunctive relief to protect Marbobs
contractual right to have the option to purchase these interests
in these common properties.
On October 15, 2010, the Company and Marbob resolved the
litigation with BP and Apache related to the disputed
contractual preferential purchase rights. As a result of the
settlement, the Company acquired a non-operated interest in
substantially all of the oil and natural gas assets subject to
the litigation for approximately $286 million in cash (the
Settlement Acquisition). The Company funded the
Settlement Acquisition with borrowings under our credit facility.
The results of operations of the Marbob and Settlement
Acquisitions are included in the Companys results of
operations since their respective closing dates in October 2010.
The following tables represent the allocation of the total
purchase price of the Marbob and Settlement Acquisitions to the
acquired assets and liabilities assumed. The allocation
represents the fair values assigned to each of the assets
acquired and liabilities assumed:
|
|
|
|
|
|
|
|
|
|
|
Marbob
|
|
|
Settlement
|
|
|
|
Acquisition
|
|
|
Acquisition
|
|
|
|
(In thousands)
|
|
|
Fair value of net assets:
|
|
|
|
|
|
|
|
|
Proved oil and natural gas properties
|
|
$
|
1,014,734
|
|
|
$
|
185,337
|
|
Unproved oil and natural gas properties
|
|
|
334,866
|
|
|
|
101,582
|
|
Other long-term assets
|
|
|
20,771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets acquired
|
|
|
1,370,371
|
|
|
|
286,919
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations and other liabilities assumed
|
|
|
(7,851
|
)
|
|
|
(689
|
)
|
|
|
|
|
|
|
|
|
|
Total purchase price
|
|
$
|
1,362,520
|
|
|
$
|
286,230
|
|
|
|
|
|
|
|
|
|
|
Fair value of consideration paid for net assets:
|
|
|
|
|
|
|
|
|
Cash consideration
|
|
$
|
1,127,747
|
|
|
$
|
286,230
|
|
Marbob $150 million senior unsecured 8% note, due 2018
|
|
|
159,000
|
(a)
|
|
|
|
|
Common stock, $0.001 par value; 1,103,752 shares issued
|
|
|
75,773
|
(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total purchase price
|
|
$
|
1,362,520
|
|
|
$
|
286,230
|
|
|
|
|
|
|
|
|
|
|
F-14
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(a) |
|
The fair value of the $150 million 8.0% senior
unsecured note due 2018 issued to Marbob, was calculated by
reference to the traded market yield of Conchos
8.625% senior unsecured notes due 2017, at
September 30, 2010. |
|
(b) |
|
The fair value of the Concho common stock issued to Marbob was
valued at the average of the high and low price on the closing
date (October 7, 2010), of $68.65 per share. |
Wolfberry acquisitions. In December
2009, together with the acquisition of related additional
interests that closed in 2010, the Company closed two
acquisitions (the Wolfberry Acquisitions) of
interests in producing and non-producing assets in the Wolfberry
play in the Permian Basin for approximately $270.7 million.
The Wolfberry Acquisitions were funded with borrowings under the
Companys credit facility. The Companys 2009 results
of operations do not include any results from the Wolfberry
Acquisitions.
The following table represents the allocation of the total
purchase price of the Wolfberry Acquisitions to the acquired
assets and liabilities assumed. The allocation represents the
fair values assigned to each of the assets acquired and
liabilities assumed:
|
|
|
|
|
|
|
Wolfberry
|
|
|
|
Acquisitions
|
|
|
|
(In thousands)
|
|
|
Fair value of net assets:
|
|
|
|
|
Proved oil and natural gas properties
|
|
$
|
212,987
|
|
Unproved oil and natural gas properties
|
|
|
58,222
|
|
|
|
|
|
|
Total assets acquired
|
|
|
271,209
|
|
Asset retirement obligations
|
|
|
(464
|
)
|
|
|
|
|
|
Net purchase price
|
|
$
|
270,745
|
|
|
|
|
|
|
Henry Entities acquisition. In July
2008, the Company closed its 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
natural gas properties from persons affiliated with the Henry
Entities. In August 2008 and September 2008, the Company
acquired additional non-operated interests in oil and natural
gas assets from persons affiliated with the Henry Entities. The
assets acquired and liabilities assumed in the Henry Entities
acquisition and the acquired additional non-operated interests
are referred to as the Henry Properties. The Company
paid $583.7 million in cash for the Henry Properties
acquisition. The Companys results of operations included
those from the Henry Properties since August 1, 2008.
The cash paid for the Henry Properties acquisition was funded
with (i) borrowings under the Companys credit
facility, and (ii) net proceeds of $242.4 million from
a private placement of approximately 8.3 million shares of
the Companys common stock.
Pro forma data. The following unaudited
pro forma combined condensed financial data for the years ended
December 31, 2010 and 2009 was derived from the historical
financial statements of the Company giving effect to the Marbob
and Settlement Acquisitions as if they had occurred on
January 1, 2009. The pro forma financial data does not
include the results of operations for the Wolfberry Acquisitions
as they are not deemed material. 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 these acquisitions
taken place as of the date indicated and is not intended to be a
projection of future results.
F-15
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands, except per share data)
|
|
|
|
(Unaudited)
|
|
|
Operating revenues
|
|
$
|
1,178,138
|
|
|
$
|
732,452
|
|
Net income (loss)
|
|
$
|
216,984
|
|
|
$
|
(893
|
)
|
Earnings per common share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
2.16
|
|
|
$
|
(0.01
|
)
|
Diluted
|
|
$
|
2.14
|
|
|
$
|
(0.01
|
)
|
|
|
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 during the years ended
December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Asset retirement obligations, beginning of period
|
|
$
|
22,754
|
|
|
$
|
16,809
|
|
|
$
|
9,418
|
|
Liabilities incurred from new wells
|
|
|
3,037
|
|
|
|
1,526
|
|
|
|
1,197
|
|
Liabilities assumed in acquisitions
|
|
|
8,290
|
|
|
|
488
|
|
|
|
7,062
|
|
Accretion expense on continuing operations
|
|
|
1,503
|
|
|
|
917
|
|
|
|
761
|
|
Accretion expense on discontinued operations
|
|
|
211
|
|
|
|
141
|
|
|
|
128
|
|
Disposition of wells
|
|
|
(3,236
|
)
|
|
|
(223
|
)
|
|
|
|
|
Liabilities settled upon plugging and abandoning wells
|
|
|
(591
|
)
|
|
|
(1,255
|
)
|
|
|
|
|
Revision of estimates
|
|
|
11,358
|
|
|
|
4,351
|
|
|
|
(1,757
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, end of period
|
|
$
|
43,326
|
|
|
$
|
22,754
|
|
|
$
|
16,809
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note F.
|
Stockholders
equity and treasury stock
|
Public common stock offering. In
December 2010, the Company issued, including the over-allotment
option, in a secondary public offering 2.9 million shares
of our common stock at $82.50 per share and we received net
proceeds of approximately $227.4 million. The Company used
the net proceeds from this offering to repay a portion of the
borrowings under our credit facility.
In February 2010, the Company issued, including the
over-allotment option, in a secondary public offering
5.3 million shares of our common stock at $42.75 per share
and we received net proceeds of approximately
$219.3 million. The Company used the net proceeds from this
offering to repay a portion of the borrowings under our credit
facility.
Private placement of common stock. In
October 2010, the Company closed the private placement of its
common stock, simultaneously with the closing of the Marbob
Acquisition, on 6.6 million shares of our common stock at a
price of $45.30 per share for net proceeds of approximately
$292.7 million.
F-16
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In July 2008, we closed the private placement of our common
stock, simultaneously with the closing of the Henry Entities
acquisition, on 8.3 million shares of our common stock at a
price of $30.11 per share for net proceeds of approximately
$242.4 million.
Treasury stock. The restrictions on
certain restricted stock awards issued to certain of the
Companys officers lapsed during the years ended
December 31, 2010, 2009, and 2008. Immediately upon the
lapse of restrictions, these officers and key employees became
liable for income taxes on the value of such shares. In
accordance with the Companys 2006 Stock Incentive Plan and
the applicable restricted stock award agreements, some of such
officers and key employees elected to deliver shares of the
Companys common stock to the Company in exchange for cash
used to satisfy such tax liability. In total, at
December 31, 2010 and 2009, the Company had acquired 31,963
and 12,380 shares of the Companys common stock,
respectively, that are held as treasury stock in the approximate
amount of $1.6 million and $0.4 million, respectively.
Defined contribution plan. The Company
sponsors a 401(k) defined contribution plan for the benefit of
substantially all employees. 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,
2010, 2009 and 2008 were approximately $0.7 million,
$1.0 million, and $1.2 million, respectively.
Stock incentive plan. The
Companys 2006 Stock Incentive Plan (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
Plan at December 31, 2010:
|
|
|
|
|
|
|
Number of
|
|
|
|
Common Shares
|
|
|
Approved and authorized awards
|
|
|
5,850,000
|
|
Stock option grants, net of forfeitures
|
|
|
(3,463,720
|
)
|
Restricted stock grants, net of forfeitures
|
|
|
(1,322,941
|
)
|
|
|
|
|
|
Awards available for future grant
|
|
|
1,063,339
|
|
|
|
|
|
|
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 restriction lapse date, the awarded
F-17
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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,
2010, 2009 and 2008 is presented below:
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Grant Date
|
|
|
|
Restricted
|
|
|
Fair Value
|
|
|
|
Shares
|
|
|
Per Share
|
|
|
Restricted stock:
|
|
|
|
|
|
|
|
|
Outstanding at January 1, 2008
|
|
|
371,549
|
|
|
|
|
|
Shares granted
|
|
|
128,001
|
|
|
$
|
32.13
|
|
Shares cancelled / forfeited
|
|
|
(46,741
|
)
|
|
|
|
|
Lapse of restrictions
|
|
|
(45,458
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
407,351
|
|
|
|
|
|
Shares granted
|
|
|
300,119
|
|
|
$
|
27.10
|
|
Shares cancelled / forfeited
|
|
|
(7,874
|
)
|
|
|
|
|
Lapse of restrictions
|
|
|
(202,339
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009
|
|
|
497,257
|
|
|
|
|
|
Shares granted
|
|
|
537,415
|
|
|
$
|
59.57
|
|
Shares cancelled / forfeited
|
|
|
(19,528
|
)
|
|
|
|
|
Lapse of restrictions
|
|
|
(194,260
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2010
|
|
|
820,884
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes information about stock-based
compensation for the Companys restricted stock awards for
the years ended December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Grant date fair value for awards during the
period:(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee grants
|
|
$
|
11,823
|
|
|
$
|
5,187
|
|
|
$
|
2,693
|
|
Officer and director grants
|
|
|
20,290
|
|
|
|
3,256
|
|
|
|
1,420
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
32,113
|
|
|
$
|
8,443
|
|
|
$
|
4,113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense from restricted
stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee grants
|
|
$
|
5,207
|
|
|
$
|
3,003
|
|
|
$
|
1,498
|
|
Officer and director grants(a)
|
|
|
5,071
|
|
|
|
1,752
|
|
|
|
624
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,278
|
|
|
$
|
4,755
|
|
|
$
|
2,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes and other information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit related to restricted stock
|
|
$
|
3,931
|
|
|
$
|
1,790
|
|
|
$
|
808
|
|
Deductions in current taxable income related to restricted stock
|
|
$
|
11,289
|
|
|
$
|
5,458
|
|
|
$
|
1,234
|
|
|
|
|
(a) |
|
The years ended December 31, 2010 and 2009 include effects
of modifications to certain stock-based awards, see discussion
below. |
F-18
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Stock option awards. A summary of the
Companys stock option activity under the Plan for the
years ended December 31, 2010, 2009 and 2008 is presented
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
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
|
|
|
2,156,503
|
|
|
$
|
14.11
|
|
|
|
2,731,324
|
|
|
$
|
12.46
|
|
|
|
3,011,722
|
|
|
$
|
9.71
|
|
Options granted
|
|
|
|
|
|
$
|
|
|
|
|
120,301
|
|
|
$
|
20.75
|
|
|
|
607,555
|
|
|
$
|
23.54
|
|
Options forfeited
|
|
|
|
|
|
$
|
|
|
|
|
(265
|
)
|
|
$
|
8.00
|
|
|
|
(275,593
|
)
|
|
$
|
14.96
|
|
Options exercised
|
|
|
(559,500
|
)
|
|
$
|
10.33
|
|
|
|
(694,857
|
)
|
|
$
|
8.80
|
|
|
|
(612,360
|
)
|
|
$
|
8.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
1,597,003
|
|
|
$
|
15.43
|
|
|
|
2,156,503
|
|
|
$
|
14.11
|
|
|
|
2,731,324
|
|
|
$
|
12.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at end of period
|
|
|
1,221,665
|
|
|
$
|
13.63
|
|
|
|
1,460,588
|
|
|
$
|
11.00
|
|
|
|
1,567,389
|
|
|
$
|
9.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period
|
|
|
816,825
|
|
|
$
|
16.33
|
|
|
|
635,861
|
|
|
$
|
14.67
|
|
|
|
517,019
|
|
|
$
|
11.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-19
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes information about the
Companys vested and exercisable stock options outstanding
at December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
Range of
|
|
Number
|
|
|
Remaining
|
|
|
Average
|
|
|
|
|
Exercise
|
|
Vested and
|
|
|
Contractual
|
|
|
Exercise
|
|
|
Intrinsic
|
|
Prices
|
|
Exercisable
|
|
|
Life
|
|
|
Price
|
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Vested options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$8.00
|
|
|
519,381
|
|
|
|
1.61 years
|
|
|
$
|
8.00
|
|
|
$
|
41,379
|
|
$12.00
|
|
|
91,124
|
|
|
|
4.05 years
|
|
|
$
|
12.00
|
|
|
|
6,895
|
|
$12.50 - $15.50
|
|
|
311,250
|
|
|
|
5.87 years
|
|
|
$
|
14.49
|
|
|
|
22,778
|
|
$20.00 - $23.00
|
|
|
258,121
|
|
|
|
7.31 years
|
|
|
$
|
21.65
|
|
|
|
17,041
|
|
$28.00 - $37.27
|
|
|
41,789
|
|
|
|
7.43 years
|
|
|
$
|
31.24
|
|
|
|
2,358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,221,665
|
|
|
|
4.28 years
|
|
|
$
|
13.63
|
|
|
$
|
90,451
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$8.00
|
|
|
132,369
|
|
|
|
3.49 years
|
|
|
$
|
8.00
|
|
|
$
|
10,546
|
|
$12.00
|
|
|
73,296
|
|
|
|
4.79 years
|
|
|
$
|
12.00
|
|
|
|
5,546
|
|
$12.50 - $15.50
|
|
|
311,250
|
|
|
|
5.87 years
|
|
|
$
|
14.49
|
|
|
|
22,778
|
|
$20.00 - $23.00
|
|
|
258,121
|
|
|
|
7.31 years
|
|
|
$
|
21.65
|
|
|
|
17,041
|
|
$28.00 - $37.27
|
|
|
41,789
|
|
|
|
7.43 years
|
|
|
$
|
31.24
|
|
|
|
2,358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
816,825
|
|
|
|
5.92 years
|
|
|
$
|
16.33
|
|
|
$
|
58,269
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$8.00
|
|
|
960,669
|
|
|
|
2.06 years
|
|
|
$
|
8.00
|
|
|
$
|
35,449
|
|
$12.00
|
|
|
116,728
|
|
|
|
4.45 years
|
|
|
$
|
12.00
|
|
|
|
3,840
|
|
$12.50 - $15.50
|
|
|
245,000
|
|
|
|
6.73 years
|
|
|
$
|
14.80
|
|
|
|
7,374
|
|
$20.00 - $23.00
|
|
|
104,625
|
|
|
|
8.18 years
|
|
|
$
|
21.86
|
|
|
|
2,411
|
|
$28.00 - $37.27
|
|
|
33,566
|
|
|
|
8.50 years
|
|
|
$
|
31.81
|
|
|
|
440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,460,588
|
|
|
|
3.62 years
|
|
|
$
|
11.00
|
|
|
$
|
49,514
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$8.00
|
|
|
171,903
|
|
|
|
4.62 years
|
|
|
$
|
8.00
|
|
|
$
|
6,343
|
|
$12.00
|
|
|
80,767
|
|
|
|
5.76 years
|
|
|
$
|
12.00
|
|
|
|
2,657
|
|
$12.50 - $15.50
|
|
|
245,000
|
|
|
|
6.73 years
|
|
|
$
|
14.80
|
|
|
|
7,374
|
|
$20.00 - $23.00
|
|
|
104,625
|
|
|
|
8.18 years
|
|
|
$
|
21.86
|
|
|
|
2,411
|
|
$28.00 - $37.27
|
|
|
33,566
|
|
|
|
8.50 years
|
|
|
$
|
31.81
|
|
|
|
440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
635,861
|
|
|
|
6.37 years
|
|
|
$
|
14.67
|
|
|
$
|
19,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$8.00
|
|
|
1,232,647
|
|
|
|
2.58 years
|
|
|
$
|
8.00
|
|
|
$
|
18,268
|
|
$12.00
|
|
|
143,492
|
|
|
|
4.99 years
|
|
|
$
|
12.00
|
|
|
|
1,553
|
|
$12.50 - $15.50
|
|
|
191,250
|
|
|
|
7.78 years
|
|
|
$
|
14.68
|
|
|
|
1,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,567,389
|
|
|
|
3.43 years
|
|
|
$
|
9.18
|
|
|
$
|
21,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-20
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
Range of
|
|
Number
|
|
|
Remaining
|
|
|
Average
|
|
|
|
|
Exercise
|
|
Vested and
|
|
|
Contractual
|
|
|
Exercise
|
|
|
Intrinsic
|
|
Prices
|
|
Exercisable
|
|
|
Life
|
|
|
Price
|
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Exercisable options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$8.00
|
|
|
236,227
|
|
|
|
5.62 years
|
|
|
$
|
8.00
|
|
|
$
|
3,501
|
|
$12.00
|
|
|
89,542
|
|
|
|
6.78 years
|
|
|
$
|
12.00
|
|
|
|
969
|
|
$12.50 - $15.50
|
|
|
191,250
|
|
|
|
7.78 years
|
|
|
$
|
14.68
|
|
|
|
1,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
517,019
|
|
|
|
6.62 years
|
|
|
$
|
11.16
|
|
|
$
|
6,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes information about stock-based
compensation for options for the years ended December 31,
2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Grant date fair value for awards during the period:
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee grants
|
|
$
|
|
|
|
$
|
50
|
|
|
$
|
580
|
|
Officer and director grants(a)
|
|
|
|
|
|
|
4,923
|
|
|
|
5,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
4,973
|
|
|
$
|
6,255
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense from stock
options:
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee grants
|
|
$
|
153
|
|
|
$
|
258
|
|
|
$
|
181
|
|
Officer and director grants(a)
|
|
|
2,500
|
|
|
|
4,027
|
|
|
|
2,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,653
|
|
|
$
|
4,285
|
|
|
$
|
3,101
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes and other information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit related to stock options
|
|
$
|
1,014
|
|
|
$
|
1,614
|
|
|
$
|
1,990
|
|
Deductions in current taxable income related to stock options
exercised
|
|
$
|
25,124
|
|
|
$
|
14,414
|
|
|
$
|
10,756
|
|
|
|
|
(a) |
|
The year ended December 31, 2009 includes effects of
modifications to certain stock-based awards, see further
discussion below. |
In calculating the compensation expense for stock options
granted during the years ended December 31, 2009 and 2008,
the Company estimated the fair value of each grant using the
Black-Scholes option-pricing model. Assumptions utilized in the
model are shown below.
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
2008
|
|
Risk-free interest rate
|
|
|
2.47
|
%
|
|
|
3.18
|
%
|
Expected term (years)
|
|
|
6.25
|
|
|
|
6.21
|
|
Expected volatility
|
|
|
63.19
|
%
|
|
|
38.88
|
%
|
Expected dividend yield
|
|
|
|
|
|
|
|
|
The Company used the simplified method that is accepted by the
SEC staff to calculate the expected term for stock options
granted during the years ended December 31, 2009 and 2008,
since it did not have sufficient historical exercise data to
provide a reasonable basis upon which to estimate expected term
due to the limited period of time its shares of common stock
have been publicly traded. Expected volatilities are based on a
combination of historical and implied volatilities of comparable
companies.
F-21
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Modification of stock-based
awards. David W. Copeland, the Companys
former Vice President, General Counsel and Corporate Secretary,
retired December 31, 2010. Mr. Copeland stepped down
from such positions on November 5, 2009, but remained with
the Company as Senior Counsel until his retirement. As part of
Mr. Copelands retirement agreement, all of
Mr. Copelands stock-based awards were modified to
permit full vesting on his retirement date. As a result of this
modification, the Company (i) recognized approximately
$0.5 million of stock-based compensation and a reduction of
approximately $5,000 during the years ended December 31,
2010 and 2009, respectively, and (ii) will recognize a
reduction in stock-based compensation of approximately
$0.1 million in future periods.
Steven L. Beal, the Companys former President and Chief
Operating Officer, retired from such positions on June 30,
2009. Mr. Beal began serving as a consultant on
July 1, 2009; see Note N. As part of the consulting
agreement, certain of Mr. Beals stock-based awards
were modified to permit vesting and exercise under the original
terms of the stock-based awards as if Mr. Beal was still an
employee of the Company while he is performing consulting
services for the Company. As a result of this modification, the
Company (i) recognized approximately $0.7 million and
$0.8 million of stock-based compensation during the years
ended December 31, 2010 and 2009 and (ii) will
recognize additional stock-based compensation of approximately
$0.2 million in future periods.
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
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 a past
business 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 a past
business combination on substantially the same terms, except
such officers were not offered the $0.50 per share payment.
In addition, the Companys 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 would be recorded during the period from
November 8, 2007 to December 31, 2007 and during the
years ending December 31, 2008, 2009 and 2010.
F-22
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted
|
|
|
Stock
|
|
|
|
|
|
|
Stock
|
|
|
Options
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
2011
|
|
$
|
3,575
|
|
|
$
|
501
|
|
|
$
|
4,076
|
|
2012
|
|
|
11,730
|
|
|
|
879
|
|
|
|
12,609
|
|
2013
|
|
|
8,269
|
|
|
|
184
|
|
|
|
8,453
|
|
2014
|
|
|
5,620
|
|
|
|
15
|
|
|
|
5,635
|
|
2015 and thereafter
|
|
|
3,112
|
|
|
|
|
|
|
|
3,112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
32,306
|
|
|
$
|
1,579
|
|
|
$
|
33,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note H.
|
Disclosures
about fair value of financial instruments
|
The Company uses a valuation framework based upon inputs that
market participants use in pricing an asset or liability, which
are classified into two categories: observable inputs and
unobservable inputs. Observable inputs represent market data
obtained from independent sources, whereas unobservable inputs
reflect a companys own market assumptions, which are used
if observable inputs are not reasonably available without undue
cost and effort. These two types of inputs are further
prioritized into the following fair value input hierarchy:
|
|
|
|
Level 1:
|
Unadjusted quoted prices in active markets that are accessible
at the measurement date for identical, unrestricted assets or
liabilities. The Company considers active markets to be those in
which transactions for the assets or liabilities occur in
sufficient frequency and volume to provide pricing information
on an ongoing basis.
|
|
|
Level 2:
|
Quoted prices in markets that are not active, or inputs which
are observable, either directly or indirectly, for substantially
the full term of the asset or liability. This category includes
those derivative instruments that the Company values using
observable market data. Substantially all of these inputs are
observable in the marketplace throughout the full term of the
derivative instrument, can be derived from observable data, or
supported by observable levels at which transactions are
executed in the marketplace. Level 2 instruments primarily
include non-exchange traded derivatives such as
over-the-counter
commodity price swaps, basis swaps, investments and interest
rate swaps. The Companys valuation models are primarily
industry-standard models that consider various inputs including:
(i) quoted forward prices for commodities, (ii) time
value and (iii) current market and contractual prices for
the underlying instruments, as well as other relevant economic
measures. The Company utilizes its counterparties
valuations to assess the reasonableness of its prices and
valuation techniques.
|
|
|
Level 3:
|
Measured based on prices or valuation models that require inputs
that are both significant to the fair value measurement and less
observable from objective sources (i.e., supported by
little or no market activity). Level 3 instruments
primarily include derivative instruments, such as commodity
price collars and floors, as well as investments. The
Companys valuation models are primarily industry-standard
models that consider various inputs including: (i) quoted
forward prices for commodities, (ii) time value,
(iii) volatility factors and (iv) current market and
contractual prices for the underlying instruments, as well as
other relevant economic measures. Although the Company utilizes
its counterparties valuations to assess the reasonableness
of our prices and valuation techniques, the Company does not
have sufficient corroborating market evidence to support
classifying these assets and liabilities as Level 2.
|
F-23
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The fair value input hierarchy level to which an asset or
liability measurement in its entirety falls is determined based
on the lowest level input that is significant to the measurement
in its entirety. The following table presents the Companys
assets and liabilities that are measured at fair value on a
recurring basis at December 31, 2010, for each of the fair
value hierarchy levels:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at Reporting Date Using
|
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
Quoted Prices in
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
|
Active Markets for
|
|
|
Observable
|
|
|
Unobservable
|
|
|
Fair Value at
|
|
|
|
Identical Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
December 31,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
$
|
|
|
|
$
|
49,519
|
|
|
$
|
|
|
|
$
|
49,519
|
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
2,481
|
|
|
|
2,481
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49,519
|
|
|
|
2,481
|
|
|
|
52,000
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
|
|
|
|
|
(183,028
|
)
|
|
|
|
|
|
|
(183,028
|
)
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
(3,552
|
)
|
|
|
|
|
|
|
(3,552
|
)
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
(5,754
|
)
|
|
|
|
|
|
|
(5,754
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(192,334
|
)
|
|
|
|
|
|
|
(192,334
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial assets (liabilities)
|
|
$
|
|
|
|
$
|
(142,815
|
)
|
|
$
|
2,481
|
|
|
$
|
(140,334
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth a reconciliation of changes in
the fair value of financial assets (liabilities) classified as
Level 3 in the fair value hierarchy:
|
|
|
|
|
|
|
(In thousands)
|
|
|
Balance at December 31, 2009
|
|
$
|
(945
|
)
|
Realized and unrealized losses
|
|
|
9,862
|
|
Settlements, net
|
|
|
(6,436
|
)
|
|
|
|
|
|
Balance at December 31, 2010
|
|
$
|
2,481
|
|
|
|
|
|
|
Total losses for the period included in earnings attributable to
the change in unrealized losses relating to assets (liabilities)
still held at the reporting date
|
|
$
|
3,426
|
|
|
|
|
|
|
F-24
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Assets
and Liabilities Measured at Fair Value on a Recurring
Basis
The following table presents the carrying amounts and fair
values of the Companys financial instruments at
December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
December 31, 2009
|
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
|
Value
|
|
Value
|
|
Value
|
|
Value
|
|
|
(In thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
$
|
9,088
|
|
|
$
|
9,088
|
|
|
$
|
24,923
|
|
|
$
|
24,923
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
$
|
149,422
|
|
|
$
|
149,422
|
|
|
$
|
91,756
|
|
|
$
|
91,756
|
|
Credit facility
|
|
$
|
613,500
|
|
|
$
|
606,042
|
|
|
$
|
550,000
|
|
|
$
|
528,849
|
|
8.625% senior notes due 2017
|
|
$
|
296,219
|
|
|
$
|
322,879
|
|
|
$
|
295,836
|
|
|
$
|
315,000
|
|
8.0% senior notes due 2018
|
|
$
|
158,802
|
|
|
$
|
162,772
|
|
|
$
|
|
|
|
$
|
|
|
7.0% senior notes due 2021
|
|
$
|
600,000
|
|
|
$
|
615,000
|
|
|
$
|
|
|
|
$
|
|
|
Cash and cash equivalents, accounts receivable, other current
assets, accounts payable, interest payable and other current
liabilities. The carrying amounts approximate
fair value due to the short maturity of these instruments.
Credit facility. The fair value of the
Companys credit facility is estimated by discounting the
principal and interest payments at the Companys credit
adjusted discount rate at the reporting date.
Senior notes. The fair values of the
Companys 8.625% and 7.0% senior notes are based on
quoted market prices. The fair value of the $150 million
8.0% unsecured senior note due 2018 issued to Marbob is based on
a risk-adjusted quoted market price of similar publicly traded
debt securities.
Derivative instruments. The fair value of the
Companys derivative instruments are estimated by
management considering various factors, including closing
exchange and
over-the-counter
quotations and the time value of the underlying commitments.
Financial assets and liabilities are classified based on the
lowest level of input that is significant to the fair value
measurement. The Companys assessment of the significance
of a particular input to the fair value measurement requires
judgment, and may affect the valuation of the fair value of
assets and liabilities and their placement within the fair value
hierarchy levels. The following table (i) summarizes the
valuation of each of the Companys financial instruments by
required pricing levels and (ii) summarizes the gross fair
value by the
F-25
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
appropriate balance sheet classification, even when the
derivative instruments are subject to netting arrangements and
qualify for net presentation in the Companys consolidated
balance sheets at December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
Total
|
|
|
|
Quoted Prices in
|
|
|
Other
|
|
|
Significant
|
|
|
Fair Value
|
|
|
|
Active Markets for
|
|
|
Observable
|
|
|
Unobservable
|
|
|
at
|
|
|
|
Identical Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
December 31,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
2010
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Assets (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
$
|
|
|
|
$
|
32,877
|
|
|
$
|
|
|
|
$
|
32,877
|
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
2,481
|
|
|
|
2,481
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32,877
|
|
|
|
2,481
|
|
|
|
35,358
|
|
Noncurrent:(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
|
|
|
|
|
16,642
|
|
|
|
|
|
|
|
16,642
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,642
|
|
|
|
|
|
|
|
16,642
|
|
Liabilities(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
|
|
|
|
|
(118,131
|
)
|
|
|
|
|
|
|
(118,131
|
)
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
(3,552
|
)
|
|
|
|
|
|
|
(3,552
|
)
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
(4,595
|
)
|
|
|
|
|
|
|
(4,595
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(126,278
|
)
|
|
|
|
|
|
|
(126,278
|
)
|
Noncurrent:(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
|
|
|
|
|
(64,897
|
)
|
|
|
|
|
|
|
(64,897
|
)
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
(1,159
|
)
|
|
|
|
|
|
|
(1,159
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(66,056
|
)
|
|
|
|
|
|
|
(66,056
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial assets (liabilities)
|
|
$
|
|
|
|
$
|
(142,815
|
)
|
|
$
|
2,481
|
|
|
$
|
(140,334
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) Total current financial liabilities, gross basis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(90,920
|
)
|
(c) Total noncurrent financial liabilities, gross basis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(49,414
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(140,334
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-26
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
Total
|
|
|
|
Quoted Prices in
|
|
|
Other
|
|
|
Significant
|
|
|
Fair Value
|
|
|
|
Active Markets for
|
|
|
Observable
|
|
|
Unobservable
|
|
|
at
|
|
|
|
Identical Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
December 31,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
2009
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Assets (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
$
|
|
|
|
$
|
13,850
|
|
|
$
|
|
|
|
$
|
13,850
|
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
134
|
|
|
|
134
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,850
|
|
|
|
134
|
|
|
|
13,984
|
|
Noncurrent:(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
|
|
|
|
|
35,016
|
|
|
|
|
|
|
|
35,016
|
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
1,369
|
|
|
|
|
|
|
|
1,369
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36,385
|
|
|
|
|
|
|
|
36,385
|
|
Liabilities(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
|
|
|
|
|
(65,351
|
)
|
|
|
|
|
|
|
(65,351
|
)
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
(5,254
|
)
|
|
|
|
|
|
|
(5,254
|
)
|
Interest rate derivative swap contracts
|
|
|
|
|
|
|
(3,870
|
)
|
|
|
|
|
|
|
(3,870
|
)
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
(619
|
)
|
|
|
(619
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(74,475
|
)
|
|
|
(619
|
)
|
|
|
(75,094
|
)
|
Noncurrent:(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
|
|
|
|
|
(38,259
|
)
|
|
|
|
|
|
|
(38,259
|
)
|
Commodity derivative basis swap contracts
|
|
|
|
|
|
|
(3,389
|
)
|
|
|
|
|
|
|
(3,389
|
)
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
|
|
|
|
(460
|
)
|
|
|
(460
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(41,648
|
)
|
|
|
(460
|
)
|
|
|
(42,108
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial liabilities
|
|
$
|
|
|
|
$
|
(65,888
|
)
|
|
$
|
(945
|
)
|
|
$
|
(66,833
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) Total current financial liabilities, gross basis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(61,110
|
)
|
(c) Total noncurrent financial liabilities, gross basis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,723
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(66,833
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-27
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(a) |
|
The fair value of derivative instruments reported in the
Companys consolidated balance sheets are subject to
netting arrangements and qualify for net presentation. The
following table reports the net basis derivative fair values as
reported in the consolidated balance sheets at December 31,
2010 and 2009: |
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Consolidated Balance Sheet Classification:
|
|
|
|
|
|
|
|
|
Current derivative contracts:
|
|
|
|
|
|
|
|
|
Assets
|
|
$
|
6,855
|
|
|
$
|
1,309
|
|
Liabilities
|
|
|
(97,775
|
)
|
|
|
(62,419
|
)
|
|
|
|
|
|
|
|
|
|
Net current
|
|
$
|
(90,920
|
)
|
|
$
|
(61,110
|
)
|
|
|
|
|
|
|
|
|
|
Noncurrent derivative contracts:
|
|
|
|
|
|
|
|
|
Assets
|
|
$
|
2,233
|
|
|
$
|
23,614
|
|
Liabilities
|
|
|
(51,647
|
)
|
|
|
(29,337
|
)
|
|
|
|
|
|
|
|
|
|
Net noncurrent
|
|
$
|
(49,414
|
)
|
|
$
|
(5,723
|
)
|
|
|
|
|
|
|
|
|
|
Assets
and Liabilities Measured at Fair Value on a Nonrecurring
Basis
Certain assets and liabilities are reported at fair value on a
nonrecurring basis in the Companys consolidated balance
sheets. The following methods and assumptions were used to
estimate the fair values:
Impairments of long-lived assets The Company
reviews its long-lived assets to be held and used, including
proved oil and natural gas properties, whenever events or
circumstances indicate that the carrying value of those assets
may not be recoverable. An impairment loss is indicated if the
sum of the expected undiscounted future net cash flows is less
than the carrying amount of the assets. In this circumstance,
the Company recognizes an impairment loss for the amount by
which the carrying amount of the asset exceeds the estimated
fair value of the asset. The Company reviews its oil and natural
gas properties by amortization base or by individual well for
those wells not constituting part of an amortization base. For
each property determined to be impaired, an impairment loss
equal to the difference between the carrying value of the
properties and the estimated fair value (discounted future cash
flows) of the properties would be recognized at that time.
Estimating future cash flows involves the use of judgments,
including estimation of the proved and unproved oil and natural
gas reserve quantities, timing of development and production,
expected future commodity prices, capital expenditures and
production costs.
The Company periodically reviews its proved oil and natural gas
properties that are sensitive to oil and natural gas prices for
impairment. Impairment expense is caused primarily due to
declines in commodity prices and well performance. The following
table reports the carrying amounts, estimated fair values and
impairment expense of long-lived assets for continuing and
discontinued operations for the years ended December 31,
2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying
|
|
Estimated
|
|
Impairment
|
|
|
Amount
|
|
Fair Value
|
|
Expense
|
|
|
(In thousands)
|
|
Year ended December 31, 2010
|
|
$
|
27,888
|
|
|
$
|
12,707
|
|
|
$
|
15,181
|
|
Year ended December 31, 2009
|
|
$
|
19,884
|
|
|
$
|
7,687
|
|
|
$
|
12,197
|
|
Year ended December 31, 2008
|
|
$
|
31,792
|
|
|
$
|
13,375
|
|
|
$
|
18,417
|
|
Asset Retirement Obligations The Company
estimates the fair value of Asset Retirement Obligations
(AROs) based on discounted cash flow projections
using numerous estimates, assumptions and judgments
F-28
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
regarding such factors as the existence of a legal obligation
for an ARO; amounts and timing of settlements; the
credit-adjusted risk-free rate to be used; and inflation rates.
See Note E for a summary of changes in AROs.
The following table sets forth the measurement information for
assets measured at fair value on a nonrecurring basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
Quoted Prices in
|
|
Other
|
|
Significant
|
|
|
|
|
Active Markets for
|
|
Observable
|
|
Unobservable
|
|
Total
|
|
|
Identical Assets
|
|
Inputs
|
|
Inputs
|
|
Impairment
|
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
Loss
|
|
|
(In thousands)
|
|
Year ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
12,707
|
|
|
$
|
15,181
|
|
Asset retirement obligations incurred in current period
|
|
|
|
|
|
|
|
|
|
|
11,327
|
|
|
|
|
|
Year ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7,687
|
|
|
$
|
12,197
|
|
Asset retirement obligations incurred in current period
|
|
|
|
|
|
|
|
|
|
|
2,014
|
|
|
|
|
|
Year ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
13,375
|
|
|
$
|
18,417
|
|
Asset retirement obligations incurred in current period
|
|
|
|
|
|
|
|
|
|
|
8,259
|
|
|
|
|
|
|
|
Note I.
|
Derivative
financial instruments
|
The Company uses derivative financial contracts to manage
exposures to commodity price and interest rate fluctuations.
Commodity hedges are used to (i) reduce the effect of the
volatility of price changes on the oil and natural gas the
Company produces and sells, (ii) support the Companys
capital budget and expenditure plans and (iii) support the
economics associated with acquisitions. Interest rate hedges are
used to mitigate the cash flow risk associated with rising
interest rates. The Company does not enter into derivative
financial instruments for speculative or trading purposes. The
Company also may enter into physical delivery contracts to
effectively provide commodity price hedges. Because these
contracts are not expected to be net cash settled, they are
considered to be normal sales contracts and not derivatives.
Therefore, these contracts are not recorded in the
Companys consolidated financial statements.
Currently, the Company does not designate its derivative
instruments to qualify for hedge accounting. Accordingly, the
Company reflects changes in the fair value of its derivative
instruments in its statements of operations as they occur. All
of the Companys remaining hedges that historically
qualified for hedge accounting or were dedesignated from hedge
accounting were settled in 2008.
During 2007, the Company determined that all of its natural gas
commodity contracts no longer qualified as hedges (referred to
as dedesignated cash flow hedges). The Company
discontinued hedge accounting from then forward for all
derivative contracts.
F-29
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
New commodity derivative contracts in
2010. During the year ended December 31,
2010, the Company entered into additional commodity derivative
contracts to hedge a portion of its estimated future production.
The following table summarizes information about these
additional commodity derivative contracts for the year ended
December 31, 2010. When aggregating multiple contracts, the
weighted average contract price is disclosed.
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
Index
|
|
Contract
|
|
|
Volume
|
|
Price
|
|
Period
|
|
Oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
670,000
|
|
|
$83.72(a)
|
|
|
1/1/10
|
- 12/31/10
|
Price swap
|
|
|
195,000
|
|
|
$76.85(a)
|
|
|
3/1/10
|
- 12/31/10
|
Price swap
|
|
|
1,463,000
|
|
|
$88.63(a)
|
|
|
5/1/10
|
- 12/31/10
|
Price swap
|
|
|
378,000
|
|
|
$85.62(a)
|
|
|
1/1/11
|
- 6/30/11
|
Price swap
|
|
|
200,000
|
|
|
$83.47(a)
|
|
|
1/1/11
|
- 11/30/11
|
Price swap
|
|
|
6,282,000
|
|
|
$85.49(a)
|
|
|
1/1/11
|
- 12/31/11
|
Price swap
|
|
|
96,000
|
|
|
$86.80(a)
|
|
|
7/1/11
|
- 12/31/11
|
Price swap
|
|
|
540,000
|
|
|
$86.84(a)
|
|
|
1/1/12
|
- 6/30/12
|
Price swap
|
|
|
389,000
|
|
|
$86.95(a)
|
|
|
1/1/12
|
- 11/30/12
|
Price swap
|
|
|
5,487,000
|
|
|
$88.21(a)
|
|
|
1/1/12
|
- 12/31/12
|
Price swap
|
|
|
261,000
|
|
|
$82.50(a)
|
|
|
7/1/12
|
- 12/31/12
|
Price swap
|
|
|
1,380,000
|
|
|
$82.58(a)
|
|
|
1/1/13
|
- 12/31/13
|
Price swap
|
|
|
1,248,000
|
|
|
$83.94(a)
|
|
|
1/1/14
|
- 12/31/14
|
Price swap
|
|
|
600,000
|
|
|
$84.50(a)
|
|
|
1/1/15
|
- 6/30/15
|
Natural gas (volumes in MMBtus):
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
418,000
|
|
|
$5.99(b)
|
|
|
2/1/10
|
- 12/31/10
|
Price swap
|
|
|
1,250,000
|
|
|
$5.55(b)
|
|
|
3/1/10
|
- 12/31/10
|
Price swap
|
|
|
5,076,000
|
|
|
$6.14(b)
|
|
|
1/1/11
|
- 12/31/11
|
Price swap
|
|
|
300,000
|
|
|
$6.54(b)
|
|
|
1/1/12
|
- 12/31/12
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the
NYMEX-West Texas Intermediate monthly average futures price. |
|
(b) |
|
The index prices for the natural gas price swaps are based on
the NYMEX-Henry Hub last trading day futures price. |
F-30
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Commodity derivative contracts at December 31,
2010. The following table sets forth the
Companys outstanding derivative contracts at
December 31, 2010. When aggregating multiple contracts, the
weighted average contract price is disclosed.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Total
|
|
Oil Swaps: (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
2,879,436
|
|
|
|
2,601,436
|
|
|
|
2,395,436
|
|
|
|
2,238,436
|
|
|
|
10,114,744
|
|
Price per Bbl
|
|
$
|
82.83
|
|
|
$
|
82.88
|
|
|
$
|
83.06
|
|
|
$
|
83.20
|
|
|
$
|
82.98
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
2,056,500
|
|
|
|
1,985,500
|
|
|
|
1,592,500
|
|
|
|
1,546,500
|
|
|
|
7,181,000
|
|
Price per Bbl
|
|
$
|
90.01
|
|
|
$
|
90.17
|
|
|
$
|
91.19
|
|
|
$
|
91.38
|
|
|
$
|
90.61
|
|
2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
345,000
|
|
|
|
345,000
|
|
|
|
345,000
|
|
|
|
345,000
|
|
|
|
1,380,000
|
|
Price per Bbl
|
|
$
|
82.58
|
|
|
$
|
82.58
|
|
|
$
|
82.58
|
|
|
$
|
82.58
|
|
|
$
|
82.58
|
|
2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
312,000
|
|
|
|
312,000
|
|
|
|
312,000
|
|
|
|
312,000
|
|
|
|
1,248,000
|
|
Price per Bbl
|
|
$
|
83.94
|
|
|
$
|
83.94
|
|
|
$
|
83.94
|
|
|
$
|
83.94
|
|
|
$
|
83.94
|
|
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
300,000
|
|
|
|
300,000
|
|
|
|
|
|
|
|
|
|
|
|
600,000
|
|
Price per Bbl
|
|
$
|
84.50
|
|
|
$
|
84.50
|
|
|
|
|
|
|
|
|
|
|
$
|
84.50
|
|
Natural Gas Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
1,569,000
|
|
|
|
3,069,000
|
|
|
|
3,069,000
|
|
|
|
3,069,000
|
|
|
|
10,776,000
|
|
Price per MMBtu
|
|
$
|
6.36
|
|
|
$
|
6.62
|
|
|
$
|
6.62
|
|
|
$
|
6.62
|
|
|
$
|
6.58
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
75,000
|
|
|
|
75,000
|
|
|
|
75,000
|
|
|
|
75,000
|
|
|
|
300,000
|
|
Price per MMBtu
|
|
$
|
6.54
|
|
|
$
|
6.54
|
|
|
$
|
6.54
|
|
|
$
|
6.54
|
|
|
$
|
6.54
|
|
Natural Gas Collars: (b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
1,500,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,500,000
|
|
Price per MMBtu
|
|
$
|
6.00 - $6.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6.00 - $6.80
|
|
Natural Gas Basis Swaps: (c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
1,800,000
|
|
|
|
1,800,000
|
|
|
|
1,800,000
|
|
|
|
1,800,000
|
|
|
|
7,200,000
|
|
Price per MMBtu
|
|
$
|
0.87
|
|
|
$
|
0.76
|
|
|
$
|
0.76
|
|
|
$
|
0.76
|
|
|
$
|
0.79
|
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the
NYMEX-West Texas Intermediate monthly average futures price. |
|
(b) |
|
The index prices for the natural gas price swaps and collars are
based on the NYMEX-Henry Hub last trading day futures price. |
|
(c) |
|
The basis differential between the El Paso Permian delivery
point and NYMEX Henry Hub delivery point. |
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.
F-31
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Companys reported oil and natural gas revenue includes
the effects of oil quality and Btu content, gathering and
transportation costs, natural gas processing and shrinkage, and
the net effect of the commodity hedges that qualified for cash
flow hedge accounting. The following table summarizes the gains
and losses reported in earnings related to the commodity and
interest rate derivative instruments and the net change in AOCI
for the years ended December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Decrease in oil and natural gas revenue from derivative
activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments on cash flow hedges in oil sales
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(30,591
|
)
|
Dedesignated cash flow hedges reclassified from AOCI in natural
gas sales
|
|
|
|
|
|
|
|
|
|
|
(696
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total decrease in oil and natural gas revenue from derivative
activity
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(31,287
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as
hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market
gain (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
(93,595
|
)
|
|
$
|
(229,896
|
)
|
|
$
|
253,960
|
|
Natural gas
|
|
|
23,347
|
|
|
|
(7,959
|
)
|
|
|
3,347
|
|
Interest rate derivatives
|
|
|
(3,253
|
)
|
|
|
(1,418
|
)
|
|
|
(1,083
|
)
|
Cash (payments on) receipts from derivatives not designated
as hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
(26,281
|
)
|
|
|
74,796
|
|
|
|
(7,780
|
)
|
Natural gas
|
|
|
17,414
|
|
|
|
10,955
|
|
|
|
1,426
|
|
Interest rate derivatives
|
|
|
(4,957
|
)
|
|
|
(3,335
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivatives not designated as hedges
|
|
$
|
(87,325
|
)
|
|
$
|
(156,857
|
)
|
|
$
|
249,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) from ineffective portion of cash flow
hedges
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,336
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market
loss of cash flow hedges
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(7,985
|
)
|
Reclassification adjustment of losses to earnings
|
|
|
|
|
|
|
|
|
|
|
30,591
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change, before income taxes
|
|
|
|
|
|
|
|
|
|
|
22,606
|
|
Income tax effect
|
|
|
|
|
|
|
|
|
|
|
(8,835
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change, net of income taxes
|
|
$
|
|
|
|
$
|
|
|
|
$
|
13,771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dedesignated cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification adjustment of losses to earnings
|
|
$
|
|
|
|
$
|
|
|
|
$
|
696
|
|
Income tax effect
|
|
|
|
|
|
|
|
|
|
|
(272
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change, net of income taxes
|
|
$
|
|
|
|
$
|
|
|
|
$
|
424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All of the Companys commodity derivative contracts at
December 31, 2010 are expected to settle by
December 31, 2015. All the Companys commodity
derivative contracts previously accounted for as cash flow
hedges and dedesignated as hedges were settled on
December 31, 2008.
F-32
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Post-2010 commodity derivative
contracts. After December 31, 2010 and
through February 23, 2011, the Company entered into the
following oil and natural gas price swaps to hedge an additional
portion of its estimated future production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
Index
|
|
Contract
|
|
|
Volume
|
|
Price
|
|
Period
|
|
Oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
115,000
|
|
|
$96.65(a)
|
|
|
3/1/11
|
- 11/30/11
|
Price swap
|
|
|
200,000
|
|
|
$97.20(a)
|
|
|
3/1/11
|
- 12/31/11
|
Price swap
|
|
|
45,000
|
|
|
$99.35(a)
|
|
|
1/1/12
|
- 3/31/12
|
Price swap
|
|
|
180,000
|
|
|
$99.00(a)
|
|
|
1/1/12
|
- 12/31/12
|
Price swap
|
|
|
300,000
|
|
|
$99.00(a)
|
|
|
7/1/12
|
- 9/30/12
|
Price swap
|
|
|
255,000
|
|
|
$99.00(a)
|
|
|
10/1/12
|
- 12/31/12
|
Price swap
|
|
|
1,080,000
|
|
|
$99.88(a)
|
|
|
1/1/13
|
- 12/31/13
|
|
|
|
(a) |
|
The index price for the oil price swap is based on the
NYMEX-West Texas Intermediate monthly average futures price. |
The Companys debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Credit facility
|
|
$
|
613,500
|
|
|
$
|
550,000
|
|
8.625% unsecured senior notes due 2017
|
|
|
300,000
|
|
|
|
300,000
|
|
7.0% unsecured senior notes due 2021
|
|
|
600,000
|
|
|
|
|
|
8.0% unsecured senior note due 2018
|
|
|
150,000
|
|
|
|
|
|
Unamortized original issue premium (discount), net
|
|
|
5,021
|
|
|
|
(4,164
|
)
|
Less: current portion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
1,668,521
|
|
|
$
|
845,836
|
|
|
|
|
|
|
|
|
|
|
Credit facility. The Companys credit
facility, as amended (the Credit Facility), has a
maturity date of July 31, 2013. At December 31, 2010,
the Company had no letters of credit outstanding under the
Credit Facility. The Companys borrowing base is
$2.0 billion until the next scheduled borrowing base
redetermination in April 2011. 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 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, 2010) or
(ii) a Eurodollar rate (substantially equal to the London
Interbank Offered Rate). At December 31, 2010, the interest
rates of Eurodollar rate advances and JPM Prime Rate advances
varied, with interest margins ranging from 200 to 300 basis
points and 112.5 to 212.5 basis points, respectively, per
annum depending on the debt balance outstanding. At
December 31, 2010, the Company paid commitment fees on the
unused portion of the available borrowing base of 50 basis
points per annum.
The Credit Facility also includes a
same-day
advance facility under which the Company may borrow funds from
the administrative agent.
Same-day
advances cannot exceed $25 million, and the maturity dates
cannot exceed fourteen days. The interest rate on this facility
is the JPM Prime Rate plus the applicable interest margin.
F-33
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Companys obligations under the Credit Facility are
secured by a first lien on substantially all of its oil and
natural gas properties. In addition, all of the Companys
subsidiaries are guarantors and have been pledged to secure
borrowings under the Credit Facility.
The credit agreement contains various restrictive covenants and
compliance requirements which include:
|
|
|
|
|
maintenance of certain financial ratios, including
(i) maintenance of a quarterly ratio of total debt to
consolidated earnings before interest expense, income taxes,
depletion, depreciation, and amortization, exploration expense
and other noncash income and expenses to be no greater than 4.0
to 1.0, and (ii) maintenance of a ratio of current assets
to current liabilities, excluding noncash assets and liabilities
related to financial derivatives and asset retirement
obligations and including the unfunded amounts under the Credit
Facility, to be not less than 1.0 to 1.0;
|
|
|
|
limits on the incurrence of additional indebtedness and certain
types of liens;
|
|
|
|
restrictions as to mergers, combinations and dispositions of
assets; and
|
|
|
|
restrictions on the payment of cash dividends.
|
At December 31, 2010, the Company was in compliance with
all of the covenants under the Credit Facility.
8.625% unsecured senior notes. The
Companys 8.625% senior notes due 2017 (the 2017
Senior Notes) are fully and unconditionally guaranteed on
a senior unsecured basis by all of the Companys
subsidiaries. The 2017 Senior Notes will mature on
October 1, 2017, and interest is payable on the 2017 Senior
Notes each April 1 and October 1.
The Company may redeem some or all of the 2017 Senior Notes at
any time on or after October 1, 2013 at the redemption
prices specified in the indenture governing the 2017 Senior
Notes. The Company may also redeem up to 35 percent of the
2017 Senior Notes using all or a portion of the net proceeds of
certain public sales of equity interests completed before
October 1, 2012 at a redemption price as specified in the
indenture. If the Company sells certain assets or experiences
specific kinds of change of control, each as described in the
indenture, each holder of the Senior Notes will have the right
to require the Company to repurchase the 2017 Senior Notes at a
purchase price described in the indenture plus accrued and
unpaid interest, if any, to the date of repurchase.
The 2017 Senior Notes are the Companys senior unsecured
obligations, and rank equally in right of payment with all of
the Companys existing and future senior debt, and rank
senior in right of payment to all of the Companys future
subordinated debt. The 2017 Senior Notes are structurally
subordinated to all of the Companys existing and future
secured debt to the extent of the value of the collateral
securing such indebtedness.
7.0% unsecured senior notes. In December 2010,
the Company issued $600 million in principal amount of
7.0% senior notes due 2021 at 100.00 percent of par
(the 2021 Senior Notes). The 2021 Senior Notes will
mature on January 15, 2021 and interest is paid in arrears
semi-annually on January 15 and July 15 beginning July 15,
2011. The 2021 Senior Notes are fully and unconditionally
guaranteed on a senior unsecured basis by substantially all of
the Companys subsidiaries.
The Company may redeem some or all of the 2021 Senior Notes at
any time on or after January 15, 2016 at the redemption
prices specified in the indenture governing the 2021 Senior
Notes. The Company may also redeem up to 35 percent of the
2021 Senior Notes using all or a portion of the net proceeds of
certain public sales of equity interests completed before
January 15, 2014 at a redemption price as specified in the
indenture. If the Company sells certain assets or experiences
specific kinds of change of control, each as described in the
indenture, each holder of the 2021 Senior Notes will have the
right to require the Company to repurchase the 2021 Senior Notes
at a purchase price described in the indenture plus accrued and
unpaid interest, if any, to the date of repurchase.
The 2021 Senior Notes are the Companys senior unsecured
obligations, and rank equally in right of payment with all of
the Companys existing and future senior debt, and rank
senior in right of payment to all of the
F-34
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Companys future subordinated debt. The 2021 Senior Notes
are structurally subordinated to all of the Companys
existing and future secured debt to the extent of the value of
the collateral securing such indebtedness.
8.0% unsecured senior note. In October 2010,
the Company issued to Marbob an unsecured senior note (the
8.0% Note) in the aggregate principal amount of
$150 million, as partial consideration for the Marbob
Acquisition. The 8.0% Note bears interest at the rate of
8.0% per year, payable semi-annually in arrears and is payable
as to principal in a lump sum on October 7, 2018. The
Company has the option to prepay the 8.0% Note, together
with accrued interest thereon, from time to time, in whole or in
part, without penalty or premium.
Future interest expense reductions from the net original issue
premium at December 31, 2010 is as follows:
|
|
|
|
|
|
|
(In thousands)
|
|
|
2011
|
|
$
|
(465
|
)
|
2012
|
|
|
(488
|
)
|
2013
|
|
|
(511
|
)
|
2014
|
|
|
(535
|
)
|
2015
|
|
|
(560
|
)
|
Thereafter
|
|
|
(2,462
|
)
|
|
|
|
|
|
Total
|
|
$
|
(5,021
|
)
|
|
|
|
|
|
Principal maturities of long-term
debt. Principal maturities of long-term debt
outstanding at December 31, 2010 are as follows:
|
|
|
|
|
|
|
(In thousands)
|
|
|
2011
|
|
$
|
|
|
2012
|
|
|
|
|
2013
|
|
|
613,500
|
|
2014
|
|
|
|
|
2015 and thereafter
|
|
|
1,050,000
|
|
|
|
|
|
|
Total
|
|
$
|
1,663,500
|
|
|
|
|
|
|
Interest expense. The following amounts have
been incurred and charged to interest expense for the years
ended December 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Cash payments for interest
|
|
$
|
48,052
|
|
|
$
|
14,862
|
|
|
$
|
27,747
|
|
Amortization of original issue discount (premium)
|
|
|
185
|
|
|
|
102
|
|
|
|
58
|
|
Amortization of deferred loan origination costs
|
|
|
6,595
|
|
|
|
3,635
|
|
|
|
2,157
|
|
Write-off of deferred loan origination costs and original issue
discount
|
|
|
|
|
|
|
57
|
|
|
|
1,547
|
|
Net changes in accruals
|
|
|
5,439
|
|
|
|
9,702
|
|
|
|
(1,237
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest costs incurred
|
|
|
60,271
|
|
|
|
28,358
|
|
|
|
30,272
|
|
Less: capitalized interest
|
|
|
(184
|
)
|
|
|
(66
|
)
|
|
|
(1,233
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest expense
|
|
$
|
60,087
|
|
|
$
|
28,292
|
|
|
$
|
29,039
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-35
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
senior officers. The current annual salaries for the
Companys officers covered under such agreements total
approximately $3.4 million.
Indemnifications. The Company has agreed to
indemnify its directors and officers, with respect to claims and
damages arising from certain acts or omissions taken in such
capacity.
Legal actions. The Company is a party to
proceedings and claims incidental to its business. While many of
these matters involve inherent uncertainty, the Company believes
that the amount of the liability, if any, ultimately incurred
with respect to any such proceedings or claims will not have a
material adverse effect on the Companys consolidated
financial position as a whole or on its liquidity, capital
resources or future results of operations. The Company will
continue to evaluate proceedings and claims involving the
Company on a
quarter-by-quarter
basis and will establish and adjust any reserves as appropriate
to reflect its assessment of the then current status of the
matters.
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, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
Less Than
|
|
1 - 3
|
|
3 - 5
|
|
More than
|
|
|
Total
|
|
1 Year
|
|
Years
|
|
Years
|
|
5 Years
|
|
|
(In thousands)
|
|
Daywork drilling contracts with related parties(a)
|
|
$
|
1,000
|
|
|
$
|
1,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Other daywork drilling contracts
|
|
|
1,400
|
|
|
|
1,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual drilling commitments
|
|
$
|
2,400
|
|
|
$
|
2,400
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Consists of daywork drilling contracts with Silver Oak Drilling,
LLC, an affiliate of Chase Oil Corporation (Chase
Oil), a stockholder of the Company. |
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, 2010, 2009 and 2008 were
approximately $2.8 million, $2.3 million and
$1.3 million, respectively.
Future minimum lease commitments under non-cancellable operating
leases at December 31, 2010 are as follows:
|
|
|
|
|
|
|
(In thousands)
|
|
|
2011
|
|
$
|
3,471
|
|
2012
|
|
|
3,151
|
|
2013
|
|
|
2,558
|
|
2014
|
|
|
2,373
|
|
2015 and thereafter
|
|
|
3,689
|
|
|
|
|
|
|
Total
|
|
$
|
15,242
|
|
|
|
|
|
|
F-36
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company uses an asset and liability approach for financial
accounting and reporting for income taxes. The Companys
objectives of accounting for income taxes are to recognize
(i) the amount of taxes payable or refundable for the
current year and (ii) deferred tax liabilities and assets
for the future tax consequences of events that have been
recognized in its financial statements or tax returns. The
Company and its subsidiaries file a federal corporate income tax
return on a consolidated basis. The tax returns and the amount
of taxable income or loss are subject to examination by federal
and state taxing authorities.
The Company continually assesses both positive and negative
evidence to determine whether it is more likely than not that
deferred tax assets can be realized prior to their expiration.
Management monitors company-specific, oil and natural gas
industry and worldwide economic factors and assesses the
likelihood that the Companys net operating loss
carryforwards (NOLs) and other deferred tax
attributes in the United States, state, and local tax
jurisdictions will be utilized prior to their expiration. At
December 31, 2010 and 2009, the Company had no valuation
allowances related to its deferred tax assets.
At December 31, 2010, the Company did not have any
significant uncertain tax positions requiring recognition in the
financial statements. The tax years 2005 through 2009 remain
subject to examination by the major tax jurisdictions.
Income tax provision. The Companys
income tax provision (benefit) and amounts separately allocated
were attributable to the following items for the years ended
December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Income (loss) from continuing operations
|
|
$
|
122,649
|
|
|
$
|
(21,510
|
)
|
|
$
|
157,434
|
|
Income from discontinued operations
|
|
|
12,956
|
|
|
|
778
|
|
|
|
4,651
|
|
Changes in stockholders equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred hedge losses
|
|
|
|
|
|
|
|
|
|
|
(3,121
|
)
|
Net settlement losses included in earnings
|
|
|
|
|
|
|
|
|
|
|
12,228
|
|
Excess tax benefits related to stock-based compensation
|
|
|
(11,346
|
)
|
|
|
(5,212
|
)
|
|
|
(3,614
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
124,259
|
|
|
$
|
(25,944
|
)
|
|
$
|
167,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys income tax provision (benefit) attributable
to income from continuing operations consisted of the following
for the years ended December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States federal
|
|
$
|
14,678
|
|
|
$
|
5,895
|
|
|
$
|
2,708
|
|
United States state and local
|
|
|
3,041
|
|
|
|
1,737
|
|
|
|
472
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,719
|
|
|
|
7,632
|
|
|
|
3,180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States federal
|
|
|
80,284
|
|
|
|
(15,800
|
)
|
|
|
142,970
|
|
United States state and local
|
|
|
24,646
|
|
|
|
(13,342
|
)
|
|
|
11,284
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
104,930
|
|
|
|
(29,142
|
)
|
|
|
154,254
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
122,649
|
|
|
$
|
(21,510
|
)
|
|
$
|
157,434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-37
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The reconciliation between the income tax expense (benefit)
computed by multiplying pretax income (loss) from continuing
operations by the United States federal statutory rate and the
reported amounts of income tax expense (benefit) from continuing
operations is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Income (loss) at United States federal statutory rate
|
|
$
|
106,989
|
|
|
$
|
(11,563
|
)
|
|
$
|
149,680
|
|
State income taxes (net of federal tax effect)
|
|
|
9,785
|
|
|
|
(954
|
)
|
|
|
12,994
|
|
Revision of previous tax estimates
|
|
|
(1,593
|
)
|
|
|
(1,559
|
)
|
|
|
|
|
Statutory depletion
|
|
|
(179
|
)
|
|
|
(581
|
)
|
|
|
|
|
Change in effective statutory state income tax rate
|
|
|
8,278
|
|
|
|
(6,556
|
)
|
|
|
(5,671
|
)
|
Nondeductible expense & other
|
|
|
(631
|
)
|
|
|
(297
|
)
|
|
|
431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)
|
|
$
|
122,649
|
|
|
$
|
(21,510
|
)
|
|
$
|
157,434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
40.1
|
%
|
|
|
65.1
|
%
|
|
|
36.8
|
%
|
The Companys income tax provision (benefit) attributable
to income from discontinued operations consisted of the
following for the years ended December 31, 2010, 2009 and
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States federal
|
|
$
|
2,350
|
|
|
$
|
2,539
|
|
|
|
5,372
|
|
United States state and local
|
|
|
18
|
|
|
|
16
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,368
|
|
|
|
2,555
|
|
|
|
5,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States federal
|
|
|
8,921
|
|
|
|
(1,847
|
)
|
|
$
|
(1,303
|
)
|
United States state and local
|
|
|
1,667
|
|
|
|
70
|
|
|
|
533
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,588
|
|
|
|
(1,777
|
)
|
|
|
(770
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
12,956
|
|
|
$
|
778
|
|
|
$
|
4,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-38
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,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
$
|
9,147
|
|
|
$
|
6,652
|
|
Derivative instruments
|
|
|
53,650
|
|
|
|
25,186
|
|
Federal tax credit carryovers
|
|
|
463
|
|
|
|
3,495
|
|
Asset retirement obligation
|
|
|
16,564
|
|
|
|
8,575
|
|
Accrued liabilities
|
|
|
4,043
|
|
|
|
4,180
|
|
Allowance for bad debt
|
|
|
491
|
|
|
|
918
|
|
Other
|
|
|
4,142
|
|
|
|
94
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
88,500
|
|
|
|
49,100
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, principally due to differences
in basis and depletion and the deduction of intangible drilling
costs for tax purposes
|
|
|
(753,130
|
)
|
|
|
(609,268
|
)
|
Intangible asset operating rights
|
|
|
(13,371
|
)
|
|
|
(13,763
|
)
|
Other
|
|
|
(172
|
)
|
|
|
(71
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(766,673
|
)
|
|
|
(623,102
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(678,173
|
)
|
|
$
|
(574,002
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Note M.
|
Major
customers and derivative counterparties
|
Sales to major customers. The Companys
share of oil and natural 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 natural gas
production.
The following purchasers individually accounted for ten percent
or more of the consolidated oil and natural gas revenues,
including the revenues from discontinued operations and the
results of commodity hedges, during the years ended
December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
Navajo Refining Company, L.P.
|
|
|
32
|
%
|
|
|
38
|
%
|
|
|
59
|
%
|
ConocoPhillips Company
|
|
|
14
|
%
|
|
|
11
|
%
|
|
|
7
|
%
|
DCP Midstream, LP
|
|
|
12
|
%
|
|
|
13
|
%
|
|
|
18
|
%
|
Plains Marketing and Transportation Inc.
|
|
|
11
|
%
|
|
|
|
%
|
|
|
|
%
|
At December 31, 2010, the Company had receivables from
Navajo Refining Company, L.P., ConocoPhillips Company, DCP
Midstream, LP and Plains Marketing and Transportation Inc. of
$38.6 million, $25.0 million, $15.7 million and
$9.3 million, respectively, which are reflected in Accounts
receivable oil and natural 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 (i) not less
than either A- by Standard & Poors Rating Group
rating system or A3 by Moodys Investors Service, Inc.
rating system or (ii) a
F-39
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
lender to the Companys credit facility. At
December 31, 2010 and 2009, 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.
|
|
Note N.
|
Related
party transactions
|
The following tables summarize charges incurred with and
payments made to the Companys related parties and reported
in the consolidated statements of operations, as well as
outstanding payables and receivables included in the
consolidated balance sheets for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
(In thousands)
|
|
Charges incurred with Chase Oil and affiliates (a)
|
|
$
|
34,263
|
|
|
$
|
32,756
|
|
|
$
|
23,171
|
|
Working interests owned by employees: (b)
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues distributed to employees
|
|
$
|
157
|
|
|
$
|
100
|
|
|
$
|
155
|
|
Joint interest payments received from employees
|
|
$
|
464
|
|
|
$
|
141
|
|
|
$
|
635
|
|
Acquisition of oil and natural gas interests from an employee
|
|
$
|
363
|
|
|
$
|
|
|
|
$
|
|
|
Overriding royalty interests paid to Chase Oil affiliates
(c)
|
|
$
|
2,078
|
|
|
$
|
1,311
|
|
|
$
|
3,113
|
|
Royalty interests paid to a director of the Company
(d)
|
|
$
|
154
|
|
|
$
|
134
|
|
|
$
|
332
|
|
Amounts paid under consulting agreement with Steven L.
Beal(e)
|
|
$
|
254
|
|
|
$
|
126
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2010
|
|
2009
|
|
|
(In thousands)
|
|
Amounts included in accounts receivable
related parties:
|
|
|
|
|
|
|
|
|
Chase Oil and affiliates(a)
|
|
$
|
115
|
|
|
$
|
88
|
|
Working interests owned by employees(b)
|
|
$
|
54
|
|
|
$
|
128
|
|
Amounts included in accounts payable related
parties:
|
|
|
|
|
|
|
|
|
Chase Oil and affiliates(a)
|
|
$
|
771
|
|
|
$
|
11
|
|
Working interests owned by employees(b)
|
|
$
|
8
|
|
|
$
|
13
|
|
Overriding royalty interests of Chase Oil affiliates (c)
|
|
$
|
407
|
|
|
$
|
255
|
|
Royalty interests of a director of the Company(d)
|
|
$
|
11
|
|
|
$
|
12
|
|
|
|
|
(a) |
|
The Company incurred charges for services rendered in the
ordinary course of business from Chase Oil and its affiliates
including a drilling contractor, an oilfield services company, a
supply company, a drilling fluids supply company, a pipe and
tubing supplier, a fixed base operator of aircraft services and
a software company. The tables above summarize the charges
incurred as well as outstanding receivables and payables. |
|
(b) |
|
The Company purchased oil and natural gas properties from third
parties in which employees of the Company owned a working
interest. The tables above summarize the Companys
activities with these employees. During the year ended
December 31, 2010, the Company acquired oil and natural gas
interests from an employee of the Company. |
|
(c) |
|
Certain persons affiliated with Chase Oil own overriding royalty
interests in certain of the Companys properties. The
tables above summarize the amounts paid attributable to such
interests and amounts due at period end. |
F-40
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(d) |
|
Royalties are paid on certain properties, located in Andrews
County, Texas, to a partnership of which one of the
Companys directors is the general partner and owns a
3.5 percent partnership interest. The tables above
summarize the amounts paid to such partnership and amounts due
at period end. |
|
(e) |
|
On June 30, 2009, Steven L. Beal, the Companys then
president and chief operating officer, retired from such
positions. On June 9, 2009, the Company entered into a
consulting agreement (the Consulting Agreement) with
Mr. Beal, under which Mr. Beal began serving as a
consultant to the Company on July 1, 2009. Either the
Company or Mr. Beal may terminate the consulting
relationship at any time by giving ninety days written notice to
the other party; however, the Company may terminate the
relationship immediately for cause. During the term of the
consulting relationship, Mr. Beal will receive a consulting
fee of $20,000 per month and a monthly reimbursement for his
medical and dental coverage costs. If Mr. Beal dies during
the term of the Consulting Agreement, his estate will receive a
$60,000 lump sum payment. As part of the consulting agreement,
certain of Mr. Beals stock-based awards were modified
to permit vesting and exercise under the original terms of the
stock-based awards as if Mr. Beal were still an employee of
the Company while he is performing consulting services for the
Company. The tables above summarize the Companys
activities pursuant to the consulting agreement with this
director. |
Saltwater disposal services agreement. Among
the assets the Company acquired from Chase Oil is an undivided
interest in a saltwater gathering and disposal system, which is
owned and maintained under a written agreement among the Company
and Chase Oil and certain of its affiliates, and under which the
Company as operator gathers and disposes of produced water. The
system is owned jointly by the Company and Chase Oil and its
affiliates in undivided ownership percentages, which are
annually redetermined as of January 1 on the basis of each
partys percentage contribution of the total volume of
produced water disposed of through the system during the prior
calendar year. As of January 1, 2011, the Company owned
97.5 percent of the system and Chase Oil and its affiliates
owned 2.5 percent.
Purchase of residence. During 2010, the
Company purchased the residence of an officer of the Company. To
effectuate the purchase, the Company engaged a third-party
relocation company, who executed the purchase for $920,000 and
will subsequently sell the officers residence. The
third-party relocation company appraised the fair value of the
residence at $920,000.
|
|
Note O.
|
Discontinued
operations
|
In December 2010, the Company closed the sale of certain of its
non-core Permian Basin assets for cash consideration of
$103.3 million. The Company recorded a gain in 2010 on the
disposition of assets in discontinued operations of
approximately $29.1 million. The Company did not complete
any material divestitures during 2009 or 2008.
F-41
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company has reflected the result of operations of the above
divestiture as discontinued operations, rather than as a
component of continuing operations. The following table
represents the components of the Companys discontinued
operations for the years ended December 31, 2010, 2009 and
2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
18,482
|
|
|
$
|
17,576
|
|
|
$
|
23,248
|
|
Natural gas sales
|
|
|
7,084
|
|
|
|
7,270
|
|
|
|
12,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
25,566
|
|
|
|
24,846
|
|
|
|
35,704
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
|
9,978
|
|
|
|
9,336
|
|
|
|
9,398
|
|
Exploration and abandonments
|
|
|
154
|
|
|
|
28
|
|
|
|
|
|
Depreciation, depletion and amortization(a)
|
|
|
7,461
|
|
|
|
9,407
|
|
|
|
6,506
|
|
Accretion of discount on asset retirement obligations(a)
|
|
|
211
|
|
|
|
141
|
|
|
|
128
|
|
Impairments of long-lived assets(a)
|
|
|
3,567
|
|
|
|
4,317
|
|
|
|
6,895
|
|
General and administrative(b)
|
|
|
(985
|
)
|
|
|
(886
|
)
|
|
|
(354
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
20,386
|
|
|
|
22,343
|
|
|
|
22,573
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
5,180
|
|
|
|
2,503
|
|
|
|
13,131
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on disposition of assets, net(a)
|
|
|
29,112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations before income taxes
|
|
|
34,292
|
|
|
|
2,503
|
|
|
|
13,131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
(2,368
|
)
|
|
|
(2,555
|
)
|
|
|
(5,421
|
)
|
Deferred(a)
|
|
|
(10,588
|
)
|
|
|
1,777
|
|
|
|
770
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations, net of tax
|
|
$
|
21,336
|
|
|
$
|
1,725
|
|
|
$
|
8,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Represents the significant noncash components of discontinued
operations. |
|
(b) |
|
Represents the fees received from third-parties for operating
oil and natural gas properties that were sold. The Company
reflects these fees as a reduction of general and administrative
expenses. |
|
|
Note P.
|
Net
income (loss) per share
|
Basic net income (loss) per share is computed by dividing net
income (loss) applicable to common shareholders by the weighted
average number of common shares treated as outstanding for the
period.
The computation of diluted income (loss) per share reflects the
potential dilution that could occur if securities or other
contracts to issue common stock that are dilutive to income
(loss) were exercised or converted into common stock or resulted
in the issuance of common stock that would then share in the
earnings of the Company. These amounts include unexercised
capital options, stock options and restricted stock. Potentially
dilutive effects are calculated using the treasury stock method.
F-42
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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,
2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
92,542
|
|
|
|
84,912
|
|
|
|
79,206
|
|
Dilutive common stock options
|
|
|
900
|
|
|
|
|
|
|
|
1,140
|
|
Dilutive restricted stock
|
|
|
395
|
|
|
|
|
|
|
|
241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
93,837
|
|
|
|
84,912
|
|
|
|
80,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, stock options to purchase
469 shares of common stock for the year ended
December 31, 2010, 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, 2010, were
6,659 shares of restricted stock because the effect would
be anti-dilutive.
In 2009, the Company incurred a net loss; accordingly, all
potentially dilutive securities were anti-dilutive and not
included in determining diluted net loss per share. In 2009, the
anti-dilutive securities included (i) common stock options
to purchase 2,156,503 shares and
(ii) 497,257 shares of restricted stock. In 2008,
since the Company had net income applicable to common
shareholders, the effects of all potentially dilutive securities
including capital options, 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, stock options to purchase
313,354 shares of common stock for the year ended
December 31, 2008, 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 Q.
|
Other
current liabilities
|
The following table provides the components of the
Companys other current liabilities at December 31,
2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Other current liabilities:
|
|
|
|
|
|
|
|
|
Accrued production costs
|
|
$
|
31,149
|
|
|
$
|
24,128
|
|
Payroll related matters
|
|
|
13,790
|
|
|
|
14,490
|
|
Accrued interest
|
|
|
15,494
|
|
|
|
10,055
|
|
Asset retirement obligations
|
|
|
7,378
|
|
|
|
3,262
|
|
Other
|
|
|
15,464
|
|
|
|
8,160
|
|
|
|
|
|
|
|
|
|
|
Other current liabilities
|
|
$
|
83,275
|
|
|
$
|
60,095
|
|
|
|
|
|
|
|
|
|
|
|
|
Note R.
|
Subsidiary
guarantors
|
All of the Companys wholly-owned subsidiaries have fully
and unconditionally guaranteed certain of the senior notes
issuances of the Company (see Note J). In accordance with
practices accepted by the SEC, the Company has prepared
Consolidating Condensed Financial Statements in order to
quantify the assets, results of operations and cash flows of
such subsidiaries as subsidiary guarantors. The following
Consolidating Condensed Balance Sheets at December 31, 2010
and 2009, and Consolidating Condensed Statements of Operations
and Consolidating Condensed Statements of Cash Flows for the
years ended December 31, 2010, 2009 and 2008,
F-43
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
present financial information for Concho Resources Inc. as the
Parent on a stand-alone basis (carrying any investments in
subsidiaries under the equity method), financial information for
the subsidiary guarantors on a stand-alone basis (carrying any
investment in non-guarantor subsidiaries under the equity
method), and the consolidation and elimination entries necessary
to arrive at the information for the Company on a consolidated
basis. All current and deferred income taxes are recorded on
Concho Resources Inc. as the subsidiaries are flow-through
entities for income tax purposes. The subsidiary guarantors are
not restricted from making distributions to the Company.
Consolidating
Condensed Balance Sheet
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Accounts receivable related parties
|
|
$
|
5,532,317
|
|
|
$
|
534,447
|
|
|
$
|
(6,066,595
|
)
|
|
$
|
169
|
|
Other current assets
|
|
|
51,084
|
|
|
|
279,380
|
|
|
|
|
|
|
|
330,464
|
|
Total oil and natural gas properties, net
|
|
|
|
|
|
|
4,885,740
|
|
|
|
|
|
|
|
4,885,740
|
|
Total property and equipment, net
|
|
|
|
|
|
|
28,047
|
|
|
|
|
|
|
|
28,047
|
|
Investment in subsidiaries
|
|
|
1,363,908
|
|
|
|
|
|
|
|
(1,363,908
|
)
|
|
|
|
|
Total other long-term assets
|
|
|
55,061
|
|
|
|
69,013
|
|
|
|
|
|
|
|
124,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
7,002,370
|
|
|
$
|
5,796,627
|
|
|
$
|
(7,430,503
|
)
|
|
$
|
5,368,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
Accounts payable related parties
|
|
$
|
2,061,777
|
|
|
$
|
4,006,015
|
|
|
$
|
(6,066,595
|
)
|
|
$
|
1,197
|
|
Other current liabilities
|
|
|
115,662
|
|
|
|
390,130
|
|
|
|
|
|
|
|
505,792
|
|
Other long-term liabilities
|
|
|
772,536
|
|
|
|
36,574
|
|
|
|
|
|
|
|
809,110
|
|
Long-term debt
|
|
|
1,668,521
|
|
|
|
|
|
|
|
|
|
|
|
1,668,521
|
|
Equity
|
|
|
2,383,874
|
|
|
|
1,363,908
|
|
|
|
(1,363,908
|
)
|
|
|
2,383,874
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
7,002,370
|
|
|
$
|
5,796,627
|
|
|
$
|
(7,430,503
|
)
|
|
$
|
5,368,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidating
Condensed Balance Sheet
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Accounts receivable related parties
|
|
$
|
2,715,307
|
|
|
$
|
1,738,382
|
|
|
$
|
(4,453,473
|
)
|
|
$
|
216
|
|
Other current assets
|
|
|
33,561
|
|
|
|
183,481
|
|
|
|
|
|
|
|
217,042
|
|
Total oil and natural gas properties, net
|
|
|
|
|
|
|
2,840,583
|
|
|
|
|
|
|
|
2,840,583
|
|
Total property and equipment, net
|
|
|
|
|
|
|
15,706
|
|
|
|
|
|
|
|
15,706
|
|
Investment in subsidiaries
|
|
|
876,154
|
|
|
|
|
|
|
|
(876,154
|
)
|
|
|
|
|
Total other long-term assets
|
|
|
44,291
|
|
|
|
53,247
|
|
|
|
|
|
|
|
97,538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,669,313
|
|
|
$
|
4,831,399
|
|
|
$
|
(5,329,627
|
)
|
|
$
|
3,171,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
Accounts payable related parties
|
|
$
|
790,251
|
|
|
$
|
3,663,513
|
|
|
$
|
(4,453,473
|
)
|
|
$
|
291
|
|
Other current liabilities
|
|
|
68,706
|
|
|
|
268,017
|
|
|
|
|
|
|
|
336,723
|
|
Other long-term liabilities
|
|
|
629,092
|
|
|
|
23,715
|
|
|
|
|
|
|
|
652,807
|
|
Long-term debt
|
|
|
845,836
|
|
|
|
|
|
|
|
|
|
|
|
845,836
|
|
Equity
|
|
|
1,335,428
|
|
|
|
876,154
|
|
|
|
(876,154
|
)
|
|
|
1,335,428
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
3,669,313
|
|
|
$
|
4,831,399
|
|
|
$
|
(5,329,627
|
)
|
|
$
|
3,171,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-44
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Consolidating
Condensed Statement of Operations
For the Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Total operating revenues
|
|
$
|
|
|
|
$
|
972,576
|
|
|
$
|
|
|
|
$
|
972,576
|
|
Total operating costs and expenses
|
|
|
(86,693
|
)
|
|
|
(509,835
|
)
|
|
|
|
|
|
|
(596,528
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
(86,693
|
)
|
|
|
462,741
|
|
|
|
|
|
|
|
376,048
|
|
Interest expense
|
|
|
(60,087
|
)
|
|
|
|
|
|
|
|
|
|
|
(60,087
|
)
|
Other, net
|
|
|
486,754
|
|
|
|
(9,278
|
)
|
|
|
(487,754
|
)
|
|
|
(10,278
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
|
339,974
|
|
|
|
453,463
|
|
|
|
(487,754
|
)
|
|
|
305,683
|
|
Income tax expense (benefit)
|
|
|
(135,604
|
)
|
|
|
12,955
|
|
|
|
|
|
|
|
(122,649
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
204,370
|
|
|
|
466,418
|
|
|
|
(487,754
|
)
|
|
|
183,034
|
|
Income from discontinued operations
|
|
|
|
|
|
|
21,336
|
|
|
|
|
|
|
|
21,336
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
204,370
|
|
|
$
|
487,754
|
|
|
$
|
(487,754
|
)
|
|
$
|
204,370
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidating
Condensed Statement of Operations
For the Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Total operating revenues
|
|
$
|
|
|
|
$
|
519,601
|
|
|
$
|
|
|
|
$
|
519,601
|
|
Total operating costs and expenses
|
|
|
(143,427
|
)
|
|
|
(380,505
|
)
|
|
|
|
|
|
|
(523,932
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
(143,427
|
)
|
|
|
139,096
|
|
|
|
|
|
|
|
(4,331
|
)
|
Interest expense
|
|
|
(28,292
|
)
|
|
|
|
|
|
|
|
|
|
|
(28,292
|
)
|
Other, net
|
|
|
141,185
|
|
|
|
(414
|
)
|
|
|
(141,185
|
)
|
|
|
(414
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
(30,534
|
)
|
|
|
138,682
|
|
|
|
(141,185
|
)
|
|
|
(33,037
|
)
|
Income tax benefit
|
|
|
20,732
|
|
|
|
778
|
|
|
|
|
|
|
|
21,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
(9,802
|
)
|
|
|
139,460
|
|
|
|
(141,185
|
)
|
|
|
(11,527
|
)
|
Income from discontinued operations
|
|
|
|
|
|
|
1,725
|
|
|
|
|
|
|
|
1,725
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(9,802
|
)
|
|
$
|
141,185
|
|
|
$
|
(141,185
|
)
|
|
$
|
(9,802
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidating
Condensed Statement of Operations
For the Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Total operating revenues
|
|
$
|
(31,287
|
)
|
|
$
|
529,372
|
|
|
$
|
|
|
|
$
|
498,085
|
|
Total operating costs and expenses
|
|
|
177,384
|
|
|
|
(220,206
|
)
|
|
|
|
|
|
|
(42,822
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
146,097
|
|
|
|
309,166
|
|
|
|
|
|
|
|
455,263
|
|
Interest expense
|
|
|
(29,039
|
)
|
|
|
|
|
|
|
|
|
|
|
(29,039
|
)
|
Other, net
|
|
|
323,729
|
|
|
|
1,432
|
|
|
|
(323,729
|
)
|
|
|
1,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
|
440,787
|
|
|
|
310,598
|
|
|
|
(323,729
|
)
|
|
|
427,656
|
|
Income tax expense (benefit)
|
|
|
(162,085
|
)
|
|
|
4,651
|
|
|
|
|
|
|
|
(157,434
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
278,702
|
|
|
|
315,249
|
|
|
|
(323,729
|
)
|
|
|
270,222
|
|
Income from discontinued operations
|
|
|
|
|
|
|
8,480
|
|
|
|
|
|
|
|
8,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
278,702
|
|
|
$
|
323,729
|
|
|
$
|
(323,729
|
)
|
|
$
|
278,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-45
CONCHO
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Consolidating
Condensed Statement of Cash Flows
For the Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Net cash flows provided by (used in) operating activities
|
|
$
|
(1,369,316
|
)
|
|
$
|
2,020,898
|
|
|
$
|
|
|
|
$
|
651,582
|
|
Net cash flows used in investing activities
|
|
|
(10,812
|
)
|
|
|
(2,032,645
|
)
|
|
|
|
|
|
|
(2,043,457
|
)
|
Net cash flows provided by financing activities
|
|
|
1,380,126
|
|
|
|
8,899
|
|
|
|
|
|
|
|
1,389,025
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(2
|
)
|
|
|
(2,848
|
)
|
|
|
|
|
|
|
(2,850
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
48
|
|
|
|
3,186
|
|
|
|
|
|
|
|
3,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
46
|
|
|
$
|
338
|
|
|
$
|
|
|
|
$
|
384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidating
Condensed Statement of Cash Flows
For the Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Net cash flows provided by (used in) operating activities
|
|
$
|
(295,240
|
)
|
|
$
|
654,786
|
|
|
$
|
|
|
|
$
|
359,546
|
|
Net cash flows provided by (used in) investing activities
|
|
|
77,185
|
|
|
|
(663,333
|
)
|
|
|
|
|
|
|
(586,148
|
)
|
Net cash flows provided by (used in) financing activities
|
|
|
218,103
|
|
|
|
(6,019
|
)
|
|
|
|
|
|
|
212,084
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
48
|
|
|
|
(14,566
|
)
|
|
|
|
|
|
|
(14,518
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
|
|
|
|
17,752
|
|
|
|
|
|
|
|
17,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
48
|
|
|
$
|
3,186
|
|
|
$
|
|
|
|
$
|
3,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidating
Condensed Statement of Cash Flows
For the Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Net cash flows provided by (used in) operating activities
|
|
$
|
(532,919
|
)
|
|
$
|
924,316
|
|
|
$
|
|
|
|
$
|
391,397
|
|
Net cash flows used in investing activities
|
|
|
(5,386
|
)
|
|
|
(940,664
|
)
|
|
|
|
|
|
|
(946,050
|
)
|
Net cash flows provided by financing activities
|
|
|
538,198
|
|
|
|
3,783
|
|
|
|
|
|
|
|
541,981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(107
|
)
|
|
|
(12,565
|
)
|
|
|
|
|
|
|
(12,672
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
107
|
|
|
|
30,317
|
|
|
|
|
|
|
|
30,424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
|
|
|
$
|
17,752
|
|
|
$
|
|
|
|
$
|
17,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note S.
|
Subsequent
Events
|
In February 2011, the Company entered into a purchase and sale
agreement to sell its North Dakota assets for cash consideration
of approximately $196.0 million, subject to customary
purchase price adjustments, and expects to close the divestiture
prior to March 31, 2011. The Company expects to recognize a
gain on this sale in excess of $140.0 million.
F-46
CONCHO
RESOURCES INC.
December 31,
2010, 2009 and 2008
Capitalized
Costs
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Oil and natural gas properties:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
4,982,316
|
|
|
$
|
3,139,424
|
|
Unproved
|
|
|
633,933
|
|
|
|
218,580
|
|
Less: accumulated depletion
|
|
|
(730,509
|
)
|
|
|
(517,421
|
)
|
|
|
|
|
|
|
|
|
|
Net capitalized costs for oil and natural gas properties
|
|
$
|
4,885,740
|
|
|
$
|
2,840,583
|
|
|
|
|
|
|
|
|
|
|
Costs
Incurred for Oil and Natural Gas Producing
Activities(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
1,224,378
|
|
|
$
|
205,817
|
|
|
$
|
597,713
|
|
Unproved
|
|
|
475,688
|
|
|
|
74,692
|
|
|
|
240,294
|
|
Exploration
|
|
|
200,797
|
|
|
|
134,105
|
|
|
|
160,174
|
|
Development
|
|
|
492,622
|
|
|
|
265,731
|
|
|
|
178,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred for oil and natural gas properties
|
|
$
|
2,393,485
|
|
|
$
|
680,345
|
|
|
$
|
1,177,023
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The costs incurred for oil and natural gas producing activities
includes the following amounts of asset retirement obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Proved property acquisition costs
|
|
$
|
8,290
|
|
|
$
|
488
|
|
|
$
|
7,062
|
|
Exploration costs
|
|
|
784
|
|
|
|
452
|
|
|
|
563
|
|
Development costs
|
|
|
13,611
|
|
|
|
5,425
|
|
|
|
(1,123
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
22,685
|
|
|
$
|
6,365
|
|
|
$
|
6,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve
Quantity Information
The following information represents estimates of our proved
reserves as of December 31, 2010, which have been prepared
and presented under SEC rules which became effective for fiscal
years ending on or after December 31, 2009. These rules
required SEC reporting companies to prepare their reserves
estimates using revised reserve definitions and revised pricing
based on a
12-month
unweighted average of the
first-day-of-the-month
pricing. The previous rules required that reserve estimates be
calculated using
last-day-of-the-year
pricing. The pricing that was used for estimates of our reserves
as of December 31, 2010 was based on an unweighted average
twelve month average West Texas Intermediate posted price of
$75.96 per Bbl for oil and a Henry Hub spot natural gas price of
$4.38 per MMBtu for natural gas, see table below. As a result of
this change in pricing methodology in 2009, direct comparisons
of reported reserves amounts prior to 2009 may be more
difficult.
Another impact of the SEC rules was a general requirement that,
subject to limited exceptions, proved undeveloped reserves may
only be booked if they relate to wells scheduled to be drilled
within five years of the date
F-47
CONCHO
RESOURCES INC.
UNAUDITED
SUPPLEMENTARY INFORMATION (Continued)
of booking. This rule limited, and may continue to limit, the
Companys potential to record additional proved undeveloped
reserves as it pursues its drilling program, particularly as it
develops its significant acreage in the Permian Basin of
Southeast New Mexico and West Texas. Moreover, the Company may
be required to write down our proved undeveloped reserves if we
do not drill on those reserves with the required five-year
timeframe. The Company does not have any proved undeveloped
reserves which have remained undeveloped for five years or more.
The Companys proved oil and natural gas reserves are all
located in the United States, primarily in the Permian Basin of
Southeast New Mexico and West Texas. All of the estimates of the
proved reserves at December 31, 2010 and 2008 are based on
reports prepared by Cawley, Gillespie & Associates,
Inc. (Cawley) and Netherland, Sewell &
Associates, Inc. (NSAI), independent petroleum
engineers. The estimates of 93 percent of the proved
reserves at December 31, 2009 were based on reports
prepared by Cawley and NSAI, independent petroleum engineers,
with the remaining portion being prepared by the Companys
internal reserve engineering staff. Proved reserves were
estimated in accordance with the guidelines established by the
SEC and the FASB.
The following table summarizes the prices utilized in the
reserve estimates for 2010, 2009 and 2008. Commodity prices
utilized for the reserve estimates were adjusted for location,
grade and quality are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
Prices utilitzed in the reserve estimates before adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil per Bbl(a)
|
|
$
|
75.96
|
|
|
$
|
57.65
|
|
|
$
|
41.00
|
|
Gas per MMBtu(b)
|
|
$
|
4.38
|
|
|
$
|
3.87
|
|
|
$
|
5.71
|
|
|
|
|
(a) |
|
The pricing used to estimate our 2010 and 2009 reserves was
based on an unweighted average twelve month average West Texas
Intermediate posted price; whereas, the pricing used for 2008
was based on year-end West Texas Intermediate posted prices. |
|
(b) |
|
The pricing used to estimate our 2010 and 2009 reserves was
based on an unweighted average twelve month average Henry Hub
price; whereas, the pricing used for 2008 was based on year-end
Henry Hub spot market prices. |
Oil and natural 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
natural gas properties. Accordingly, these estimates are
expected to change as additional information becomes available
in the future.
F-48
CONCHO
RESOURCES INC.
UNAUDITED
SUPPLEMENTARY INFORMATION (Continued)
The following table provides a rollforward of the total proved
reserves for the years ended December 31, 2010, 2009 and
2008, as well as proved developed and proved undeveloped
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
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
|
|
|
142,018
|
|
|
|
416,911
|
|
|
|
211,503
|
|
|
|
86,285
|
|
|
|
305,948
|
|
|
|
137,275
|
|
|
|
53,361
|
|
|
|
225,837
|
|
|
|
91,000
|
|
Purchases of
minerals-in-place
|
|
|
43,364
|
|
|
|
188,422
|
|
|
|
74,768
|
|
|
|
13,916
|
|
|
|
38,096
|
|
|
|
20,265
|
|
|
|
20,837
|
|
|
|
56,022
|
|
|
|
30,174
|
|
Sales of
minerals-in-place
|
|
|
(2,938
|
)
|
|
|
(18,402
|
)
|
|
|
(6,005
|
)
|
|
|
(18
|
)
|
|
|
(315
|
)
|
|
|
(71
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions and discoveries(a)
|
|
|
41,151
|
|
|
|
110,923
|
|
|
|
59,638
|
|
|
|
47,750
|
|
|
|
109,150
|
|
|
|
65,942
|
(b)
|
|
|
24,194
|
|
|
|
73,380
|
|
|
|
36,424
|
|
Revisions of previous estimates
|
|
|
(1,842
|
)
|
|
|
5,725
|
|
|
|
(888
|
)
|
|
|
1,421
|
|
|
|
(14,400
|
)
|
|
|
(977
|
)
|
|
|
(7,521
|
)
|
|
|
(34,323
|
)
|
|
|
(13,242
|
)
|
Production
|
|
|
(10,330
|
)
|
|
|
(31,405
|
)
|
|
|
(15,564
|
)
|
|
|
(7,336
|
)
|
|
|
(21,568
|
)
|
|
|
(10,931
|
)
|
|
|
(4,586
|
)
|
|
|
(14,968
|
)
|
|
|
(7,081
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31
|
|
|
211,423
|
|
|
|
672,174
|
|
|
|
323,452
|
|
|
|
142,018
|
|
|
|
416,911
|
|
|
|
211,503
|
|
|
|
86,285
|
|
|
|
305,948
|
|
|
|
137,275
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
|
|
|
66,578
|
|
|
|
222,776
|
|
|
|
103,707
|
|
|
|
46,661
|
|
|
|
179,124
|
|
|
|
76,515
|
|
|
|
27,617
|
|
|
|
128,872
|
|
|
|
49,096
|
|
December 31
|
|
|
115,439
|
|
|
|
414,491
|
|
|
|
184,521
|
|
|
|
66,578
|
|
|
|
222,776
|
|
|
|
103,707
|
|
|
|
46,661
|
|
|
|
179,124
|
|
|
|
76,515
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
|
|
|
75,440
|
|
|
|
194,135
|
|
|
|
107,796
|
|
|
|
39,624
|
|
|
|
126,824
|
|
|
|
60,760
|
|
|
|
25,744
|
|
|
|
96,965
|
|
|
|
41,904
|
|
December 31
|
|
|
95,984
|
|
|
|
257,683
|
|
|
|
138,931
|
|
|
|
75,440
|
|
|
|
194,135
|
|
|
|
107,796
|
(b)
|
|
|
39,624
|
|
|
|
126,824
|
|
|
|
60,760
|
|
|
|
|
(a) |
|
The 2010, 2009 and 2008 extensions and discoveries included
24,960, 42,645 and 14,533 MBoe, respectively, related to
additions from the Companys infill drilling activities. |
|
(b) |
|
Includes additions of 13.6 MMBoe resulting from the
adoption of the new SEC rules related to disclosures of oil and
natural gas reserves that are effective for fiscal years ending
on or after December 31, 2009. |
Standardized
Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is
computed by applying at December 31, 2010 and 2009 the
12-month
unweighted average of the
first-day-of-the-month
pricing for oil and natural gas and at December 31,
2008 year-end prices of oil and natural gas (with
consideration of price changes only to the extent provided by
contractual arrangements) to the estimated future production of
proved oil and natural 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 natural 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
natural gas properties. Estimates of fair value would also
consider probable and possible reserves, anticipated future oil
and natural 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.
F-49
CONCHO
RESOURCES INC.
UNAUDITED
SUPPLEMENTARY INFORMATION (Continued)
The following table provides the standardized measure of
discounted future net cash flows at December 31, 2010, 2009
and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Oil and gas producing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
20,915,232
|
|
|
$
|
10,145,876
|
|
|
$
|
5,785,109
|
|
Future production costs
|
|
|
(5,749,840
|
)
|
|
|
(2,956,257
|
)
|
|
|
(1,666,380
|
)
|
Future development and abandonment costs(a)
|
|
|
(1,893,323
|
)
|
|
|
(1,272,695
|
)
|
|
|
(668,005
|
)
|
Future income tax expense
|
|
|
(4,128,038
|
)
|
|
|
(1,807,582
|
)
|
|
|
(919,251
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,144,031
|
|
|
|
4,109,342
|
|
|
|
2,531,473
|
|
10% annual discount factor
|
|
|
(4,967,901
|
)
|
|
|
(2,187,313
|
)
|
|
|
(1,332,488
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
4,176,130
|
|
|
$
|
1,922,029
|
(b)
|
|
$
|
1,198,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes $49.6 million of undiscounted asset retirement
cash outflow estimated at December 31, 2010, and
$11.7 million and $28.8 million of undiscounted asset
retirement cash inflow estimated at December 31, 2009 and
2008, 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. |
|
(b) |
|
Includes $66.4 million resulting from the adoption of SEC
rules related to determination and disclosures of oil and
natural gas reserves that are effective for fiscal years ending
on or after December 31, 2009. |
Changes
in Standardized Measure of Discounted Future Net Cash
Flows
The following table provides a rollforward of the standardized
measure of discounted future net cash flows for the years ended
December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Oil and gas producing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of
minerals-in-place
|
|
$
|
1,447,792
|
|
|
$
|
403,242
|
|
|
$
|
1,014,689
|
|
Sales of
minerals-in-place
|
|
|
(75,699
|
)
|
|
|
(953
|
)
|
|
|
(24
|
)
|
Extensions and discoveries
|
|
|
931,591
|
|
|
|
844,742
|
|
|
|
426,208
|
|
Net changes in prices and production costs
|
|
|
1,408,342
|
|
|
|
220,372
|
|
|
|
(1,622,800
|
)
|
Oil and natural gas sales, net of production costs
|
|
|
(817,397
|
)
|
|
|
(436,329
|
)
|
|
|
(411,268
|
)
|
Changes in future development costs
|
|
|
98,538
|
|
|
|
49,626
|
|
|
|
74,160
|
|
Revisions of previous quantity estimates
|
|
|
(27,622
|
)
|
|
|
(19,234
|
)
|
|
|
(283,556
|
)
|
Accretion of discount
|
|
|
312,674
|
|
|
|
162,844
|
|
|
|
255,660
|
|
Changes in production rates, timing and other
|
|
|
18,051
|
|
|
|
(87,960
|
)
|
|
|
41,563
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in present value of future net revenues
|
|
|
3,296,270
|
|
|
|
1,136,350
|
|
|
|
(505,368
|
)
|
Net change in present value of future income taxes
|
|
|
(1,042,169
|
)
|
|
|
(413,306
|
)
|
|
|
272,579
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,254,101
|
|
|
|
723,044
|
|
|
|
(232,789
|
)
|
Balance, beginning of year
|
|
|
1,922,029
|
|
|
|
1,198,985
|
|
|
|
1,431,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
$
|
4,176,130
|
|
|
$
|
1,922,029
|
|
|
$
|
1,198,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-50
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, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
(In thousands, except per share data)
|
|
|
Year ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
212,000
|
|
|
$
|
215,710
|
|
|
$
|
240,496
|
|
|
$
|
323,192
|
|
Less: discontinued operations
|
|
|
(7,244
|
)
|
|
|
(6,287
|
)
|
|
|
(5,291
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
|
|
$
|
204,756
|
|
|
$
|
209,423
|
|
|
$
|
235,205
|
|
|
$
|
323,192
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
93,382
|
|
|
$
|
5,299
|
|
|
$
|
194,082
|
|
|
$
|
320,234
|
|
Less: discontinued operations
|
|
|
(7,113
|
)
|
|
|
(5,731
|
)
|
|
|
(3,625
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
|
|
$
|
86,269
|
|
|
$
|
(432
|
)
|
|
$
|
190,457
|
|
|
$
|
320,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
67,540
|
|
|
$
|
124,171
|
|
|
$
|
20,775
|
|
|
$
|
(8,116
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share Basic
|
|
$
|
0.76
|
|
|
$
|
1.36
|
|
|
$
|
0.23
|
|
|
$
|
(0.08
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share Diluted
|
|
$
|
0.75
|
|
|
$
|
1.35
|
|
|
$
|
0.22
|
|
|
$
|
(0.08
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
86,002
|
|
|
$
|
127,332
|
|
|
$
|
153,494
|
|
|
$
|
177,619
|
|
Less: discontinued operations
|
|
|
(3,947
|
)
|
|
|
(7,492
|
)
|
|
|
(6,363
|
)
|
|
|
(7,044
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
|
|
$
|
82,055
|
|
|
$
|
119,840
|
|
|
$
|
147,131
|
|
|
$
|
170,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
102,635
|
|
|
$
|
180,221
|
|
|
$
|
104,899
|
|
|
$
|
158,520
|
|
Less: discontinued operations
|
|
|
(4,289
|
)
|
|
|
(7,492
|
)
|
|
|
(5,136
|
)
|
|
|
(5,426
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
|
|
$
|
98,346
|
|
|
$
|
172,729
|
|
|
$
|
99,763
|
|
|
$
|
153,094
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(13,225
|
)
|
|
$
|
(33,218
|
)
|
|
$
|
19,762
|
|
|
$
|
16,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share Basic
|
|
$
|
(0.16
|
)
|
|
$
|
(0.39
|
)
|
|
$
|
0.23
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share Diluted
|
|
$
|
(0.16
|
)
|
|
$
|
(0.39
|
)
|
|
$
|
0.23
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-51
Index of
Exhibits
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
2
|
.1
|
|
Asset Purchase Agreement, dated July 19, 2010, by and among
Concho Resources Inc., Marbob Energy Corporation, Pitch Energy
Corporation, Costaplenty Energy Corporation and John R. Gray,
LLC (filed as Exhibit 2.1 to the Companys Current Report
on Form 8-K on July 20, 2010, and incorporated herein by
reference).
|
|
2
|
.2
|
|
Purchase and Sale Agreement, dated November 20, 2009, between
Terrace Petroleum Corporation, et al., as Seller, and COG
Operating LLC, as Buyer, (filed as Exhibit 2.1 to the
Companys Current Report on Form 8-K on November 25, 2009,
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 Registration Statement on Form S-1/A on July 5,
2007, and incorporated herein by reference).
|
|
4
|
.2
|
|
Indenture, dated September 18, 2009, between Concho Resources
Inc., the subsidiary guarantors named therein, and Wells Fargo
Bank, National Association, as trustee (filed as Exhibit 4.1 to
the Companys Current Report on Form 8-K on September 22,
2009, and incorporated herein by reference).
|
|
4
|
.3
|
|
First Supplemental Indenture, dated September 18, 2009, between
Concho Resources Inc., the subsidiary guarantors named therein,
and Wells Fargo Bank, National Association, as trustee (filed as
Exhibit 4.2 to the Companys Current Report on Form 8-K on
September 22, 2009, and incorporated herein by reference).
|
|
4
|
.4
|
|
Form of 8.625% Senior Notes due 2017 (included in Exhibit
4.2 to the Companys Current Report on Form 8-K on
September 22, 2009, and incorporated herein by reference).
|
|
4
|
.5
|
|
Second Supplemental Indenture, dated November 3, 2010, between
Concho Resources Inc., the subsidiary guarantors named therein,
and Wells Fargo Bank, National Association, as trustee (filed as
Exhibit 4.4 to the Post-Effective Amendment to the
Companys Registration Statement on Form S-3 on December 7,
2010, and incorporated herein by reference).
|
|
4
|
.6
|
|
Third Supplemental Indenture, dated December 14, 2010, between
Concho Resources Inc., the subsidiary guarantors named therein,
and Wells Fargo Bank, National Association, as trustee (filed as
Exhibit 4.1 to the Companys Current Report on Form 8-K on
December 14, 2010, and incorporated herein by reference).
|
|
4
|
.7
|
|
Form of 7.0% Senior Notes due 2021 (included in Exhibit 4.1
to the Companys Current Report on Form 8-K on
December 14, 2010, and incorporated herein by reference).
|
|
10
|
.1
|
|
Form of Drilling Agreement with Silver Oak Drilling, LLC (filed
as Exhibit 10.4 to the Companys Registration Statement on
Form S-1/A on July 5, 2007, and incorporated herein by
reference).
|
|
10
|
.2
|
|
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 Registration Statement on
Form S-1 on April 24, 2007, and incorporated herein by
reference).
|
|
10
|
.3
|
|
Software License Agreement dated March 2, 2006, between Enertia
Software Systems and Concho Resources Inc. (filed as Exhibit
10.6 to the Companys Registration Statement on Form S-1 on
April 24, 2007, and incorporated herein by reference).
|
|
10
|
.4
|
|
Transfer of Operating Rights (Sublease) in a Lease for Oil and
Gas for Valhalla properties (filed as Exhibit 10.8 to the
Companys Registration Statement on Form S-1 on April 24,
2007, and incorporated herein by reference).
|
|
10
|
.5
|
|
Business Opportunities Agreement dated February 27, 2006, among
Concho Resources Inc. and the other signatories thereto (filed
as Exhibit 10.11 to the Companys Registration Statement on
Form S-1 on April 24, 2007, and incorporated herein by
reference).
|
|
10
|
.6
|
|
Registration Rights Agreement dated February 27, 2006, among
Concho Resources Inc. and the other signatories thereto (filed
as Exhibit 10.12 to the Companys Registration Statement on
Form S-1 on April 24, 2007, and incorporated herein by
reference).
|
|
10
|
.7**
|
|
Concho Resources Inc. 2006 Stock Incentive Plan (filed as
Exhibit 10.13 to the Companys Registration Statement on
Form S-1 on April 24, 2007, and incorporated herein by
reference).
|
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
10
|
.8**
|
|
Form of Nonstatutory Stock Option Agreement (filed as Exhibit
10.16 to the Companys Annual Report on Form 10-K on
March 28, 2008, and incorporated herein by reference).
|
|
10
|
.9**
|
|
Form of Restricted Stock Agreement (for employees) (filed as
Exhibit 10.16 to the Companys Registration Statement on
Form S-1 on April 24, 2007, and incorporated herein by
reference).
|
|
10
|
.10**
|
|
Form of Restricted Stock Agreement (for non-employee directors)
(filed as Exhibit 10.18 to the Companys Annual Report on
Form 10-K on March 28, 2008, and incorporated herein by
reference).
|
|
10
|
.11**
|
|
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
|
.12**
|
|
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
|
.13**
|
|
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
|
.14**
|
|
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
|
.15**
|
|
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
|
.16**
|
|
Employment Agreement dated November 5, 2009, between Concho
Resources Inc. and C. William Giraud (filed as Exhibit 10.18 to
the Companys Annual Report on From 10-K on February 26,
2010, and incorporated herein by reference).
|
|
10
|
.17**
|
|
Form of Indemnification Agreement between Concho Resources Inc.
and each of the officers and directors thereof (filed as Exhibit
10.23 to the Companys Registration Statement on Form S-1
on April 24, 2007, and incorporated herein by reference).
|
|
10
|
.18**
|
|
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
|
.19**
|
|
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
|
.20**
|
|
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
|
.21**
|
|
Indemnification Agreement, dated November 5, 2009, by and
between Concho Resources, Inc. and Mark B. Puckett (filed as
Exhibit 10.1 to the Companys Current Report on Form 8-K on
November 12, 2009, and incorporated herein by reference).
|
|
10
|
.22**
|
|
Indemnification Agreement, dated November 5, 2009, by and
between Concho Resources, Inc. and C. William Giraud (filed as
Exhibit 10.2 to the Companys Current Report on Form 8-K on
November 12, 2009, and incorporated herein by reference).
|
|
10
|
.23**
|
|
Indemnification Agreement, dated September 24, 2010, between
Concho Resources Inc. and Don McCormack (filed as Exhibit 10.1
to the Companys Current Report on Form 8-K on September
29, 2010, and incorporated herein by reference).
|
|
10
|
.24**
|
|
Consulting Agreement dated June 9, 2009, by and between Concho
Resources Inc. and Steven L. Beal (filed as Exhibit 10.1 to the
Companys Current Report on Form 8-K on June 12, 2009, and
incorporated herein by reference).
|
|
10
|
.25
|
|
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).
|
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
10
|
.26
|
|
First Amendment to Amended and Restated Credit Agreement dated
as of April 7, 2009, to the 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 4.1 to the
Companys Current Report on Form 8-K on April 9, 2009, and
incorporated herein by reference).
|
|
10
|
.27
|
|
Limited Consent and Waiver, dated September 4, 2009, to the
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 10.1 to the Companys Current Report on Form 8-K
on September 22, 2009, and incorporated herein by reference).
|
|
10
|
.28
|
|
Common Stock Purchase Agreement, dated July 19, 2010, by and
among Concho Resources Inc. and the purchasers named therein
(filed as Exhibit 10.1 to the Companys Current Report on
Form 8-K on July 20, 2010, and incorporated herein by
reference).
|
|
10
|
.29
|
|
Promissory Note in the principal amount of $150,000,000 between
Concho Resources Inc. and Pitch Energy Corporation, dated
October 7, 2010 (filed as Exhibit 10.5 to the Companys
Quarterly Report on Form 10-Q on November 4, 2010, and
incorporated herein by reference).
|
|
10
|
.30
|
|
Registration Rights Agreement, dated October 7, 2010, 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 October 13, 2010, and incorporated herein by
reference).
|
|
10
|
.31
|
|
Second Amendment to Amended and Restated Credit Agreement, dated
April 26, 2010, by and among Concho Resources Inc., JP Morgan
Chase Bank, N.A., as Administrative Agent (filed as Exhibit 4.1
to the Companys Current Report on Form 8-K on April 29,
2010, and incorporated herein by reference).
|
|
10
|
.32
|
|
Third Amendment to Amended and Restated Credit Agreement and
Limited Waiver, dated June 16, 2010, among Concho Resources Inc.
and the lenders party thereto and JPMorgan Chase Bank, N.A., as
Administrative Agent (filed as Exhibit 10.1 to the
Companys Current Report on Form 8-K on June 18, 2010, and
incorporated herein by reference).
|
|
10
|
.33
|
|
Fourth Amendment to Amended and Restated Credit Agreement, dated
October 7, 2010, among Concho Resources Inc. and the lenders
party thereto and JPMorgan Chase Bank, N.A., as administrative
agent (filed as Exhibit 10.2 to the Companys Current
Report on Form 8-K on October 13, 2010, and incorporated herein
by reference).
|
|
10
|
.34
|
|
Fifth Amendment to Amended and Restated Credit Agreement and
Limited Waiver, dated as of December 7, 2010, among Concho
Resources Inc. and the lenders party thereto and JPMorgan Chase
Bank, N.A., as administrative agent (filed as Exhibit 10.1 to
the Companys Current Report on Form 8-K on December 10,
2010, and incorporated herein by reference).
|
|
10
|
.35(a)**
|
|
Form of Restricted Stock Agreement (for officers).
|
|
10
|
.36(a)**
|
|
Form of Restricted Stock Agreement (for non-officer employees).
|
|
12
|
.1(a)
|
|
Ratio of Earnings to Fixed Charges and Ratio of Earnings to
Fixed Charges and Preferred Stock Dividends
|
|
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)
|
|
Netherland, Sewell & Associates, Inc. Reserve Report.
|
|
23
|
.4(a)
|
|
Consent of Cawley, Gillespie & Associates, Inc.
|
|
23
|
.5(a)
|
|
Cawley, Gillespie & Associates, Inc. Reserve Report.
|
|
31
|
.1(a)
|
|
Certification of Chief Executive Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2(a)
|
|
Certification of Chief Financial Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1(b)
|
|
Certification of Chief Executive Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2(b)
|
|
Certification of Chief Financial Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
|
|
101
|
.INS(a)
|
|
XBRL Instance Document.
|
|
101
|
.SCH(a)
|
|
XBRL Schema Document.
|
|
101
|
.CAL(a)
|
|
XBRL Calculation Linkbase Document.
|
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Exhibit
|
|
|
101
|
.DEF(a)
|
|
XBRL Definition Linkbase Document.
|
|
101
|
.LAB(a)
|
|
XBRL Labels Linkbase Document.
|
|
101
|
.PRE(a)
|
|
XBRL Presentation Linkbase Document.
|
|
|
|
(a) |
|
Filed herewith. |
|
(b) |
|
Furnished herewith. |
|
|
|
** |
|
Management contract or compensatory plan or arrangement. |