sv1za
As filed with the Securities and Exchange Commission on
December 6, 2007
Registration
No. 333-147655
SECURITIES AND EXCHANGE
COMMISSION
Washington, D.C.
20549
Amendment No. 1
to
Form S-1
REGISTRATION
STATEMENT
UNDER
THE SECURITIES ACT OF
1933
Concho Resources Inc.
(Exact name of registrant as
specified in charter)
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Delaware
(State or other jurisdiction
of
incorporation or organization)
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1311
(Primary Standard
Industrial
Classification Code Number)
550 West Texas Avenue,
Suite 1300
Midland, Texas 79701
(432) 683-7443
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76-0818600
(I.R.S. Employer
Identification Number)
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(Address, including zip code,
and telephone number, including area code,
of registrants principal
executive offices)
David W. Copeland
Vice President and General
Counsel
550 West Texas Avenue,
Suite 1300
Midland, Texas 79701
(432) 683-7443
(Name, address, including zip
code, and telephone number, including area code,
of agent for service)
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With a copy to:
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T. Mark Kelly
Douglas E. McWilliams
Vinson & Elkins L.L.P.
1001 Fannin, Suite 2500
Houston, Texas
77002-6760
(713) 758-2222
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William S. Anderson
Bracewell & Giuliani LLP
711 Louisiana Street,
Suite 2300
Houston, Texas 77002-2770
(713) 221-1122
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Gerald S. Tanenbaum
Cahill Gordon & Reindel LLP
80 Pine Street
New York, New York 10005
(212) 701-3224
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Approximate date of commencement of proposed sale to the
public: As soon as practicable on or after the
effective date of this Registration Statement.
If any of the securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to
Rule 415 under the Securities Act of 1933, check the
following
box. o
If this Form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act,
check the following box and list the Securities Act registration
statement number of the earlier effective registration statement
for the same
offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(c) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(d) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
CALCULATION OF
REGISTRATION FEE
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Proposed Maximum
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Proposed Maximum
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Amount of
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Title of Each Class of
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Amount
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Offering
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Aggregate
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Registration
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Securities to be Registered
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to be Registered(1)
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Price per Share
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Offering Price
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Fee
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Common Stock, par value $.001
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10,000,000
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$6,288(2)
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Common Stock, par value $.001
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5,000
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$18.36(3)
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$91,800(3)
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$3(3)
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(1)
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Includes common stock issuable upon
exercise of the underwriters option to purchase additional
shares of common stock.
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(3)
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Calculated in accordance with
Rule 457(c) based on the average high and low prices of our
common stock as reported by the New York Stock Exchange on
December 4, 2007.
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The registrant hereby amends this registration statement on
such date or dates as may be necessary to delay its effective
date until the registrant shall file a further amendment which
specifically states that this registration statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act of 1933 or until the registration
statement shall become effective on such date as the Securities
and Exchange Commission, acting pursuant to said
Section 8(a), may determine.
The
information in this preliminary prospectus is not complete and
may be changed. These securities may not be sold until the
registration statement filed with the Securities and Exchange
Commission is effective. This preliminary prospectus is not an
offer to sell these securities and it is not soliciting an offer
to buy these securities in any jurisdiction where the offer or
sale is not permitted.
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SUBJECT TO COMPLETION, DATED DECEMBER 6, 2007
Prospectus
8,700,000 shares
Concho
Resources Inc.
Common
Stock
All of the
shares of common stock offered by this prospectus are being sold
by the selling stockholders. We will not receive any proceeds
from the sale of such shares.
Our common
stock is listed on the New York Stock Exchange under the symbol
CXO. On December 5, 2007, the last reported
sales price of our common stock on the New York Stock Exchange
was $17.79 per share.
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Per
share
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Total
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Price to the public
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$
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$
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Underwriting discount
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$
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$
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Net proceeds to selling stockholders, before expenses
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$
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$
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One of the
selling stockholders has granted the underwriters an option for
a period of 30 days to purchase up to an aggregate of
1,305,000 additional shares of our common stock on the same
terms and conditions set forth above to cover over-allotments,
if any.
Investing
in our common stock involves a high degree of risk. See
Risk factors beginning on page 16.
Neither
the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or
passed upon the adequacy or accuracy of this prospectus. Any
representation to the contrary is a criminal offense.
The
underwriters expect to deliver the shares of common stock to
investors
on ,
2007.
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JPMorgan |
Banc
of America Securities LLC |
Lehman
Brothers
BNP
PARIBAS
Merrill Lynch & Co.
UBS Investment Bank
,
2007
Table of
contents
You should rely only on the information contained in this
prospectus and the registration statement of which this
prospectus is a part. We have not authorized anyone to provide
you with information different from that contained in this
prospectus. The selling stockholders are offering to sell, and
seeking offers to buy, shares of our common stock only in
jurisdictions where offers and sales are permitted. The
information contained in this prospectus is accurate only as of
the date of this prospectus, regardless of the time of delivery
of this prospectus or of any sale of our common stock.
No action is being taken in any jurisdiction outside the United
States to permit a public offering of our common stock or
possession or distribution of this prospectus in that
jurisdiction. Persons who come into possession of this
prospectus in jurisdictions outside the United States are
required to inform themselves about and to observe any
restrictions as to this offering and the distribution of this
prospectus applicable to those jurisdictions.
Concho and Concho Resources are registered trademarks of ours.
Other products, services and company names mentioned in this
prospectus are the service marks/trademarks of their respective
owners.
i
The market data and certain other statistical information used
throughout this prospectus are based on independent industry
publications, government publications, reports by market
research firms or other published independent sources. Some data
are also based on our good faith estimates. Although we believe
these third-party sources are reliable, we have not
independently verified the information.
ii
This summary highlights information contained elsewhere in
this prospectus. Because this section is only a summary, it does
not contain all of the information that may be important to you
or that you should consider before making an investment
decision. For a more complete understanding of this offering, we
encourage you to read this entire prospectus, including the
information contained under the heading Risk
factors. You should read the following summary together
with the more detailed information, pro forma financial
information and consolidated financial information and the notes
thereto included elsewhere in this prospectus. In this
prospectus, unless the context otherwise requires, the terms
we, us, our and Concho
Resources refer to Concho Resources Inc. and its
subsidiaries and the term well means a gross well,
unless otherwise noted.
In this prospectus, pro forma means after giving
pro forma effect to the combination transaction that occurred on
February 27, 2006 and the initial public offering of our
common stock that occurred in August 2007 as if the combination
transaction and the initial public offering occurred on
January 1, 2006, unless otherwise noted. Please read
Business and propertiesCombination transaction
for more information about the combination transaction.
We have provided definitions for the oil and natural gas
terms used in this prospectus in the Glossary of
terms beginning on page 136 of this prospectus.
Our
business
We are an independent oil and natural gas company engaged in the
acquisition, development, exploitation and exploration of oil
and natural gas properties. Our conventional operations are
primarily focused in the Permian Basin of Southeast New Mexico
and West Texas. These conventional operations are complemented
by our activities in unconventional emerging resource plays. We
intend to grow our reserves and production through development
drilling, exploitation and exploration activities on our
multi-year project inventory and through acquisitions that meet
our strategic and financial objectives.
We were formed in February 2006 as a result of the combination
of Concho Equity Holdings Corp. and a portion of the oil and
natural gas properties and related assets owned by Chase Oil
Corporation and certain of its affiliates. Concho Equity
Holdings Corp. was formed in April 2004 and represents the third
of three Permian Basin-focused companies that have been formed
since 1997 by our current management team (the prior two
companies were sold to large domestic independent oil and
natural gas companies). We completed the initial public offering
of our common stock in August 2007.
Our operations are primarily concentrated in the Permian Basin,
the largest onshore oil and gas basin in the United States. As
of December 31, 2006, 99% of our total estimated net proved
reserves were located in the Permian Basin and consisted of
approximately 57% crude oil and 43% natural gas. This basin is
characterized by an extensive production history, mature
infrastructure, long reserve life, multiple producing horizons,
enhanced recovery potential and a large number of operators. The
primary producing formation in the Permian Basin under our core
properties in Southeast New Mexico is the Paddock interval of
the Yeso formation, which is located at depths ranging from
3,800 feet to 5,800 feet. We have also discovered
reserves and are producing oil and natural gas from the Blinebry
interval of the Yeso formation, the top of which is located
approximately 400 feet below the base of the Paddock
interval. In addition, we
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have assembled a multi-year inventory of development drilling
and exploitation projects, including further projects to
evaluate the aerial extent of the Blinebry interval, that we
believe will allow us to grow proved reserves and production. We
have also acquired significant acreage positions in
unconventional emerging resource plays, where we intend to apply
horizontal drilling, advanced fracture stimulation and/or
enhanced recovery technologies.
Following the formation of our company, we drilled
140 gross (86.4 net) wells in 2006, 89% of which were
completed as producers, 7% of which were dry holes and 4% of
which were awaiting completion as of December 31, 2006. In
addition, following the formation of our company, we recompleted
103 gross (77.1 net) wells in 2006, 98% of which were
productive. As a result, we increased our total estimated net
proved reserves by approximately 51 Bcfe from 416 Bcfe
as of December 31, 2005, on a pro forma basis, to
467 Bcfe as of December 31, 2006, while producing
approximately 26 Bcfe of oil and natural gas on a pro forma
basis during the year ended December 31, 2006. In addition,
following the formation of our company, we increased our average
net daily production from 62 MMcfe during March 2006 to
80 MMcfe during September 2007.
The following table provides a summary of selected operating
information of our conventional properties in the Permian Basin,
which is our core operating area, and in our unconventional
emerging resource plays.
PV-10
includes the present value of our estimated future abandonment
and site restoration costs for proved properties net of the
present value of estimated salvage proceeds from each of these
properties. We set forth our definition of
PV-10 (a
non-GAAP financial measure) and a reconciliation of
PV-10 to the
standardized measure of discounted future net cash flows under
Non-GAAP financial measures and
reconciliations.
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Nine months
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As of
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ended
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December 31, 2006
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September 30,
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Pro forma
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As of
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2007
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Total
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reserve/
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September 30, 2007
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Average
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proved
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production
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Identified
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Identified
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Total
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Total
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net daily
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reserves
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PV-10
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index(1)
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drilling
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recompletion
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gross
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net
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production
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Areas
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(Bcfe)
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($ in millions)
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(years)
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locations(2)
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projects(2)
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acreage
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acreage
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(MMcfe/d)
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Permian Basin
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Southeast New Mexico
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387.5
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$
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782.6
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18.7
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1,505
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489
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170,035
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75,606
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63.5
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West Texas
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70.2
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154.5
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15.5
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148
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49
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91,547
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34,358
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13.1
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Emerging Plays and
Other(3)
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9.1
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16.9
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19.2
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23
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2
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245,566
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128,343
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3.1
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Total
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466.8
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$
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954.0
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18.1
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1,676
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540
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507,148
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238,307
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79.7
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(1)
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The pro forma reserve/production
index is the number of years proved reserves would last assuming
current production continued at the same rate. This index is
calculated by dividing pro forma production during the year
ended December 31, 2006, into the proved reserve quantity
as of December 31, 2006. Pro forma production during the
year ended December 31, 2006 was 25,735.0 MMcfe, consisting
of 20,734.0 MMcfe in the Southeast New Mexico part of the
Permian Basin, 4,526.5 MMcfe in the West Texas part of the
Permian Basin and 474.5 MMcfe in Emerging Plays and Other. Pro
forma production information assumes the combination transaction
had taken place on January 1, 2006.
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(2)
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The identified drilling locations
and identified recompletion projects listed in the table above
included 817 drilling locations and recompletion projects
for which proved reserves had been included in our reserve
reports as of December 31, 2006.
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(3)
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Information with respect to
Other includes conventional oil and gas operations
on properties that are not located in the Permian Basin. As of
December 31, 2006, 3.1 Bcfe of the proved reserves and
$5.4 million of the
PV-10, as
well as one of the identified drilling locations and two
identified recompletion projects, were related to oil and
natural gas properties categorized as Other and not
as Emerging Plays. In addition, as of
September 30, 2007, 39,668 gross (28,573 net)
acres reflected above were categorized as Other, and
1.1 MMcfe per day of the average daily production
during the nine months ended September 30, 2007
reflected above were categorized as Other.
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An unconventional emerging resource play generally consists of a
large area that, based on its geological and geophysical
characteristics, indicates the possible existence of a
continuous accumulation of hydrocarbons. These plays are
typically associated with tight, fractured rocks, such as
fractured shales, fractured carbonates, coal seams and tight
sands, which may serve as the source of the hydrocarbons and as
the productive reservoir. In our unconventional emerging
resource plays, we target areas where we can acquire large
undeveloped acreage positions and apply horizontal drilling,
advanced fracture stimulation and enhanced recovery technologies
to achieve economic, repeatable production results. As of
September 30, 2007, we held interests in 205,898 gross
(99,769 net) acres in five unconventional emerging resource
plays. Our current positions include acreage in:
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the Northwest Shelf area in Southeast New Mexico, where we have
tested one re-entry well and drilled thirteen wells targeting
the Wolfcamp Carbonate;
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the Central Basin Platform of West Texas, where we plan to
target the Woodford Shale;
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the Delaware Basin of West Texas, where we have drilled four
exploratory wells targeting the Bone Spring, Atoka, Barnett and
Woodford Shales;
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the North Dakota portion of the Williston Basin, where we have
participated in the drilling of four exploratory wells targeting
the Bakken Shale; and
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the eastern Arkoma Basin in Arkansas, where we plan to drill our
first test well in 2008, which will target the Fayetteville
Shale.
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Our exploration and development budget for our oil and gas
properties for the year ending December 31, 2008 is
approximately $250 million. We plan to spend approximately
92% of this budget on exploration and development activities
associated with our conventional properties in the Permian
Basin, 2% for leasehold acquisitions and 6% for exploration
activities in our unconventional emerging resource plays. If we
achieve successful results from exploratory drilling in our
unconventional emerging resource plays, we may allocate a
greater portion of our planned 2008 capital expenditure budget
to those plays.
Our business
strategy
Our goal is to enhance stockholder value through profitably
increasing reserves, production and cash flow by executing our
strategy as described below:
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Exploit our multi-year project inventory. We
believe our multi-year drilling and exploitation inventory of
2,216 drilling locations and recompletion projects on our
existing properties as of December 31, 2006 will allow us
to grow our proved reserves and production for the next several
years.
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Enhance production from our existing properties through
development of additional producing horizons and enhanced
recovery methods. We have begun to evaluate additional
productive horizons underlying certain of our existing producing
horizons in Southeast New Mexico. During 2006, we drilled
52 wells in the Blinebry interval, all of which have since
been
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completed as producers. During the nine months ended
September 30, 2007, we drilled 58 Blinebry wells, of
which 46 were completed as producers, 11 were awaiting
completion as of September 30, 2007 and 1 was a dry hole.
In addition, in September 2007, we began injecting water on our
pilot waterflood covering approximately 160 acres in the
Paddock interval of the Yeso formation.
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Pursue the acquisition, exploration and development of
unconventional emerging oil and natural gas resource
plays. We have assembled an exploration team to
target unconventional emerging resource plays. Members of our
technical staff, consisting of seven petroleum engineers, seven
geoscientists and ten landmen, have, on average, more than
23 years experience in the industry.
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Make opportunistic acquisitions that meet our strategic
and financial objectives. We seek to acquire oil
and gas properties that we believe complement our existing
properties in our core areas of operation, as well as other
properties that provide opportunities for the addition of
reserves and production through a combination of exploitation,
development, high-potential exploration and control of
operations.
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Our
strengths
We have a number of strengths that we believe will help us
successfully execute our strategy:
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Experienced and incentivized management
team. Our executive officers average over
19 years of experience in the oil and gas industry, having
led both public and private oil and natural gas exploration and
production companies, all of which have had substantially all of
their operations in our core area of the Permian Basin.
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History of growth and capital efficiency.
Despite increasing costs of oilfield services and equipment in
our areas of operation, we added 101 Bcfe of proved
reserves in 2006 through new discoveries and extensions,
excluding revisions of previous estimates, at a total cost of
$193.3 million.
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Large inventory of drilling and recompletion
opportunities. As of December 31, 2006, we had
identified multiple undrilled well locations and recompletion
opportunities, with proved reserves attributed to a portion of
such locations and opportunities. During the nine months ended
September 30, 2007, we drilled 75 wells, of which 59
were completed as producers, 14 were awaiting completion as of
September 30, 2007 and 2 were dry holes. In addition,
during the nine months ended September 30, 2007, we
recompleted 78 wells, of which 75 were producing and 3 were
dry holes.
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Geographically concentrated operations. The
geographic concentration of our current operations in the
Permian Basin allows us to establish economies of scale with
respect to drilling, production, operating and administrative
costs, in addition to further leveraging our base of technical
expertise in this region.
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Significant operational control. Our high
proportion of operated properties enables us to exercise a
significant level of control over the amount and timing of
expenses, capital allocation and other aspects of exploration
and development.
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4
Combination
transaction
We were formed as a Delaware corporation on February 22,
2006, in connection with a combination transaction whereby
certain of the stockholders of Concho Equity Holdings Corp.
exchanged their equity interests in that company for
approximately 26 million shares of our common stock and
options to purchase shares of our common stock, and each of
Chase Oil Corporation, Caza Energy LLC and their affiliated oil
and gas working interest owners (which we refer to herein as the
Chase Group) contributed their interests in certain
oil and gas properties to our company in exchange for
approximately 35 million shares of our common stock and
total cash payments of approximately $409 million. Upon the
initial closing of the combination transaction on
February 27, 2006, the executive officers of Concho Equity
Holdings Corp. became the executive officers of our company. For
more information about the combination transaction, please see
Business and properties Combination
transaction. Prior to the completion of our initial public
offering in August 2007, the field operations of the oil and gas
properties we acquired from the Chase Group were conducted on
our behalf and at our direction by employees of Mack Energy
Corporation, an affiliate of Chase Oil. Upon the completion of
our initial public offering, we assumed those operations. For
more information about our transactions with certain affiliates
of Chase Oil, please see Certain relationships and related
party transactions.
Concho Equity Holdings Corp. was formed in April 2004 by
our existing senior management team and private equity
investors, and it commenced oil and gas operations in December
2004 upon its acquisition of certain oil and natural gas
properties located in Southeast New Mexico and West Texas from
Lowe Partners, L.P. for approximately $117 million, which
properties we refer to herein as the Lowe Properties.
Risk
factors
Investing in our common stock involves risks that include the
speculative nature of oil and natural gas exploration,
competition, volatile oil and natural gas prices and other
material factors. You should read carefully the section entitled
Risk factors for an explanation of these risks
before investing in our common stock. In particular, the
following considerations may offset our business strengths or
have a negative effect on our business strategy as well as on
activities on our properties, which could cause a decrease in
the price of our common stock and result in a loss of all or a
portion of your investment:
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A substantial or extended decline in oil and natural gas prices
may adversely affect our business, financial condition or
results of operations and our ability to meet our capital
expenditure obligations and financial commitments.
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Our development and exploitation projects require 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.
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Reserve estimates depend on many assumptions that may turn out
to be inaccurate. Any material inaccuracies in these reserve
estimates or underlying assumptions could materially reduce the
estimated quantity and present value of our reserves.
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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.
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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. We may not be insured for, or our insurance may be
inadequate to protect us against, these risks.
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Unless we replace our oil and natural gas reserves, our reserves
and production will decline, which would adversely affect our
cash flows, our ability to raise capital and the value of our
common stock.
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The unavailability or high cost of drilling and workover rigs,
equipment, supplies, materials, electricity, personnel and
oilfield services could adversely affect our ability to execute
our exploration and development plans within our budget or on a
timely basis.
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Substantially all of our producing properties are located in
Southeast New Mexico and West Texas, making us vulnerable to
risks associated with operating in one major geographic area.
Furthermore, approximately 53% of our proved reserves as of
December 31, 2006, are from the Yeso formation, which
includes both the Paddock and Blinebry intervals, within this
geographic area, thus making us vulnerable to risks associated
with this concentration of assets.
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Uncertainties associated with enhanced recovery methods may
result in us not realizing an acceptable return on the
investments we make to use such methods.
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For a discussion of other considerations that could negatively
affect us, including risks related to this offering and our
common stock, see Risk factors and Cautionary
statement regarding forward-looking statements.
Corporate
information
Concho Resources Inc. is a Delaware corporation. Our principal
executive offices are located at 550 West Texas Avenue,
Suite 1300, Midland, Texas 79701, and our telephone number
at that address is
(432) 683-7443.
6
The
offering
|
|
|
Common stock offered by the selling stockholders: |
|
8,700,000 shares |
|
|
|
Common stock outstanding as of November 20, 2007(1): |
|
75,833,972 shares |
|
Use of proceeds: |
|
We will not receive any of the proceeds from the sale of the
shares by the selling stockholders. |
|
Dividend policy: |
|
We do not anticipate paying any cash dividends on our common
stock. |
|
New York Stock
Exchange symbol: |
|
CXO |
|
Risk factors: |
|
See Risk factors and the other information included
in this prospectus for a discussion of the factors you should
consider carefully before deciding to invest in shares of our
common stock. |
(1) The number of shares of our common stock outstanding as
of November 20, 2007 excludes:
|
|
|
|
|
3,011,722 shares of our common stock reserved for issuance
upon exercise of stock options that were granted under our stock
option plan at a weighted average exercise price of
$9.71 per share; and
|
|
|
|
2,405,067 shares of our common stock reserved for issuance
pursuant to future awards under our 2006 Stock Incentive Plan.
|
7
Summary
historical and pro forma consolidated
financial data
This section presents our summary historical and pro forma
consolidated financial data. The summary historical consolidated
financial data presented below is not intended to replace our
historical consolidated financial statements.
The following table shows summary historical financial data
related to Concho Resources (as the accounting successor to
Concho Equity Holdings Corp.), combined financial data of the
properties we acquired from the Chase Group (which we refer to
as the Chase Group Properties) and unaudited pro
forma financial data of Concho Resources for the year ended
December 31, 2006 and the nine months ended
September 30, 2007. We have accounted for the combination
transaction that occurred on February 27, 2006, as an
acquisition by Concho Equity Holdings Corp. of the Chase Group
Properties and a simultaneous reorganization of Concho Resources
such that Concho Equity Holdings Corp. is now our wholly owned
subsidiary.
Our historical results of operations for the periods presented
below may not be comparable either from period to period or
going forward, for the following reasons:
|
|
|
Prior to December 7, 2004, Concho Equity Holdings Corp. did
not own any material assets and did not conduct substantial
operations other than organizational activities.
|
|
|
On December 7, 2004, Concho Equity Holdings
Corp. acquired the Lowe Properties for approximately
$117 million and commenced oil and gas operations.
|
|
|
On February 27, 2006, the initial closing of the
combination transaction occurred. Pursuant to the combination
transaction, Concho Resources acquired the Chase Group
Properties for approximately 35 million shares of common
stock and approximately $409 million in cash.
|
|
|
On March 27, 2007, Concho Resources entered into a
$200.0 million second lien term loan facility from which it
received proceeds of $199.0 million that it used to repay
the $39.8 million outstanding under its prior term loan
facility and to reduce the outstanding balance under its
revolving credit facility by $154.0 million, with the
remaining $5.2 million used to pay loan fees, accrued
interest and for general corporate purposes.
|
|
|
In August 2007, Concho Resources completed its initial public
offering of common stock from which it received proceeds of
$173.0 million that it used to retire outstanding
borrowings under its second lien term loan facility totaling
$86.5 million and to retire outstanding borrowings under
its revolving credit facility totaling $86.5 million.
|
The summary historical financial data for the Chase Group
Properties for the years ended December 31, 2004 and 2005
are derived from the audited financial statements of the Chase
Group Properties. The summary historical financial data for
Concho Resources for the period from inception (April 21,
2004) through December 31, 2004, and for the years
ended December 31, 2005 and 2006, are derived from the
audited financial statements of Concho Resources. The summary
historical financial data for Concho Resources for the nine
months ended September 30, 2006 and 2007, are derived from
the unaudited financial statements of Concho Resources.
The summary pro forma financial data for the year ended
December 31, 2006 and the nine months ended
September 30, 2007 set forth in the following table are
derived from the unaudited pro forma financial statements of
Concho Resources included in this prospectus. The pro forma
statement of operations data has been prepared as if the closing
of the combination
8
transaction and the completion of our initial public offering
had taken place as of January 1, 2006.
You should read the following data along with Selected
historical consolidated financial information,
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 prospectus. You should also read the pro forma
information together with the unaudited pro forma combined
financial statements and related notes included in this
prospectus.
9
The following table includes the non-GAAP financial measure
EBITDA. For a definition of this measure and a reconciliation to
its most directly comparable financial measure calculated and
presented in accordance with generally accepted accounting
principles, which we refer to as GAAP, please read
Non-GAAP financial measures and
reconciliations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chase Group
|
|
Concho Resources Inc.
|
|
|
|
Properties
|
|
Inception
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(April 21,
|
|
|
|
|
|
Pro forma
|
|
|
|
|
|
|
|
|
2004)
|
|
|
|
|
|
|
|
|
Nine months
|
|
|
Nine months
|
|
|
|
Years ended
|
|
through
|
|
|
Years ended
|
|
|
Year ended
|
|
|
ended
|
|
|
ended
|
|
|
|
December 31,
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
September 30,
|
|
|
September 30,
|
|
(In thousands, except per share amounts)
|
|
2004
|
|
2005
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
Statement of operations data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
66,529
|
|
$
|
73,132
|
|
$
|
1,851
|
|
|
$
|
31,621
|
|
|
$
|
131,773
|
|
|
$
|
145,713
|
|
|
$
|
128,152
|
|
|
$
|
90,737
|
|
|
$
|
128,152
|
|
Natural gas sales
|
|
|
41,247
|
|
|
46,546
|
|
|
1,771
|
|
|
|
23,315
|
|
|
|
66,517
|
|
|
|
74,033
|
|
|
|
67,395
|
|
|
|
44,908
|
|
|
|
67,395
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
107,776
|
|
|
119,678
|
|
|
3,622
|
|
|
|
54,936
|
|
|
|
198,290
|
|
|
|
219,746
|
|
|
|
195,547
|
|
|
|
135,645
|
|
|
|
195,547
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
11,762
|
|
|
12,979
|
|
|
512
|
|
|
|
10,923
|
|
|
|
22,060
|
|
|
|
24,456
|
|
|
|
22,309
|
|
|
|
14,511
|
|
|
|
22,309
|
|
Oil and gas production taxes
|
|
|
9,202
|
|
|
10,298
|
|
|
234
|
|
|
|
3,712
|
|
|
|
15,762
|
|
|
|
17,602
|
|
|
|
15,616
|
|
|
|
10,831
|
|
|
|
15,616
|
|
Exploration and abandonments
|
|
|
179
|
|
|
|
|
|
1,850
|
|
|
|
2,666
|
|
|
|
5,612
|
|
|
|
5,612
|
|
|
|
18,110
|
|
|
|
4,717
|
|
|
|
18,110
|
|
Depreciation, depletion and accretion
|
|
|
20,459
|
|
|
19,092
|
|
|
963
|
|
|
|
11,574
|
|
|
|
61,009
|
|
|
|
66,520
|
|
|
|
55,370
|
|
|
|
42,366
|
|
|
|
55,370
|
|
Impairments of proved oil and gas properties
|
|
|
3,233
|
|
|
194
|
|
|
|
|
|
|
2,295
|
|
|
|
9,891
|
|
|
|
9,892
|
|
|
|
4,577
|
|
|
|
5,762
|
|
|
|
4,577
|
|
Contract drilling feesstacked rigs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,269
|
|
|
|
|
|
|
|
4,269
|
|
General and administrative
|
|
|
1,387
|
|
|
1,702
|
|
|
3,086
|
|
|
|
8,055
|
|
|
|
12,577
|
|
|
|
12,861
|
|
|
|
13,911
|
|
|
|
8,003
|
|
|
|
13,911
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
1,128
|
|
|
|
3,252
|
|
|
|
9,144
|
|
|
|
9,144
|
|
|
|
2,656
|
|
|
|
8,041
|
|
|
|
2,656
|
|
Ineffective portion of cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
1,148
|
|
|
|
(1,193
|
)
|
|
|
(1,193
|
)
|
|
|
1,134
|
|
|
|
(64
|
)
|
|
|
1,134
|
|
(Gain) loss on derivatives not designated as hedges
|
|
|
7,936
|
|
|
1,062
|
|
|
(684
|
)
|
|
|
5,001
|
|
|
|
|
|
|
|
|
|
|
|
(3,088
|
)
|
|
|
|
|
|
|
(3,088
|
)
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
54,158
|
|
|
45,327
|
|
|
7,089
|
|
|
|
48,626
|
|
|
|
134,862
|
|
|
|
144,894
|
|
|
|
134,864
|
|
|
|
94,167
|
|
|
|
134,864
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
53,618
|
|
|
74,351
|
|
|
(3,467
|
)
|
|
|
6,310
|
|
|
|
63,428
|
|
|
|
74,852
|
|
|
|
60,683
|
|
|
|
41,478
|
|
|
|
60,683
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
|
|
|
|
|
|
(272
|
)
|
|
|
(3,096
|
)
|
|
|
(30,567
|
)
|
|
|
(21,677
|
)
|
|
|
(20,819
|
)
|
|
|
(20,998
|
)
|
|
|
(29,803
|
)
|
Other, net
|
|
|
|
|
|
|
|
|
168
|
|
|
|
779
|
|
|
|
1,186
|
|
|
|
636
|
|
|
|
787
|
|
|
|
907
|
|
|
|
957
|
|
|
|
|
|
|
|
Total other expense
|
|
|
|
|
|
|
|
|
(104
|
)
|
|
|
(2,317
|
)
|
|
|
(29,381
|
)
|
|
|
(21,041
|
)
|
|
|
(20,032
|
)
|
|
|
(20,091
|
)
|
|
|
(28,846
|
)
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
53,618
|
|
|
74,351
|
|
|
(3,571
|
)
|
|
|
3,993
|
|
|
|
34,047
|
|
|
|
53,811
|
|
|
|
40,651
|
|
|
|
21,387
|
|
|
|
31,837
|
|
Income tax (expense) benefit
|
|
|
|
|
|
|
|
|
915
|
|
|
|
(2,039
|
)
|
|
|
(14,379
|
)
|
|
|
(22,086
|
)
|
|
|
(17,031
|
)
|
|
|
(8,664
|
)
|
|
|
(13,335
|
)
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
53,618
|
|
$
|
74,351
|
|
|
(2,656
|
)
|
|
|
1,954
|
|
|
|
19,668
|
|
|
|
31,725
|
|
|
|
23,620
|
|
|
|
12,723
|
|
|
|
18,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
(804
|
)
|
|
|
(4,766
|
)
|
|
|
(1,244
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,210
|
)
|
|
|
(45
|
)
|
Effect of induced conversion of preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,601
|
|
|
|
|
|
|
|
|
|
|
|
11,601
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) applicable to common shareholders
|
|
|
|
|
|
|
|
$
|
(3,460
|
)
|
|
$
|
(2,812
|
)
|
|
$
|
30,025
|
|
|
$
|
31,725
|
|
|
$
|
23,620
|
|
|
$
|
23,114
|
|
|
$
|
18,457
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
(unaudited)
|
|
$
|
74,077
|
|
$
|
93,443
|
|
$
|
(2,336
|
)
|
|
$
|
18,663
|
|
|
$
|
125,623
|
|
|
$
|
142,008
|
|
|
$
|
116,840
|
|
|
$
|
84,751
|
|
|
$
|
117,010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
|
|
|
|
|
|
|
|
$
|
(3.48
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
0.63
|
|
|
$
|
0.45
|
|
|
$
|
0.31
|
|
|
$
|
0.52
|
|
|
$
|
0.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in basic earnings (loss) per share
|
|
|
|
|
|
|
|
|
994
|
|
|
|
4,059
|
|
|
|
47,287
|
|
|
|
70,634
|
|
|
|
77,114
|
|
|
|
44,710
|
|
|
|
60,648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
|
|
|
|
|
|
|
|
$
|
(3.48
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
0.59
|
|
|
$
|
0.43
|
|
|
$
|
0.30
|
|
|
$
|
0.48
|
|
|
$
|
0.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in diluted earnings (loss) per share
|
|
|
|
|
|
|
|
|
994
|
|
|
|
4,059
|
|
|
|
50,729
|
|
|
|
74,172
|
|
|
|
79,324
|
|
|
|
47,937
|
|
|
|
62,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chase Group
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Properties
|
|
|
Concho Resources Inc.
|
|
|
|
|
|
|
|
|
|
Inception (April 21,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended
|
|
|
2004) through
|
|
|
Years ended
|
|
|
Nine months ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
September 30,
|
|
(In thousands)
|
|
2004
|
|
|
2005
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
Other financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operations
|
|
$
|
84,202
|
|
|
$
|
93,162
|
|
|
$
|
(2,193
|
)
|
|
$
|
25,070
|
|
|
$
|
112,181
|
|
|
$
|
58,941
|
|
|
$
|
102,932
|
|
Net cash provided by (used in) investing
|
|
|
(30,045
|
)
|
|
|
(35,611
|
)
|
|
|
(122,473
|
)
|
|
|
(61,902
|
)
|
|
|
(596,852
|
)
|
|
|
(537,930
|
)
|
|
|
(115,028
|
)
|
Net cash provided by (used in) financing
|
|
|
(54,157
|
)
|
|
|
(57,551
|
)
|
|
|
125,322
|
|
|
|
45,358
|
|
|
|
476,611
|
|
|
|
469,807
|
|
|
|
30,842
|
|
Capital expenditures
|
|
|
25,451
|
|
|
|
32,352
|
|
|
|
116,880
|
|
|
|
72,758
|
|
|
|
1,226,180
|
|
|
|
1,162,328
|
|
|
|
125,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chase Group
|
|
|
|
|
|
|
|
|
|
|
Properties
|
|
Concho Resources Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of December 31,
|
|
As of December 31,
|
|
September 30,
|
(In thousands)
|
|
2004
|
|
2005
|
|
2004
|
|
2005
|
|
2006
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
Balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
|
|
$
|
|
|
$
|
656
|
|
$
|
9,182
|
|
$
|
1,122
|
|
$
|
19,868
|
Property and equipment, net
|
|
|
135,568
|
|
|
149,042
|
|
|
115,455
|
|
|
170,583
|
|
|
1,320,655
|
|
|
1,368,026
|
Total assets
|
|
|
145,100
|
|
|
161,792
|
|
|
130,717
|
|
|
232,385
|
|
|
1,390,072
|
|
|
1,443,507
|
Long-term debt, including current maturities
|
|
|
|
|
|
|
|
|
53,000
|
|
|
72,000
|
|
|
495,500
|
|
|
345,880
|
Stockholders equity/net investment
|
|
|
134,014
|
|
|
150,814
|
|
|
71,710
|
|
|
109,670
|
|
|
575,156
|
|
|
773,384
|
|
|
|
|
|
(1)
|
|
EBITDA is defined as net income,
plus (1) interest, the amortization of related debt
issuance costs and other financial costs, net of capitalized
interest, (2) federal and state income taxes and
(3) depreciation, depletion and accretion. See
Non-GAAP financial measures and
reconciliations.
|
11
Summary reserve
and pro forma production
and operating data (unaudited)
The following estimates of net proved oil and natural gas
reserves as of December 31, 2006 and pro forma net proved
oil and natural gas reserves as of December 31, 2005, are
based on reports prepared by Netherland, Sewell &
Associates, Inc. and Cawley, Gillespie & Associates,
Inc., independent petroleum engineers. In preparing their
reports, Netherland, Sewell & Associates, Inc. and
Cawley, Gillespie & Associates, Inc. evaluated
properties representing 100% of our
PV-10 as of
the end of the applicable periods. Summaries of the Netherland,
Sewell & Associates, Inc. and Cawley,
Gillespie & Associates, Inc. reports on our proved
reserves as of December 31, 2006, are attached to this
prospectus as Annex A and Annex B, respectively. All
calculations of estimated net proved reserves have been made in
accordance with the rules and regulations of the SEC. Please
read Risk factors, Managements
discussion and analysis of financial condition and results of
operations, Business and propertiesOur oil and
natural gas reserves, Business and
propertiesOur production, prices and expenses, and
the Netherland, Sewell & Associates, Inc. and Cawley,
Gillespie & Associates, Inc. summary reports included
in this prospectus in evaluating the material presented below.
The pro forma reserve data was prepared as if the combination
transaction had taken place on December 31, 2005 for proved
reserves data. The pro forma production data was prepared as if
the combination transaction had taken place on January 1,
2006 for production, price and cost data.
|
|
|
|
|
|
|
|
|
|
Pro forma as of
|
|
As of
|
|
|
December 31, 2005
|
|
December 31, 2006
|
|
|
Proved reserves:
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
37,492
|
|
|
44,322
|
Natural gas (MMcf)
|
|
|
190,938
|
|
|
200,818
|
Natural gas equivalent (MMcfe)
|
|
|
415,890
|
|
|
466,750
|
Proved developed reserves percentage
|
|
|
55.0%
|
|
|
54.2%
|
PV-10 (in
millions)(1)
|
|
$
|
1,324.5
|
|
$
|
954.0
|
Estimated reserve life (in
years)(2)
|
|
|
18.7
|
|
|
18.1
|
|
|
|
|
(1)
|
PV-10
is a non-GAAP financial measure and generally differs from
standardized measure, the most directly comparable GAAP
financial measure, because it does not include the effects of
income taxes on future net revenues. See Non-GAAP
financial measures and reconciliations. Prices used in the
computation of future net cash flows were adjusted for location
and quality by field, and were $61.04 per Bbl and
$10.08 per MMBtu for purposes of estimating pro forma net
proved reserves as of December 31, 2005 and were
$57.75 per Bbl and $5.64 per MMBtu for purposes of
estimating net proved reserves as of December 31, 2006.
|
|
(2)
|
Calculated by dividing proved
reserves by pro forma production volumes for the years indicated.
|
12
|
|
|
|
|
|
|
|
|
|
Pro forma
|
|
Nine months
|
|
|
year ended
|
|
ended
|
|
|
December 31,
|
|
September 30,
|
|
|
2006
|
|
2007
|
|
|
Net production volumes:
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
2,539.6
|
|
|
2,143.2
|
Natural gas (MMcf)
|
|
|
10,497.6
|
|
|
8,887.5
|
Natural gas equivalent (MMcfe)
|
|
|
25,735.0
|
|
|
21,746.9
|
Average prices:
|
|
|
|
|
|
|
Oil, without hedges ($/Bbl)
|
|
$
|
60.13
|
|
$
|
61.36
|
Oil, with hedges ($/Bbl)
|
|
$
|
57.38
|
|
$
|
59.79
|
Natural gas, without hedges ($/Mcf)
|
|
$
|
6.94
|
|
$
|
7.48
|
Natural gas, with hedges ($/Mcf)
|
|
$
|
7.05
|
|
$
|
7.58
|
Natural gas equivalent, without hedges ($/Mcfe)
|
|
$
|
8.76
|
|
$
|
9.10
|
Natural gas equivalent, with hedges ($/Mcfe)
|
|
$
|
8.54
|
|
$
|
8.99
|
Operating costs and expenses:
|
|
|
|
|
|
|
Oil and gas production ($/Mcfe)
|
|
$
|
0.95
|
|
$
|
1.03
|
Oil and gas production taxes ($/Mcfe)
|
|
$
|
0.68
|
|
$
|
0.72
|
General and administrative ($/Mcfe)
|
|
$
|
0.50
|
|
$
|
0.64
|
Depreciation and depletion expense ($/Mcfe)
|
|
$
|
2.57
|
|
$
|
2.53
|
|
13
Non-GAAP
financial measures and reconciliations
(unaudited)
PV-10
The 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%. We believe that the presentation of
the PV-10 is
relevant and useful to investors because it presents the
discounted future net cash flows attributable to our estimated
net proved reserves prior to taking into account future
corporate income taxes, and it is a useful measure for
evaluating the relative monetary significance of our oil and
natural gas properties. Further, investors may utilize the
measure as a basis for comparison of the relative size and value
of our reserves to other companies. We use this measure when
assessing the potential return on investment related to our oil
and natural gas properties.
PV-10,
however, is not a substitute for the standardized measure 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 the
standardized measure of discounted future net cash flows to
PV-10 as of
December 31, 2005 and 2006.
|
|
|
|
|
|
|
|
|
|
|
(Dollars in millions)
|
|
Pro forma 2005
|
|
|
2006
|
|
|
|
|
PV-10
|
|
$
|
1,324.5
|
|
|
$
|
954.0
|
|
Present value of future income tax discounted at 10%
|
|
|
(379.7
|
)
|
|
|
(243.7
|
)
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
$
|
944.8
|
|
|
$
|
710.3
|
|
|
|
|
|
|
|
EBITDA
We define EBITDA as net income, plus (1) interest, the
amortization of related debt issuance costs and other financing
costs, net of capitalized interest, (2) federal and state
income taxes and (3) depreciation, depletion and accretion.
EBITDA is not a measure of net income or cash flow as determined
by generally accepted accounting principles.
Our EBITDA measure provides additional information which may be
used to better understand our operations. EBITDA 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, as an
alternative to cash flows from operating activities or as a
measure of liquidity. Certain items excluded from EBITDA 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 assets, none of which are components of EBITDA.
EBITDA as used by us may not be comparable to similarly titled
measures reported by other companies. We believe that EBITDA 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. For example, EBITDA can
be used to assess our operating performance and return on
capital in comparison to other independent exploration and
production companies, without regard to
14
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. EBITDA on a pro
forma basis for the year ended December 31, 2006 and the
nine months ended September 30, 2007, gives effect to the
combination transaction and the initial public offering of our
common stock as if they had occurred on January 1, 2006.
The following table provides a reconciliation of net income
(loss) to EBITDA.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chase Group Properties
|
|
Concho Resources Inc.
|
|
|
|
|
|
|
Inception
|
|
|
|
|
|
|
|
Pro forma
|
|
|
|
|
|
|
|
|
|
|
(April 21, 2004)
|
|
|
|
|
|
Pro forma
|
|
nine months
|
|
|
|
|
|
|
Years ended
|
|
through
|
|
Years ended
|
|
year ended
|
|
ended
|
|
Nine months
|
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
September 30,
|
|
ended September 30,
|
(In thousands)
|
|
2004
|
|
2005
|
|
2004
|
|
2005
|
|
2006
|
|
2006
|
|
2007
|
|
2006
|
|
2007
|
|
|
Net income (loss)
|
|
$
|
53,618
|
|
|
$
|
74,351
|
|
|
$
|
(2,656
|
)
|
|
$
|
1,954
|
|
$
|
19,668
|
|
$
|
31,725
|
|
$
|
23,620
|
|
$
|
12,723
|
|
$
|
18,502
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
272
|
|
|
|
3,096
|
|
|
30,567
|
|
|
21,677
|
|
|
20,819
|
|
|
20,998
|
|
|
29,803
|
Income tax expense (benefit)
|
|
|
|
|
|
|
|
|
|
|
(915
|
)
|
|
|
2,039
|
|
|
14,379
|
|
|
22,086
|
|
|
17,031
|
|
|
8,664
|
|
|
13,335
|
Depreciation, depletion and accretion
|
|
|
20,459
|
|
|
|
19,092
|
|
|
|
963
|
|
|
|
11,574
|
|
|
61,009
|
|
|
66,520
|
|
|
55,370
|
|
|
42,366
|
|
|
55,370
|
|
|
|
|
|
|
EBITDA
|
|
$
|
74,077
|
|
|
$
|
93,443
|
|
|
$
|
(2,336
|
)
|
|
$
|
18,663
|
|
$
|
125,623
|
|
$
|
142,008
|
|
$
|
116,840
|
|
$
|
84,751
|
|
$
|
117,010
|
|
|
|
|
|
|
|
|
15
You should carefully consider the risk factors set forth
below as well as the other information contained in this
prospectus before investing in our common stock. Any of the
following risks could materially and adversely affect our
business, financial condition or results of operations. In such
a case, you may lose all or part of your investment. The risks
described below are not the only risks facing us. Additional
risks and uncertainties not currently known to us or those we
currently view to be immaterial may also materially adversely
affect our business, financial condition or results of
operations.
Risks relating 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 flows, 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 our
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,
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 and South America;
|
|
|
technological advances affecting energy consumption; and
|
|
|
worldwide economic conditions.
|
Declines in oil and natural gas prices would not only reduce our
revenue, but could 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
16
obtain additional capital on attractive terms, all of which can
affect the value of our common stock.
Furthermore, recent oil prices have been high compared to
historical prices and have been particularly volatile. For
example, the NYMEX crude oil price per Bbl was $32.52, $43.45,
$61.04 and $61.05 as of December 31, 2003, 2004, 2005 and
2006, respectively, and during the ten months ended
October 31, 2007, the NYMEX crude oil spot price has ranged
from a high of $94.53 to a low of $50.48. In addition, natural
gas prices have been subject to significant fluctuations during
the past several years. For example, the NYMEX natural gas price
per Mcf was $5.96, $6.18, $10.08 and $5.64 as of
December 31, 2003, 2004, 2005 and 2006, respectively, and
during the ten months ended October 31, 2007, the NYMEX
natural gas spot price ranged from a high of $9.14 to a low of
$5.30.
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 exploitation, 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. For a
discussion of the uncertainty involved in these processes, see
Reserve estimates depend on many assumptions that
may turn out to be inaccurate. Any material inaccuracies in
these reserve estimates or underlying assumptions could
materially affect the quantities and present value of our
reserves. 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. 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;
|
|
|
title problems; and
|
|
|
limitations in the market for oil and natural gas.
|
17
Reserve estimates
depend on many assumptions that may turn out to be inaccurate.
Any material inaccuracies in these reserve estimates or
underlying assumptions could materially reduce the estimated
quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is
complex. It requires interpretations of available technical data
and many estimates, including estimates based upon assumptions
relating to economic factors. Any significant inaccuracies in
these interpretations or estimates could materially reduce the
estimated quantities and present value of reserves shown in this
prospectus. See Business and propertiesOur oil and
natural gas reserves for information about our oil and
natural gas reserves.
In order to prepare our estimates, we must project production
rates and timing of development expenditures. We must also
analyze available geological, geophysical, production and
engineering data. The extent, quality and reliability of this
data can vary. The process also requires economic assumptions
about matters such as oil and natural gas prices, drilling and
operating expenses, the amount and timing of capital
expenditures, taxes and the availability of funds.
Actual future production, oil and natural gas prices, revenues,
taxes, development expenditures, operating expenses and
quantities of recoverable oil and natural gas reserves most
likely will vary from our estimates. Any significant variance
could materially affect the estimated quantities and present
value of reserves shown in this prospectus. For example, in
connection with the preparation of our total estimated net
proved reserves as of December 31, 2006, we revised our
estimated natural gas reserves downward by 16,595 MMcf from
our previous estimates. This reduction in natural gas reserves
was primarily because of the decrease in natural gas prices
during 2006. In addition, we may adjust estimates of proved
reserves to reflect production history, results of exploration
and development, prevailing oil and natural gas prices and other
factors.
You should not assume that the present value of future net
revenues from our proved reserves referred to in this prospectus
is the current market value of our estimated oil and natural gas
reserves. In accordance with SEC requirements, we generally base
the estimated discounted future net cash flows from our proved
reserves on prices and costs on the date of the estimate. Actual
future prices and costs may differ materially from those used in
the present value estimate. The present value of future net
revenues from our proved reserves as of December 31, 2006
referred to in this prospectus was based on a $57.75 per
Bbl price for oil and a $5.64 per MMBtu price for natural
gas. If oil prices were $1.00 per Bbl lower than the price
we used, our
PV-10 as of
December 31, 2006, would have decreased from
$954.0 million to $934.9 million. If natural gas
prices were $0.10 per Mcf lower than the price we used, our
PV-10 as of
December 31, 2006, would have decreased from
$954.0 million to $945.3 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.
Almost all of our
producing properties are located in the Permian Basin region of
Southeast New Mexico and West Texas, making us vulnerable to
risks associated with operating in one major geographic area. In
addition, a substantial portion of our proved reserves as of
December 31, 2006, are from a single producing horizon
within this area.
Our producing properties are geographically concentrated in the
Permian Basin region of Southeast New Mexico and West Texas. At
December 31, 2006, approximately 99% of our
PV-10 was
attributable to properties located in the Permian Basin. As a
result of this concentration, we
18
may be disproportionately exposed to the impact of regional
supply and demand factors, delays or interruptions of production
from these wells caused by significant governmental regulation,
processing or transportation capacity constraints, market
limitations, curtailment of production or interruption of the
processing or transportation of oil and natural gas produced
from the wells in these areas.
In addition to the geographic concentration of our producing
properties described above, approximately 53% of our proved
reserves as of December 31, 2006, were attributable to the
Yeso formation, which includes both the Paddock and Blinebry
intervals, underlying our oil and gas properties located in
Southeast New Mexico. This concentration of assets within one
producing horizon exposes us to 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 the
field. Furthermore, we are in the process of drilling and
completing wells in the Blinebry interval (the lower member of
the Yeso formation), which lies beneath the Paddock interval on
certain of our properties located in Southeast New Mexico. These
activities could result in delays in the production of our
proved reserves from the Paddock interval in the event that
commingling of both formations is imprudent or otherwise not
feasible.
Part of our
strategy involves exploratory drilling, including drilling in
new or emerging plays. As a result, our drilling results in
these areas are uncertain, and the value of our undeveloped
acreage will decline if drilling results are
unsuccessful.
The results of our exploratory drilling in new or emerging areas
are more uncertain than drilling results in areas that are
developed and have established production. Since new or emerging
plays and new formations have limited or no production history,
we are unable to use past drilling results in those areas to
help predict our future drilling results. As a result, our cost
of drilling, completing and operating wells in these areas may
be higher than initially expected, and the value of our
undeveloped acreage will decline if drilling results are
unsuccessful.
Our commodity
price risk management program may cause us to forego additional
future profits or result in our making cash payments to our
counterparties.
To reduce our exposure to changes in the prices of 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 contract counterparty.
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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. As of September 30, 2007, the net unrealized
loss
19
on our commodity price risk management contracts was
$9.7 million. An average increase in the commodity price of
$1.00 per barrel of crude oil and $0.10 per Mcf for
natural gas from the commodity prices as of September 30,
2007 would have resulted in an increase in the net unrealized
loss on our commodity price risk management contracts as
reflected on our balance sheet as of September 30, 2007 of
approximately $3 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 continue to increase and our derivatives contracts remain
in place. See Managements discussion and analysis of
financial condition and results of operationsLiquidity and
capital resourcesHedging.
If we enter into
derivative instruments that require us to post cash collateral,
our cash otherwise available for use in our operations would be
reduced, which could limit our ability to make future capital
expenditures.
The use of derivatives may, in some cases, require the posting
of cash collateral with counterparties. If we enter into
derivative instruments that require cash collateral and
commodity prices change in a manner adverse to us, our cash
otherwise available for use in our operations would be reduced,
which could limit our ability to make future capital
expenditures. Future collateral requirements will depend on
arrangements with our counterparties and highly volatile oil and
natural gas prices.
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
in our business for the development, exploitation, production
and acquisition of oil and natural gas reserves. For example,
during the first three months of 2007, we curtailed our drilling
program in order to preserve liquidity until we could complete
our second lien term loan facility. As of September 30,
2007, our total debt outstanding was $345.9 million, and
$141.0 million was available to be borrowed under our revolving
credit facility. Expenditures for exploration and development of
oil and natural gas properties are the primary use of our
capital resources. We anticipate investing approximately
$183 million and $250 million for exploration and
development expenditures in 2007 and 2008, respectively. See
Managements discussion and analysis of financial
condition and results of operations Liquidity and
capital resources Future capital expenditures and
commitments.
We intend to finance our future capital expenditures primarily
through cash flow from operations and through borrowings under
our revolving 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 your common stock. Additional borrowings under our
revolving credit facility or the issuance of additional debt
will require that a greater portion of our cash flow from
operations be used for the payment of interest and principal on
our debt, thereby reducing our ability to use cash flow to fund
working capital, capital expenditures and acquisitions. In
addition, our bank credit facilities impose certain limitations
on our ability to incur additional indebtedness other than
indebtedness under our revolving credit facility. If we desire
to issue additional debt securities other than as expressly
permitted under our bank credit facilities, we will be required
to seek the consent of the lenders in accordance with the
requirements of those
20
facilities, which consent may be withheld by the lenders under
our bank credit facilities in their discretion. Additional
financing also may not be available on acceptable terms or at
all. In the event additional capital resources are unavailable,
we may curtail drilling, development and other activities or be
forced to sell some of our assets on an untimely or unfavorable
basis.
Our cash flow from operations and access to capital are subject
to a number of variables, including:
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our proved reserves;
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the level of oil and natural gas we are able to produce from
existing wells;
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the prices at which our oil and natural gas are sold; and
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our ability to acquire, locate and produce new reserves.
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If our revenues or the borrowing base under our revolving credit
facility decrease as a result of lower oil or natural gas
prices, operating difficulties, declines in reserves, lending
requirements or regulations, or for any other reason, we may
have limited ability to obtain the capital necessary to sustain
our operations at current levels. As a result, we may require
additional capital to fund our operations, and we may not be
able to obtain debt or equity financing to satisfy our capital
requirements. If cash generated from operations or cash
available under our revolving credit facility is not sufficient
to meet our capital requirements, the failure to obtain
additional financing could result in a curtailment of our
operations relating to development of our prospects, which in
turn could lead to a decline in our oil and natural gas
reserves, and could adversely affect our business, financial
condition and results of operations.
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.
Our management has specifically identified and scheduled the
drilling and recompletion of our drilling and recompletion
opportunities as an estimation of our future multi-year
development activities on our existing acreage. As of
December 31, 2006, we had identified 1,676 drilling
locations with proved undeveloped reserves attributable to 595
of such locations, and 540 recompletion opportunities with
proved reserves attributed to 222 of such opportunities. These
identified opportunities represent a significant part of our
growth strategy. Our ability to drill and develop these
opportunities depends on a number of uncertainties, including
the availability of capital, equipment, services and personnel,
seasonal conditions, regulatory and third party approvals, oil
and natural gas prices, costs and drilling and recompletion
results. Because of these uncertainties, we may never drill or
recomplete the numerous potential opportunities we have
identified or produce oil or natural gas from these or any other
potential opportunities. As such, our actual development
activities may materially differ from those presently
identified, which could adversely affect our business.
Approximately 46%
of our total estimated net proved reserves as of
December 31, 2006, were undeveloped, and those reserves may
not ultimately be developed.
As of December 31, 2006, approximately 46% of our total
estimated net proved reserves were undeveloped. Recovery of
undeveloped reserves requires significant capital expenditures
and successful drilling. The reserve data assumes that we can
and will make these expenditures and
21
conduct these operations successfully. These assumptions,
however, may not prove correct. If we choose not to spend the
capital to develop these reserves, or if we are not able to
successfully develop these reserves, we will be required to
write-off these reserves. Any such write-offs of our reserves
could reduce our ability to borrow money and could reduce the
value of our common stock.
Because we do not
control the development of the properties we own but do not
operate, we may not be able to achieve any production from these
properties in a timely manner.
As of December 31, 2006, approximately 11% of our
PV-10 was
attributable to properties for which we were not designated as
the operator. As a result, the success and timing of our
drilling and development activities on such nonoperated
properties depend upon a number of factors, including:
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the nature and timing of drilling and operational activities;
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the timing and amount of capital expenditures;
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the operators expertise and financial resources;
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the approval of other participants in such properties; and
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the selection of suitable technology.
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If drilling and development activities are not conducted on
these properties or are not conducted on a timely basis, we may
be unable to increase our production or offset normal production
declines, which may adversely affect our production, revenues
and results of operations.
Unless we replace
our oil and natural gas reserves, our reserves and production
will decline, which would adversely affect our cash flows, our
ability to raise capital and the value of our common
stock.
Unless we conduct successful development, exploitation and
exploration activities or acquire properties containing proved
reserves, our proved reserves will decline as those reserves are
produced. Producing 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 integrate acquired companies,
and any inability to do so may disrupt our business and hinder
our ability to grow through the acquisition of
businesses.
One aspect of our business strategy calls for acquisitions of
businesses that complement or expand our current business. We
may not be able to identify attractive acquisition
opportunities.
22
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 bank credit facilities impose certain direct
limitations on our ability to enter into mergers or combination
transactions involving our company. Our bank credit facilities
also limit our ability to incur certain indebtedness, which
could indirectly limit our ability to engage in acquisitions of
businesses. If we desire to engage in an acquisition that is
otherwise prohibited by our bank credit facilities, we will be
required to seek the consent of the lenders in accordance with
the requirements of those facilities, which consent may be
withheld by the lenders under our bank credit facilities in
their discretion.
If we acquire another business, we could have difficulty
integrating its operations, systems, management and other
personnel and technology with our own. These difficulties could
disrupt our ongoing business, distract our management and
employees, increase our expenses and adversely affect our
results of operations. In addition, we may incur additional debt
or issue additional equity to pay for any future acquisitions,
subject to the limitations described above.
Acquisitions may
prove to be worth less than we paid because of uncertainties in
evaluating recoverable reserves and potential
liabilities.
We obtained nearly all of our current reserve base through
acquisitions of producing properties and undeveloped acreage. We
expect acquisitions will continue to contribute to our future
growth. Successful acquisitions require an assessment of a
number of factors, including estimates of recoverable reserves,
exploration potential, future oil and gas prices, operating
costs and potential environmental and other liabilities. Such
assessments are inexact and we cannot make these assessments
with a high degree of accuracy. In connection with our
assessments, we perform a review of the acquired properties.
However, such a review will not reveal all existing or potential
problems. In addition, our review may not permit us to become
sufficiently familiar with the properties to fully assess their
deficiencies and capabilities. We do not inspect every well.
Even when we inspect a well, we do not always discover
structural, subsurface and environmental problems that may exist
or arise.
We are generally not entitled to contractual indemnification for
preclosing liabilities, including environmental liabilities.
Normally, we acquire interests in properties on an as
is basis with limited remedies for breaches of
representations and warranties.
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
23
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 increased compensation for trained personnel could
have a material adverse effect on our business.
Shortages of oil
field 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
rigs 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 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
efforts, not only from dry holes but also from wells that are
productive but do not produce sufficient net reserves to return
a profit at then realized prices after deducting drilling,
operating and other costs. The cost of drilling, completing and
operating a well is often uncertain, and cost factors can
adversely affect the economics of a project. Further, our
drilling operations may be curtailed, delayed or canceled as a
result of numerous factors, including:
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unexpected drilling conditions;
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title problems;
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pressure or lost circulation in formations;
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equipment failures or accidents;
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adverse weather conditions;
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compliance with environmental and other governmental or
contractual requirements; and
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24
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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 our company 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 business, financial condition
or results of operations.
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 and the
proximity of reserves to pipelines and terminal facilities. Our
ability to market our production
25
depends in substantial part on the availability and capacity of
gathering systems, pipelines and processing facilities owned and
operated by third parties. Our failure to obtain such services
on acceptable terms could have a material adverse effect on our
business, financial condition and results of operations. We may
be required to shut in wells due to lack of a market or
inadequacy or unavailability of crude oil or natural gas
pipeline or gathering system capacity. If that were to occur,
then we would be unable to realize revenue from those wells
until suitable arrangements were made to market our production.
We are subject to
complex federal, state, local and other laws and regulations
that could adversely affect the cost, timing, manner or
feasibility of conducting our operations.
Our oil and natural gas exploration, development and production,
and saltwater disposal operations are subject to complex and
stringent laws and regulations. In order to conduct our
operations in compliance with these laws and regulations, we
must obtain and maintain numerous permits, approvals and
certificates from various federal, state, local and governmental
authorities. We may incur substantial costs and experience
delays in order to maintain compliance with these existing laws
and regulations. In addition, our costs of compliance may
increase or 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. For instance, the New Mexico Oil Conservation
Division is considering amending or replacing an existing rule
regulating the permitting, construction, operation and closure
of oilfield pits at well sites in New Mexico. If the agency
adopts a new or revised pit rule that imposes stricter
requirements on the construction and use of oilfield pits, then
it is possible that the cost to operate our wells in New Mexico
could increase. These and other future costs could have a
material adverse effect on our business, financial condition or
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
business, financial condition or results of operations. Please
read Business and propertiesApplicable laws and
regulations for a description of the laws and regulations
that affect us.
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 saltwater disposal activities. These delays,
costs and liabilities could arise under a wide range of federal,
state and local laws and regulations relating to protection of
the environment, health and safety, including regulations and
enforcement policies that have tended to become increasingly
strict over time. Failure to comply with these laws and
regulations may result in the assessment of administrative,
civil and criminal penalties, imposition of cleanup and site
restoration costs and liens, and, to a lesser extent, issuance
of injunctions to limit or cease operations. In addition, claims
for damages to persons or property, including natural resources,
may result from the environmental, health and safety impacts of
our operations.
Strict as well as joint and several liability may be imposed
under certain environmental laws, which could cause us to become
liable for the conduct of others or for consequences of our own
actions that were in compliance with all applicable laws at the
time those actions were taken. New laws, regulations or
enforcement policies could be more stringent and impose
unforeseen liabilities or significantly increase compliance
costs. If we were not able to recover
26
the resulting costs through insurance or increased revenues, our
business, financial condition or results of operations could be
adversely affected. Please read Business and
propertiesApplicable laws and
regulationsEnvironmental, health and safety matters
for more information.
The loss of our
chief executive officer or our chief operating 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 Timothy A. Leach, our chairman
of the board and chief executive officer, Steven L. Beal, our
president and chief operating officer, and other officers and
key employees with 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 gas
production, and developing and executing acquisition, financing
and hedging strategies. These persons include the executive
officers listed in ManagementExecutive officers and
directors. Our ability to hire and retain our officers is
important to our continued success and growth. The unexpected
loss of the services of one or more of these individuals could
negatively impact our ability to execute our business strategy.
Uncertainties
associated with enhanced recovery methods may result in us not
realizing an acceptable return on the investments we make to use
such methods.
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 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 the
investments we make to use such methods.
Our indebtedness
could restrict our operations and make us more vulnerable to
adverse economic conditions.
We now have, and will continue to have, a significant amount of
indebtedness, and the terms of our revolving credit facility
require us to pay higher interest rate margins as we utilize a
larger percentage of our available borrowing base. As of
September 30, 2007, our total debt was $345.9 million.
At September 30, 2007, our revolving credit facility bore
interest at a rate of 6.83% per annum and our second lien
term loan facility bore interest at 9.76% per annum. Assuming
our total debt outstanding as of September 30, 2007 was
held constant throughout the nine months ended
September 30, 2007, if interest rates had been higher or
lower by 1% per annum, interest expense for the nine months
ended September 30, 2007 would have increased or decreased
by approximately $3.5 million. As of September 30,
2007, our total borrowing capacity under our revolving credit
facility was $375.0 million, of which $141.0 million
was available. Effective November 21, 2007, the borrowing
base under our revolving credit facility was increased to
$425.0 million.
Our current and future indebtedness could have important
consequences to you. For example, it could:
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impair our ability to make investments and obtain additional
financing for working capital, capital expenditures,
acquisitions or other general corporate purposes;
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limit our ability to use operating cash flow in other areas of
our business because we must dedicate a substantial portion of
these funds to make principal and interest payments on our
indebtedness;
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limit our ability to borrow funds that may be necessary to
operate or expand our business;
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put us at a competitive disadvantage to competitors that have
less debt;
|
|
|
increase our vulnerability to interest rate increases; and
|
|
|
hinder our ability to adjust to rapidly changing economic and
industry conditions.
|
Our ability to meet our debt service and other obligations may
depend in significant part on the extent to which we can
successfully implement our business strategy. We may not be able
to implement or realize the benefits of our business strategy.
Our existing bank
credit facilities impose restrictions on us that may affect our
ability to successfully operate our business.
Our bank credit facilities limit our ability to take various
actions, such as:
|
|
|
incurring additional indebtedness;
|
|
|
paying dividends;
|
|
|
creating certain additional liens on our assets;
|
|
|
entering into sale and leaseback transactions;
|
|
|
making investments;
|
|
|
entering into transactions with affiliates;
|
|
|
making material changes to the type of business we conduct or
our business structure;
|
|
|
making guarantees;
|
|
|
disposing of assets in excess of certain permitted amounts;
|
|
|
merging or consolidating with other entities; and
|
|
|
selling all or substantially all of our assets.
|
In addition, our bank credit facilities require us to maintain
certain financial ratios and to satisfy certain financial
conditions, which may require us to reduce our debt or take some
other action in order to comply with each of them.
These restrictions could also limit our ability to obtain future
financings, make needed capital expenditures, withstand a
downturn in our business or the economy in general, or otherwise
conduct necessary corporate activities. We also may be prevented
from taking advantage of business opportunities that arise
because of the limitations imposed on us by the restrictive
covenants under each of our bank credit facilities.
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 we use for
the production, transportation or marketing of our 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.
28
Risks relating to
the offering and our common stock
Certain
stockholders shares are restricted from immediate resale
but may be sold into the market in the near future. This could
cause the market price of our common stock to drop
significantly.
We had outstanding 75,833,972 shares of common stock as of
November 20, 2007. Of these shares, the 24,020,173 shares
sold in our initial public offering and the
8,700,000 shares the selling stockholders are selling in
this offering, or 10,005,000 shares if the underwriters
exercise their over-allotment option in full, will be freely
tradeable without restriction under the Securities Act except
for any shares purchased by one of our affiliates as
defined in Rule 144 under the Securities Act. Following the
completion of this offering, approximately 43 million
shares will be restricted securities (within the
meaning of Rule 144), some of which will be subject to
lock-up
arrangements entered into in connection with our initial public
offering and/or this offering. A substantial number of these
restricted securities are not subject to lock-up arrangements
and currently may be sold under Rule 144. In connection
with this offering, we, our executive officers and directors,
the selling stockholders and certain affiliates of one of our
outside directors have entered into
lock-up
agreements under which we and they have agreed not to offer or
sell any shares of common stock or securities convertible into
or exchangeable or exercisable for shares of common stock for an
initial period of 90 days from the date of this prospectus
without the prior written consent of J.P. Morgan Securities
Inc. and Banc of America Securities LLC, on behalf of the
underwriters. J.P. Morgan Securities Inc. and Banc of
America Securities LLC may, at any time and without notice,
waive any of the terms of these
lock-up
agreements. See Underwriting for a description of
these
lock-up
agreements.
Our management
and directors and their affiliates beneficially own, control or
have substantial influence over a significant amount of our
common stock, giving them a significant influence over our
corporate transactions and other matters. Their interests may
conflict with yours, and the concentration of ownership of our
common stock by such stockholders will limit the influence of
public stockholders.
As of November 20, 2007, our management and directors and
their affiliates beneficially owned, controlled or had
substantial influence over approximately 22.2% of our
outstanding common stock. If these stockholders voted together
as a group, they would have the ability to exert significant
influence over our board of directors and its policies. These
stockholders would, acting together, be able to significantly
influence the outcome of stockholder votes, including votes
concerning the election of directors, the adoption or amendment
of provisions in our certificate of incorporation or bylaws and
possible mergers, corporate control contests and other
significant corporate transactions. This concentration of
ownership may have the effect of delaying, deferring or
preventing a change in control, a merger, consolidation,
takeover or other business combination. This concentration of
ownership could also discourage a potential acquiror from making
a tender offer or otherwise attempting to obtain control of us,
which could in turn have an adverse effect on the market price
of our common stock.
Our certificate
of incorporation, 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 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
29
be more difficult for a third party to acquire us. In addition,
some provisions of our certificate of incorporation, bylaws and
Delaware law could make it more difficult for a third party to
acquire control of us, even if the change of control would be
beneficial to our stockholders, including:
|
|
|
the organization of our board of directors as a classified
board, which allows no more than approximately one-third of our
directors to be elected each year;
|
|
|
stockholders cannot remove directors from our board of directors
except for cause and then only by the holders of not less than
662/3%
of the voting power of all outstanding voting stock;
|
|
|
the prohibition of stockholder action by written consent; and
|
|
|
limitations on the ability of our stockholders to call special
meetings and establish advance notice provisions for stockholder
proposals and nominations for elections to the board of
directors to be acted upon at meetings of stockholders.
|
Please read Description of capital
stockAnti-takeover provisions of our certificate of
incorporation and bylaws for more information about these
provisions.
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. The
terms of our existing bank credit facilities restrict the
payment of dividends without the prior written consent of the
lenders. 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 our
common stock. Any of these events may dilute your ownership
interest in our company 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.
30
The requirements
of being a public company, including compliance with the
reporting requirements of the Securities Exchange Act of 1934
and the requirements of the Sarbanes-Oxley Act, may strain our
resources and increase our costs. We may be unable to comply
with these requirements in a timely or cost-effective
manner.
As a new public company with listed equity securities, we are
now required to comply with new laws, regulations and
requirements, certain corporate governance provisions of the
Sarbanes-Oxley Act of 2002, related regulations of the SEC and
the requirements of the NYSE with which we are not required to
comply as a private company. Complying with these statutes,
regulations and requirements occupies a significant amount of
the time of our board of directors and management and will
increase our costs and expenses compared to those we incurred
while a private company. We will need to:
|
|
|
design, establish, evaluate and maintain a system of internal
controls over financial reporting in compliance with the
requirements of Section 404 of the Sarbanes-Oxley Act of
2002 and the related rules and regulations of the SEC and the
Public Company Accounting Oversight Board;
|
|
|
involve and retain to a greater degree outside counsel and
accountants in the above activities; and
|
|
|
attract and retain qualified personnel for compliance.
|
As a public company, we will be required to evaluate our
internal control systems to allow management to report on, and
our independent auditors to audit, our internal control over
financial reporting. As part of this process, we will be
performing the system and process evaluation and testing (and
any necessary remediation) required to comply with the
management certification and auditor attestation requirements of
Section 404 of the Sarbanes-Oxley Act. We will first be
required to comply with Section 404 for the year ending
December 31, 2008.
In addition, we also expect that being a public company subject
to these rules and regulations will require us to modify our
director and officer liability insurance, and we may be required
to accept reduced coverage or to incur substantially higher
costs to obtain coverage. These factors could also make it more
difficult for us to attract and retain qualified members of our
board of directors, particularly to serve on our audit
committee, as well as qualified executive officers.
31
Cautionary
statement regarding forward-looking statements
This prospectus contains forward-looking statements intended to
qualify for the safe harbors from liability established by the
Private Securities Litigation Reform Act of 1995,
Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. These
forward-looking statements are subject to a number of risks and
uncertainties, many of which are beyond our control. All
statements, other than statements of historical fact included in
this prospectus, regarding our strategy, future operations,
financial position, estimated revenues and losses, projected
costs, prospects, plans and objectives of management are
forward-looking statements. When used in this prospectus, the
words could, believe,
anticipate, intend,
estimate, expect, may,
continue, predict,
potential, project and similar
expressions are intended to identify forward-looking statements,
although not all forward-looking statements contain such
identifying words.
Forward-looking statements may include statements about our:
|
|
|
business strategy;
|
|
estimated quantities of oil and natural gas reserves;
|
|
technology;
|
|
financial strategy;
|
|
oil and natural gas realized prices;
|
|
timing and amount of future production of oil and natural gas;
|
|
the amount, nature and timing of capital expenditures;
|
|
drilling of wells;
|
|
competition and government regulations;
|
|
marketing of oil and natural gas;
|
|
exploitation or property acquisitions;
|
|
costs of exploiting and developing our properties and conducting
other operations;
|
|
general economic and business conditions;
|
|
cash flow and anticipated liquidity;
|
|
uncertainty regarding our future operating results; and
|
|
plans, objectives, expectations and intentions contained in this
prospectus that are not historical.
|
You should not place undue reliance on these forward-looking
statements. All forward-looking statements speak only as of the
date of this prospectus. We do not undertake any obligation to
release publicly any revisions to the forward-looking statements
to reflect events or circumstances after the date of this
prospectus or to reflect the occurrence of unanticipated events,
unless the securities laws require us to do so.
Although we believe that our plans, objectives, expectations and
intentions reflected in or suggested by the forward-looking
statements we make in this prospectus are reasonable, we can
give no assurance that they will be achieved. We disclose
important factors that could cause our actual results to differ
materially from our expectations under Risk factors
and Managements discussion and analysis of financial
condition and results of operations and elsewhere in this
prospectus. These cautionary statements qualify all
forward-looking statements attributable to us or persons acting
on our behalf.
32
We will not receive any of the proceeds from the sale of the
shares of our common stock by the selling stockholders.
Price range of
common stock
Our common stock has been traded on the New York Stock Exchange
under the symbol CXO since it opened for trading on
August 3, 2007 in connection with our initial public
offering. The following table shows the high and low sale prices
for our common stock for the periods presented.
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|
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|
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High
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Low
|
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|
Year Ending December 31, 2007
|
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|
|
|
|
|
|
|
Third Quarter (August 3, 2007 through September 30,
2007)
|
|
$
|
16.44
|
|
|
$
|
11.60
|
|
Fourth Quarter (through December 5, 2007)
|
|
$
|
22.30
|
|
|
$
|
14.30
|
|
On December 5, 2007, the last reported sale price of our
common stock on the New York Stock Exchange was $17.79 per
share.
As of December 5, 2007, there were 142 stockholders of
record of our common stock.
We do not currently anticipate paying any cash dividends on our
common stock. We currently intend to retain future earnings, if
any, to finance the expansion of our business. Our future
dividend policy is within the discretion of our board of
directors and will depend upon various factors, including our
results of operations, financial condition, capital requirements
and investment opportunities. We are also currently prohibited
from paying dividends by our bank credit facilities.
33
Selected
historical consolidated financial information
This section presents our selected historical consolidated
financial data. The selected historical consolidated financial
data presented below is not intended to replace our historical
consolidated financial statements. You should read the following
data along with Managements discussion and analysis
of financial condition and results of operations and the
consolidated financial statements and related notes, each of
which is included in this prospectus.
Selected
historical financial information for Concho Resources
Inc.
The following table shows selected historical financial data
related to Concho Resources Inc. (as the accounting successor to
Concho Equity Holdings Corp., which converted to a Delaware
limited liability company in April 2007 and is now known as
Concho Equity Holdings LLC) and combined financial data of the
Chase Group Properties. We have accounted for the combination
transaction that occurred on February 27, 2006, as an
acquisition by Concho Equity Holdings Corp. of the Chase Group
Properties and a simultaneous reorganization of Concho Resources
such that Concho Equity Holdings Corp. is now our wholly owned
subsidiary.
Our historical results of operations for the periods presented
below may not be comparable either from period to period or
going forward, for the following reasons:
|
|
|
Prior to December 7, 2004, Concho Equity Holdings Corp. did
not own any material assets and did not conduct substantial
operations other than organizational activities.
|
|
|
On December 7, 2004, Concho Equity Holdings Corp. acquired
the Lowe Properties for approximately $117 million and
commenced oil and gas operations.
|
|
|
On February 27, 2006, the initial closing of the
combination transaction occurred. Pursuant to the combination
transaction, Concho Resources acquired the Chase Group
Properties for approximately 35 million shares of common
stock and approximately $409 million in cash.
|
|
|
On March 27, 2007, Concho Resources entered into a
$200.0 million second lien term loan facility from which it
received proceeds of $199.0 million that it used to repay
the $39.8 million outstanding under its prior term loan
facility and to reduce the outstanding balance under its
revolving credit facility by $154.0 million, with the
remaining $5.2 million used to pay loan fees, accrued
interest and for general corporate purposes.
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|
In August 2007, Concho Resources completed its initial public
offering of common stock from which it received proceeds of
$173.0 million that it used to retire outstanding
borrowings under its second lien term loan facility totaling
$86.5 million and to retire outstanding borrowings under
its revolving credit facility totaling $86.5 million.
|
The historical financial data for the Chase Group Properties for
the years ended December 31, 2003, 2004 and 2005 are
derived from the audited financial statements of the Chase Group
Properties. The historical financial data for the Chase Group
Properties for the year ended December 31, 2002 is derived
from the unaudited financial statements of the Chase Group
Properties. The historical financial data for Concho Resources
for the period from inception (April 21, 2004) through
December 31, 2004, and for the years ended
December 31, 2005 and 2006, are derived from the audited
financial statements of Concho Resources. The historical
financial data for Concho Resources for the nine months ended
September 30, 2006 and 2007, are derived from the unaudited
financial statements of Concho Resources.
34
The following table includes the non-GAAP financial measure
EBITDA. For a definition of this measure and a reconciliation to
its most directly comparable financial measure calculated and
presented in accordance with generally accepted accounting
principles, which we refer to as GAAP, please read
Prospectus summaryNon-GAAP financial measures and
reconciliations.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chase Group Properties
|
|
Concho Resources Inc.
|
|
|
|
|
|
|
|
|
|
|
|
Inception
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(April 21,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended
|
|
2004) through
|
|
|
Years ended
|
|
|
Nine months
|
|
(in thousands, except
|
|
December 31,
|
|
December 31,
|
|
|
December 31,
|
|
|
ended September 30,
|
|
per share amounts)
|
|
2002
|
|
2003
|
|
2004
|
|
2005
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
Statement of operations data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
59,881
|
|
$
|
62,016
|
|
$
|
66,529
|
|
$
|
73,132
|
|
$
|
1,851
|
|
|
$
|
31,621
|
|
|
$
|
131,773
|
|
|
$
|
90,737
|
|
|
$
|
128,152
|
|
Natural gas sales
|
|
|
23,870
|
|
|
41,486
|
|
|
41,247
|
|
|
46,546
|
|
|
1,771
|
|
|
|
23,315
|
|
|
|
66,517
|
|
|
|
44,908
|
|
|
|
67,395
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
83,751
|
|
|
103,502
|
|
|
107,776
|
|
|
119,678
|
|
|
3,622
|
|
|
|
54,936
|
|
|
|
198,290
|
|
|
|
135,645
|
|
|
|
195,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
10,386
|
|
|
9,868
|
|
|
11,762
|
|
|
12,979
|
|
|
512
|
|
|
|
10,923
|
|
|
|
22,060
|
|
|
|
14,511
|
|
|
|
22,309
|
|
Oil and gas production taxes
|
|
|
6,928
|
|
|
8,815
|
|
|
9,202
|
|
|
10,298
|
|
|
234
|
|
|
|
3,712
|
|
|
|
15,762
|
|
|
|
10,831
|
|
|
|
15,616
|
|
Exploration and abandonments
|
|
|
900
|
|
|
2,116
|
|
|
179
|
|
|
|
|
|
1,850
|
|
|
|
2,666
|
|
|
|
5,612
|
|
|
|
4,717
|
|
|
|
18,110
|
|
Depreciation, depletion and accretion
|
|
|
16,239
|
|
|
19,643
|
|
|
20,459
|
|
|
19,092
|
|
|
963
|
|
|
|
11,574
|
|
|
|
61,009
|
|
|
|
42,366
|
|
|
|
55,370
|
|
Impairments of proved oil and gas properties
|
|
|
1,587
|
|
|
2,065
|
|
|
3,233
|
|
|
194
|
|
|
|
|
|
|
2,295
|
|
|
|
9,891
|
|
|
|
5,762
|
|
|
|
4,577
|
|
Contract drilling feesstacked rigs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,269
|
|
General and administrative
|
|
|
1,128
|
|
|
1,246
|
|
|
1,387
|
|
|
1,702
|
|
|
3,086
|
|
|
|
8,055
|
|
|
|
12,577
|
|
|
|
8,003
|
|
|
|
13,911
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,128
|
|
|
|
3,252
|
|
|
|
9,144
|
|
|
|
8,041
|
|
|
|
2,656
|
|
Ineffective portion of cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,148
|
|
|
|
(1,193
|
)
|
|
|
(64
|
)
|
|
|
1,134
|
|
(Gain) loss on derivatives not designated as hedges
|
|
|
3,379
|
|
|
576
|
|
|
7,936
|
|
|
1,062
|
|
|
(684
|
)
|
|
|
5,001
|
|
|
|
|
|
|
|
|
|
|
|
(3,088
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
40,547
|
|
|
44,329
|
|
|
54,158
|
|
|
45,327
|
|
|
7,089
|
|
|
|
48,626
|
|
|
|
134,862
|
|
|
|
94,167
|
|
|
|
134,864
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
43,204
|
|
|
59,173
|
|
|
53,618
|
|
|
74,351
|
|
|
(3,467
|
)
|
|
|
6,310
|
|
|
|
63,428
|
|
|
|
41,478
|
|
|
|
60,683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(272
|
)
|
|
|
(3,096
|
)
|
|
|
(30,567
|
)
|
|
|
(20,998
|
)
|
|
|
(29,803
|
)
|
Other, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
168
|
|
|
|
779
|
|
|
|
1,186
|
|
|
|
907
|
|
|
|
957
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(104
|
)
|
|
|
(2,317
|
)
|
|
|
(29,381
|
)
|
|
|
(20,091
|
)
|
|
|
(28,846
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
43,204
|
|
|
59,173
|
|
|
53,618
|
|
|
74,351
|
|
|
(3,571
|
)
|
|
|
3,993
|
|
|
|
34,047
|
|
|
|
21,387
|
|
|
|
31,837
|
|
Income tax (expense) benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
915
|
|
|
|
(2,039
|
)
|
|
|
(14,379
|
)
|
|
|
(8,664
|
)
|
|
|
(13,335
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
43,204
|
|
$
|
59,173
|
|
$
|
53,618
|
|
$
|
74,351
|
|
|
(2,656
|
)
|
|
|
1,954
|
|
|
|
19,668
|
|
|
|
12,723
|
|
|
|
18,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(804
|
)
|
|
|
(4,766
|
)
|
|
|
(1,244
|
)
|
|
|
(1,210
|
)
|
|
|
(45
|
)
|
Effect of induced conversion of preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,601
|
|
|
|
11,601
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) applicable to common shareholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3,460
|
)
|
|
$
|
(2,812
|
)
|
|
$
|
30,025
|
|
|
$
|
23,114
|
|
|
$
|
18,457
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
(unaudited)
|
|
|
|
|
|
|
|
$
|
74,077
|
|
$
|
93,443
|
|
$
|
(2,336
|
)
|
|
$
|
18,663
|
|
|
$
|
125,623
|
|
|
$
|
84,751
|
|
|
$
|
117,010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3.48
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
0.63
|
|
|
$
|
0.52
|
|
|
$
|
0.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in basic earnings (loss) per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
994
|
|
|
|
4,059
|
|
|
|
47,287
|
|
|
|
44,710
|
|
|
|
60,648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3.48
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
0.59
|
|
|
$
|
0.48
|
|
|
$
|
0.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in diluted earnings (loss) per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
994
|
|
|
|
4,059
|
|
|
|
50,729
|
|
|
|
47,937
|
|
|
|
62,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chase Group Properties
|
|
|
Concho Resources Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
Inception
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(April 21,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended
|
|
|
2004) through
|
|
|
Years ended
|
|
|
Nine months
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
ended September 30,
|
|
(in thousands)
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
Other financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operations
|
|
$
|
84,264
|
|
|
$
|
84,202
|
|
|
$
|
93,162
|
|
|
$
|
(2,193
|
)
|
|
$
|
25,070
|
|
|
$
|
112,181
|
|
|
$
|
58,941
|
|
|
$
|
102,932
|
|
Net cash provided by (used in) investing
|
|
|
(31,823
|
)
|
|
|
(30,045
|
)
|
|
|
(35,611
|
)
|
|
|
(122,473
|
)
|
|
|
(61,902
|
)
|
|
|
(596,852
|
)
|
|
|
(537,930
|
)
|
|
|
(115,028
|
)
|
Net cash provided by (used in) financing
|
|
|
(52,441
|
)
|
|
|
(54,157
|
)
|
|
|
(57,551
|
)
|
|
|
125,322
|
|
|
|
45,358
|
|
|
|
476,611
|
|
|
|
469,807
|
|
|
|
30,842
|
|
Capital expenditures
|
|
|
29,449
|
|
|
|
25,451
|
|
|
|
32,352
|
|
|
|
116,880
|
|
|
|
72,758
|
|
|
|
1,226,180
|
|
|
|
1,162,328
|
|
|
|
125,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chase Group Properties
|
|
Concho Resources Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of December 31,
|
|
As of December 31,
|
|
September 30,
|
(in thousands)
|
|
2002
|
|
2003
|
|
2004
|
|
2005
|
|
2004
|
|
2005
|
|
2006
|
|
2007
|
|
|
|
(unaudited)
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
Balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
|
|
$
|
|
|
$
|
|
|
$
|
|
|
$
|
656
|
|
$
|
9,182
|
|
$
|
1,122
|
|
$
|
19,868
|
Property and equipment, net
|
|
|
126,956
|
|
|
133,547
|
|
|
135,568
|
|
|
149,042
|
|
|
115,455
|
|
|
170,583
|
|
|
1,320,655
|
|
|
1,368,026
|
Total assets
|
|
|
135,973
|
|
|
141,860
|
|
|
145,100
|
|
|
161,792
|
|
|
130,717
|
|
|
232,385
|
|
|
1,390,072
|
|
|
1,443,507
|
Long-term debt, including current maturities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53,000
|
|
|
72,000
|
|
|
495,500
|
|
|
345,880
|
Stockholders equity/net investment
|
|
|
127,821
|
|
|
134,554
|
|
|
134,014
|
|
|
150,814
|
|
|
71,710
|
|
|
109,670
|
|
|
575,156
|
|
|
773,384
|
|
|
|
|
|
(1)
|
|
EBITDA is defined as net income,
plus (1) interest, the amortization of related debt
issuance costs and other financial costs, net of capitalized
interest, (2) federal and state income taxes and
(3) depreciation, depletion and accretion. See
Prospectus summaryNon-GAAP financial measures and
reconciliations.
|
36
Selected
historical financial and operating information for Lowe
Properties
The selected financial data for the Lowe Properties for the
years ended December 31, 2002 and 2003 and for the period
from January 1, 2004 through November 30, 2004 were
derived from the audited and unaudited statements of revenue and
direct operating expenses of the Lowe Properties included in
this prospectus and information provided by the seller.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
January 1, 2004
|
|
|
Years ended
|
|
through
|
|
|
December 31,
|
|
November 30,
|
Statement of revenues and direct
operating expenses data: (in thousands)
|
|
2002
|
|
2003
|
|
2004
|
|
|
|
(unaudited)
|
|
|
|
|
|
Revenues
|
|
$
|
25,753
|
|
$
|
32,371
|
|
$
|
34,663
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
7,519
|
|
|
6,652
|
|
|
6,983
|
Production tax expense
|
|
|
1,597
|
|
|
2,023
|
|
|
2,159
|
Other expenses
|
|
|
|
|
|
435
|
|
|
461
|
|
|
|
|
|
|
Total direct operating expenses
|
|
|
9,116
|
|
|
9,110
|
|
|
9,603
|
|
|
|
|
|
|
Revenues in excess of direct operating expenses
|
|
$
|
16,637
|
|
$
|
23,261
|
|
$
|
25,060
|
|
|
|
|
|
|
|
|
37
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
prospectus.
Statements in our discussion may be forward-looking statements.
These forward-looking statements involve risks and
uncertainties. We caution that a number of factors could cause
future production, revenue and expenses to differ materially
from our expectations.
Overview
We are an independent oil and natural gas company engaged in the
acquisition, development, exploitation and exploration of
producing oil and natural gas properties. Our conventional
operations are primarily focused in the Permian Basin of
Southeast New Mexico and West Texas. We have also acquired
significant acreage positions in the Permian Basin of Southeast
New Mexico, the Central Basin Platform and the Delaware Basin of
West Texas, the Williston Basin in North Dakota and the Arkoma
Basin in Arkansas, covering unconventional emerging resource
plays, where we intend to apply horizontal drilling, advanced
fracture stimulation and enhanced recovery technologies. Crude
oil comprised 57% of our 467 Bcfe of estimated net proved
reserves as of December 31, 2006, and 59% of our
23.3 Bcfe of production for the year ended
December 31, 2006. Crude oil comprised 59% of our
21.7 Bcfe of production for the nine months ended
September 30, 2007. We seek to operate the wells in which
we own an interest, and we operated wells that accounted for 89%
of our PV-10
and 48% of our 1,921 wells as of December 31, 2006 and
49% of our 2,007 wells as of September 30, 2007. 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.
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, Caza Energy LLC and
certain other individual 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. As a result of the
initial closing of the combination transaction, the members of
the Chase Group that sold their working interests to us at the
initial closing of the combination transaction received
34,683,315 shares of our common stock and approximately
$400 million in cash, and the former shareholders of Concho
Equity Holdings Corp. that were a party to the combination
agreement received 23,767,691 shares of our common stock.
In addition, certain options held by our employees to purchase
preferred and common stock of Concho Equity Holdings Corp. were
converted into options to purchase 2,349,113 shares of our
common stock. The oil and gas properties contributed to us by
the Chase Group (which we refer to as the Chase Group
Properties) represent approximately 76% of our
PV-10 as of
December 31, 2006. The executive officers of Concho Equity
Holdings Corp. became the executive officers of our company in
connection with the initial closing of the combination
transaction. We have accounted for the combination transaction
as a reorganization of our company, such that Concho Equity
Holdings Corp. is now our
38
wholly owned subsidiary, and a simultaneous acquisition by our
company of the assets contributed by the Chase Group.
We agreed in the combination agreement to offer to acquire
additional interests in the Chase Group Properties from persons
associated with the Chase Group. In May 2006, we acquired
certain of such interests from ten of such persons in exchange
for an aggregate consideration of 111,323 shares of our
common stock and $8.9 million in cash. In April 2007, we
offered to acquire the remainder of such interests from an
additional nine persons in exchange for, at the respective
sellers option, shares of our common stock or cash, or any
combination thereof, aggregating a total purchase offer of
$906,000. Terms concerning the exchange of such interests for
shares of our common stock were the same as the terms in the
combination agreement. During April 2007, we acquired these
interests for $256,000 in cash and 54,230 shares of our
common stock.
In addition, because certain employee stockholders of Concho
Equity Holdings Corp. were not confirmed to have been accredited
investors at the time of the combination transaction, their
254,621 units, consisting of one preferred and one-half of
a common share of Concho Equity Holdings Corp., could not be
immediately exchanged for our common shares. On April 16, 2007,
these remaining shares of Concho Equity Holdings Corp. were
exchanged for 318,285 shares of our common stock. As a
result, Concho Equity Holdings Corp. is now our wholly owned
subsidiary. The common and preferred shares of Concho Equity
Holdings Corp. which were outstanding between February 27,
2006 and April 16, 2007 have been treated as exchangeable for
and equivalent to shares of our common stock in our consolidated
financial statements.
We completed the initial public offering of our common stock in
August 2007.
Factors that
significantly affect our results
Our revenue, cash flow from operations and future growth depend
substantially on factors beyond our control, such as economic,
political and regulatory developments and competition from other
sources of energy. Oil and natural gas prices have historically
been volatile and may fluctuate widely in the future. Sustained
periods of low prices for oil or natural gas could materially
and adversely affect our financial position, our results of
operations, the quantities of oil and gas that we can
economically produce and our ability to access capital.
We generally hedge a portion of our expected future oil and
natural gas production to reduce our exposure to fluctuations in
commodity price. See Liquidity and capital
resourcesHedging for a discussion of our hedging and
hedge positions.
Like all businesses engaged in the exploration and production of
oil and natural gas, we face the challenge of natural production
declines. As initial reservoir pressures are depleted, oil and
natural gas production from a given well decreases. Thus, an oil
and natural gas exploration and production company depletes part
of its asset base with each unit of oil or natural gas it
produces. We attempt to overcome this natural decline by
drilling to find additional reserves and acquiring more reserves
than we produce and by implementing secondary recovery
techniques. Our future growth will depend on our ability to
enhance production levels from our existing reserves and to
continue to add reserves in excess of production. We will
maintain our focus on costs necessary to produce our reserves as
well as the costs necessary to add reserves through drilling and
acquisitions. Our ability to make capital expenditures to
increase production from our existing reserves and to add
reserves through drilling is dependent on our capital
39
resources and can be limited by many factors, including our
ability to access capital in a cost-effective manner and to
timely obtain drilling permits and regulatory approvals.
Items impacting
comparability of our financial results
Our historical results of operations for the periods presented
may not be comparable, either from period to period or going
forward, for the reasons described below.
Combination
transaction
We were formed in February 2006 as a result of the combination
transaction between Concho Equity Holdings Corp. and the Chase
Group.
Concho Equity Holdings Corp. is our predecessor for accounting
purposes. As a result, our historical financial statements prior
to February 27, 2006, are the financial statements of
Concho Equity Holdings Corp. Concho Equity Holdings Corp. was
formed on April 21, 2004, and did not own any material
assets and did not conduct substantial operations other than
organizational activities until it acquired the Lowe Properties
on December 7, 2004. For a discussion of the results of
operations of Concho Resources (as the accounting successor to
Concho Equity Holdings Corp.), please read Results
of operations of Concho Resources. The financial
statements of Concho Resources (as the accounting successor to
Concho Equity Holdings Corp.), together with the notes thereto,
are also included in this prospectus.
As of December 31, 2006, approximately 76% of our
PV-10 was
attributable to the properties contributed to us by the Chase
Group in the combination transaction. For a discussion of the
results of operations of the Chase Group Properties, please read
Results of operations of the Chase Group
Properties. The combined financial statements of the Chase
Group Properties, together with the notes thereto, are also
included in this prospectus.
Additional
indebtedness and other expenses
During 2006 and 2007, we incurred additional indebtedness and
other expenses as a result of our rapid growth, particularly as
a result of the combination transaction. Our historical
financial information prior to 2006 does not give effect to
various items that will affect our results of operations and
liquidity in the future, including the following items:
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we closed the combination transaction on February 27, 2006
and properties were contributed to us by the Chase Group that
represent approximately 76% of our
PV-10 as of
December 31, 2006;
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we incurred approximately $405 million of new indebtedness
upon the initial closing of the combination transaction;
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we entered into a $200.0 million second lien term loan
facility on March 27, 2007, from which we received proceeds
of $199.0 million that we used to repay the
$39.8 million outstanding under our prior term loan
facility, to reduce the outstanding balance under our revolving
credit facility by $154.0 million and the remaining
$5.2 million to pay loan fees, accrued interest and for
general corporate purposes;
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we received proceeds of $173.0 million from our initial
public offering that was completed in August 2007 that we
used to retire outstanding borrowings under our second lien term
loan
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40
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facility totaling $86.5 million and to retire outstanding
borrowings under our revolving credit facility totaling
$86.5 million; and
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we have incurred additional general and administrative costs as
a result of the expansion of our technical and administrative
staffs and as a result of increased amounts of professional fees.
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Curtailment of
drilling
We determined in January 2007 to reduce our drilling activities
for the three months ended March 31, 2007. This
determination was due to a decline in oil and natural gas prices
in January 2007 compared to such prices in the fourth quarter of
2006, the costs of goods and services necessary to complete our
drilling activities and the resulting effect of these
circumstances on our expected cash flow. In addition, we
determined to reduce our drilling activities and curtail capital
expenditures until we were able to complete our second lien term
loan facility in March 2007 in order to preserve liquidity. Also
due to the reduced drilling activities described above, we
recorded an expense during the six months ended June 30,
2007 of $4.3 million for contract drilling fees related to
stacked rigs subject to daywork drilling contracts with two
drilling contractors. Approximately $3 million of this
amount was paid to Silver Oak Drilling, LLC, which is an
affiliate of the Chase Group. We resumed drilling activities in
April 2007, and we believe we will spend our planned 2007
exploration and development budget of approximately
$183 million during 2007. We incurred no contract drilling
fees related to stacked rigs in the three months ended
September 30, 2007.
Natural gas
processing plant interruption
On June 27, 2007, we were notified that a natural gas
processing plant through which we process and sell a portion of
the production from our Shelf Properties in New Mexico was
shut-down for repairs as a result of a storm. Approximately
40 MMcfe per day of our production was shut-in as a result
of this plant shut-down. The plant became fully operational on
July 3, 2007, and we resumed production from all of our
properties that had been affected. On July 16, 2007, this
plant was shut-down again for repairs. Approximately
40 MMcfe per day of our production was shut-in again as a
result of this plant shut-down. The plant became fully
operational on July 20, 2007, and we resumed production
from all of our properties that had been affected. As a result
of this plant downtime and associated gathering system
interruptions and high line pressure, our production delivery
was further restricted in varying amounts during late July and
the full months of August and September. Our total net
production during the nine months ended September 30, 2007
was reduced by approximately 660 MMcfe as a result of this
situation. These production delivery restrictions were reduced
significantly toward the end of September and the beginning of
October and, as a result, we resumed full levels of production
delivery during the month of October.
Public company
expenses
In addition, we believe that our expected future financial
results will be impacted as a result of our having become a
public corporation in August 2007. We anticipate initially
incurring additional annual general and administrative expenses
relating to operating as a separate publicly held corporation,
including costs associated with annual and quarterly reports to
stockholders, costs associated with our compliance with the
Sarbanes-Oxley Act of 2002,
41
independent auditor fees, investor relations activities,
registrar and transfer agent fees, incremental director and
officer liability insurance costs, and director compensation.
Amendment of
certain outstanding stock options
On November 8, 2007, the compensation committee of our
board of directors authorized and approved amendments to certain
outstanding agreements related to options to purchase our common
stock that were previously awarded to certain of our executive
officers and employees in order to amend such award agreements
so that the subject stock option awards would constitute
deferred compensation that is compliant with Section 409A
of the Internal Revenue Code of 1986, as amended, or exempt such
awards from the application of Section 409A. Because the
offer to amend outstanding stock option agreements previously
issued to our employees may constitute a tender offer under the
Securities Exchange Act of 1934, on November 8, 2007, our
board of directors authorized commencement of a tender offer to
amend the applicable outstanding stock option award agreements
in the form approved by the compensation committee. Generally,
the amendments provide that the employee stock options, which
had previously vested in connection with the combination
transaction, will become exercisable in 25% increments over a
four year period or upon the occurrence of certain specified
events. Any employee who elects to amend his stock option award
agreement will receive on January 2, 2008 a cash payment
equal to $0.50 for each share of common stock subject to the
amendment. Assuming all affected employees elect to amend their
options subject to the offer, we expect to make aggregate cash
payments of approximately $275,000 to such employees. Our
affected executive officers received and accepted an offer to
amend their stock option awards issued prior to the combination
transaction on substantially the same terms, except such
executive officers were not offered the $0.50 per share cash
payment. Each of these executive officers executed the amendment
on November 16, 2007.
In addition, our named executive officers received stock option
awards in June 2006 to purchase 450,000 shares of common
stock, in the aggregate, at a purchase price of $12.00 per
share. We 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 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.
Our named executive officers executed these amendments on
November 16, 2007. To compensate our named executive
officers for the $3.40 increase in the exercise price, we issued
to each of them 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) $18.38, which was the mean of the high and
low sales price of a share of our common stock on
November 19, 2007. As a result, our named executive
officers were granted 83,242 shares of restricted stock in
the aggregate on November 19, 2007 with a grant date fair
market value of $18.38, for an aggregate value of approximately
$1.5 million. This represents incremental value of
approximately $0.9 million above the value of the June 2006
options. Such incremental value will be recognized in General
and administrative expense in the consolidated statement of
operations beginning in November 2007 and continuing through the
final dates of the lapse of forfeiture restrictions. The lapse
of forfeiture restrictions of this restricted stock is in 25%
increments on the lapse dates of January 1, 2008,
June 12, 2008, June 12, 2009, and June 12, 2010,
or upon the occurrence of certain specified events.
Based on our preliminary estimates, which are subject to change
depending on the timing of acceptance of our offers by the
subject employees, we have determined that our aggregate
42
compensation expense of approximately $1.2 million
resulting from these proposed modifications will be recorded
during the remainder of the year ending December 31, 2007
and during the years ending December 31, 2008, 2009 and
2010.
Results of
operations of Concho Resources Inc.
The following table presents selected financial and operating
information of Concho Resources Inc. (as successor to Concho
Equity Holdings Corp.) for the period of inception
(April 21, 2004) through December 31, 2004, for
the years ended December 31, 2005 and 2006 and for the
nine months ended September 30, 2006 and 2007:
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Inception (April 21,
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Years ended
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Nine months ended
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2004) through
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December 31,
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September 30,
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(in thousands, except price data)
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December 31, 2004
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2005
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2006
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2006
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2007
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|
|
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(unaudited)
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(unaudited)
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Oil sales
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$
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1,851
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$
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31,621
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$
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131,773
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$
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90,737
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$
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128,152
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Natural gas sales
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1,771
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23,315
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66,517
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44,908
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67,395
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Total operating revenues
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3,622
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54,936
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198,290
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135,645
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195,547
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Operating costs and expenses
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7,089
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48,626
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134,862
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94,167
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134,864
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Interest, net and other revenue
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104
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2,317
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29,381
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20,091
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28,846
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Income (loss) before income taxes
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(3,571
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)
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3,993
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34,047
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21,387
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31,837
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Income tax (expense) benefit
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915
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(2,039
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)
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(14,379
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)
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(8,664
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)
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(13,335
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)
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Net income (loss)
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$
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(2,656
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)
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$
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1,954
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$
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19,668
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$
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12,723
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$
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18,502
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Production volumes (unaudited):
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Oil (MBbl)
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44.7
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599.0
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2,294.8
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1,553.7
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2,143.2
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Natural gas (MMcf)
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290.7
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3,403.8
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9,506.8
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6,634.3
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8,887.5
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Natural gas equivalent (MMcfe)
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559.1
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6,997.7
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23,275.4
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15,956.2
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21,746.9
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Average prices (unaudited):
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Oil, without hedges ($/Bbl)
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$
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41.37
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$
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54.71
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$
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60.47
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$
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63.20
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$
|
61.36
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Oil, with hedges ($/Bbl)
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41.37
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|
52.79
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57.42
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58.40
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59.79
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Natural gas, without hedges ($/Mcf)
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6.09
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|
|
|
6.99
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|
|
|
6.87
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|
|
|
6.75
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|
|
|
7.48
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|
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Natural gas, with hedges ($/Mcf)
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6.09
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|
|
|
6.85
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|
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7.00
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|
|
|
6.77
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|
|
|
7.58
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Natural gas equivalent, without hedges ($/Mcfe)
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6.48
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|
|
|
8.08
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|
|
|
8.77
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|
|
|
8.96
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|
|
9.10
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Natural gas equivalent, with hedges ($/Mcfe)
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6.48
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|
|
|
7.85
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|
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8.52
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8.50
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8.99
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|
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Nine months ended
September 30, 2006, compared to nine months ended
September 30, 2007
Oil and gas revenues. Revenue from oil
and gas operations increased by $59.9 million (44%) from
$135.6 million for the nine months ended September 30,
2006 to $195.5 million for the nine months ended
September 30, 2007. This increase was primarily because of
increased production as a result of the acquisition of the Chase
Group Properties and secondarily due to successful drilling
efforts during 2006 and 2007, coupled with moderate increases in
realized oil and gas prices. Total production increased
5,791 MMcfe (36%) from 15,956 MMcfe for the nine
months ended September 30, 2006 to 21,747 MMcfe for
the nine months ended September 30, 2007. Total production
during the nine months ended September 30, 2007 was reduced
by approximately 660 MMcfe as a result of the temporary
shut-downs of a natural gas processing
43
plant through which we process and sell a portion of our
production. See Items impacting comparability of our
financial resultsNatural gas processing plant
interruption. The increases in revenue and production
attributable to the acquired Chase Group Properties between 2006
and 2007 were $27.8 million and 3,397 MMcfe,
respectively. In addition:
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average realized oil prices (after giving effect to hedging
activities) increased 2% from $58.40 per Bbl during the nine
months ended September 30, 2006 to $59.79 per Bbl during
the nine months ended September 30, 2007;
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average realized natural gas prices (after giving effect to
hedging activities) increased 12% from $6.77 per Mcf during the
nine months ended September 30, 2006 to $7.58 per Mcf
during the nine months ended September 30, 2007; and
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average realized natural gas equivalent prices (after giving
effect to hedging activities) increased 6% from $8.50 per Mcfe
during the nine months ended September 30, 2006 to $8.99
per Mcfe during the nine months ended September 30, 2007.
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Hedging activities. The oil and gas
prices that we report are based on the market price received for
the commodities adjusted to give effect to the results of our
cash flow hedging activities. We utilize commodity derivative
instruments (swaps and zero cost collar option contracts) in
order to (1) reduce the effect of the volatility of price
changes on the commodities we produce and sell, (2) support
our annual capital budgeting and expenditure plans and
(3) lock-in commodity prices to protect economics related
to certain capital projects. Following is a summary of the
effects of commodity hedges for the nine months ended
September 30, 2006 and 2007:
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Crude Oil Hedges
|
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Natural Gas Hedges
|
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Nine months ended
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Nine months ended
|
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September 30,
|
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September 30,
|
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|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
|
(unaudited)
|
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|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
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Hedging revenue increase (decrease)
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|
$
|
(7,456,000
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)
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$
|
(3,347,000
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)
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|
$
|
114,000
|
|
|
$
|
909,000
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Hedged volumes (Bbls and MMBtus, respectively)
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740,100
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|
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805,350
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|
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3,745,500
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|
|
|
4,817,400
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Hedged revenue increase (decrease) per hedged volume
|
|
$
|
(10.07
|
)
|
|
$
|
(4.16
|
)
|
|
$
|
0.03
|
|
|
$
|
0.19
|
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During the nine months ended September 30, 2006, our
commodity price hedges decreased oil revenues by
$7.5 million ($4.80 per Bbl). During the nine months ended
September 30, 2007, our commodity price hedges decreased
oil revenues by $3.3 million ($1.56 per Bbl). The effect of
the commodity price hedges in decreasing oil revenues during the
nine months ended September 30, 2007 less than their effect
of decreasing oil revenues during the nine months ended
September 30, 2006 was the result of (1) a lower
average market price of NYMEX crude oil of $66.21 per Bbl in
2007 as compared to $68.23 per Bbl in 2006, and (2) the
lower hedged revenue per hedged volume in 2007 as compared to
2006, as shown in the table above, partially offset by a larger
amount of hedged volumes of 805,350 Bbls in 2007 as
compared to 740,100 Bbls in 2006.
During the nine months ended September 30, 2006, our
commodity price hedges increased gas revenues by
$0.1 million ($0.02 per Mcf). During the nine months ended
September 30, 2007, our commodity price hedges increased
gas revenues by $0.9 million ($0.10 per Mcf). The effect of
commodity price hedges in increasing gas revenues in 2007 more
than their effect of
44
increasing gas revenues in 2006 was the result of (1) a
higher amount of hedged volumes of 4,817,400 MMBtus in 2007
as compared to 3,745,500 MMBtus in 2006, (2) the
higher hedged revenue per hedged volume in 2007 as compared to
2006, as shown in the table above, and (3) a lower
reference market price for natural gas of $6.13 per MMBtu in
2007 as compared to $6.21 per MMBtu in 2006.
The hedged revenue per hedged volume for natural gas in 2007 was
partially reduced because we determined that all of our natural
gas commodity contracts no longer qualified as hedges under the
requirements of Financial Accounting Standards Board
(FASB) Statement of Financial Accounting Standards
(SFAS) No. 133 Accounting for Derivative
Instruments and Hedging Activities, as amended
(SFAS No. 133) during the three months
ended September 30, 2007. Derivative contract settlement
amounts for the three months ended September 30, 2007 were
reclassified from Accumulated other comprehensive income
(AOCI) rather than recorded from the cash
settlements. Cash settlements for the three months ended
September 30, 2007 were recorded to (Gain) loss on
derivatives not designated as hedges. As a result, the
pre-tax amount of $0.7 million was reclassified from
AOCI to Natural gas revenues. The cash settlement
receipts of approximately $1.3 million were recorded in
earnings under (Gain) loss on derivatives not designated as
hedges. The cash settlement receipts of approximately
$0.2 million on these same natural gas commodity contracts
during the six months ended June 30, 2007 (the periods in
which these contracts qualified to use hedge accounting), were
recorded in Natural gas revenues. See
Note IDerivative financial instruments in the
condensed notes to the consolidated financial statements. Any
amounts in AOCI as of June 30, 2007 related to these
dedesignated hedges will remain in AOCI and be
reclassified into earnings under Natural gas revenues
during the periods which the hedged forecasted transaction
occurs.
Production expenses. Production
expenses (including production taxes) increased
$12.6 million (50%) from $25.3 million ($1.59 per
Mcfe) for the nine months ended September 30, 2006 to
$37.9 million ($1.74 per Mcfe) for the nine months ended
September 30, 2007. The increase in production expenses was
due to: (1) production expenses associated with the Chase
Group Properties acquired in February 2006 of approximately
$2.9 million, (2) production expenses associated with
new wells that were successfully completed in 2006 and 2007 as a
result of our drilling activities, and (3) an increase in
repair activity on a well in Gaines County, Texas in the amount
of $0.9 million. Lease operating expenses and workover
costs comprised approximately 57% and 59% of production expenses
for the nine months ended September 30, 2006 and 2007,
respectively. These costs per unit of production increased 13%
from $0.91 per Mcfe during the nine months ended
September 30, 2006 to $1.03 per Mcfe during the nine months
ended September 30, 2007. Lease operating expenses include
ad valorem taxes that are affected by commodity price changes
and ad valorem tax rates. Ad valorem taxes were approximately 5%
and 6% of lease operating expenses for the nine months ended
September 30, 2006 and 2007, respectively.
The secondary component of production expenses is production
taxes and is directly related to commodity price changes. These
costs comprised approximately 43% and 41% of production expenses
during the nine months ended September 30, 2006 and 2007,
respectively. Production taxes per unit of production increased
6% from $0.68 per Mcfe during the nine months ended
September 30, 2006 to $0.72 per Mcfe during the nine months
ended September 30, 2007. This increase was primarily due
to an increase in average natural gas equivalent prices we
received.
45
Exploration and abandonments
expense. The following table provides a
breakdown of our exploration and abandonments expense for the
nine months ended September 30, 2006 and 2007:
|
|
|
|
|
|
|
|
|
|
|
Nine months ended
|
|
|
|
September 30,
|
|
(in thousands)
|
|
2006
|
|
|
2007
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
Geological and geophysical
|
|
$
|
1,513
|
|
|
$
|
993
|
|
Exploratory dry holes
|
|
|
3,172
|
|
|
|
16,222
|
|
Leasehold abandonments and other
|
|
$
|
32
|
|
|
|
895
|
|
|
|
|
|
|
|
|
|
|
Total exploration and abandonments
|
|
$
|
4,717
|
|
|
$
|
18,110
|
|
|
|
|
|
|
|
|
|
|
Our geological and geophysical expense, which primarily consists
of general and administrative costs for our geology department
as well as seismic data, geophysical data and core analysis,
decreased $0.5 million from $1.5 million for the nine
months ended September 30, 2006 to $1.0 million during
the nine months ended September 30, 2007. This 34% decrease
was primarily attributable to a data license and a core analysis
purchased in the first quarter of 2006.
Of our exploratory dry holes expense during the nine months
ended September 30, 2006, $2.6 million was
attributable to one unsuccessful outside operated exploratory
well located in Val Verde County, Texas.
Our exploratory dry holes expense during the nine months ended
September 30, 2007 was primarily attributable to five
operated exploratory wells that were unsuccessful. The costs
associated with three of these wells drilled in the Western
Delaware Basin in Culberson County, Texas approximated
$11.7 million. Another of these wells, which was drilled in
the Southeastern New Mexico Basin in Lea County, New Mexico, had
costs of approximately $2.3 million. An additional
$0.8 million was charged to exploratory dry hole costs
relative to a target zone in the fifth of these wells in the
Southeastern New Mexico Basin in Eddy County, New Mexico which
was determined to be dry. Exploration expense of
$1.4 million related to two outside operated wells located
in Eddy County, New Mexico was also recorded.
We had minimal leasehold abandonments during the nine months
ended September 30, 2006. For the nine months ended
September 30, 2007, we recorded $0.9 million of
leasehold abandonments, $0.8 million of which was related
to one prospect located in Edwards County, Texas.
Depreciation and depletion
expense. Depreciation and depletion expense
increased $12.8 million from $42.2 million ($2.64 per
Mcfe) for the nine months ended September 30, 2006 to
$55.0 million ($2.53 per Mcfe) for the nine months ended
September 30, 2007. The increase in depreciation and
depletion expense was primarily due to the acquisition of the
Chase Group Properties and related acquisition costs associated
with the combination transaction. The decrease in depreciation
and depletion expense per Mcfe was primarily due to an increase
in proved oil and natural gas reserves as a result of our
successful development and exploratory drilling program.
Impairment of oil and gas
properties. In accordance with
SFAS No. 144 Accounting for the Impairment or
Disposal of Long-Lived Assets, we review our long-lived
assets to be held and used, including proved oil and gas
properties accounted for under the successful efforts method of
accounting. As a result of this review of the recoverability of
the carrying value of our assets during the nine months ended
September 30, 2006, we recognized a non-cash charge against
46
earnings of $5.8 million, 42% of which related to a
property acquired in our Lowe Acquisition in December 2004
located in Pecos County, Texas, 7% related to a well drilled on
acreage in Lea County, New Mexico and 17% of which related to a
property drilled in Eddy County, New Mexico. For the nine months
ended September 30, 2007, we recognized a non-cash charge
against earnings of $4.6 million, 44% of which related to a
well drilled on acreage in Schleicher County, Texas, 28% of
which related to a well drilled in Crane County, Texas and 8% of
which related to a well drilled on acreage in Mountrail County,
North Dakota. Of the total amount, $0.2 million was
related to the Chase Group Properties.
Contract drilling fees stacked
rigs. As discussed above under
Items impacting comparability of our financial
resultsCurtailment of drilling, we determined in
January 2007 to reduce our drilling activities for the three
months ended March 31, 2007. As a result, we recorded an
expense during the six months ended June 30, 2007 of
approximately $4.3 million for contract drilling fees
related to stacked rigs subject to daywork drilling contracts
with two drilling contractors. No additional costs were incurred
during the three months ended September 30, 2007. We
resumed our drilling activities in April 2007. These costs were
minimized during the first six months of 2007 as one contractor
secured work for a rig for 71 days during that period and
charged us only the difference between the then-current
operating day rate pursuant to the contract and the lower
operating day rate received from the new customer.
General and administrative
expenses. General and administrative expenses
increased $0.6 million (3%) from $16.0 million ($1.01
per Mcfe) for the nine months ended September 30, 2006 to
$16.6 million ($0.76 per Mcfe) for the nine months ended
September 30, 2007. Excluding non-cash stock-based
compensation of $8.0 million during the nine months ended
September 30, 2006 and $2.7 million during the nine
months ended September 30, 2007, general and administrative
expenses increased $5.9 million (74%) from
$8.0 million ($0.50 per Mcfe) for the nine months ended
September 30, 2006 to $13.9 million ($0.64 per Mcfe)
for the nine months ended September 30, 2007. The increase
in general and administrative expenses during the nine months
ended September 30, 2007 was primarily due to the increase
in the size and complexity of our operations following the
combination transaction and related increase in professional
fees. In addition, annual bonuses in the aggregate amount of
$2.5 million were paid to the officers and employees in
April 2007 as compared to $0.9 million aggregate bonuses
paid to employees in February 2006, all of which were approved
by the Compensation Committee of our board of directors.
We earn revenue as operator of certain oil and gas properties in
which we own interests. As such, we earned revenue of
$0.6 million and $0.9 million during the nine months
ended September 30, 2006 and 2007, respectively. This
revenue is reflected as a reduction of general and
administrative expenses in the consolidated statements of
operations.
(Gain) loss on derivatives not designated as
hedges. As explained in Hedging
activities, during the three months ended September 30,
2007, we determined that all of our natural gas commodity
contracts no longer qualified as hedges under the requirements
of SFAS No. 133. If the hedge is no longer highly
effective, according to SFAS No. 133, an entity shall
discontinue hedge accounting for an existing hedge,
prospectively and during the period the hedges became
ineffective. As a result, any changes in fair value must be
recorded in earnings under (Gain) loss on derivatives not
designated as hedges and any related cash settlements are
recorded to (Gain) loss on derivatives not designated as
hedges. For the three months since de-designation beginning
on July 1, 2007, the mark-to-market adjustment, for
de-designated
47
contracts and new contracts not designated as hedges, was a gain
of $1.8 million and the related cash settlement receipts
were approximately $1.3 million.
Interest expense. Interest expense
increased $8.8 million from $21.0 million for the nine
months ended September 30, 2006 to $29.8 million for
the nine months ended September 30, 2007. The weighted
average interest rate for the nine months ended
September 30, 2006 and 2007 was 7.4% and 7.8%,
respectively. The weighted average debt balance during the nine
months ended September 30, 2006 and 2007 was approximately
$378.3 million and $472.4 million, respectively. The
increase in weighted average debt balance during the nine months
ended September 30, 2007 was primarily due to our borrowing
$400.0 million to fund the cash portion of the combination
transaction on February 27, 2006, and additional borrowings
to fund our drilling activities, partially offset by the partial
prepayment in August 2007 of $86.5 million on our new
second lien term loan facility and the repayment in August 2007
of $86.5 million on our revolving credit facility. The
increase in interest expense is due to a slight increase in the
weighted average interest rate and the acceleration of deferred
loan cost amortization and original issue discount amortization.
In March 2007, we reduced the borrowing base for our revolving
credit facility by $100.0 million, or 21%, resulting in
accelerated amortization of $0.8 million, and we fully
repaid our original second lien term facility, resulting in
accelerated amortization of $0.4 million. The prepayment of
$86.5 million on our new second lien term loan facility in
August 2007 resulted in accelerated amortization of
$1.0 million in deferred loan costs and $0.4 million
in original issue discount.
Income tax provisions. We recorded
income tax expense of $8.7 million and $13.3 million
for the nine months ended September 30, 2006 and 2007,
respectively. The income tax expense was due to the income
reported during the nine months ended September 30, 2006
and 2007. The effective income tax rate for the nine months
ended September 30, 2006 and 2007 was 40.5% and 41.9%,
respectively.
We had a net deferred tax liability of $241.7 million and
$248.2 million at December 31, 2006 and
September 30, 2007, respectively. The net liability balance
was primarily due to differences in basis and depletion of oil
and gas properties for tax purposes as compared to book purposes
related to the acquisition of the Chase Group Properties in
February 2006. The net change was due to 2007 intangible
drilling costs which are allowed by the Internal Revenue Service
as deductions and are capitalized under generally accepted
accounting principles in the United States of America, partially
offset by an increase in deferred hedge losses.
Year ended
December 31, 2005, compared to year ended December 31,
2006
Oil and gas revenues. Revenue from oil and gas operations
increased by $143.4 million (261%)from $54.9 million for the
year ended December 31, 2005 to $198.3 million for the year
ended December 31, 2006. This increase was primarily because of
increased production as a result of the acquisition of the Chase
Group Properties and secondarily due to successful drilling
efforts during 2005 and 2006. Total production increased 16,277
MMcfe (233%) from 6,998 MMcfe for the year ended December 31,
2005 to 23,275 MMcfe for the year ended December 31, 2006. The
increases in revenue and production attributable to the Chase
Group Properties between 2005 and 2006 were $136.2 million and
11,747 MMcfe, respectively. In addition, average realized oil
prices (after giving effect to hedging activities) increased 9%
from $52.79 per Bbl in 2005 to $57.42 per Bbl in 2006,
average realized natural gas prices (after giving effect to
hedging activities) increased 2% from $6.85 per Mcf in 2005
to $7.00 per Mcf in 2006 and
48
average realized natural gas equivalent prices (after giving
effect to hedging activities) increased 9% from $7.85 per
Mcfe in 2005 to $8.52 per Mcfe in 2006.
Hedging activities. The oil and gas prices
that we report are based on the market price received for the
commodities adjusted to give effect to the results of our cash
flow hedging activities. We utilize commodity derivative
instruments (swaps and zero cost collar option contracts) in
order to (1) reduce the effect of the volatility of price
changes on the commodities we produce and sell, (2) support
our annual capital budgeting and expenditure plans and
(3) lock-in commodity prices to protect economics related
to certain capital projects. During 2005, our commodity price
hedges decreased oil revenues by $1.2 million
($1.92 per Bbl) and decreased gas revenues by
$0.5 million ($0.14 per Mcf). During 2006, our
commodity price hedges decreased oil revenues by
$7.0 million ($3.05 per Bbl) and increased gas
revenues by $1.2 million ($0.13 per Mcf).
The increased effect of the commodity price hedges in reducing
oil revenues during 2006 as compared to 2005 was the result of
(1) increased hedged volumes from 292,000 Bbls in 2005
to 1,080,500 Bbls in 2006 and (2) an increase in the
market price of NYMEX crude oil from an average of
$56.57 per Bbl in 2005 to $66.21 per Bbl in 2006. The
effect of the commodity price hedges in increasing gas revenues
during 2006 as compared to reducing gas revenues in 2005 was the
result of (1) increased hedged volumes from
1,642,500 MMBtus in 2005 to 5,447,500 MMBtus in 2006
and (2) a decrease in the reference market price of natural
gas from an average of $7.17 per MMBtu in 2005 to
$6.05 per MMBtu in 2006.
Production expenses Production expenses
(including production taxes) increased $23.2 million (159%)
from $14.6 million ($2.09 per Mcfe) to
$37.8 million ($1.62 per Mcfe) for the years ended
December 31, 2005 and 2006, respectively. The increase in
production expenses are due to two sources: (1) production
costs associated with the Chase Group Properties acquired in
February 2006 of approximately $20.2 million and
(2) costs associated with new wells that were successfully
completed in 2005 and 2006 as a result of our drilling
activities. Lease operating expenses and workover costs
comprised approximately 75% and 58% of production expenses for
2005 and 2006, respectively. These costs per unit of production
decreased 39% from $1.56 per Mcfe in 2005 to $0.95 per
Mcfe in 2006. This is because the Chase Group Properties are, on
average, less expensive to operate than the properties we
operated prior to the combination transaction. Lease operating
expenses include ad valorem taxes that are affected by commodity
price changes and ad valorem tax rates. Ad valorem taxes were
approximately 9% and 5% of lease operating expenses for 2005 and
2006, respectively.
The secondary component of production expenses is production
taxes and is directly related to commodity price changes. These
costs comprised approximately 25% and 42% of production expenses
for 2005 and 2006, respectively. Production taxes per unit of
production increased 28% from $0.53 per Mcfe in 2005 to
$0.68 per Mcfe in 2006. This increase was primarily due to an
increase in commodity prices.
Exploration and abandonments / geological and geophysical
costs. Exploration and abandonments / geological
and geophysical costs increased by $2.9 million from
$2.7 million during 2005 to $5.6 million during 2006.
The exploration and abandonments / geological and geophysical
costs during 2005 consisted of $1.4 million of exploratory
dry hole costs and $1.3 million of geological and
geophysical costs. The exploratory dry hole costs during 2005
were attributable to one exploratory dry hole in each of Eddy
and Lea Counties, New Mexico that we operated and to one
exploratory dry hole in Zapata County, Texas operated by another
company. The geological and geophysical costs for 2005 primarily
consisted of general and administrative costs
49
for our geology department as well as seismic data, geophysical
data and core analysis. The exploration and abandonments
/geological and geophysical costs during 2006 consisted of
$3.4 million of exploratory dry hole costs and
$2.2 million of geological and geophysical costs. The
exploratory dry hole costs during 2006 were attributable to one
exploratory dry hole in Gaines County, Texas that we operated
and one exploratory dry hole in Val Verde County, Texas operated
by another company. The geological and geophysical costs for
2006 primarily consisted of general and administrative costs for
our geology department as well as seismic data, geophysical data
and core analysis.
Depreciation and depletion expense. Total
depreciation and depletion expense increased $49.2 million
(428%) from $11.5 million ($1.64 per Mcfe) to
$60.7 million ($2.61 per Mcfe) for the years ended
December 31, 2005 and 2006, respectively. The increase in
total expense and expense per Mcfe was primarily due to the
acquisition of the Chase Group Properties and related
acquisition costs associated with the combination transaction.
Approximately $30.7 million of the increase in depreciation
and depletion expense for 2006 was attributable to the
acquisition of the Chase Group Properties.
Impairment of oil and gas properties. In
accordance with SFAS No. 144, we review our long-lived
assets to be held and used, including proved oil and gas
properties accounted for under the successful efforts method of
accounting. As a result of this review of the recoverability of
the carrying value of our assets during 2005, we recognized a
non-cash charge against earnings of $2.3 million related to
our proved oil and gas properties. For the year ended
December 31, 2006, we recognized a non-cash charge against
earnings of $9.9 million related to our proved oil and gas
properties. Of this amount, $0.1 million was related to the
Chase Group Properties.
General and administrative expenses. General
and administrative expenses increased $10.4 million (92%)
from $11.3 million ($1.62 per Mcfe) to
$21.7 million ($0.93 per Mcfe) for the years ended
December 31, 2005 and 2006 respectively. Excluding non-cash
stock-based compensation of $3.3 million in 2005 and
$9.1 million in 2006, general and administrative expenses
increased $4.5 million (56%) from $8.1 million
($1.15 per Mcfe) to $12.6 million ($0.54 per
Mcfe) for the years ended December 31, 2005 and 2006,
respectively. The increase in general and administrative expense
during 2006 was primarily because of the hiring of additional
staff and an increase in professional fees related to the
combination transaction and other activities of our company. We
earn revenue as operator of certain oil and gas properties in
which we own interests. As such, we earned revenue of
$0.6 million and $0.8 million during the years ended
December 31, 2005 and 2006, respectively. This revenue is
reflected as a reduction of general and administrative expenses
in the consolidated statements of operations.
Interest expense. Interest expense increased
$27.5 million from $3.1 million to $30.6 million
for the years ended December 31, 2005 and 2006,
respectively. The weighted average interest rate for the years
ended December 31, 2005 and 2006 was 5.5% and 7.5%,
respectively. The weighted average debt outstanding during 2005
and 2006 was approximately $59 million and
$407 million, respectively. The increase in interest
expense was due to the increase in overall debt outstanding and
the increase in interest rates. The increase in weighted average
debt outstanding during 2006 was primarily due to our borrowing
under our revolving credit facility on February 27, 2006 to
fund the cash payment due as part of the combination
transaction, to repay the Concho Equity Holdings Corp. credit
facility, and to pay bank and legal fees. The increase in
weighted average debt outstanding was also due to our borrowing
$40 million under our prior second lien term loan facility
on July 6, 2006 to reduce the amount outstanding
50
under our revolving credit facility by $32.1 million, with
the remaining $7.9 million used for general corporate
purposes.
Other, net. Interest and other revenue
increased by $407,000 from $779,000 to $1,186,000 during the
years ended December 31, 2005 and 2006, respectively.
Interest earned increased by $450,000 from $367,000 during the
year ended December 31, 2005 to $817,000 during the year
ended December 31, 2006, due to interest on officer and
employee notes. Other revenue decreased by $43,000 from $412,000
to $369,000 during the years ended December 31, 2005 and
2006, respectively.
Income tax provisions (benefits). We recorded
income tax expense of $2.0 million and $14.4 million
for the years ended December 31, 2005 and 2006,
respectively. The income tax expense was due to the income
reported during the years ended December 31, 2005 and 2006.
We had a net deferred federal and state tax asset at
December 31, 2005 in the amount of $4.9 million. This
accumulated balance is based on deferred hedge losses and
differences in basis of oil and gas properties for tax purposes
as compared to book purposes and offset by the effect of a net
operating loss. Intangible drilling costs are allowed as
deductions by the Internal Revenue Service and are capitalized
under the generally accepted accounting principles in the United
States of America. At December 31, 2006, we had a net
deferred tax liability of $241.7 million. This change is
primarily due to differences in basis and depletion of oil and
gas properties for tax purposes as compared to book purposes
related to the acquisition of the Chase Group Properties in
February 2006, a reduction of deferred hedge losses and the
elimination of the net operating loss.
Inception
(April 21, 2004) through December 31, 2004,
compared to year ended December 31, 2005
Oil and gas revenues. Revenues from oil and
gas operations increased by $51.3 million from
$3.6 million for the period April 21, 2004 to
December 31, 2004 to $54.9 million for the year ended
December 31, 2005. This increase was primarily because we
did not conduct any substantial operations other than
organizational activities from our formation on April 21,
2004 until the acquisition of the Lowe Properties on
December 7, 2004. In addition, revenue during the year
ended December 31, 2005 increased due to the successful
completion of new wells as a result of our drilling activities
during 2005. Finally, average oil prices after giving effect to
hedging activities increased 28% between 2004 and 2005 from
$41.37 per Bbl to $52.79 per Bbl, respectively, and
average natural gas prices after giving effect to hedging
activities increased 12% between 2004 and 2005 from
$6.09 per Mcf to $6.85 per Mcf, respectively. Average
natural gas equivalent prices increased 21% from $6.48 per
Mcfe in 2004 to $7.85 per Mcfe in 2005.
Hedging activities. The oil and gas prices
that we report are based on the market price received for the
commodities adjusted by the results of our cash flow hedging
activities. We utilize commodity derivative instruments (swaps
and zero cost collar option contracts) in order to
(1) reduce the effect of the volatility of price changes on
the commodities we produce and sell, (2) support our annual
capital budgeting and expenditure plans and (3) lock-in
prices to protect economics related to certain capital projects.
During 2005, our commodity price hedges decreased oil revenues
by $1.2 million ($1.92 per Bbl) and decreased gas
revenues by $0.5 million ($0.14 per Mcf). During 2004,
there were no settlements of oil or gas hedges as the first
hedged period began in January 2005.
51
Derivatives not designated as hedges. During
the period from April 24, 2004 through December 31,
2004, we entered into certain oil and natural gas derivative
financial instruments that did not qualify for cash flow hedge
accounting treatment under SFAS No. 133. In October
2004, we purchased put contracts for, in the
aggregate, 182,500 Bbls of oil and 1,095,000 MMBtus
of natural gas, respectively, for production months in the year
ended December 31, 2005. In December 2004, our position in
these contracts was exchanged for swap contracts for
a like amount of 2005 production. These contracts were
originally entered into in anticipation of the acquisition on
December 7, 2004 of certain producing oil and natural gas
properties from Lowe Partners, LP. The objective of these
arrangements was to protect against commodity price fluctuations
and achieve a more predictable cash flow. SFAS No. 133
requires that every derivative instrument (including those not
designated as cash flow hedges) be recorded on the balance sheet
as either an asset or liability measured at its fair value.
SFAS No. 133 generally requires that changes in the
derivatives fair value be recognized currently in earnings
unless specific hedge accounting criteria are met and the
derivative is designated as a hedge unless exemptions for normal
purchases and normal sales as allowed by SFAS No. 133
are applicable.
During the period from April 24, 2004 through
December 31, 2004, we recognized gains of approximately
$0.7 million as the fair value of these derivative
instruments increased because of a decrease in the market price
for oil, offset in part by an increase in the market price for
natural gas, from the date the contracts were entered into in
comparison to market prices at December 31, 2004. During
the year ended December 31, 2005, we recorded losses of
approximately $5.0 million in these contracts as a result
of increases in oil and natural gas prices.
Production expenses. Production costs
(including production taxes) increased by $13.9 million
from $0.7 million ($1.33 per Mcfe) during the period
from April 21, 2004 to December 31, 2004 to
$14.6 million ($2.09 per Mcfe) during the year ended
December 31, 2005. Lease operating expenses and workover
costs, the components of production costs over which we have
management control, increased by $10.4 million from
$0.5 million ($0.91 per Mcfe) during the period from
April 21, 2004 to December 31, 2004 to
$10.9 million ($1.56 per Mcfe) during the year ended
December 31, 2005. The increase in production costs,
including lease operating expenses and workover costs, between
the period from April 21, 2004 to December 31, 2004
and the year ended December 31, 2005 was primarily because
of our less extensive oil and gas operations during the period
from April 21, 2004 to December 31, 2004, prior to our
acquisition of the Lowe Properties on December 7, 2004.
Lease operating expenses include ad valorem taxes that are
affected by commodity price changes and ad valorem tax rates. Ad
valorem taxes were approximately 10% and 9% of lease operating
expenses for 2004 and 2005 respectively.
The secondary component of production costs is production taxes
and is directly related to commodity price changes. Our
production taxes increased from $0.2 million
($0.42 per Mcfe) during the period from April 21, 2004
to December 31, 2004 to $3.7 million ($0.53 per
Mcfe) during the year ended December 31, 2005, primarily
due to higher commodity prices and increased production during
the year ended December 31, 2005.
Exploration and abandonments / geological and geophysical
costs. Exploration and abandonments / geological
and geophysical costs increased by $0.8 million from
$1.9 million during the period from April 21, 2004 to
December 31, 2004 to $2.7 million during the year
ended December 31, 2005. The exploration and abandonments /
geological and geophysical costs during the period from
April 21, 2004 to December 31, 2004 consisted of
$1.3 million of exploratory dry hole costs and
$0.6 million of geological and geophysical costs. The
geological and geophysical costs for the period from
April 21, 2004 to December 31, 2004 included a non-
52
cash charge of $0.4 million related to an abandoned
prospect in the Gulf Coast region. The exploration and
abandonments / geological and geophysical costs during the year
ended December 31, 2005 consisted of $1.4 million of
exploratory dry hole costs and $1.3 million of geological
and geophysical costs. The exploratory dry hole costs during the
year ended December 31, 2005 were attributable to two wells
drilled in the Permian Basin region that we operated and one
well in the Gulf Coast region that we did not operate.
Depreciation and depletion expense. Our total
depreciation and depletion expense increased by
$10.5 million from $1.0 million ($1.71 per Mcfe)
during the period from April 21, 2004 to December 31,
2004 to $11.5 million ($1.64 per Mcfe) during year
ended December 31, 2005. The increase in the total
depreciation and depletion expense was primarily because of the
impact of the acquisition of the Lowe Properties on the full
year ended December 31, 2005. Our depreciation and
depletion expense per Mcfe decreased from during the period from
April 21, 2004 to December 31, 2004 to the year ended
December 31, 2005 because of additional reserves added to
the depletable properties base during 2005 resulting from the
Companys successful drilling operations.
Impairment of oil and gas properties. In
accordance with SFAS No. 144, we reviewed our
long-lived assets to be held and used, including proved oil and
gas properties accounted for under the successful efforts method
of accounting. As a result of this review of the recoverability
of the carrying value of our assets during 2005, we recognized a
non-cash charge against earnings of $2.3 million related to
our proved oil and gas properties. At December 31, 2004, we
did not recognize a charge against earnings related to our
proved oil and gas properties.
General and administrative expenses. General
and administrative expenses increased by $7.1 million from
$4.2 million ($7.54 per Mcfe) during the period from
April 21, 2004 to December 31, 2004 to
$11.3 million ($1.62 per Mcfe) during the year ended
December 31, 2005, respectively. Excluding non-cash
stock-based compensation of $1.1 million in 2004 and
$3.3 million in 2005, our general and administrative
expenses increased by $4.9 million from $3.1 million
($5.52 per Mcfe) during the period from April 21, 2004
to December 31, 2004 to $8.1 million ($1.15 per
Mcfe) during the year ended December 31, 2005. The increase
in general and administrative expense during the year ended
December 31, 2005 was primarily because of increased
business activity in 2005 as well as the hiring of additional
staff in 2005. From time to time, we also earn revenue in our
capacity as operator of certain oil and gas properties in which
we own interests. As such, we earned revenue of $38,000 and
$591,000 during the period from April 21, 2004 to
December 31, 2004 and during the year ended
December 31, 2005, respectively. This revenue is reflected
as a reduction of general and administrative expenses in the
consolidated statements of operations.
Interest expense. Interest expense increased
by $2.8 million from $0.3 million during the period
from April 21, 2004 to December 31, 2004 to
$3.1 million during the year ended December 31, 2005.
The increase in interest expense during the year ended
December 31, 2005 was primarily due to increased borrowings
under our former revolving credit facility that we incurred to
fund a portion of the cash consideration for the Lowe
Properties. Prior to October 14, 2004, the date on which we
were required to make a cash escrow deposit for the acquisition
of the Lowe Properties, we had not borrowed any funds under the
former revolving credit facility.
Other, net. Interest and other revenue
increased by $611,000 from $168,000 during the period from
April 21, 2004 to December 31, 2004 to $779,000 during
the year ended December 31, 2005. Interest earned increased
by $256,000 from $111,000 during the period from April 21,
2004 to December 31, 2004 to $367,000 during the year ended
December 31, 2005 due to
53
interest on officer and employee notes. Other revenue increased
by $355,000 from $57,000 during the period from April 21,
2004 to December 31, 2004 to $412,000 during the year ended
December 31, 2005.
Income tax provisions (benefits). We recorded
an income tax benefit of $0.9 million during the period
from April 21, 2004 to December 31, 2004 and an income
tax expense of $2.0 million during the year ended
December 31, 2005. The income tax benefit during the period
from April 21, 2004 to December 31, 2004 was due to
the loss we reported during that period while the income tax
expense during the year ended December 31, 2005 was due to
the income we reported during that period.
We recognized a net deferred federal and state tax asset during
the period from April 21, 2004 to December 31, 2004 in
the amount of $0.9 million at December 31, 2004. This
accumulated balance is based on differences in basis and
depletion of oil and gas properties for tax purposes as compared
to book purposes offset by the effects of a net operating loss
and the tax effects of deferred hedge gains. The deferred tax
asset increased by $4.0 million from December 31, 2004
to December 31, 2005, primarily due to the tax effect of
deferred hedge losses offset by an increase in intangible
drilling costs which are allowed by the Internal Revenue Service
as deductions and are capitalized under generally accepted
accounting principles in the United States of America.
Liquidity and
capital resources
Our primary sources of liquidity have been cash flows generated
from operating activities and financing provided by our bank
credit facilities. We believe that funds from operating cash
flows and our bank credit facilities should be sufficient to
meet both our short-term working capital requirements and our
2008 exploration and development budget.
Cash flow from
operating activities
Our net cash provided by operating activities was
$58.9 million and $102.9 million for the nine months
ended September 30, 2006 and 2007, respectively. The
increase in operating cash flows during the nine months ended
September 30, 2007 was principally due to increases in our
oil and gas production as a result of our exploration and
development program and cash flow from production attributable
to the Chase Group Properties that we acquired in the
combination transaction in February 2006.
Our net cash provided by operating activities was
$25.1 million and $112.2 million for the years ended
December 31, 2005 and 2006, respectively. The increase in
operating cash flows in 2006 was principally due to increases in
our oil and gas production as a result of our exploration and
development program and cash flow from production attributable
to the Chase Group Properties that we acquired in the
combination transaction in February 2006.
Cash flow used in
investing activities
During the nine months ended September 30, 2006 and 2007,
we invested $536.7 million and $114.2 million,
respectively, for additions to, and acquisitions of, oil and gas
properties, inclusive of dry hole costs. Cash flows used in
investing activities were substantially higher during the nine
months ended September 30, 2006, primarily due to the
approximately $409 million cash portion of the
consideration we paid to the Chase Group in the combination
transaction. We
54
determined to reduce our drilling activities and curtail capital
expenditures during the three months ended March 31, 2007
until we were able to complete our second lien term loan
facility in March 2007 in order to preserve liquidity. As a
result, we recorded an expense during the six months ended
June 30, 2007 of approximately $4.3 million for
contract drilling fees related to stacked rigs subject to day
work drilling contracts with two drilling contractors. See
Items impacting comparability of our financial
resultsCurtailment of drilling above.
During the years ended December 31, 2005 and 2006, we
invested $55.6 million and $595.6 million,
respectively, in our capital program, inclusive of dry hole
costs. Cash flows used in investing activities increased during
the year ended December 31, 2006, primarily due to the
approximately $409 million cash portion of the
consideration we paid to the Chase Group in the combination
transaction and drilling activities in 2006.
Cash flow from
financing activities
Net cash provided by financing activities was
$469.8 million and $30.8 million for the nine months
ended September 30, 2006 and 2007, respectively. Cash
provided by financing activities in the nine months ended
September 30, 2006 was primarily due to borrowings under
our revolving credit facility to fund the approximately
$409 million cash portion of the consideration paid to the
Chase Group pursuant to the combination transaction and proceeds
from private issuances of equity in our company.
Net cash provided by financing activities was $45.4 million
and $476.6 million for the years ended December 31,
2005 and 2006, respectively. In 2005, cash provided by financing
activities was primarily attributable to net proceeds from the
issuance of debt and equity in our company, partially offset by
payment of dividends on preferred stock. The increase during
2006 was primarily due to borrowings under our revolving credit
agreement to fund the approximately $409 million cash
portion of the consideration paid to the Chase Group and
associated persons pursuant to the combination transaction and
proceeds from private issuances of equity in our company.
Bank credit
facilities
We have two separate bank credit facilities. The first bank
credit facility is our Credit Agreement, dated as of
February 24, 2006, with JPMorgan Chase Bank, N.A. as the
administrative agent for a group of lenders that provides a
revolving line of credit having a total commitment of
$475.0 million, which we refer to as the revolving
credit facility. The total amount that we can borrow and
have outstanding at any one time is limited to the lesser of the
total commitment of $475.0 million or the borrowing base
established by the lenders. As of December 31, 2006, the
borrowing base under our revolving credit facility was
$475.0 million, but was reduced to $375.0 million on
March 27, 2007 in connection with the completion of our
second lien term loan facility described below. As of
September 30, 2007, the principal amount outstanding under
our revolving credit facility was $234.0 million. Effective
November 21, 2007, the borrowing base under our revolving
credit facility was increased to $425.0 million. In
February 2006, we incurred borrowings of approximately
$421.0 million under our revolving credit facility in
connection with the combination transaction to pay the cash
purchase price of $400.0 million to the Chase Group,
$15.9 million to repay the balance on the prior revolving
credit facility of Concho Equity Holdings Corp. and
approximately $5.1 million for bank fees and legal costs
associated with our revolving credit facility. We also incurred
borrowings of approximately $8.9 million in May 2006 in
connection with the purchase of additional working interests
55
in the Chase Group Properties pursuant to the combination
transaction from persons associated with the Chase Group. The
remaining borrowings under our revolving credit facility during
2006 were used for working capital and to fund a portion of our
exploration and development drilling program.
The second bank credit facility is our Second Lien Credit
Agreement, dated as of March 27, 2007, with Bank of
America, N.A., as the administrative agent for the other lenders
thereunder, that provides a five year term loan in the amount of
$200.0 million, which we refer to as the second lien
term loan facility. Upon execution of the second lien term
loan facility, we funded the full amount under that facility and
received proceeds of $199.0 million to repay the
$39.8 million outstanding under our prior term loan
facility, to reduce the outstanding balance under our revolving
credit facility by $154.0 million and the remaining
$5.2 million to pay loan fees, accrued interest and for
general corporate purposes. We used net proceeds of
approximately $173.0 million from our initial public
offering that was completed in August 2007 to retire
outstanding borrowings under our second lien term loan facility
totaling $86.5 million and to retire outstanding borrowings
under our revolving credit facility totaling $86.5 million.
Revolving credit facility. The revolving credit
facility allows us to borrow, repay and reborrow amounts
available under the revolving credit facility. The amount of the
borrowing base is based primarily upon the estimated value of
our oil and natural gas reserves. The borrowing base under our
revolving credit facility is re-determined at least
semi-annually. The revolving credit facility matures on
February 24, 2010, and borrowings under our revolving
credit facility bear interest, payable quarterly, at our option,
at (1) a rate (as defined and further described in our
revolving credit facility) per annum equal to a Eurodollar Rate
(which is substantially the same as the London Interbank Offered
Rate) for one, two, three or six months as offered by the lead
bank under our revolving credit facility, plus an applicable
margin ranging from 100 to 225 basis points, or
(2) such banks Prime Rate, plus an applicable margin
ranging from 0 to 125 basis points, dependent in each case
upon the percentage of our available borrowing base then
utilized. Our revolving credit facility bore interest at
6.83% per annum as of September 30, 2007. We pay
quarterly commitment fees under our revolving credit facility on
the unused portion of the available borrowing base ranging from
25 to 50 basis points, dependent upon the percentage of our
available borrowing base then utilized.
Borrowings under our revolving credit facility are secured by a
first lien on substantially all of our assets and properties.
Our revolving credit facility also contains restrictive
covenants that may limit our ability to, among other things, pay
cash dividends, incur additional indebtedness, sell assets, make
loans to others, make investments, enter into mergers involving
our company, incur liens and engage in certain other
transactions without the prior consent of the lenders. The
revolving credit facility also requires us to maintain certain
ratios as defined and further described in our revolving credit
facility, including a current ratio of not less than 1.0 to 1.0
and a maximum leverage ratio (generally defined as the ratio of
total funded debt to a defined measure of cash flow) of no
greater than 4.0 to 1.0. In addition, at the inception of the
revolving credit facility, we had a one-time requirement to
enter into hedging agreements with respect to not less than 75%
of our forecasted production through December 31, 2008,
that was attributable to our proved developed producing reserves
estimated as of December 31, 2005. As of September 30,
2007, we were in compliance with all such covenants.
Second lien term loan facility. The second lien term
loan facility provides a $200.0 million term loan, which
bears interest, at our option, at (1) a rate per annum
equal to the London Interbank Offered Rate, plus an applicable
margin of 425 basis points or (2) the prime rate, plus
an
56
applicable margin of 275 basis points. We have the option
to select different interest periods, subject to availability,
and interest is payable at the end of the interest period we
select, though such interest payments must be made at least on a
quarterly basis. We are required to repay $500,000 of the second
lien term loan facility on the last day of each calendar
quarter, commencing June 30, 2007, until the remaining
balance of the loan matures on March 27, 2012. Our second
lien term loan facility bore interest at 9.76% per annum as
of September 30, 2007. We have the right to prepay the
outstanding balance under the second lien term loan facility at
any time, provided, however, that we will incur a 2% prepayment
penalty on any principal amount prepaid from March 27, 2008
until March 26, 2009 and a 1% prepayment penalty on any
principal amount prepaid from March 27, 2009 until
March 26, 2010.
Borrowings under the second lien term loan facility are secured
by a second lien on the same assets as are securing our
revolving credit facility, which liens are subordinated to liens
securing our revolving credit agreement. The second lien term
loan facility also contains various restrictive financial
covenants and compliance requirements that are similar to those
contained in the revolving credit agreement, including the
maintenance of certain financial ratios.
Future capital
expenditures and commitments
We evaluate opportunities to purchase or sell oil and natural
gas properties in the marketplace and could participate as a
buyer or seller of properties at various times. We seek to
acquire oil and gas properties that provide opportunities for
the addition of reserves and production through a combination of
exploitation, development, high-potential exploration and
control of operations and that will allow us to apply our
operating expertise or that otherwise have geologic
characteristics that are similar to our existing properties.
Expenditures for exploration and development of oil and natural
gas properties are the primary use of our capital resources. We
anticipate investing approximately $183.0 million for
exploration and development expenditures in 2007 as follows (in
millions):
|
|
|
|
|
Drilling and recompletion opportunities in our core operating
area
|
|
$
|
135.2
|
Projects in our emerging plays
|
|
|
28.9
|
Projects operated by third parties
|
|
|
14.2
|
Acquisition of leasehold acreage and other property interests
|
|
|
4.7
|
|
|
|
|
Total 2007 exploration and development budget
|
|
$
|
183.0
|
|
|
|
|
|
|
On November 8, 2007 our board of directors approved our
2008 exploration and development budget in the amount of
$250.4 million. We anticipate investing our 2008
exploration and development budget as follows (in millions):
|
|
|
|
|
Drilling and recompletion opportunities in our core operating
area
|
|
$
|
209.5
|
Projects operated by third parties
|
|
|
14.3
|
Emerging plays, acquisition of leasehold acreage and other
property interests, and geological and geophysical
|
|
|
20.0
|
Maintenance capital in our core operating areas
|
|
|
6.6
|
|
|
|
|
Total 2008 exploration and development budget
|
|
$
|
250.4
|
|
|
|
|
|
|
57
Other than leasehold acreage and other property interests shown
above, our 2007 and 2008 exploration and development budgets are
exclusive of acquisitions. We do not have a specific acquisition
budget since the timing and size of acquisitions are difficult
to forecast.
Although we cannot provide any assurance, assuming successful
implementation of our strategy, including the future development
of our proved reserves and realization of our cash flows as
anticipated, we believe that our remaining cash balance and cash
flows from operations will be sufficient to satisfy our 2007 and
2008 exploration and development budgets. The actual amount and
timing of our expenditures may differ materially from our
estimates as a result of, among other things, actual drilling
results, the timing of expenditures by third parties on projects
that we do not operate, the availability of drilling rigs and
other services and equipment, and regulatory, technological and
competitive developments.
Hedging
We account for derivative instruments in accordance with
SFAS No. 133. The specific accounting treatment for
changes in the market value of the derivative instruments used
in hedging activities is determined based on the designation of
the derivative instruments as a cash flow or fair value hedge
and effectiveness of the derivative instruments. Certain of our
derivative contracts related to oil production entered into
prior to 2007 are accounted for as cash flow hedges. As
described below, certain natural gas derivative contracts were
originally designated as cash flow hedges, but because of a
change in the correlation between the underlying natural gas
production and the index referenced in the derivative contracts,
we have discontinued hedge accounting related to natural gas
contracts as of July 1, 2007. Management has not and does
not currently intend to designate or account for derivative
contracts entered into subsequent to June 30, 2007 as cash
flow hedges.
We have utilized fixed-price contracts and zero-cost collars to
reduce exposure to unfavorable changes in oil and natural gas
prices that are subject to significant and often volatile
fluctuation. Under the fixed price physical delivery contracts,
we receive the fixed price stated in the contract. Under the
zero-cost collars, if the market price of crude oil or natural
gas, as applicable, is less than the ceiling strike price and
greater than the floor strike price, we receive the market
price. If the market price of crude oil or natural gas, as
applicable, exceeds the ceiling strike price or falls below the
floor strike price, we receive the applicable collar strike
price.
During the three months ended September 30, 2007, we
determined that all of our natural gas commodity contracts no
longer qualified as hedges under the requirements of
SFAS No. 133, for the reason stated in the following
paragraph. These contracts are referred to as dedesignated
hedges.
A key requirement for designation of derivative instruments as
cash flow hedges is that at both the inception of the hedge and
on an ongoing basis, the hedging relationship is expected to be
highly effective in achieving offsetting cash flows attributable
to the hedged risk during the term of the hedge. Generally, the
hedging relationship can be considered to be highly effective if
there is a high degree of historical correlation between the
hedging instrument and the forecasted transaction. In prior
quarters, prices received for our natural gas have been highly
correlated with the Inside FERCEl Paso Natural Gas
index, which we refer to herein as the Index, which is the index
referenced in all of our natural gas derivative instruments.
However, during the quarter ended September 30, 2007, this
historical relationship has not met the
58
criteria as being highly correlated. Natural gas produced from
our New Mexico Shelf assets has a substantial component of
natural gas liquids. Prices received for natural gas liquids are
not highly correlated to the price of natural gas, but are more
closely correlated to the price of oil. During the third quarter
of 2007, the price of oil and natural gas liquids, and therefore
the prices we received for our natural gas (including natural
gas liquids), have risen substantially and at a significantly
higher rate than the corresponding change in the Index. This has
resulted in a decrease in correlation between the prices
received and the Index below the level required for cash flow
hedge accounting. According to SFAS No. 133, an entity
should discontinue prospectively hedge accounting for an
existing hedge if the hedge is no longer highly effective. Hedge
accounting must be discontinued regardless of whether we believe
the hedge will be prospectively highly effective. The hedge must
be discontinued during the period the hedges became ineffective.
As a result, any changes in fair value must be recorded in
earnings under (Gain) loss on derivatives not designated as
hedges. Because the natural gas and natural gas liquids
prices fluctuate at different rates over time, the loss of
effectiveness does not relate to any single date.
Therefore, June 30, 2007, is considered the last date our
natural gas hedges were highly effective, and we must
discontinue hedge accounting during the three months ended
September 30, 2007 and all periods thereafter.
Mark-to-market adjustments related to these dedesignated hedges
will be recorded each period to (Gain) loss on derivatives
not designated as hedges. Effective portions of dedesignated
hedges, previously recorded in Accumulated other
comprehensive income as of June 30, 2007, will remain
in Accumulated other comprehensive income and be
reclassified into earnings under Natural gas revenues,
during the periods which the hedged forecasted transaction
affects earnings.
Due to the fact that this correlation relationship is expected
to continue in the future on the gas produced from the
properties originally identified in our hedge documentation in
2004, 2006 and 2007, we do not intend to attempt to re-designate
these natural gas derivatives as cash flow hedges in future
periods; rather, they will be accounted for as described above
through the remaining derivative contract term.
On September 20, 2007, we entered into four crude oil price
swaps to hedge an additional portion of our estimated crude oil
production for calendar years 2008 and 2009. The contracts are
for 1,000 Bbls per day each with various fixed prices. We
have not designated these derivative instruments as cash flow
hedges. Mark-to-market adjustments related to these derivative
instruments will be recorded each period to (Gain) loss on
derivatives not designated as hedges.
At September 30, 2007, we had an oil price collar and oil
price swaps that settle on a monthly basis covering future oil
production from October 1, 2007 through December 31,
2009. The volumes are detailed in the table below. Subsequent to
September 30, 2007, oil futures prices have increased
significantly and continue to exceed the oil price collar cap of
$41.75 and have risen to a level that exceeds the weighted
average price swap fixed price of $70.65. The average futures
NYMEX price for the three months ended September 30, 2007,
was $75.33. As of October 31, 2007, the NYMEX futures price
was $94.53. At this level, we will continue to remit the excess
of the average monthly NYMEX futures price for each settlement
period over the oil collar cap price of $41.75 and the weighted
average price swap fixed price of $70.65. While these payments
should not significantly affect our cash flow since
(1) payments made to counterparties to these contracts
should be substantially offset by increased commodity prices
received on the sale of our production and (2) only a
portion of the total contract volume
59
settles each month. The increase in oil prices, should it
continue, will negatively affect the fair value of our
commodities contracts as recorded in our balance sheet at
December 31, 2007, during future periods and, consequently,
our reported net income. Changes in the recorded fair value of
certain of our commodity derivatives are marked to market
through earnings and are likely to result in substantial charges
to earnings for the decrease in the fair value of these
contracts during the fourth quarter of 2007. If oil prices
continue to increase, this negative effect on earnings will
become more significant. We are currently unable to estimate the
effects on earnings in the fourth quarter of 2007, but the
effects may be substantial.
The table below provides the volumes and related data associated
with our oil and natural gas derivatives as of
September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Market Value
|
|
|
remaining
|
|
|
Daily
|
|
|
Index
|
|
|
Contract
|
|
|
|
Asset / (Liability)
|
|
|
volume
|
|
|
volume
|
|
|
price
|
|
|
period
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar
|
|
$
|
(2,278
|
)
|
|
|
59,800
|
|
|
|
650
|
|
|
$
|
37.95 -
$41.75(a
|
)
|
|
|
10/1/07 - 12/31/07
|
|
Price swap
|
|
|
(2,570
|
)
|
|
|
211,600
|
|
|
|
2,300
|
|
|
$
|
67.85(a
|
)
|
|
|
10/1/07 - 12/31/07
|
|
Price swap
|
|
|
(7,668
|
)
|
|
|
951,600
|
|
|
|
2,600
|
|
|
$
|
67.50(a
|
)
|
|
|
1/1/08 - 12/31/08
|
|
Cash flow hedges dedesignated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar
|
|
|
735
|
|
|
|
1,472,000
|
|
|
|
16,000
|
|
|
$
|
5.98 -
$9.75(b
|
)(c)
|
|
|
10/1/07 - 12/31/07
|
|
Price collar
|
|
|
1,740
|
|
|
|
4,941,000
|
|
|
|
13,500
|
|
|
$
|
6.50 -
$9.35(b
|
)
|
|
|
1/1/08 - 12/31/08
|
|
Price swap
|
|
|
257
|
|
|
|
193,200
|
|
|
|
2,100
|
|
|
$
|
7.40(b
|
)
|
|
|
10/1/07 - 12/31/07
|
|
Derivatives not designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
(33
|
)
|
|
|
732,000
|
|
|
|
2,000
|
|
|
$
|
75.78(a
|
)(c)
|
|
|
1/1/08 - 12/31/08
|
|
Price swap
|
|
|
71
|
|
|
|
730,000
|
|
|
|
2,000
|
|
|
$
|
72.84(a
|
)(c)
|
|
|
1/1/09 - 12/31/09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net liability
|
|
$
|
(9,746
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
The index prices for the oil price
collars and price swaps are based on the NYMEX-West Texas
Intermediate monthly average futures price.
|
|
(b)
|
|
The index prices for the natural
gas price collars and price swaps are based on the Inside
FERC-El Paso Permian Basin first-of-the-month spot price.
|
|
(c)
|
|
Amounts disclosed represent
weighted average prices.
|
60
Obligations and
commitments
We had the following contractual obligations and commitments as
of September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by period
|
|
|
|
|
Less than
|
|
1 - 3
|
|
3 - 5
|
|
More than
|
(In thousands)
|
|
Total
|
|
1 year
|
|
years
|
|
years
|
|
5 years
|
|
|
Long-term
debt(a)
|
|
$
|
346,400
|
|
$
|
2,000
|
|
$
|
238,000
|
|
$
|
106,400
|
|
$
|
|
Operating lease
obligation(b)
|
|
|
2,952
|
|
|
462
|
|
|
953
|
|
|
993
|
|
|
544
|
Daywork drilling
contracts(c)
|
|
|
18,410
|
|
|
18,410
|
|
|
|
|
|
|
|
|
|
Employment agreements with executive
officers(d)
|
|
|
2,828
|
|
|
1,700
|
|
|
1,128
|
|
|
|
|
|
|
Asset retirement
obligations(e)
|
|
|
7,277
|
|
|
1,005
|
|
|
144
|
|
|
213
|
|
|
5,915
|
|
|
|
|
|
|
Total contractual cash obligations
|
|
$
|
377,867
|
|
$
|
23,577
|
|
$
|
240,225
|
|
$
|
107,606
|
|
$
|
6,459
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
See Note JLong-term
debt to our consolidated financial statements.
|
|
(b)
|
|
Operating lease obligation is for
office space.
|
|
(c)
|
|
Consists of daywork drilling
contracts related to five drilling rigs contracted for a portion
of 2007 and a portion of 2008. See Note K - Commitments
and contingencies to our consolidated financial statements.
|
|
(d)
|
|
Represents amounts of cash
compensation we are obligated to pay to our executive officers
under employment agreements assuming such employees continue to
serve the entire term of their employment agreement and their
cash compensation is not adjusted in the discretion of the board
of directors.
|
|
(e)
|
|
Amounts represent costs related to
expected oil and gas property abandonments related to proved
reserves by period, net of any future accretion.
|
Off-balance sheet
arrangements
Currently we do not have any off-balance sheet arrangements.
Critical
accounting policies and practices
Our historical consolidated financial statements and notes to
our historical 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 and impairment of assets.
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.
61
Successful
efforts method of accounting
We utilize the successful efforts method of accounting for our
oil and natural gas exploration and development activities under
this method. Exploration expenses, including geological and
geophysical costs, lease rentals and exploratory dry holes, are
charged against income as incurred. Costs of successful wells
and related production equipment, undeveloped leases and
developmental dry holes are also capitalized. This accounting
method may yield significantly different results than the full
cost method of accounting. Exploratory drilling costs are
initially capitalized, but are charged to expense if and when
the well is determined not to have found proved reserves.
Generally, a gain or loss is recognized when producing
properties are sold.
The application of the successful efforts method of accounting
requires managements judgment to determine the proper
designation of wells as either developmental or exploratory,
which will ultimately determine the proper accounting treatment
of costs of dry holes. Once a well is drilled, the determination
that proved reserves have been discovered may take considerable
time, and requires both judgment and application of industry
experience. The evaluation of oil and gas leasehold acquisition
costs included in unproved properties requires managements
judgment to estimate the fair value of such properties. Drilling
activities in an area by other companies may also effectively
condemn our leasehold positions.
Non-producing properties consist of undeveloped leasehold costs
and costs associated with the purchase of certain proved
undeveloped reserves. Individually significant non-producing
properties are periodically assessed for impairment of value.
Depreciation of capitalized drilling and development costs of
oil and natural gas properties is computed using the
unit-of-production
method on an individual property or unit basis based on total
estimated proved developed oil and natural gas reserves.
Depletion of producing leaseholds is based on the
unit-of-production
method using our total estimated net proved reserves. In
arriving at rates under the
unit-of-production
method, the quantities of recoverable oil and natural gas are
established based on estimates made by our geologists and
engineers and independent engineers. Service properties,
equipment and other assets are depreciated using the
straight-line method over estimated useful lives of 1 to
50 years. Upon sale or retirement of depreciable or
depletable property, the cost and related accumulated depletion
are eliminated from the accounts and the resulting gain or loss
is recognized.
Oil and natural
gas reserves and standardized measure of future cash
flows
Our independent engineers and technical staff prepare the
estimates of our oil and natural gas reserves and associated
future net cash flows. Current accounting guidance allows only
proved oil and natural gas reserves to be included in our
financial statement disclosures. The SEC has defined proved
reserves as the estimated quantities of crude oil and natural
gas which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating
conditions. Even though our independent engineers and technical
staff are knowledgeable and follow authoritative guidelines for
estimating reserves, they must make a number of subjective
assumptions based on professional judgments in developing the
reserve estimates. Reserve estimates are updated at least
annually and consider recent production levels and other
technical information about each field. Periodic revisions to
the estimated reserves and future cash flows may be necessary as
a result of a number of factors, including reservoir
performance, new drilling, oil and natural gas prices, cost
changes, technological advances, new geological or geophysical
data, or other
62
economic factors. We cannot predict the amounts or timing of
future reserve revisions. If such revisions are significant,
they could significantly alter future DD&A and result in
impairment of assets that may be material.
Asset retirement
obligations
In June 2001, the FASB issued SFAS No. 143,
Accounting for Asset Retirement Obligations, which
applies to legal obligations associated with the retirement of
long-lived assets that result from the acquisition,
construction, development and the normal operation of a
long-lived asset. The primary impact of this standard on us
relates to oil and natural gas wells on which we have a legal
obligation to plug and abandon. SFAS No. 143 requires
us to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred and
a corresponding increase in the carrying amount of the related
long-lived asset. The determination of the fair value of the
liability requires us to make numerous judgments and estimates,
including judgments and estimates related to future costs to
plug and abandon wells, future inflation rates and estimated
lives of the related assets.
Impairment of
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 a field
for impairment may result from significant declines in sales
prices or downward revisions to estimated quantities of oil and
natural gas reserves. Any assets held for sale are reviewed for
impairment when we approve the plan to sell. Estimates of
anticipated sales prices are highly judgmental and subject to
material revision in future periods. Because of the uncertainty
inherent in these factors, we cannot predict when or if future
impairment charges will be recorded.
Recent accounting
pronouncements
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurement. This statement defines fair
value, establishes a framework for measuring fair value and
expands disclosures about fair value measurements. This
statement is effective for financial statements issued for
fiscal years beginning after November 15, 2007. We will
adopt SFAS No. 157 effective January 1, 2008. We
are currently evaluating the impact of SFAS No. 157.
In February 2007, the FASB issued SFAS 159, The Fair
Value Option for Financial Assets and Financial Liabilities,
Including an Amendment of FASB Statement No. 115,
(FAS 159) which will become effective in 2008.
FAS 159 permits entities to measure eligible financial
assets, financial liabilities and firm commitments at fair
value, on an
instrument-by-instrument
basis, that are otherwise not permitted to be accounted for at
fair value under other generally accepted accounting principles.
The fair value measurement election is irrevocable and
subsequent changes in fair value must be recorded in earnings.
We will adopt this statement January 1, 2008, and we do not
expect that we will elect the fair value option for any of our
eligible financial instruments and other items.
63
In June 2007, the FASB ratified a consensus opinion reached by
the Emerging Issues Task Force (EITF) on EITF Issue
06-11,
Accounting for Income Tax Benefits of Dividends on
Share-Based Payment Awards. EITF Issue
06-11
requires an employer to recognize tax benefits realized from
dividend or dividend equivalents paid to employees for certain
share-based payment awards as an increase to additional paid-in
capital and include such amounts in the pool of excess tax
benefits available to absorb future tax deficiencies on
share-based payment awards. If an entitys estimate of
forfeitures increases (or actual forfeitures exceed the
entitys estimates), or if an award is no longer expected
to vest, entities should reclassify the dividends or dividend
equivalents paid on that award from retained earnings to
compensation cost. However, the tax benefits from dividends that
are reclassified from additional paid-in capital to the income
statement are limited to the entitys pool of excess tax
benefits available to absorb tax deficiencies on the date of
reclassification. The consensus in EITF Issue
06-11 is
effective for fiscal years, and interim periods within those
fiscal years, beginning after December 15, 2007.
Retrospective application of EITF Issue
06-11 is not
permitted. Early adoption is permitted; however, we do not
intend to adopt EITF Issue
06-11 prior
to the required effective date of January 1, 2008. We do
not expect the adoption of EITF Issue
06-11 to
have a significant effect on our financial statements since we
historically have accounted for the income tax benefits of
dividends paid for share-based payment awards in the manner
described in the consensus.
In May 2007, the FASB issued FASB Staff Position
(FSP)
FIN No. 48-1,
Definition of Settlement in FASB Interpretation
No. 48, to clarify when a tax position is effectively
settled. This guidance is important in determining the proper
timing for recognizing tax benefits and applying the new
information relevant to the technical merits of a tax position
obtained during a tax authority examination. FSP
FIN No. 48-1 provides criteria to determine whether a
tax position is effectively settled after completion of a tax
authority examination, even if the potential legal obligation
remains under the statute of limitations. We adopted FASB
Interpretation (FIN) No. 48, Accounting
for Uncertainty in Income Taxes an Interpretation of
FASB Statement 109 effective January 1, 2007.
Our adoption and subsequent application of FIN No. 48 is
consistent with the provisions of FSP FIN No. 48-1.
Inflation
Historically, general inflationary trends have not had a
material effect on our operating results. However, we have
experienced inflationary pressure on technical staff
compensation and the cost of oilfield services and equipment due
to the increase in drilling activity and competitive pressures
resulting from higher oil and natural gas prices in recent years.
Quantitative and
qualitative disclosures 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 including the
use of derivative instruments.
Credit risk. We monitor our risk of loss due to
non-performance by counterparties of their contractual
obligations. Our principal exposure to credit risk is through
the sale of our oil and natural gas production, which we market
to energy marketing companies and refineries, as described under
Business and propertiesMarketing arrangements.
We monitor our exposure to these counterparties primarily by
reviewing credit ratings, financial statements and payment
history. We extend credit terms based on our evaluation of each
counterpartys creditworthiness. Although we have not
generally required our counterparties to provide collateral to
support
64
their obligation to us, we may, if circumstances dictate,
require collateral in the future. In this manner, we reduce
credit risk.
Commodity price risk. We are exposed to market risk
as the prices of crude oil and natural gas are subject to
fluctuations resulting from changes in supply and demand. To
partially reduce price risk caused by these market fluctuations,
we have entered into zero-cost collars and fixed price
contracts. See Liquidity and capital
resourcesHedging.
Interest rate risk. Our exposure to changes in
interest rates relates primarily to long-term debt obligations.
We manage our interest rate exposure by limiting our
variable-rate debt to a certain percentage of total
capitalization and by monitoring the effects of market changes
in interest rates. 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 bank
credit facilities, and the terms of our revolving credit
facility require us to pay higher interest rate margins as we
utilize a larger percentage of our available borrowing base. We
had total indebtedness of $234.0 million outstanding under
our revolving credit facility at September 30, 2007. The
impact of a 1% increase in interest rates on this amount of debt
would result in increased interest expense of approximately
$2.3 million and a corresponding decrease in net income
before income tax. On March 27, 2007, we entered into a
$200.0 million second lien term loan facility, from which
we received $199.0 million in proceeds, with
$39.8 million of such amount used to retire our prior
second lien term loan facility, $154.0 million of such
amount used to reduce the amount outstanding under our revolving
credit facility and the remaining $5.2 million of such
amount used to pay loan fees, accrued interest and for general
corporate purposes. In connection with the completion of our
initial public offering in August 2007, we used
$86.5 million of the net proceeds from that offering to
reduce the outstanding indebtedness under our second lien term
loan facility. As of September 30, 2007, we had
$111.9 million of outstanding indebtedness under our second
lien term loan facility. The impact of a 1% increase in interest
rates on this amount of debt under our second lien term loan
facility would result in increased interest expense of
approximately $1.1 million and a corresponding decrease in
net income before income tax.
65
Results of
operations of the Chase Group Properties
The following table presents selected financial and operating
information of the Chase Group Properties for the years ended
December 31, 2004 and 2005:
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
(in thousands, except price
data)
|
|
2004
|
|
2005
|
|
|
Oil sales
|
|
$
|
66,529
|
|
$
|
73,132
|
Natural gas sales
|
|
|
41,247
|
|
|
46,546
|
|
|
|
|
|
|
Total operating revenues
|
|
|
107,776
|
|
|
119,678
|
|
|
|
|
|
|
Oil and gas production
|
|
|
11,762
|
|
|
12,979
|
Oil and gas production taxes
|
|
|
9,202
|
|
|
10,298
|
Depreciation, depletion and amortization
|
|
|
20,196
|
|
|
18,646
|
Impairments of proved properties
|
|
|
3,233
|
|
|
194
|
Exploration and abandonments
|
|
|
179
|
|
|
|
Accretion of discount on asset retirement obligations
|
|
|
263
|
|
|
446
|
General and administrative
|
|
|
1,387
|
|
|
1,702
|
Loss on derivatives not designated as hedges
|
|
|
7,936
|
|
|
1,062
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
54,158
|
|
|
45,327
|
|
|
|
|
|
|
Revenues in excess of expenses
|
|
$
|
53,618
|
|
$
|
74,351
|
|
|
|
|
|
|
Production volumes (unaudited):
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
1,751
|
|
|
1,429
|
Natural gas (MMcf)
|
|
|
7,636
|
|
|
6,636
|
Natural gas equivalents (Mcfe)
|
|
|
18,142
|
|
|
15,210
|
Average prices (unaudited):
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
37.99
|
|
$
|
51.17
|
Natural gas ($/Mcf)
|
|
|
5.40
|
|
|
7.01
|
Natural gas equivalents ($/Mcfe)
|
|
|
5.94
|
|
|
7.87
|
|
|
Year ended
December 31, 2004, compared to year ended December 31,
2005
Oil and gas revenues. Revenue from oil and
gas operations increased by $11.9 million (11%) from
$107.8 million for the year ended December 31, 2004 to
$119.7 million for the year ended December 31, 2005.
This increase was primarily because of increased commodity
prices which more than offset the declines in production. Total
production decreased 2,932 MMcfe (16%) from
18,142 MMcfe for the year ended December 31, 2004 to
15,210 MMcfe for the year ended December 31, 2005.
Production decreased because capital funds expended for property
acquisition and development was not sufficient to overcome the
natural decline of the existing wells. Average realized oil
prices increased 35% from $37.99 per Bbl in 2004 to
$51.17 per Bbl in 2005, average realized natural gas prices
increased 30% from $5.40 per Mcf in 2004 to $7.01 per
Mcf
66
in 2005 and total realized production equivalent prices
increased 32% from $5.94 per Mcfe in 2004 to $7.87 per
Mcfe in 2005.
Oil and gas production costs. Total operating
costs increased $2.3 million (11%) from $21.0 million
($1.16 per Mcfe) to $23.3 million ($1.53 per
Mcfe) for the years ended December 31, 2004 and 2005,
respectively. The increase in operating costs was due to general
increases in oil and gas service and equipment rates. Lease
operating expenses and workover costs comprised approximately
56% of total operating costs during both 2004 and 2005. These
costs per unit of production increased 31% from $0.65 per
Mcfe in 2004 to $0.85 per Mcfe in 2005. Per unit costs
increased because of increases in oil and gas service and
equipment rates along with lower production volumes. Included in
operating costs are costs of salaries and benefits of pumpers
and field level supervisors of the Chase Group and the Chase
Groups share of general liability insurance that do not
necessarily decrease when production volumes decrease.
Oil and gas production taxes. Production
taxes comprised approximately 44% of total operating costs for
2004 and 2005. Production taxes per unit of production increased
33% from $0.51 per Mcfe in 2004 to $0.68 per Mcfe in
2005. This increase was directly related to an increase in
commodity prices. In general, production taxes rates are based
on the value of production rather than production volumes.
Depletion, depreciation and amortization
expense. Total depletion, depreciation and
amortization expense decreased $1.6 million (8%) from
$20.2 million ($1.11 per Mcfe) to $18.6 million
($1.23 per Mcfe) for the years ended December 31, 2004
and 2005, respectively. The decrease in total expense was
primarily due to lower production volumes.
Impairment of oil and gas properties. In
accordance with SFAS 144, the long-lived assets of the
Chase Group Properties to be held and used, including proved oil
and gas properties accounted for under the successful efforts
method of accounting are reviewed. As a result of this review of
the recoverability of the carrying value of its assets during
2004, the Chase Group Properties recognized non-cash charges
against earnings of $3.2 million related to its proved oil
and gas properties. During 2005, the Chase Group Properties
recognized non-cash charges against earnings of
$0.2 million related to its proved oil and gas properties.
General and administrative expenses. General
and administrative expenses increased $0.3 million (21%)
from $1.4 million ($0.08 per Mcfe) to
$1.7 million ($0.11 per Mcfe) for the years ended
December 31, 2004 and 2005, respectively. The increase in
general and administrative expense during 2005 was primarily
because of increases in compensation expenses.
Loss on derivatives not designated as
hedges. Gains and losses on derivative transactions
are a result of fluctuations in oil and natural gas prices and,
consequently, the change in fair values of derivatives as
included in our earnings for each accounting period. Losses in
2004 exceeded those in 2005 because the derivative transactions
were entered into in the second quarter of 2004, resulting in
2004 mark-to-market adjustments being larger due to larger
remaining contractual volumes than in 2005. Also, no derivative
transactions were outstanding for the period of June 2005
through December 2005.
67
We are an independent oil and natural gas company engaged in the
acquisition, development, exploitation and exploration of oil
and natural gas properties. Our conventional operations are
primarily focused in the Permian Basin of Southeast New Mexico
and West Texas. These conventional operations are complemented
by our activities in unconventional emerging resource plays. We
intend to grow our reserves and production through development
drilling, exploitation and exploration activities on our
multi-year project inventory and through acquisitions that meet
our strategic and financial objectives.
We were formed in February 2006 as a result of the combination
of Concho Equity Holdings Corp. and a portion of the oil and
natural gas properties and related assets owned by Chase Oil
Corporation and certain of its affiliates. Concho Equity
Holdings Corp. was formed in April 2004 and represents the third
of three Permian Basin-focused companies that have been formed
since 1997 by our current management team (the prior two
companies were sold to large domestic independent oil and gas
companies).
Our operations are primarily concentrated in the Permian Basin,
the largest onshore oil and gas basin in the United States. As
of December 31, 2006, 99% of our total estimated net proved
reserves were located in the Permian Basin and consisted of
approximately 57% crude oil and 43% natural gas. This basin is
characterized by an extensive production history, mature
infrastructure, long reserve life, multiple producing horizons,
enhanced recovery potential and a large number of operators. The
primary producing formation in the Permian Basin under our core
properties in Southeast New Mexico is the Paddock interval of
the Yeso formation, which is located at depths ranging from
3,800 feet to 5,800 feet. We have also discovered
reserves and are producing oil and natural gas from the Blinebry
interval of the Yeso formation, the top of which is located
approximately 400 feet below the base of the Paddock
interval. In addition, we have assembled a multi-year inventory
of development drilling and exploitation projects, including
further projects to evaluate the aerial extent of the Blinebry
interval, that we believe will allow us to grow proved reserves
and production. We have also acquired significant acreage
positions in the Permian Basin of Southeast New Mexico, the
Central Basin Platform and the Delaware Basin of West Texas, the
Williston Basin in North Dakota and the Arkoma Basin in Arkansas
covering unconventional emerging resource plays, where we intend
to apply horizontal drilling, advanced fracture stimulation
and/or enhanced recovery technologies.
Following the formation of our company, we drilled
140 gross (86.4 net) wells in 2006, 89% of which were
completed as producers, 7% of which were dry holes and 4% of
which were awaiting completion as of December 31, 2006. In
addition, following the formation of our company, we recompleted
103 gross (77.1 net) wells in 2006, 98% of which were
productive. As a result, we increased our total estimated net
proved reserves by approximately 51 Bcfe from 416 Bcfe
as of December 31, 2005, on a pro forma basis, to
467 Bcfe as of December 31, 2006, while producing
approximately 26 Bcfe of oil and natural gas on a pro forma
basis during the year ended December 31, 2006. In addition,
following the formation of our company, we increased our average
net daily production from 62 MMcfe during March 2006 to
80 MMcfe during September 2007.
The following table provides a summary of selected operating
information of our conventional properties in the Permian Basin,
which is our core operating area, and in our unconventional
emerging resource plays. PV-10 includes the present value of our
estimated future abandonment and site restoration costs for
proved properties net of the present value of estimated salvage
68
proceeds from each of these properties. We set forth our
definition of
PV-10 (a
non-GAAP financial measure) and a reconciliation of
PV-10 to the
standardized measure of discounted future net cash flows under
Prospectus summaryNon-GAAP financial measures and
reconciliations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months
|
|
|
As of
|
|
ended
|
|
|
December 31, 2006
|
|
September 30,
|
|
|
|
|
|
|
Pro forma
|
|
|
|
|
|
2007
|
|
|
Total
|
|
|
|
reserve/
|
|
|
|
|
|
Average
|
|
|
proved
|
|
|
|
production
|
|
Identified
|
|
Identified
|
|
net daily
|
|
|
reserves
|
|
PV-10
|
|
index(1)
|
|
drilling
|
|
recompletion
|
|
production
|
Areas
|
|
(Bcfe)
|
|
($ in millions)
|
|
(years)
|
|
locations(2)
|
|
projects(2)
|
|
(MMcfe/d)
|
|
|
Permian Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southeast New Mexico
|
|
|
387.5
|
|
$
|
782.6
|
|
|
18.7
|
|
|
1,505
|
|
|
489
|
|
|
63.5
|
West Texas
|
|
|
70.2
|
|
|
154.5
|
|
|
15.5
|
|
|
148
|
|
|
49
|
|
|
13.1
|
Emerging Plays and
Other(3)
|
|
|
9.1
|
|
|
16.9
|
|
|
19.2
|
|
|
23
|
|
|
2
|
|
|
3.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
466.8
|
|
$
|
954.0
|
|
|
18.1
|
|
|
1,676
|
|
|
540
|
|
|
79.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The pro forma reserve/production
index is the number of years proved reserves would last assuming
current production continued at the same rate. This index is
calculated by dividing pro forma production during the year
ended December 31, 2006, into the proved reserve quantity
as of December 31, 2006. Pro forma production during the
year ended December 31, 2006 was 25,735.0 MMcfe, consisting
of 20,734.0 MMcfe in the Southeast New Mexico part of the
Permian Basin, 4,526.5 MMcfe in the West Texas part of the
Permian Basin and 474.5 MMcfe in Emerging Plays and Other. Pro
forma production information assumes the combination transaction
had taken place on January 1, 2006.
|
|
(2)
|
|
The identified drilling locations
and identified recompletion projects listed in the table above
included 817 drilling locations and recompletion projects
for which proved reserves had been included in our reserve
reports as of December 31, 2006.
|
|
(3)
|
|
Information with respect to
Other includes conventional oil and gas operations
on properties that are not located in the Permian Basin. As of
December 31, 2006, 3.1 Bcfe of the proved reserves and
$5.4 million of the
PV-10, as
well as one of the identified drilling locations and two
identified recompletion projects, were related to oil and
natural gas properties categorized as Other and not
as Emerging Plays. In addition, as of
September 30, 2007, 39,668 gross (28,573 net)
acres reflected above were categorized as Other, and
1.1 MMcfe/d of the average daily production during the nine
months ended September 30, 2007 reflected above were
categorized as Other.
|
An unconventional emerging resource play generally consists of a
large area that, based on its geological and geophysical
characteristics, indicates the possible existence of a
continuous accumulation of hydrocarbons. These plays are
typically associated with tight, fractured rocks, such as
fractured shales, fractured carbonates, coal seams and tight
sands, which may serve as the source of the hydrocarbons and as
the productive reservoir. In our unconventional emerging
resource plays, we target areas where we can acquire large
undeveloped acreage positions and apply horizontal drilling,
advanced fracture stimulation and enhanced recovery technologies
to achieve economic, repeatable production results. As of
September 30, 2007, we held interests in 205,898 gross
(99,769 net) acres in five unconventional emerging resource
plays. Our current positions include acreage in:
|
|
|
the Northwest Shelf area in Southeast New Mexico, where we have
tested one re-entry well and drilled thirteen wells targeting
the Wolfcamp Carbonate;
|
|
|
the Central Basin Platform of West Texas, where we plan to
target the Woodford Shale;
|
|
|
the Delaware Basin of West Texas, where we have drilled four
exploratory wells targeting the Bone Spring, Atoka, Barnett and
Woodford Shales;
|
|
|
the North Dakota portion of the Williston Basin, where we have
participated in the drilling of four exploratory wells targeting
the Bakken Shale; and
|
69
|
|
|
the eastern Arkoma Basin in Arkansas, where we plan to drill our
first test well in 2008, which will target the Fayetteville
Shale.
|
Our exploration and development budget for our oil and gas
properties for the year ending December 31, 2008 is
approximately $250 million. We plan to spend approximately
92% of our capital budget on exploration and development
activities associated with our conventional properties in the
Permian Basin, 2% for leasehold acquisitions and 6% for
exploration activities in our unconventional emerging resource
plays. If we achieve successful results from exploratory
drilling in our unconventional emerging resource plays, we may
allocate a greater portion of our planned 2008 capital
expenditure budget to those plays.
Our business
strategy
Our goal is to enhance stockholder value through profitably
increasing reserves, production and cash flow by executing our
strategy as described below:
|
|
|
Exploit our multi-year project inventory. We
believe our multi-year drilling and exploitation inventory will
allow us to grow our proved reserves and production for the next
several years. As of December 31, 2006, we had identified
2,216 drilling locations and recompletion projects on our
existing properties, including step-out drilling, infill
drilling (including well deepening opportunities), workovers and
recompletions.
|
|
|
Enhance production from our existing properties through
development of additional producing horizons and enhanced
recovery methods. We believe there are additional
productive horizons underlying certain of our existing producing
horizons in Southeast New Mexico that have not been fully
developed. During 2006, we accelerated an evaluation, which had
begun in late 2005, of the Blinebry interval, which lies below
the primary producing interval under our core properties in
Southeast New Mexico. During 2006, we drilled 52 wells in
the Blinebry interval, all of which have since been completed as
producers. At December 31, 2006, the wells in the Blinebry
interval which had been drilled and completed and were producing
only from the Blinebry interval were producing an average of
80 Bbl and 176 Mcf per well per day. During the nine
months ended September 30, 2007, we drilled
58 Blinebry wells, of which 46 were completed as
producers, 11 were awaiting completion as of September 30,
2007 and 1 was a dry hole. We intend to drill an additional
30 wells in the fourth quarter of 2007 to further evaluate
the Blinebry interval. In addition, in September 2007 we began
injecting water on our pilot waterflood covering approximately
160 acres in the Paddock interval of the Yeso formation.
|
|
|
Pursue the acquisition, exploration and development of
unconventional emerging oil and natural gas resource
plays. We have assembled an exploration team to
target unconventional emerging resource plays where we can
acquire large undeveloped acreage positions and apply horizontal
drilling, advanced fracture stimulation and enhanced recovery
technologies to achieve economic, repeatable production results.
Members of our technical staff, consisting of seven petroleum
engineers, seven geoscientists and ten landmen, have, on
average, more than 23 years experience in the industry. As
of September 30, 2007, we had accumulated
205,898 gross (99,769 net) acres in five
unconventional emerging resource plays, and our technical team
is focused on exploring, developing and exploiting these
resource plays as well as evaluating and acquiring acreage in
similar plays in North America.
|
|
|
Make opportunistic acquisitions that meet our strategic
and financial objectives. We seek to acquire oil
and gas properties that we believe complement our existing
properties in our core
|
70
areas of operation. We have an experienced team of management,
engineering and geoscience professionals to identify and
evaluate acquisition opportunities. We also seek to acquire
other oil and gas properties that provide opportunities for the
addition of reserves, production and value through a combination
of exploitation, development, high-potential exploration and
control of operations and that will allow us to apply our
operating expertise or that otherwise have geologic
characteristics that are similar to our existing properties.
Our
strengths
We have a number of strengths that we believe will help us
successfully execute our strategy:
|
|
|
Experienced and incentivized management
team. Our executive officers average over
19 years of experience in the oil and gas industry, having
led both public and private oil and natural gas exploration and
production companies. These companies have had substantially all
of their operations in our core area of the Permian Basin and
were headquartered in Midland, Texas, which is located in the
heart of the Permian Basin. Our executive officers beneficially
own an aggregate of 4.5% of our outstanding common stock as of
November 20, 2007, which aligns their objectives with those
of our stockholders.
|
|
|
History of growth and capital
efficiency. During the year ended December 31,
2006, we increased our total estimated net proved reserves by
approximately 51 Bcfe from 416 Bcfe as of December 31,
2005, on a pro forma basis, to 467 Bcfe as of
December 31, 2006, and produced approximately 26 Bcfe
of oil and natural gas on a pro forma basis. In addition,
following the formation of our company, we increased our average
net daily production from 62 MMcfe during March 2006 to
80 MMcfe during September 2007. The increase in
reserves and production during the year ended December 31,
2006 was primarily attributable to our successful drilling
program in the Permian Basin. Despite increasing costs of
oilfield services and equipment in our areas of operation, we
added 101 Bcfe of proved reserves in 2006 through new
discoveries and extensions, excluding revisions of previous
estimates at a total cost of $193.3 million.
|
|
|
Large inventory of drilling and recompletion
opportunities. Following the formation of our
company, we drilled 140 gross wells in 2006, of which
125 gross wells were completed as producers, and
10 wells were dry holes. During the nine months ended
September 30, 2007, we drilled 75 wells, of which
59 were completed as producers, 14 were awaiting
completion as of September 30, 2007 and 2 were dry
holes. In addition, following the formation of our company, we
recompleted 103 wells in 2006, 98% of which were
productive. During the nine months ended September 30,
2007, we recompleted 78 wells, of which 75 were
completed as producers and 3 were dry holes. As of
December 31, 2006, we had identified 1,676 undrilled well
locations on our acreage, with proved undeveloped reserves
attributed to 595 of such locations, and 540 recompletion
opportunities, with proved reserves attributed to 222 of such
opportunities. We plan to drill an additional 40 wells and
recomplete an additional 36 wells during the fourth quarter
of 2007.
|
|
|
Geographically concentrated operations. Our
current operations are focused in the Permian Basin of Southeast
New Mexico and West Texas, where 99% of our proved reserves are
located. Our geographic concentration allows us to establish
economies of scale with respect to drilling, production,
operating and administrative costs, in addition to further
leveraging our base of technical expertise in this region.
|
71
|
|
|
Significant operational control. As of
December 31, 2006, we operated 916 wells on properties
which comprised 89% of our
PV-10. As of
September 30, 2007, we operated 987 wells.
Additionally, as of December 31, 2006, approximately 72% of
our identified drilling locations and recompletion projects were
associated with properties we operate. Our high proportion of
operated properties enables us to exercise a significant level
of control over the amount and timing of expenses, capital
allocation and other aspects of exploration and development.
|
Combination
transaction
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, Caza Energy LLC and
certain other individual 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. As a result of the
initial closing of the combination transaction agreement, the
members of the Chase Group that sold their working interests to
us at the initial closing of the combination transaction
received 34,683,315 shares of our common stock and
approximately $400 million in cash, and the former
shareholders of Concho Equity Holdings Corp. that were a party
to the combination agreement received 23,767,691 shares of
our common stock. In addition, certain options held by our
employees to purchase preferred and common stock of Concho
Equity Holdings Corp. were converted into options to purchase
2,349,113 shares of our common stock. The oil and gas
properties contributed to us by the Chase Group (which we refer
to as the Chase Group Properties) represent
approximately 76% of our
PV-10 as of
December 31, 2006. The executive officers of Concho Equity
Holdings Corp. became the executive officers of our company in
connection with the initial closing of the combination
transaction. We have accounted for the combination transaction
as a reorganization of our company, such that Concho Equity
Holdings Corp. is now our wholly owned subsidiary, and a
simultaneous acquisition by our company of the assets
contributed by the Chase Group.
We agreed in the combination agreement to offer to acquire
additional interests in the Chase Group Properties from persons
associated with the Chase Group. In May 2006, we acquired
certain of such interests from ten of such persons in exchange
for an aggregate consideration of 111,323 shares of our
common stock and $8.9 million in cash. In April 2007, we
offered to acquire the remainder of such interests from an
additional nine persons in exchange for, at the respective
sellers option, shares of our common stock or cash, or any
combination thereof, aggregating a total purchase offer of
$906,000. Terms concerning the exchange of such interests for
shares of our common stock were the same as the terms in the
combination agreement.
In addition, because certain employee stockholders of Concho
Equity Holdings Corp. were not confirmed to have been accredited
investors at the time of the combination transaction, their
254,621 units, consisting of one preferred and one-half of
a common share of Concho Equity Holdings Corp., could not be
immediately exchanged for our common shares. On April 16,
2007, these remaining shares of Concho Equity Holdings Corp.
were exchanged for 318,285 shares of our common stock. As a
result, Concho Equity Holdings Corp. is now our wholly owned
subsidiary.
Prior to the completion of our initial public offering in August
2007, the field operations of the oil and gas properties we
acquired from the Chase Group were conducted on our behalf and
at our direction by employees of Mack Energy Corporation, an
affiliate of Chase Oil. Upon the completion of our initial
public offering, we assumed those operations. For more
information
72
about our transactions with certain affiliates of Chase Oil,
please see Certain relationships and related party
transactions.
Concho Equity Holdings Corp. was formed in April 2004 by our
existing senior management team and private equity investors,
and it commenced oil and gas operations in December 2004 upon
its acquisition of the Lowe Properties for approximately
$117 million. As of January 1, 2006, Concho Equity
Holdings Corp. had 107.5 Bcfe in proved oil and natural gas
reserves that were primarily located in the Permian Basin of
Southeast New Mexico and West Texas. As of that same date,
Concho Equity Holdings Corp. also held exploration leasehold
acreage in emerging resource plays in the Wolfcamp Carbonate in
Southeast New Mexico, the Delaware Basin Shale plays in West
Texas, the Bakken Shale in North Dakota and the Fayetteville
Shale in Arkansas. As a result of the combination transaction,
we acquired all of the oil and gas properties and related
operations of Concho Equity Holdings Corp., and now employ its
personnel.
Chase Oil is a private company formed by Mack C. Chase in 1992
to engage in oil and natural gas exploitation, acquisition,
exploration and production activities primarily in the Permian
Basin region of Southeast New Mexico. The oil and gas interests
contributed by the Chase Group in the combination transaction
represented a portion of the total assets held by the Chase
Group. As of January 1, 2006, the net interests in the
properties contributed by the Chase Group in the combination
transaction consisted of 305.5 Bcfe in net proved oil and
natural gas reserves located in the Permian Basin region of
Southeast New Mexico.
After the closing of the combination transaction, the former
holders of Concho Equity Holdings Corp. owned approximately 41%
of our outstanding common stock, the Chase Group owned the
remaining 59%, and the executive officers of Concho Equity
Holdings Corp. became the executive officers of our company. The
oil and gas property interests contributed by the Chase Group
represented approximately 76% of our pro forma
PV-10 as of
December 31, 2006. These oil and gas properties are
primarily located in Lea and Eddy Counties in New Mexico.
Productive
wells
The following table presents our total gross and net productive
wells by region and by oil or gas completion as of
September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
Oil wells
|
|
gas wells
|
|
Total wells
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
|
Permian Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southeast New Mexico
|
|
|
1,281
|
|
|
783.8
|
|
|
186
|
|
|
54.8
|
|
|
1,467
|
|
|
838.6
|
West Texas
|
|
|
424
|
|
|
137.7
|
|
|
66
|
|
|
10.9
|
|
|
490
|
|
|
148.6
|
Emerging Plays and Other
|
|
|
7
|
|
|
2.2
|
|
|
43
|
|
|
7.4
|
|
|
50
|
|
|
9.6
|
|
|
|
|
|
|
Total
|
|
|
1,712
|
|
|
923.7
|
|
|
295
|
|
|
73.1
|
|
|
2,007
|
|
|
996.8
|
|
|
|
|
|
|
|
|
73
Developed and
undeveloped acreage
The following table presents the total gross and net developed
and undeveloped acreage by region as of September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed acres
|
|
Undeveloped acres
|
|
Total acres
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
|
Permian Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southeast New Mexico
|
|
|
108,968
|
|
|
54,208
|
|
|
61,067
|
|
|
21,398
|
|
|
170,035
|
|
|
75,606
|
West Texas
|
|
|
76,705
|
|
|
25,502
|
|
|
14,842
|
|
|
8,856
|
|
|
91,547
|
|
|
34,358
|
Emerging Plays and
Other(1)
|
|
|
18,858
|
|
|
7,787
|
|
|
226,708
|
|
|
120,556
|
|
|
245,566
|
|
|
128,343
|
|
|
|
|
|
|
Total
|
|
|
204,531
|
|
|
87,497
|
|
|
302,617
|
|
|
150,810
|
|
|
507,148
|
|
|
238,307
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The following table sets forth
gross and net acreage as of September 30, 2007 for each of
our five emerging resource plays and our plays categorized as
Other included in Emerging Plays and
Other.
|
|
|
|
|
|
|
|
|
|
|
Total acres
|
|
|
Gross
|
|
Net
|
|
|
Southeast New Mexico
|
|
|
56,828
|
|
|
23,445
|
Central Basin Platform
|
|
|
22,925
|
|
|
22,155
|
Western Delaware Basin
|
|
|
68,814
|
|
|
22,794
|
Williston Basin of North Dakota
|
|
|
40,309
|
|
|
16,923
|
Arkoma Basin of Arkansas
|
|
|
17,022
|
|
|
14,452
|
|
|
|
|
|
|
Total Emerging Plays
|
|
|
205,898
|
|
|
99,769
|
Other
|
|
|
39,668
|
|
|
28,573
|
|
|
|
|
|
|
Total Emerging Plays and Other
|
|
|
245,566
|
|
|
128,342
|
|
|
|
|
|
|
|
|
The following table sets forth the amount of our gross and net
undeveloped acreage as of December 31, 2006 that will
expire over the next three years by region unless production is
established within the spacing units covering the acreage prior
to the expiration dates:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
2008
|
|
2009
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
|
Permian Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southeast New Mexico
|
|
|
5,805
|
|
|
2,876
|
|
|
23,696
|
|
|
7,490
|
|
|
8,601
|
|
|
3,423
|
West Texas
|
|
|
3,991
|
|
|
2,072
|
|
|
14,155
|
|
|
3,200
|
|
|
2,726
|
|
|
1,975
|
Emerging Plays and
Other(1)
|
|
|
37,341
|
|
|
30,449
|
|
|
11,358
|
|
|
2,766
|
|
|
39,111
|
|
|
16,045
|
|
|
|
|
|
|
Total
|
|
|
47,137
|
|
|
35,397
|
|
|
49,209
|
|
|
13,456
|
|
|
50,438
|
|
|
21,443
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
In the Delaware Basin shale play in
Culberson and Reeves Counties, Texas, we have the option to
extend the expiration terms by two additional years on leases
covering approximately 1,000 net acres whose original primary
term expires between January and May 2008. Should we elect to
exercise these extensions, our net cost would be approximately
$80,000.
|
Drilling
activities
The following table sets forth information with respect to wells
drilled during the periods indicated and does not include wells
drilled on the oil and gas properties we acquired from the Chase
Group in the combination transaction on February 27, 2006.
The information should not
74
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.
Development wells are wells drilled within the proved area of an
oil or gas reservoir to the depth of a stratigraphic horizon
known to be productive. Exploratory wells are wells drilled to
find and produce oil or gas in an unproved area, to find a new
reservoir in a field previously found to be productive of oil or
gas in another reservoir, or to extend a known reservoir.
Productive wells are those that produce commercial quantities of
hydrocarbons, exclusive of their capacity to produce at a
reasonable rate of return.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inception (April 21,
|
|
|
|
|
|
Nine months
|
|
|
2004) through
|
|
Years ended December 31,
|
|
ended
|
|
|
December 31, 2004
|
|
2005
|
|
2006
|
|
September 30, 2007
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
|
Development wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
2.0
|
|
|
1.0
|
|
|
61.0
|
|
|
23.5
|
|
|
93.0
|
|
|
57.8
|
|
|
34.0
|
|
|
20.6
|
Dry
|
|
|
2.0
|
|
|
1.0
|
|
|
3.0
|
|
|
1.7
|
|
|
7.0
|
|
|
2.4
|
|
|
|
|
|
|
Exploratory wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
3.0
|
|
|
1.5
|
|
|
8.0
|
|
|
2.2
|
|
|
37.0
|
|
|
25.4
|
|
|
37.0
|
|
|
34.4
|
Dry
|
|
|
1.0
|
|
|
0.7
|
|
|
3.0
|
|
|
1.4
|
|
|
3.0
|
|
|
0.8
|
|
|
4.0
|
|
|
2.4
|
Total wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
5.0
|
|
|
2.5
|
|
|
69.0
|
|
|
25.7
|
|
|
130.0
|
|
|
83.2
|
|
|
71.0
|
|
|
55.0
|
Dry
|
|
|
3.0
|
|
|
1.7
|
|
|
6.0
|
|
|
3.1
|
|
|
10.0
|
|
|
3.2
|
|
|
4.0
|
|
|
2.4
|
|
|
|
|
|
|
Total
|
|
|
8.0
|
|
|
4.2
|
|
|
75.0
|
|
|
28.8
|
|
|
140.0
|
|
|
86.4
|
|
|
75.0
|
|
|
57.4
|
|
|
|
|
|
|
|
|
As of September 30, 2007, we had 4 gross
(3.2 net) wells that were in the process of drilling, all
of which were exploratory wells.
As of September 30, 2007, we operated 5 rigs on our
properties.
We determined in January 2007 to reduce our drilling activities
for the three months ended March 31, 2007. This
determination was due to a decline in oil and natural gas prices
in January 2007 compared to such prices in the fourth quarter of
2006, the costs of goods and services necessary to complete our
drilling activities and the resulting effect of these
circumstances on our expected cash flow for the three months
ended March 31, 2007. This reduction in drilling activities
will likely result in a reduction in oil and gas production,
revenues and cash provided by operating activities for the year
ended December 31, 2007. We resumed our drilling activities
in April 2007, and we believe we will spend our planned 2007
exploration and development budget of approximately
$183 million during 2007.
Our oil and
natural gas reserves
The following table sets forth our estimated net proved oil and
natural gas reserves,
PV-10 and
standardized measure of discounted future net cash flows as of
December 31, 2006. PV-10 includes the present value of our
estimated future abandonment and site restoration costs for
proved properties net of the present value of estimated salvage
proceeds from each of these properties. Our reserve estimates
are based on independent engineering evaluations prepared
75
by Netherland, Sewell & Associates, Inc. and Cawley
Gillespie & Associates, Inc. as of December 31,
2006, ($57.75 per Bbl and $5.635 per MMBtu, adjusted
for location and quality by field, were used in the computation
of future net cash flows).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
Gas (MMcf)
|
|
Total (MMcfe)
|
|
PV-10
($MM)
|
|
|
Proved developed producing
|
|
|
21,032
|
|
|
101,544
|
|
|
227,736
|
|
$
|
619.0
|
Proved developed non-producing
|
|
|
2,411
|
|
|
10,879
|
|
|
25,345
|
|
|
52.1
|
Proved undeveloped
|
|
|
20,879
|
|
|
88,395
|
|
|
213,669
|
|
|
282.9
|
|
|
|
|
|
|
Total proved
|
|
|
44,322
|
|
|
200,818
|
|
|
466,750
|
|
$
|
954.0
|
|
|
|
|
|
|
Standardized measure of discounted future net cash
flows(1)
|
|
|
$710.3
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Standardized measure of discounted
future net cash flows is computed by applying year-end prices,
costs and a discount factor of 10 percent to net proved
reserves, taking into account the effect of future income taxes.
|
The following table sets forth our estimated net proved reserves
and PV-10 as
of December 31, 2006, by region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
Percent of
|
|
|
|
|
Oil (MBbl)
|
|
Gas (MMcf)
|
|
(MMcfe)
|
|
total
|
|
PV-10
($MM)
|
|
|
Permian Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southeast New Mexico
|
|
|
35,084
|
|
|
177,005
|
|
|
387,509
|
|
|
83%
|
|
$
|
782.6
|
West Texas
|
|
|
8,887
|
|
|
16,843
|
|
|
70,165
|
|
|
15%
|
|
|
154.5
|
Emerging Plays and Other
|
|
|
351
|
|
|
6,970
|
|
|
9,076
|
|
|
2%
|
|
|
16.9
|
|
|
|
|
|
|
Total
|
|
|
44,322
|
|
|
200,818
|
|
|
466,750
|
|
|
100%
|
|
$
|
954.0
|
|
|
|
|
|
|
|
|
Our production,
prices and expenses
The following table sets forth summary information concerning
our production results, average sales prices and production
costs for the period from inception (April 21,
2004) through December 31, 2004, the years ended
December 31, 2005 and 2006 and the nine months ended
September 30, 2006 and 2007. The actual historical data in
this table excludes for periods prior to February 27, 2006,
production from the oil and gas properties we acquired from the
Chase Group in connection with the combination transaction. The
pro forma data for the year ended December 31, 2006 gives
effect to the oil and gas properties we acquired from the Chase
Group as if we had acquired such properties on January 1,
2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inception
|
|
|
|
|
|
|
|
|
|
|
|
|
(April 21,
|
|
|
|
|
|
|
|
|
|
|
|
|
2004)
|
|
|
|
|
|
Pro forma
|
|
|
|
|
|
|
through
|
|
Years ended
|
|
year ended
|
|
Nine months ended
|
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
September 30,
|
|
|
2004
|
|
2005
|
|
2006
|
|
2006
|
|
2006
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
(unaudited)
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
44.7
|
|
|
599.0
|
|
|
2,294.8
|
|
|
2,539.6
|
|
|
1,553.7
|
|
|
2,143.2
|
Natural gas (MMcf)
|
|
|
290.7
|
|
|
3,403.8
|
|
|
9,506.8
|
|
|
10,497.6
|
|
|
6,634.3
|
|
|
8,887.5
|
Natural gas equivalent (MMcfe)
|
|
|
559.1
|
|
|
6,997.7
|
|
|
23,275.4
|
|
|
25,735.0
|
|
|
15,956.2
|
|
|
21,746.9
|
76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inception
|
|
|
|
|
|
|
|
|
|
|
|
|
(April 21,
|
|
|
|
|
|
|
|
|
|
|
|
|
2004)
|
|
|
|
|
|
Pro forma
|
|
|
|
|
|
|
through
|
|
Years ended
|
|
year ended
|
|
Nine months ended
|
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
September 30,
|
|
|
2004
|
|
2005
|
|
2006
|
|
2006
|
|
2006
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
(unaudited)
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without hedges ($/Bbl)
|
|
$
|
41.37
|
|
$
|
54.71
|
|
$
|
60.47
|
|
$
|
60.13
|
|
$
|
63.20
|
|
$
|
61.36
|
Oil, with hedges ($/Bbl)
|
|
$
|
41.37
|
|
$
|
52.79
|
|
$
|
57.42
|
|
$
|
57.38
|
|
$
|
58.40
|
|
$
|
59.79
|
Natural gas, without hedges ($/Mcf)
|
|
$
|
6.09
|
|
$
|
6.99
|
|
$
|
6.87
|
|
$
|
6.94
|
|
$
|
6.75
|
|
$
|
7.48
|
Natural gas, with hedges ($/Mcf)
|
|
$
|
6.09
|
|
$
|
6.85
|
|
$
|
7.00
|
|
$
|
7.05
|
|
$
|
6.77
|
|
$
|
7.58
|
Natural gas equivalent, without hedges ($/Mcfe)
|
|
$
|
6.48
|
|
$
|
8.08
|
|
$
|
8.77
|
|
$
|
8.76
|
|
$
|
8.96
|
|
$
|
9.10
|
Natural gas equivalent, with hedges ($/Mcfe)
|
|
$
|
6.48
|
|
$
|
7.85
|
|
$
|
8.52
|
|
$
|
8.54
|
|
$
|
8.50
|
|
$
|
8.99
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production ($/Mcfe)
|
|
$
|
0.92
|
|
$
|
1.56
|
|
$
|
0.95
|
|
$
|
0.95
|
|
$
|
0.91
|
|
$
|
1.03
|
Oil and gas production taxes ($/Mcfe)
|
|
$
|
0.42
|
|
$
|
0.53
|
|
$
|
0.68
|
|
$
|
0.66
|
|
$
|
0.68
|
|
$
|
0.72
|
General and administrative ($/Mcfe)
|
|
$
|
5.52
|
|
$
|
1.15
|
|
$
|
0.54
|
|
$
|
0.50
|
|
$
|
0.50
|
|
$
|
0.64
|
Depreciation and depletion expense ($/Mcfe)
|
|
$
|
1.71
|
|
$
|
1.64
|
|
$
|
2.61
|
|
$
|
2.57
|
|
$
|
2.64
|
|
$
|
2.53
|
|
|
The following table sets forth information regarding our average
daily pro forma production during the year ended
December 31, 2006 and average daily production during the
nine months ended September 30, 2007, by geographic region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma average
|
|
|
|
|
daily production
|
|
Average daily production
|
|
|
for the year ended
|
|
for the nine months ended
|
|
|
December 31, 2006
|
|
September 30, 2007
|
|
|
Bbl
|
|
Mcf
|
|
Mcfe
|
|
Bbl
|
|
Mcf
|
|
Mcfe
|
|
|
Permian Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southeast New Mexico
|
|
|
5,465
|
|
|
23,950
|
|
|
56,740
|
|
|
6,034
|
|
|
27,306
|
|
|
63,510
|
West Texas
|
|
|
1,451
|
|
|
3,722
|
|
|
12,428
|
|
|
1,629
|
|
|
3,290
|
|
|
13,064
|
Emerging Plays and Other
|
|
|
40
|
|
|
1,088
|
|
|
1,328
|
|
|
187
|
|
|
1,960
|
|
|
3,082
|
|
|
|
|
|
|
Total
|
|
|
6,956
|
|
|
28,760
|
|
|
70,496
|
|
|
7,850
|
|
|
32,556
|
|
|
79,656
|
|
|
|
|
|
|
|
|
Summary of core
operating areas and emerging plays
Permian
Basin
The Permian Basin is one of the most prolific oil and gas
regions in the United States, with its first commercial
discovery in 1923 and cumulative production of 32.5 billion
barrels of oil and 105 trillion cubic feet of gas as of
December 31, 2006. Current average daily production in the
Permian Basin is approximately 10 billion cubic feet
equivalent gas per day from approximately 118,000 active
producing wells. It underlies an area of Southeast New Mexico
and West Texas approximately 250 miles wide and
300 miles long. Commercial accumulations of hydrocarbons
77
occur in multiple stratigraphic horizons, at depths ranging from
approximately 1,000 feet to over 25,000 feet. This
area is characterized by long life shallow decline reserves.
The Permian Basin is our core operating area, and, as of
December 31, 2006, our estimated net proved reserves of
464 Bcfe in this basin accounted for 99% of our total
estimated net proved reserves and 99% of our
PV-10. As of
September 30, 2007, we owned an interest in
1,963 wells in the Permian Basin, of which we operated 987.
Based on our total proved reserves as of December 31, 2006,
and our pro forma 2006 production, our reserve to production
ratio was 18.3 years. As of December 31, 2006, we
identified 1,675 drilling locations, with proved undeveloped
reserves attributed to 595 of such locations, and 538
recompletion opportunities, with proved reserves attributed to
221 of such opportunities. During the year ended
December 31, 2006, our pro forma average net daily
production in the Permian Basin was 69.3 MMcfe per day, and
during the nine months ended September 30, 2007, our
average net daily production in the Permian Basin was
78.6 MMcfe per day.
Southeast New
Mexico Permian
Our Permian Basin operations in Southeast New Mexico represent
our most significant concentration of assets and, as of
December 31, 2006, our estimated proved reserves of
387.5 Bcfe in this basin accounted for 83% of our total net
proved reserves and 82% of our proved
PV-10. As of
December 31, 2006, the wells that we operated accounted for
92% of our proved
PV-10 in
this core area. As of September 30, 2007, we had 1,467
producing wells in Southeast New Mexico. During the nine months
ended September 30, 2007, our average net daily production
from this area was approximately 63.5 MMcfe per day,
representing 80% of our total production for that time period.
We target two distinct producing areas, which we refer to as the
Shelf Properties and the Basinal Properties. The Shelf
Properties generally produce from the Yeso (Paddock and Blinebry
intervals), San Andres and Grayburg formations, with
producing depths generally ranging from 900 feet to
7,500 feet. The Basinal Properties generally produce from
the Morrow formation, with producing depths generally ranging
from 7,500 feet to 15,000 feet.
Shelf
Properties
Our Shelf Properties represented 75% of our total
PV-10 as of
December 31, 2006. We acquired most of these properties
from the Chase Group upon closing of the combination
transaction. As of December 31, 2006, we had
353.5 Bcfe of proved reserves and 1,137 producing wells in
this area. As of September 30, 2007, we had 1,195 producing
wells on 102,607 gross (51,310 net) acres in this area. As
of December 31, 2006, on our Shelf Properties, we
identified 1,416 drilling locations, with proved undeveloped
reserves attributed to 395 of such locations, and 452
recompletion opportunities, with proved reserves attributed to
155 of such opportunities. Average net daily production from
this area for the nine months ended September 30, 2007, was
approximately 55.2 MMcfe per day, and production from this
area represented 69% of our total average daily net production
for the same period. Our properties are primarily located in
Eddy and Lea counties, along the Abo-Yeso shelf edge on the
northern rim of the Delaware Basin. This east to west trending
fairway produces from a succession of stacked pays. The majority
of the production in this region is from the Grayburg,
San Andres and Yeso (Paddock and Blinebry intervals)
formations. During 2006, we accelerated an evaluation, which had
begun in late 2005, of the Blinebry interval of the Yeso
formation, the top of which is located approximately
400 feet below the base of the Paddock interval of the Yeso
formation. In 2006, we drilled 52 wells in the Blinebry
interval, all of which have since been completed as producers.
78
At December 31, 2006, the wells in the Blinebry interval
which had been drilled and completed and were producing only
from the Blinebry interval were producing an average of
80 Bbl and 176 Mcf per well per day. Included in the
drilling locations we identified as of December 31, 2006
were 801 drilling locations in the Blinebry interval, with
proved undeveloped reserves attributed to 77 of such locations.
Of the remaining locations, 193 of such locations are intended
to evaluate both the Blinebry and the Paddock intervals while
531 of such locations are intended to evaluate just the Blinebry
interval. During the nine months ended September 30, 2007,
we drilled 58 Blinebry wells, of which 46 were completed as
producers, 11 were awaiting completion as of September 30,
2007 and 1 was a dry hole. In addition, in September 2007 we
began injecting water on our pilot waterflood covering
approximately 160 acres in the Paddock interval of the Yeso
formation. The Empire/Empire East and Loco Hills fields
collectively comprised 61% of our Southeast New Mexico
PV-10 as of
December 31, 2006.
Empire/Empire East. Producing intervals include the
Yates, Morrow, Grayburg, Queen, Strawn, Wolfcamp, Seven Rivers,
Yeso (Paddock and Blinebry intervals) and Abo formations. As of
December 31, 2006, we had 167 Bcfe of proved reserves
and 399 wells producing in the area. As of September 30,
2007, we had 555 gross producing wells in this area. In
addition, as of December 31, 2006, we identified 511
drilling locations, with proved undeveloped reserves attributed
to 153 of such locations, and 183 recompletion opportunities,
with proved reserves attributed to 66 of such opportunities. As
of December 31, 2006, proved reserves attributable to the
Empire/Empire East field had a
PV-10 of
$373.0 million, which represented approximately 48% of the
total PV-10
attributable to our entire Southeast New Mexico properties.
Average net daily production for the nine months ended
September 30, 2007 was approximately 23.8 MMcfe.
Loco Hills. We are currently producing from the
Seven Rivers, Queen, Grayburg, Morrow, Abo, San Andres and
Yeso (Paddock and Blinebry intervals) formations. As of
September 30, 2007, we had 173 producing wells in this
field. In addition, as of December 31, 2006, we identified
246 drilling locations, with proved undeveloped reserves
attributed to 70 of such locations, and 207 recompletion
opportunities, with proved reserves attributed to 65 of such
opportunities. As of December 31, 2006, reserves
attributable to the Loco Hills field had a
PV-10 of
$204.0 million, which represented approximately 26% of the
total PV-10
attributable to our Southeast New Mexico properties. Average net
daily production for the nine months ended September 30,
2007 was approximately 19.6 MMcfe.
Basinal
Properties
Our Basinal Properties in Southeast New Mexico represented
approximately 7% of our total
PV-10 as of
December 31, 2006. As of December 31, 2006, we had 34
Bcfe of proved reserves and 259 wells producing in this area. As
of September 30, 2007, we had 272 wells producing on
67,668 gross (25,273 net) acres in this area. As of
December 31, 2006, on our Basinal Properties, we identified
89 drilling locations, with proved undeveloped reserves
attributed to 60 of such locations, and 37 recompletion
opportunities, with proved reserves attributed to 32 of such
opportunities. Average net daily production from this area for
the nine months ended September 30, 2007, was approximately
8.3 MMcfe per day, and production from this area
represented 10% of our total average daily net production for
the same period. The majority of the production in this region
is from the Morrow formation, with significant additional
contributions from the shallower Atoka and Strawn formations.
During the nine months ended September 30, 2007, we drilled
5 wells to the Morrow formation, of which 2 were completed
as producers, 2 were dry holes and 1 was awaiting completion as
of September 30, 2007. In addition, during the nine months
ended September 30, 2007, we commenced the recompletion
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of 3 wells in the Morrow formation, of which 2 were
producing and 1 was awaiting completion as of September 30,
2007.
Texas
Permian
This core area accounted for approximately 15% of our total
proved reserves and approximately 16% of our total
PV-10 as of
December 31, 2006. As of December 31, 2006, we had
70 Bcfe of proved reserves and 480 wells producing in
this area. As of September 30, 2007, we had 490 wells
producing in this area. In addition, as of December 31,
2006, we identified 148 drilling locations, with proved
undeveloped reserves attributed to 127 of such locations, and 49
recompletion opportunities, with proved reserves attributed to
34 of such opportunities. During the nine months ended
September 30, 2007, we drilled 6 wells, of which 5
were completed as producers and 1 was awaiting completion as of
September 30, 2007. In addition, during the nine months
ended September 30, 2007, we commenced the recompletion of
19 wells, of which 18 were producing and 1 was awaiting
completion as of September 30, 2007. As of
December 31, 2006, approximately 52% of the total
PV-10
attributable to our Texas Permian core area was concentrated in
the areas three most significant fields. Two of the top
three fields (Fullerton and Deep Rock) are located on the
Central Basin Platform, while the third (Coyanosa) is located
just off the western edge of the platform.
Fullerton. Our interests in this field as of
September 30, 2007 consisted of 32 wells producing
from the Clearfork formation. In addition, as of
December 31, 2006, we identified 30 drilling locations,
with proved reserves attributed to 24 of such locations. The
PV-10 of our
proved reserves in this field as of December 31, 2006 was
approximately $39 million. This field represented
approximately 25% of the total
PV-10
attributable to our Texas Permian core area and contained
16.8 Bcfe of proved reserves as of December 31, 2006.
Average net daily production for the nine months ended
September 30, 2007 was approximately 3.6 MMcfe.
Deep Rock. Our interests in this field as of
September 30, 2007 consisted of 31 wells producing
from multiple intervals, including the Ellenberger, Devonian,
Pennsylvanian, Wolfcamp and Glorieta formations, at depths
ranging from 3,500 feet to 10,000 feet. In addition,
as of December 31, 2006, we identified 14 drilling
locations, with proved undeveloped reserves attributable to 11
of such locations, and one recompletion opportunity. The
PV-10 of our
proved reserves in this field as of December 31, 2006, was
approximately $30 million. This field represented
approximately 20% of the total
PV-10
attributable to our Texas Permian core area and contained
15.1 Bcfe of proved reserves as of December 31, 2006.
Average net daily production for the nine months ended
September 30, 2007 was approximately 2.0 MMcfe.
Coyanosa. Our interests in this field as of
September 30, 2007 consisted of 51 wells producing
from multiple intervals, including the Ellenberger, Wolfcamp or
Delaware formations, at depths ranging from 3,500 feet to
18,000 feet. In addition, as of December 31, 2006, we
identified two drilling locations, with proved reserves
attributed to one of such locations, and 25 recompletion
opportunities, with proved reserves attributed to 19 of such
opportunities. The
PV-10 of our
proved reserves in this field as of December 31, 2006, was
approximately $12 million. This field represented
approximately 8% of the total
PV-10
attributable to our Texas Permian core area and contained 4.9
Bcfe of proved reserves as of December 31, 2006. Average
net daily production for the nine months ended
September 30, 2007 was approximately 1.3 MMcfe.
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Emerging Resource
Play Areas
As of September 30, 2007, we were involved in five
unconventional emerging resource plays, with a total acreage
position of 205,898 gross (99,769 net) acres. These
plays are currently in various stages of maturity. As of
December 31, 2006, we had an aggregate of 6.0 Bcfe of
proved reserves attributed to these plays.
Southeast New
Mexico
Horizontal Wolfcamp gas and oil plays are being actively
exploited along the northwestern rim of the Delaware Basin, in
Eddy and Chaves Counties, New Mexico, with several operators
flowing gas to sales. As of September 30, 2007, we owned
56,828 gross (23,445 net) acres.
The Wolfcamp horizontal gas play is found at depths ranging from
4,100 feet to 6,000 feet. We have tested one re-entry,
and have participated with Mack Energy Corporation in the
drilling of six horizontal exploration wells. We have also
participated in four additional horizontal Wolfcamp gas wells
with a different operator. Three of these wells were completed
with each having initial rates exceeding 2 MMcfe per day, with
the fourth well awaiting completion as of September 30,
2007.
The horizontal Wolfcamp oil play is found at depths ranging from
6,500 feet to 9,000 feet. Of our horizontal Wolfcamp acreage,
17,532 gross (13,635 net) acres are in the horizontal
Wolfcamp oil play. During the fourth quarter of 2006, we drilled
one horizontal test well to a total depth of approximately 6,500
feet with a 3,000 foot lateral in the oil window of the Wolfcamp
horizon and completed such well as a producer in mid-February
2007. Through September 30, 2007, this well averaged
approximately 1.5 MMcfe per day. During August and
September 2007, we drilled our second and third wells in the
play. Initial evaluation indicated higher water saturation
levels than anticipated in the second well, so we decided to
drill only a vertical hole on the third well and await further
evaluation on the first two wells before drilling a lateral
section in such well. The drilling rig, which was on a
well-by-well contract, was released after drilling the third
well and will not continue drilling in this area until further
evaluation of these wells is complete. Subsequently, we placed
the second well on pump, and it was producing approximately
65 Bbls of oil and 175 Bbls of water per day as of
December 1, 2007.
As of December 31, 2006, we had 5.9 Bcfe of proved
reserves booked to the horizontal Wolfcamp play in Eddy and
Chaves Counties, New Mexico.
Central Basin
Platform
As of September 30, 2007, we had acquired 22,925 gross
(22,155 net) acres in an unconventional shale play in
Andrews County, Texas. This unconventional shale is prospective
at depths of 8,000 to 10,000 feet. We currently plan to
drill our first test well in the fourth quarter of 2007 or the
first quarter of 2008.
Western
Delaware Basin
This play is located in West Texas in a lightly explored portion
of the Delaware Basin. As of September 30, 2007, we owned
68,814 gross (22,794 net) acres in Culberson and
Reeves Counties, Texas. Both conventional and unconventional
targets are prospective in this area. We have drilled four
exploratory wells targeting the Bone Spring, Atoka, Barnett and
Woodford Shales, which are found at depths ranging from
5,000 feet to 12,000 feet. Three of these wells
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have been deemed
non-commercial.
A vertical Woodford Shale completion in the fourth well tested
at a rate of approximately 1 MMcf per day, and is currently
flowing gas to sales at a rate of approximately 650 Mcf per
day.
North
Dakota
This horizontal Bakken Shale play is being developed in the
North Dakota portion of the Williston Basin. This Mississippian
age horizon consists of a siltstone encased within a highly
organic oil-rich shale package and is found at depths ranging
from 9,000 feet to 11,000 feet. We have participated
in four horizontal Bakken wells, of which three were producing
and one was awaiting completion as of September 30, 2007.
As of September 30, 2007, we owned 40,309 gross
(16,923 net) acres in this play, primarily in Mountrail and
McKenzie Counties, North Dakota. As of December 31, 2006,
we had 0.1 Bcfe of proved reserves booked to this play.
During November 2007, we entered into an agreement with a third
party to jointly develop a portion of such other partys
and our lands in this play. As a result, the parties jointly
own (50% each) approximately 16,000 net acres in the combined
acreage and have established an area of mutual interest among
them of certain lands, including the combined lands, which is to
be operated by the third party. We expect that the drilling of
an exploratory well will be commenced on the combined lands by
the third party prior to December 31, 2007.
Arkansas
As of September 30, 2007, we owned 17,022 gross
(14,452 net) acres in the Fayetteville Shale play in
Faulkner and White Counties, Arkansas. The Fayetteville Shale
play in the eastern Arkoma Basin of Arkansas is the geological
time equivalent to the Barnett Shale, a proved productive
horizon in the Ft. Worth Basin. The Fayetteville Shale has
production from both vertical and horizontal wells, and on our
acreage position the Fayetteville Shale is found at depths
ranging from 7,000 feet to 8,500 feet.
Marketing
arrangements
General. We market our crude oil and natural gas in
accordance with standard energy practices utilizing certain of
our employees and external consultants, in each case in
consultation with our chief financial officer and our production
engineers. The marketing effort is coordinated with the
operations group as it relates to the planning and preparation
of future drilling programs so that available markets can be
assessed and secured. This planning also involves the
coordination of procuring the physical facilities necessary to
connect new producing wells as efficiently as possible upon
their completion. When possible, we negotiate with our
purchasers on multiple well drilling programs in an attempt to
improve our economics on such wells due to the commitment of
potentially increased production volumes. Our current drilling
plans consist substantially of multiple well programs.
Crude Oil. We do not refine or process the crude oil
we produce. The majority of our crude oil is transported by
truck to various pipeline stations throughout Southeast New
Mexico and West Texas. The oil is then delivered either to hub
facilities located in Midland, Texas or Cushing, Oklahoma or to
third party refineries located in Southeast New Mexico and the
panhandle of Texas, with the majority of our crude oil going to
a refinery in Southeast New Mexico. The remaining oil that we
produce is connected directly to pipelines via gathering
facilities in the respective field locations. This oil is also
transported to the hub facilities and refineries
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mentioned above. We sell the majority of the oil we produce
under short-term contracts using market sensitive pricing.
Approximately 36% of our oil and natural gas revenues for the
year ended December 31, 2006, were attributable to a verbal
agreement with Navajo Refining Company, L.P., an arrangement
pursuant to which crude oil production attributable to the
properties located in Southeast New Mexico that we acquired in
the combination transaction has been marketed for several years.
We entered into an agreement as of January 1, 2007 with
Navajo Refining Company, L.P. that sets forth in writing the
fundamental terms of the verbal agreement under which we had
previously conducted business with that purchaser. The agreement
with Navajo Refining Company, L.P. sets forth the applicable
market-based pricing metric for specific leases. The agreement
currently runs on a 30-day evergreen basis and is terminable by
either party upon 30-day advanced written notice. The majority
of our contracts are based on a Platts formula which is
calculated based on an intermediate posting deemed 40 degrees
(typically as published by major crude oil purchasers at the
Cushing, Oklahoma delivery point) for each calendar month plus
the average of the Platts P-Plus WTI price as published
monthly in the Platts Oilgram Price Report. This price is
then adjusted for differentials based upon delivery location and
oil quality. We also sell a portion of our oil at prices posted
by the principal purchaser of oil where our producing properties
are located.
Natural Gas. When assessing the market for our
natural gas we must first determine the type of gas connection
needed based upon the type of gas expected to be produced. We
also consider any gas gathering and delivery infrastructure in
the areas of our production and evaluate market options to
obtain the best price reasonably available under the
circumstances. We sell the majority of our gas under
individually negotiated gas purchase contracts using market
sensitive pricing. The majority of our gas contracts are term
agreements that extend at least three years from the date of the
subject contract.
The majority of the gas we sell is casinghead gas which is sold
at the wellhead under a percentage of proceeds processing
contract. The purchaser gathers our casinghead gas in the field
where produced and transports it via pipeline to a gas
processing plant where the liquid products are extracted. The
remaining gas product is residue gas, or dry gas. Under our
percentage of proceeds contract, we receive the value for the
extracted liquids and the residue gas. Each of the liquid
products has its own individual market and is therefore priced
separately.
The remaining portion of our gas is dry gas which is gathered at
the wellhead and delivered into the purchasers residue or
mainline transportation system. In many cases, the gas gathering
and transportation is performed by a third party gathering
company which transports the production from the production
location to the purchasers mainline. The majority of our
dry gas and residue gas sales contracts are 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 nearby
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 a description of some of these factors, see
Risk factorsMarket conditions or operational
impediments may hinder our access to oil and natural gas markets
or delay our production.
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On a pro forma basis (assuming the combination transaction took
place on January 1, 2006), for the year ended December 31,
2006, revenues from oil and natural gas sales to Navajo Refining
Company, L.P. and DCP Midstream, LP, formerly Duke Energy Field
Services, accounted for approximately 53% and 18%, respectively,
of our total operating revenues. Navajo Refining Company, L.P.
accounted for approximately 57% and 54% of our oil and gas
revenues during the nine months ended September 30, 2006
and 2007, respectively. DCP Midstream LP accounted for
approximately 15% and 26% of our oil and gas revenues during the
nine months ended September 30, 2006 and 2007,
respectively. While the loss of either of these purchasers may
result in a temporary interruption in sales of, or a lower price
for, our production, we believe that the loss of either of these
purchasers would not have a material adverse effect on our
operations, as there are a number of alternative purchasers in
our producing regions.
Competition
The oil and natural gas industry in the regions in which we
operate is highly competitive. We encounter strong competition
from numerous parties, ranging generally from small independent
producers to major integrated oil companies. We primarily
encounter significant competition in acquiring properties,
contracting for drilling and workover equipment and securing
trained personnel. Many of these competitors have financial and
technical resources and staffs substantially larger than ours.
As a result, our competitors may be able to pay more for
desirable leases, or to evaluate, bid for and purchase a greater
number of properties or prospects than our financial or
personnel resources will permit.
We are also affected by competition for drilling rigs and the
availability of related equipment. The oil and natural gas
industry is currently experiencing shortages of drilling and
workover rigs, equipment, pipe, materials and personnel, which
has delayed developmental drilling and exploitation activities
and caused significant price increases. The shortage of
personnel has also made it difficult to attract and retain
personnel with experience in the oil and gas industry and has
caused us to increase our general and administrative budget. We
are unable to predict when, or if, such shortages may be
alleviated.
Competition is also strong for attractive oil and natural gas
producing properties, undeveloped leases and drilling rights,
and we cannot assure you that we will be able to compete
satisfactorily. 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.
Applicable laws
and regulations
Regulation of the
oil and natural gas industry
Regulation of transportation of oil. Sales of
crude oil, condensate and natural gas liquids are not currently
regulated and are made at negotiated prices. Nevertheless,
Congress could reenact price controls in the future.
Our sales of crude oil are affected by the availability, terms
and cost of transportation. The transportation of oil in common
carrier pipelines is also subject to rate regulation. The
Federal Energy Regulatory Commission, or the FERC,
regulates interstate oil pipeline transportation rates under the
Interstate Commerce Act. In general, interstate oil pipeline
rates must be cost-based, although settlement rates agreed to by
all shippers are permitted and market-based rates
84
may be permitted in certain circumstances. Effective
January 1, 1995, the FERC implemented regulations
establishing an indexing system (based on inflation) for
transportation rates for oil that allowed for an increase or
decrease in the cost of transporting oil to the purchaser. A
review of these regulations by the FERC in 2000 was successfully
challenged on appeal by an association of oil pipelines. On
remand, the FERC in February 2003 increased the index slightly,
effective July 2001. Intrastate oil pipeline transportation
rates are subject to regulation by state regulatory commissions.
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. Under this
open access standard, common carriers must offer service to all
similarly situated shippers requesting service on the same terms
and under the same rates. When oil pipelines operate at full
capacity, access is governed by prorationing provisions set
forth in the pipelines published tariffs. Accordingly, we
believe that access to oil pipeline transportation services
generally will be available to us to the same extent as to our
competitors.
Regulation of transportation and sale of natural
gas. Historically, the transportation and sale
for resale of natural gas in interstate commerce have been
regulated pursuant to the Natural Gas Act of 1938, the Natural
Gas Policy Act of 1978 and regulations issued under those Acts
by the FERC. In the past, the federal government has regulated
the prices at which natural gas could be sold. While sales by
producers of natural gas can currently be made at uncontrolled
market prices, Congress could reenact price controls in the
future. Deregulation of wellhead natural gas sales began with
the enactment of the Natural Gas Policy Act. In 1989, Congress
enacted the Natural Gas Wellhead Decontrol Act which removed all
Natural Gas Act and Natural Gas Policy Act price and non-price
controls affecting wellhead sales of natural gas effective
January 1, 1993.
The FERC regulates interstate natural gas transportation rates
and service conditions, which affects the marketing of natural
gas that we produce, as well as the revenues we receive for
sales of our natural gas. Since 1985, the FERC has endeavored to
make natural gas transportation more accessible to natural gas
buyers and sellers on an open and non-discriminatory basis. The
FERC has stated that open access policies are necessary to
improve the competitive structure of the interstate natural gas
pipeline industry and to create a regulatory framework that will
put natural gas sellers into more direct contractual relations
with natural gas buyers by, among other things, unbundling the
sale of natural gas from the sale of transportation and storage
services. Beginning in 1992, the FERC issued Order No. 636
and a series of related orders to implement its open access
policies. As a result of the Order No. 636 program, the
marketing and pricing of natural gas have been significantly
altered. The interstate pipelines traditional role as
wholesalers of natural gas has been eliminated and replaced by a
structure under which pipelines provide transportation and
storage service on an open access basis to others who buy and
sell natural gas. Although the FERCs orders do not
directly regulate natural gas producers, they are intended to
foster increased competition within all phases of the natural
gas industry.
In 2000, the FERC issued Order No. 637 and subsequent
orders, which imposed a number of additional reforms designed to
enhance competition in natural gas markets. Among other things,
Order No. 637 effected changes in FERC regulations relating
to scheduling procedures, capacity segmentation, penalties,
rights of first refusal and information reporting. Most
85
pipelines tariff filings to implement the requirements of
Order No. 637 have been accepted by the FERC and placed
into effect.
We cannot accurately predict whether the FERCs actions
will achieve the goal of increasing competition in markets in
which our natural gas is sold. Additional proposals and
proceedings that might affect the natural gas industry are
pending before the FERC and the courts. The natural gas industry
historically has been very heavily regulated. Therefore, we
cannot provide any assurance that the less stringent regulatory
approach recently established by the FERC will continue.
However, we do not believe that any action taken will affect us
in a way that materially differs from the way it affects other
natural gas producers.
Gathering service, which occurs upstream of jurisdictional
transmission services, is regulated by the states onshore and in
state waters. Although its policy is still in flux, the FERC has
reclassified certain jurisdictional transmission facilities as
non-jurisdictional gathering facilities, which has the tendency
to increase our costs of getting gas to point of sale locations.
Intrastate natural gas transportation is also subject to
regulation by state regulatory agencies. The basis for
intrastate regulation of natural gas transportation and the
degree of regulatory oversight and scrutiny given to intrastate
natural gas pipeline rates and services varies from state to
state. 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;
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restrict the types, quantities and concentration of various
substances that can be released into the environment in
connection with oil and natural gas drilling and production, and
saltwater disposal activities;
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limit or prohibit drilling activities on certain lands lying
within wilderness, wetlands and other protected areas; and
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require remedial measures to mitigate pollution from former and
ongoing operations, such as requirements to close pits and plug
abandoned wells.
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These laws, rules and regulations may also restrict the rate of
oil and natural gas production below the rate that would
otherwise be possible. The regulatory burden on the oil and gas
industry increases the cost of doing business in the industry
and consequently affects profitability. Additionally, Congress
and federal and state agencies frequently revise environmental
laws and regulations, and any changes that result in more
stringent and costly waste handling, disposal and cleanup
requirements for the oil and gas industry could have a
significant impact on our operating costs.
The following is a summary of some of the existing laws, rules
and regulations to which our business operations are subject.
Waste Handling. The Resource Conservation and
Recovery Act, or RCRA, and comparable state
statutes, regulate the generation, transportation, treatment,
storage, disposal and cleanup of hazardous and non-hazardous
wastes. Under the auspices of the federal Environmental
Protection Agency, or EPA, the individual states
administer some or all of the provisions of RCRA, sometimes in
conjunction with their own, more stringent requirements.
Drilling fluids, produced waters, and most of the other wastes
associated with the exploration, development, and production of
crude oil or natural gas are currently regulated under
RCRAs non-hazardous waste provisions. However, it is
possible that certain oil and natural gas exploration and
production wastes now classified as non-hazardous could be
classified as hazardous wastes in the future. Any such change
could result in an increase in our costs to manage and dispose
of wastes, which could have a material adverse effect on our
results of operations and financial position.
Comprehensive Environmental Response, Compensation and
Liability Act. The Comprehensive Environmental
Response, Compensation and Liability Act, or CERCLA,
also known as the Superfund law, imposes joint and several
liability, without regard to fault or legality of conduct, on
classes of persons who are considered to be responsible for the
release of a hazardous substance into the environment. These
persons include the owner or operator of the site where the
release occurred, and anyone who disposed or arranged for the
disposal of a hazardous 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
87
properties owned or leased by us, or on or under other
locations, including off-site locations, where such substances
have been taken for disposal. In addition, some of our
properties have been operated by third parties or by previous
owners or operators whose treatment and disposal of hazardous
substances, wastes, or hydrocarbons was not under our control.
These properties and the substances disposed or released on them
may be subject to CERCLA, RCRA, and analogous state laws. Under
such laws, we could be required to remove previously disposed
substances and wastes, remediate contaminated property, or
perform remedial plugging or pit closure operations to prevent
future contamination.
Water Discharges. The Federal Water Pollution
Control Act, or the Clean Water Act, and analogous
state laws, impose restrictions and strict controls with respect
to the discharge of pollutants, including spills and leaks of
oil and other substances, into waters of the United States. The
discharge of pollutants into regulated waters is prohibited,
except in accordance with the terms of a permit issued by the
EPA or an analogous state agency. Federal and state regulatory
agencies can impose administrative, civil and criminal penalties
for non-compliance with discharge permits or other requirements
of the Clean Water Act and analogous state laws and regulations.
Air Emissions. The federal Clean Air Act, and
comparable state laws, regulate emissions of various air
pollutants through air emissions permitting programs and the
imposition of other requirements. In addition, the EPA has
developed, and continues to develop, stringent regulations
governing emissions of toxic air pollutants at specified
sources. Federal and state regulatory agencies can impose
administrative, civil and criminal penalties for non-compliance
with air permits or other requirements of the federal Clean Air
Act and associated state laws and regulations.
Recent scientific studies have suggested that emissions of
certain gases, commonly referred to as greenhouse
gases and including carbon dioxide and methane, may be
contributing to warming of the Earths atmosphere. In
response to such studies, the U.S. Congress is actively
considering legislation to reduce emissions of greenhouse gases.
In addition, several states have declined to wait on Congress to
develop and implement climate control legislation and have
already taken legal measures to reduce emissions of greenhouse
gases. For instance, at least ten states in the Northeast
(Connecticut, Delaware, Maine, Maryland, Massachusetts, New
Hampshire, New Jersey, New York, Rhode Island and Vermont) and
six states in the West (Arizona, California, New Mexico, Oregon,
Utah and Washington) have passed laws, adopted regulations or
undertaken regulatory initiatives to reduce the emission of
greenhouse gases, primarily through the planned development of
greenhouse gas emission inventories and/or regional greenhouse
gas cap and trade programs. Also, as a result of the U.S.
Supreme Courts decision on April 2, 2007 in
Massachusetts, et al. v. EPA, the EPA may be required to
regulate greenhouse gas emissions from mobile sources
(e.g., cars and trucks) even if Congress does not adopt
new legislation specifically addressing emissions of greenhouse
gases. Other nations have already agreed to regulate emissions
of greenhouse gases pursuant to the United Nations Framework
Convention on Climate Change, also known as the Kyoto
Protocol, an international treaty pursuant to which
participating countries (not including the United States) have
agreed to reduce their emissions of greenhouse gases to below
1990 levels by 2012. Passage of climate control legislation or
other regulatory initiatives by Congress or various states of
the U.S., or the adoption of regulations by the EPA and
analogous state agencies that restrict emissions of greenhouse
gases in areas in which we conduct business could have an
adverse affect on our operations and demand for our products.
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National Environmental Policy Act. Oil and natural
gas exploration and production activities on federal lands are
subject to the National Environmental Policy Act, or
NEPA. NEPA requires federal agencies, including the
Department of Interior, to evaluate major agency actions having
the potential to significantly impact the environment. In the
course of such evaluations, an agency will prepare an
environmental assessment that assesses the potential direct,
indirect and cumulative impacts of a proposed project and, if
necessary, will prepare a more detailed environmental impact
statement that may be made available for public review and
comment. All of our current exploration and production
activities, as well as proposed exploration and development
plans, on federal lands require governmental permits that are
subject to the requirements of NEPA. This process has the
potential to delay the development of oil and natural gas
projects.
OSHA and Other Laws and Regulation. We are subject
to the requirements of the federal Occupational Safety and
Health Act, or OSHA, and comparable state statutes.
The OSHA hazard communication standard, the EPA community
right-to-know
regulations under the Title III of CERCLA and similar state
statutes require that we organize
and/or
disclose information about hazardous materials used or produced
in our operations. We believe that we are in substantial
compliance with these applicable requirements and with other
OSHA and comparable requirements.
We believe that we are in substantial compliance with all
existing environmental laws and regulations applicable to our
current operations and that our continued compliance with
existing requirements will not have a material adverse impact on
our financial condition and results of operations. For instance,
we did not incur any material capital expenditures for
remediation or pollution control activities for the year ended
December 31, 2006. Additionally, as of the date of this
prospectus, we are not aware of any environmental issues or
claims that will require material capital expenditures during
2007. However, we cannot assure you that the passage of more
stringent laws or regulations in the future will not have an
negative impact on our financial position or results of
operation. For instance, the New Mexico Oil Conservation
Division is considering amending or replacing an existing rule
regulating the permitting, construction, operation and closure
of oilfield pits at well sites in New Mexico. If the agency
adopts a new or revised pit rule that imposes stricter
requirements on the construction and use of oilfield pits, then
it is possible that the cost to operate our wells in New Mexico
could increase.
Grayburg-Jackson
West Cooperative Unit Regulatory Matter
From 1984 through 1997, the owners of the Grayburg-Jackson West
Cooperative Unit (which is referred to herein as the GJ
Unit), a group of formations and intervals unitized by
state regulatory authorities, comprised of approximately
2,400 acres in Eddy County, New Mexico and which comprises
a portion of the Chase Group Properties, drilled or deepened
approximately 70 wells that produced from zones below a
depth approved as the unitized formation. The owners of the
working interests in the GJ Unit possessed the ownership rights
entitling them to produce hydrocarbons from the subject
producing intervals below the unitized formation, but had not
obtained the necessary regulatory approval (1) as to
certain wells, to drill or deepen below the base of the unitized
formation or (2) to produce hydrocarbons from intervals
below the base of the unitized formation and to commingle such
production with production from the unitized formation. In
connection with the failure to obtain the required regulatory
approval to produce on a commingled basis from these deeper
intervals, the operators filed incorrect perforation and
completion reports with state regulatory authorities, and filed
monthly
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production reports that did not disclose that hydrocarbons had
been produced from intervals below the unitized formation and
that hydrocarbons produced from these deeper intervals were
improperly commingled with production from the unitized
formation (although the reports apparently reflected the actual
volumes produced by the wells). As a result, a unit royalty
interest owner in the unitized formation was overpaid and the
State of New Mexico, which was the owner of the royalty interest
in the subject producing intervals below the unitized formation,
was underpaid for several years.
On November 15, 2005, Mack Energy Corporation filed an
application with the New Mexico Oil Conservation Division (which
is referred to herein as the NMOCD) to expand the
vertical limit of the unitized formation to include the deeper
intervals that had been accessed, produced and commingled
without obtaining regulatory approval. A hearing on the
application was originally scheduled for December 15, 2005,
but was continued at the request of Mack Energy. On
February 27, 2006, the combination transaction occurred
and, as a result, we acquired the GJ Unit.
On April 13, 2006, the NMOCD held a hearing on Mack
Energys application to expand the vertical limit of the
unitized formation. Representatives of Mack Energy, acting under
our Contract Operator Agreement with Mack Energy, participated
in the hearing and presented testimony during that hearing that
intervals below the unitized formation had not been tested or
developed. Based on the application submitted by Mack Energy and
the evidence and testimony presented at the hearing, on
June 13, 2006, the NMOCD approved the application and
entered its order expanding the vertical limit of the unitized
formation to include certain deeper intervals, including one of
those that had previously been produced and commingled without
regulatory approval.
Over the course of developing our drilling program for the Chase
Group Properties in July and August 2006, we discovered the
existence of these violations and this testimony. Following
further investigation by our employees and discussions with a
representative of Chase Oil and Mack Energy and our counsel, we
reported these developments to our board of directors. Because
this matter related to ongoing regulatory violations by entities
that were under the control of certain members of our board of
directors, our board of directors determined on
September 6, 2006, to form a special committee of the board
of directors that consisted of independent and disinterested
non-management directors for the purpose of investigating the
matters identified by our management relating to the GJ Unit.
The special committee engaged separate legal counsel to assist
it with its investigation of this matter. Also, in September
2006, representatives of Mack Energy and our company met with
relevant regulatory authorities from the State of New Mexico,
and voluntarily self-reported the matters related to the GJ
Unit, and we filed amended reports to correct prior reporting
inaccuracies.
As a result of these actions, we, along with Mack Energy,
entered into a settlement agreement with the New Mexico State
Land Office on November 2, 2006 related to the underpayment
of royalties arising from these circumstances. Under the terms
of the settlement agreement, Mack Energy paid $615,444 to the
State of New Mexico for underpayment of royalties and interest
thereon. We were not required to make any payments under the
settlement agreement. Further, on January 22, 2007, the
State of New Mexico advised us that there was no basis for a
compliance and enforcement proceeding against our company and no
evidence of a knowing and willful violation of applicable law by
our company. On January 19, 2007, Mack Energy entered into
an Agreed Compliance Order and agreed to pay a penalty of
$250,000 for its violations of applicable rules, regulations and
statutes. Finally, the NMOCD approved our
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correction of the prior records related to the GJ Unit and, in
February 2007, approved our application to expand the vertical
limit of the unitized formation below the depth of the intervals
that had previously been improperly produced and commingled with
production from the unitized formation and to bring all of the
wells in the GJ Unit into compliance with all applicable rules,
regulations and statutes.
The special committee of the board of directors examined
relevant documents provided by our company and our regulatory
counsel in New Mexico, conducted interviews of members of
management and heard a presentation from a representative of
Chase Oil and Mack Energy. The special committee also monitored
the activities of our company and our legal counsel during the
discussions and proceedings with relevant New Mexico regulatory
authorities. Based on its review of this matter, the special
committee recommended the adoption of certain policies and
procedures governing the operation of all legal proceedings
involving our company as well as a review of the due diligence
processes associated with future acquisitions of properties. The
special committee also recommended certain actions to address
corporate governance matters at our company. Finally, the
special committee reviewed the conduct of our officers and
directors to determine whether any such conduct would indicate
that an officer or director was unsuitable to continue in their
position, and the special committee did not determine that any
officer or director was unsuitable to continue in their position
with our company.
Legal
proceedings
We are not a party to any material pending legal proceedings,
other than ordinary course proceedings incidental to our
business. While the ultimate outcome and impact of any
proceeding cannot be predicted with certainty, our management
does not believe that the resolution of any of these matters
will have a material adverse effect on our financial condition
or result of operations.
Title to our
properties
As is customary in the oil and gas industry, we initially
conduct only a cursory review of the title to our properties on
which we do not have proved reserves. Prior to the commencement
of drilling operations on those properties, we conduct a
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 any material title defects on such
property. We have reviewed the title to substantially all of our
producing properties and believe that we have satisfactory title
to our producing properties in accordance with standards
generally accepted in the oil and gas industry. Prior to
completing an acquisition of producing oil and natural gas
leases, we perform title reviews on the most significant leases
and, depending on the materiality of properties, we may obtain a
title opinion or review previously obtained title opinions. Our
oil and natural gas properties are subject to customary royalty
and other interests, liens to secure borrowings under our bank
credit facilities, 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.
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Our
employees
As of September 30, 2007, we employed 104 employees,
including 41 in drilling and production, 16 in
financial and accounting, 16 in land, 14 in
exploration, 7 in reservoir engineering and 10 in
administration. Of these, 78 worked in our Midland, Texas
headquarters and 26 were in our field operations. Our
future success will depend partially on our ability to attract,
retain and motivate qualified personnel. We are not a party to
any collective bargaining agreements and have not experienced
any strikes or work stoppages. We consider our relations with
our employees to be satisfactory. We also utilize the services
of independent contractors to perform various field and other
services.
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Executive
officers and directors
The following table sets forth names, ages and titles of our
executive officers and directors as of December 6, 2007:
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Name
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Age
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Title
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Timothy A. Leach
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48
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Chairman of the Board, Chief Executive Officer and Director
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Steven L. Beal
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48
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President, Chief Operating Officer and Director
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David W. Copeland
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50
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Vice President, General Counsel and Secretary
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Curt F. Kamradt
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45
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Vice President, Chief Financial Officer and Treasurer
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David M. Thomas III
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53
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Vice PresidentExploration and Land
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E. Joseph Wright
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47
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Vice PresidentEngineering and Operations
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Jack F. Harper
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36
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Vice PresidentBusiness Development and Capital Markets
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Tucker S. Bridwell
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56
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Director
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W. Howard Keenan, Jr.
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|
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56
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Director
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Ray M. Poage
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|
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60
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Director
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A. Wellford Tabor
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39
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Director
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Timothy A. Leach has been the Chairman of the Board of
Directors and Chief Executive Officer of our company since its
formation in February 2006. Mr. Leach has been the Chairman
of the Board and Chief Executive Officer of Concho Equity
Holdings Corp. since its inception in April 2004. Mr. Leach
was Chairman of the Board and Chief Executive Officer of Concho
Oil & Gas Corp. from its inception in January 2001
until its sale in January 2004. From January 2004 to April 2004,
Mr. Leach was involved in private investments.
Mr. Leach was Chairman of the Board of Directors and Chief
Executive Officer of Concho Resources Inc. (which was a
different company than our company) from its inception in August
1997 until its sale in June 2001. From September 1989 until May
1997, Mr. Leach was employed by Parker & Parsley
Petroleum Company (now Pioneer Natural Resources Company) in a
variety of capacities, including serving as Executive Vice
President and as a member of Parker & Parsleys
Executive Committee. He is a graduate of Texas A&M
University with a Bachelor of Science degree in Petroleum
Engineering.
Steven L. Beal has been a Director and the President and
Chief Operating Officer of our company since its formation in
February 2006. Mr. Beal has been a director and the
President and Chief Operating Officer of Concho Equity Holdings
Corp. since its inception in April 2004. Mr. Beal was a
director and the Executive Vice President and Chief Financial
Officer of Concho Oil & Gas Corp. from its inception
in January 2001 until he became its President and Chief
Operating Officer in August 2002, a position he held until its
sale in January 2004. From January 2004 to April 2004,
Mr. Beal was involved in private investments. Mr. Beal
was a director and the Vice President and Chief Financial
Officer of Concho Resources Inc. (which was a different company
than our company) from its inception in August 1997 until its
sale in June 2001. From October 1988 until May 1997,
Mr. Beal was employed by Parker & Parsley
Petroleum Company (now Pioneer Natural Resources Company) in a
variety of capacities, including serving as its Senior Vice
President and Chief Financial Officer and as a member of
Parker & Parsleys Executive Committee. From 1981
until February 1988, Mr. Beal was employed by the
accounting firm of
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Price Waterhouse. He is a graduate of the University of Texas
with a Bachelor of Business Administration degree in Accounting
and is a certified public accountant.
David W. Copeland has been Vice PresidentGeneral
Counsel and corporate Secretary of our company since its
formation in February 2006. Mr. Copeland has been the Vice
PresidentGeneral Counsel and corporate Secretary of Concho
Equity Holdings Corp. since its inception in April 2004.
Mr. Copeland was a director and the Executive Vice
PresidentGeneral Counsel and corporate Secretary of Concho
Oil & Gas Corp. from its inception in January 2001
until its sale in January 2004. From January 2004 to April 2004,
Mr. Copeland was involved in private investments.
Mr. Copeland was a director and the Vice
PresidentGeneral Counsel and Corporate Secretary of Concho
Resources Inc. (which was a different company than our company)
from its inception in August 1997 until its sale in June 2001.
From 1991 until June 1997, Mr. Copeland was employed in the
Legal Department of Parker & Parsley Petroleum Company
(now Pioneer Natural Resources Company), and served as Vice
President, Associate General Counsel from 1994 until June 1997.
Prior to joining Parker & Parsley, Mr. Copeland
was a partner with the Midland, Texas law firm of Stubbeman,
McRae, Sealy, Laughlin & Browder, where his practice
was concentrated in corporate, banking and other commercial
matters. He is a graduate of Midwestern State University with a
Bachelor of Business Administration and a graduate of Texas Tech
University School of Law with a Doctor of Jurisprudence.
Curt F. Kamradt has been the Vice PresidentChief
Financial Officer and Treasurer of our company since its
formation in February 2006. Mr. Kamradt has been the Vice
PresidentChief Financial Officer and Treasurer of Concho
Equity Holdings Corp. since its inception in April 2004.
Mr. Kamradt was Vice PresidentChief Accounting
Officer and Treasurer of Concho Oil & Gas Corp. from
its inception in January 2001 until he became its Vice President
and Chief Financial Officer in August 2002, a position he held
until its sale in January 2004. From January 2004 to April 2004,
Mr. Kamradt was involved in private investments.
Mr. Kamradt was the Treasurer of Concho Resources Inc.
(which was a different company than our company) from February
1999 until its sale in June 2001. From December 1989 until
October 1998, Mr. Kamradt was employed by
Parker & Parsley Petroleum Company (now Pioneer
Natural Resources Company) in a variety of capacities, including
serving as its Treasurer. From 1985 until December 1989,
Mr. Kamradt was employed by the accounting firms of Price
Waterhouse and Grant Thornton. He is a graduate of Eastern New
Mexico University with a Bachelor of Business Administration
degree in Accounting and is a certified public accountant.
David M. Thomas III has been the Vice
PresidentExploration and Land of our company since its
formation in February 2006. Mr. Thomas has been the Vice
PresidentExploration & Land of Concho Equity
Holdings Corp. since April 2005. From July 2004 until April
2005, Mr. Thomas was involved in private investments. From
August 2000 to July 2004, Mr. Thomas served as
Exploration Manager/Southern Region for Tom Brown, Inc. In 2000,
prior to joining Tom Brown, Inc., he served as a geologist for
Pure Resources Inc. From 1998 to 2000, he served as Senior Staff
Geologist for Mobil E&P U.S. Inc. and Senior Geologist
for Conoco, Inc. in Midland, Texas. Mr. Thomas is certified
as a Professional Geoscientist and is a Certified Professional
Landman. He is a graduate of the University of New Mexico with a
Bachelor of Business Administration degree, and a graduate of
the University of Oklahoma with a Master of Science degree in
Geology.
E. Joseph Wright has been the Vice
PresidentEngineering and Operations of our company since
February 2006. Mr. Wright has been the Vice
PresidentOperations & Engineering of Concho
Equity Holdings Corp. since its inception in April 2004.
Mr. Wright was Vice President
94
Operations/Engineering of Concho Oil & Gas Corp. from
its inception in January 2001 until its sale in January 2004.
From January 2004 to April 2004, Mr. Wright was involved in
private investments. Mr. Wright served in various
engineering and operations positions for Concho Resources Inc.
(which was a different company than our company), including
serving as Vice PresidentOperations, from February 1998
until its sale in June 2001. From 1982 until February 1998,
Mr. Wright was employed by Mewbourne Oil Company in several
operations, reservoir and evaluation engineering and capital
markets positions. He is a graduate of Texas A&M University
with a Bachelor of Science degree in Petroleum Engineering.
Jack F. Harper has been the Vice President
Business Development and Capital Markets of our company since
May 2007. Mr. Harper was the Director of Investor Relations
and Business Development of our company from July 2006 until May
2007. From October 2005 until July 2006, Mr. Harper was
involved in private investments. From October 2002 until October
2005, Mr. Harper was employed by Unocal Corporation where
he served as Manager of Planning and Evaluation and Manager of
Business Development for Unocal Corporations wholly owned
subsidiary, Pure Resources. From May 2000 until October 2002,
Mr. Harper was employed by Pure Resources, Inc. in a
variety of capacities, including in his last position as Vice
President, Finance and Investor Relations. From December 1996
until May 2000, Mr. Harper was employed by Tom Brown,
Inc., where his last position was Vice President, Investor
Relations, Corporate Development and Treasurer. He is a graduate
of Baylor University with a BBA degree in Finance.
Tucker S. Bridwell has been a Director of our company
since February 2006. Mr. Bridwell was a director of Concho
Equity Holdings Corp. from its inception in April 2004 until
February 2006, and served as Chairman of its Compensation
Committee. Mr. Bridwell has been the President of each of
the Mansefeldt Investment Corporation and the Dian Graves Owen
Foundation since September 1997 and manages investments for both
entities; both of which are stockholders of our company. He has
been in the energy business in various capacities for over
twenty-five years. Mr. Bridwell served as Chairman of the
Board of Directors of First Permian, LLC from 2000 until its
sale to Energen Corporation in April 2002. Mr. Bridwell is
also a director of Petrohawk Energy Corporation and serves on
its audit committee. He is a graduate of Southern Methodist
University with a Bachelor of Business Administration degree and
a Master of Business Administration degree, and is a certified
public accountant.
W. Howard Keenan, Jr. has been a Director of
our company since February 2006. Mr. Keenan previously was
a director of Concho Equity Holdings Corp., Concho
Oil & Gas Corp. and Concho Resources Inc. (which was a
different company than our company). Mr. Keenan has over
thirty years of experience in the financial and energy
businesses. Since 1997, he has been a Member of Yorktown
Partners LLC, a private equity investment manager focused on the
energy industry. Two limited partnerships managed by Yorktown
Partners LLC are stockholders of our company. Mr. Keenan
currently serves on the Board of Directors of GeoMet, Inc. From
1975 to 1997, he was in the Corporate Finance Department of
Dillon, Read & Co. Inc. and active in the private
equity and energy areas, including the founding of the first
Yorktown Partners fund in 1991. He is serving or has served as a
director of multiple Yorktown Partners portfolio companies.
Mr. Keenan holds a Bachelors degree from Harvard College
and a Master of Business Administration from Harvard University.
Ray M. Poage has been a Director of our company since
August 2007. Mr. Poage was a partner in KPMG LLP from 1980
to June 2002 when he retired. Mr. Poages
responsibilities included supervising and managing both audit
and tax professionals and providing accounting services,
primarily in the area of taxation, to private and publicly held
companies engaged in the oil and
95
natural gas industry. Since June 2002, Mr. Poage has been
involved in private investments. Mr. Poage currently serves
as the Chairman of the audit committee and as a member of the
Board of Directors of Parallel Petroleum Corporation.
A. Wellford Tabor has been a Director of our company
since February 2006. Mr. Tabor was a director of Concho
Equity Holdings Corp. from its inception in April 2004 until
February 2006. Mr. Tabor also served as a director of
Concho Oil & Gas Corp. from March 2003 until its sale
to a large domestic independent oil and gas company in January
2004. Mr. Tabor is a Partner with Wachovia Capital
Partners, which is a stockholder of our company. Prior to
joining Wachovia Capital Partners in 2000, Mr. Tabor was a
director at The Beacon Group from 1995 to 2000. From 1991 to
1993, he worked in the Investment Banking Division at Morgan
Stanley & Co. Mr. Tabor currently serves on the
Board of Directors of James River Specialty, a publicly traded
insurance company, and several other privately held energy and
financial services companies in which Wachovia Capital Partners
is an investor. Mr. Tabor earned his undergraduate degree
from The University of Virginia and his Master of Business
Administration from The Graduate School of Business at Stanford
University.
Board of
directors
We currently have six directors. Our restated certificate
of incorporation and bylaws provide for a classified board of
directors consisting of three classes of directors, each serving
staggered three-year terms. As a result, stockholders will elect
a portion of our board of directors each year. Class I
directors terms will expire at the annual meeting of
stockholders to be held in 2008, Class II directors
terms will expire at the annual meeting of stockholders to be
held in 2009 and Class III directors terms will
expire at the annual meeting of stockholders to be held in 2010.
The Class I directors are Messrs. Leach and Keenan, the
Class II directors are Messrs. Beal and Bridwell and
the Class III director are Messrs. Tabor and Poage. At each
annual meeting of stockholders held after the initial
classification, the successors to directors whose terms will
then expire will be elected to serve from the time of election
until the third annual meeting following election. The division
of our board of directors into three classes with staggered
terms may delay or prevent a change of our management or a
change in control. See Description of capital
stockAnti-takeover provisions of our certificate of
incorporation and bylaws.
In addition, our restated bylaws provide that the authorized
number of directors, which shall constitute the whole board of
directors, may be changed by a resolution duly adopted by the
board of directors. Any additional directorships resulting from
an increase in the number of directors will be distributed among
the three classes so that, as nearly as possible, each class
will consist of one-third of the total number of directors.
Vacancies and newly created directorships may be filled by the
affirmative vote of a majority of our directors then in office,
even if less than a quorum.
Board
committees
Our board of directors currently has an audit committee, a
compensation committee and a nominating & governance
committee. We are currently actively recruiting additional
directors to serve on our board of directors. We expect that
these additional directors will qualify as
independent for purposes of serving on our board of
directors.
Audit committee. Our audit committee currently
consists of Messrs. Bridwell, Poage and Tabor, with Mr.
Poage serving as chairman of the audit committee. Messrs.
Bridwell, Poage and
96
Tabor are independent under the standards of the
New York Stock Exchange and SEC regulations. Our audit committee
operates pursuant to a written charter. This committee oversees,
reviews, acts on and reports to our board of directors on
various auditing and accounting matters, including the selection
of our independent accountants, the scope of our annual audits,
fees to be paid to the independent accountants, the performance
of our independent accountants and our accounting practices. In
addition, the audit committee oversees our compliance programs
relating to legal and regulatory requirements.
Compensation committee. Our compensation committee
currently consists of Messrs. Bridwell, Keenan and Tabor,
with Mr. Tabor serving as chairman of the compensation
committee. Messrs. Bridwell, Keenan and Tabor are
independent under the standards of the New York
Stock Exchange and SEC regulations. As required by the standards
of the New York Stock Exchange, the compensation committee
consists solely of independent directors and operates pursuant
to a written charter. This committee establishes salaries,
incentives and other forms of compensation for officers. Our
compensation committee also administers our incentive
compensation and benefit plans.
Nominating & Governance Committee. Our
nominating & governance committee currently consists of
Messrs. Bridwell, Keenan and Tabor, with Mr. Keenan serving as
chairman of the nominating & governance committee. Messrs.
Bridwell, Keenan and Tabor are independent under the
standards of the New York Stock Exchange, and the committee
operates pursuant to a written charter. This committee advises
the board of directors and is responsible for matters related to
corporate governance and the composition of the board of
directors.
Compensation
committee interlocks and insider participation
The compensation committee consists of Messrs. Bridwell,
Keenan and Tabor, all of whom are non-employee directors, with
Mr. Tabor serving as chairman of the compensation
committee. None of these individuals has ever been an officer or
employee of our company. In addition, none of our executive
officers serves as a member of a board of directors or
compensation committee of any entity that has one or more
executive officers who serve on our board or on our compensation
committee.
Executive officer
compensation
Compensation
discussion and analysis
This compensation discussion and analysis explains our
compensation philosophy, policies and practices with respect to
our chief executive officer, chief financial officer and the
other four most highly-compensated executive officers, which are
collectively referred to as our named executive officers.
General. Our compensation committee is responsible
for establishing and administering policies governing the
compensation of our named executive officers. The compensation
committee is composed entirely of independent directors. See
Board committeesCompensation committee.
Our executive compensation program is designed to accomplish the
following objectives:
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attract individuals with the skills necessary for us to execute
our business plan;
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97
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motivate and reward executive officers whose knowledge, skills
and performance are critical to our success;
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align the interests of our named executive officers and
stockholders with the performance of our company on both a
short-term and long-term basis; and
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retain those individuals who continue to perform at or above the
levels that we expect.
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To accomplish these objectives, we provide what we believe is a
competitive total compensation package to our executive
management team through a combination of base salary, annual
cash bonuses, long-term equity incentive compensation and
broad-based benefits programs.
Our compensation committee determines the appropriate level for
each compensation component based on our recruiting and
retention goals, our view of internal parity and consistency,
market survey data and overall company performance. In
determining current levels of compensation, the compensation
committee did not determine a discrete set of companies
considered to be our peer group, but instead utilized the 2006
Energy Compensation Survey prepared by Mercer Human Resource
Consulting, Inc. to evaluate the market for compensation of
energy company executives. The Mercer survey contains
compensation information for officers and employees at 184
public and privately owned, energy-focused organizations, which
is a broad peer group that the compensation committee considers
appropriate because it includes similar organizations against
whom we compete for executive talent. The Mercer survey provides
specific compensation information gathered from
74 organizations engaged in the oil and gas exploration and
production industry. This data is provided in the survey on an
aggregated basis within certain subcategories based on industry,
geographic location and position or role within the applicable
organization. The survey does not provide specific compensation
information for individual organizations and employees among the
organizations included in the survey. In reviewing the Mercer
survey, the compensation committee does not seek to establish
benchmarks with respect to the compensation levels of our named
executive officers. Rather, the compensation committee used the
Mercer survey to confirm that the base salary levels established
by the committee were at competitive levels with comparably
titled officers in the exploration and production industry
segment of the Mercer survey. The ultimate levels of
compensation paid to our named executive officers, however, are
subject to the discretion of and determination by the
compensation committee.
Our compensation committee has not engaged a compensation
consultant in the past. In anticipation of implementing a
compensation structure after becoming a public company that
includes certain performance metrics and targets commonly used
by public companies in our industry to set compensation for
executive officers, the compensation committee has retained
Longnecker & Associates as a compensation consultant to
assist with future development of our compensation strategy, to
annually review the competitiveness of our executive
compensation programs and to provide recommendations for changes
or adjustments to these programs. The compensation
consultants work has commenced, but its analysis is
not yet complete. Changes to our compensation structure, if any,
will be implemented during the 2008 calendar year.
In consideration of internal parity and consistency concerns,
the compensation committee has historically grouped
Messrs. Leach and Beal into one compensation tier and
Messrs. Copeland, Kamradt, Wright and Thomas into a second
compensation tier. It is possible that in the future, after
consultation with the compensation consultant, the compensation
committee may add additional compensation tiers or eliminate
this tier system entirely. Our compensation committee has not
adopted any formal or informal policies or guidelines for
allocating compensation
98
between long-term and currently paid out compensation, between
cash and non-cash compensation or among different forms of
non-cash compensation.
In connection with becoming a public company, our compensation
committees intent is to perform at least annually a
strategic review of our named executive officers overall
compensation package to determine whether it provides adequate
incentives and motivation and whether it adequately compensates
our named executive officers relative to comparable officers in
other companies with which we compete for executives. Our
compensation committee is currently working with Longnecker
& Associates to conduct a review of our named executive
officers overall compensation package for the remainder of
2007 and for 2008. The compensation committee meets outside the
presence of all of our named executive officers to consider
appropriate compensation for our chief executive officer and our
president. For all other named executive officers, our
compensation committee meets outside the presence of all named
executive officers except our chief executive officer and
president. Our chief executive officer and president together
annually review other named executive officers performance
with our compensation committee and make recommendations with
respect to the appropriate base salary, targets for and payments
under our annual cash bonus plan and the grants of long-term
equity incentive awards for those named executive officers.
Based in part on these recommendations from our chief executive
officer and president and other considerations discussed below,
the compensation committee establishes and approves the annual
compensation package of our named executive officers other than
our chief executive officer and president.
Base compensation. On an annual basis, the
compensation committee reviews salary ranges and individual
salaries for each of our named executive officers as compared to
the salaries of comparably titled officers as described in the
Mercer survey. The compensation committee uses the median base
salary information for comparably titled officers in the
exploration and production industry segment from the Mercer
survey as a general indicator of the competitive base salary
levels of our named executive officers. The compensation
committee is currently working with the compensation consultant
to determine an appropriate peer group from which to calculate
the compensation market median for base salaries in the future.
We believe that paying base salaries close to the market median
is necessary to achieve our compensation objectives of
attracting and retaining executives with the appropriate
abilities and experience required to lead us. The compensation
committee, in its discretion, established base salary levels for
each named executive officer based on consideration of market
median pay levels, the individuals responsibilities,
skills and experience, and the pay of others on the executive
team.
In connection with the combination transaction, each of our
named executive officers entered into a separate employment
agreement, under which Messrs. Leach and Beal are
guaranteed a minimum base annual salary of $350,000 and
Messrs. Copeland, Kamradt, Wright and Thomas are guaranteed
a minimum base annual salary of $250,000. Our compensation
committee believes that these base salary levels achieve its
executive compensation objectives.
From January 1, 2006 until the completion of the
combination transaction on February 27, 2006, our named
executive officers received compensation as officers of Concho
Equity Holdings Corp., our predecessor for accounting purposes.
Base salary levels for our named executive officers during that
period remained the same as in 2005 and consisted of $50,000 for
each of Messrs. Leach and Beal and $33,333 for each of
Messrs. Copeland, Kamradt, Wright and Thomas.
Cash bonuses. We utilize cash bonuses to reward
achievement of performance targets with a time horizon of one
year or less. Our compensation committee plans to determine
performance targets for each of our named executive officers on
an annual basis, though performance
99
targets have not been established for 2007. We believe that the
payment of cash bonuses upon the achievement of performance
targets is necessary to achieve our compensation objectives of
motivating and rewarding our named executive officers, as well
as aligning the interests of our named executive officers and
stockholders with the performance of our company on a short-term
basis.
For 2006, the only performance target established by our
compensation committee was the filing of the registration
statement for our initial public offering. As this performance
target was not achieved in 2006, none of our named executive
officers received a cash bonus in 2006. In connection with the
filing of the registration statement for our initial public
offering in April 2007, Messrs. Leach and Beal each
received a $313,000 cash bonus; Messrs. Copeland, Kamradt
and Wright each received a $172,000 cash bonus; and
Mr. Thomas received a $199,000 cash bonus. In determining
the amount of this cash bonus for each of our named executive
officers, the primary factors considered by our compensation
committee were each named executive officers overall
responsibility for the management of our company and the process
associated with our initial public offering and each named
executive officers overall prior investment in our
securities (including the debt obligations incurred by each
named executive officer in connection with such investment).
Ultimately, the compensation committee exercised its discretion
in determining the amount of the cash bonus.
For 2007, and in addition to the bonus payable upon the filing
of the registration statement for our initial public offering,
each of our named executive officers are eligible to earn a
bonus ranging from 0% to 100% of their base salary based on the
performance measure of net asset value per share growth, but the
committee may decide, in its sole discretion, to consider other
operational performance measures of production growth, reserve
growth, finding and development costs and lease operating and
general and administrative expense management. The compensation
committee believes that managements ultimate goal should
be to grow our equity value. Net asset value per share growth is
a comprehensive measure of the growth of our equity value per
share. Net asset value per share is calculated as (1) the
PV-10 of our oil and gas properties plus the book value of our
assets other than our oil and gas properties, less the book
value of our liabilities, divided by (2) the number of
shares of our common stock outstanding.
PV-10 is
defined as 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, discounted to a present value using an annual discount
rate of 10% in accordance with the guidelines of the SEC. For
more information about the
PV-10 of our
oil and gas properties, see Prospectus summary
Non-GAAP financial measures and reconciliations. While the
compensation committee may consider the other operational
measures listed above when paying bonuses, we expect that net
asset value per share growth will be the primary consideration
because the committee believes it to be the single most accurate
indicator of our financial success and stockholder value
creation. When evaluating net asset value per share growth or
other operational measures used to determine cash bonuses, our
compensation committee has wide discretion to determine the
appropriate percentage of base salary for each named executive
officer. The committee retains the discretion to award bonuses
even if there is zero or negative asset value per share growth,
but other operational measures indicate successful management of
our assets. For example, a significant commodity price decrease
could cause net asset value per share growth to become negative,
but meaningful production or reserve growth without accompanying
increases in costs could result in the compensation committee to
determine that it is appropriate to pay bonuses at some level
within the discretion of the compensation committee.
100
Stock options. We utilize stock option grants to
motivate and reward our named executive officers, as well as to
align the interests of our named executive officers and
stockholders with the performance of our company on a long-term
basis. In addition, we utilize multi-year vesting periods when
granting stock options to facilitate the compensation objective
of retaining our named executive officers.
Typically, our stock options vest at a rate of one-quarter of
the shares subject to the option on each of the first four
anniversaries of the grant date. The stock options that we have
granted under our 2006 Stock Incentive Plan typically may be
exercised by the recipient at any time once vested and will
expire ten years from the date of the grant, but may expire
earlier upon termination of employment. While the 2006 Stock
Incentive Plan allows for other forms of equity compensation,
the compensation committee and management currently believe that
stock options are the appropriate vehicle to provide long-term
incentive compensation to our named executive officers. Other
types of long-term equity incentive compensation may be
considered in the future as our business strategy evolves.
Since the completion of our initial public offering, all options
have been granted with an exercise price equal to the fair
market value of our common stock on the date of the grant. Such
fair market value will be defined as the closing market price of
a share of our common stock on the date of the grant. We do not
have any program, plan or practice of setting the exercise price
on a date or price other than the fair market value of our
common stock on the grant date. We do not have any program, plan
or obligation that requires us to grant equity compensation on
specified dates to our named executive officers.
During 2006, we granted options to
purchase 62,500 shares of our common stock to each of
Messrs. Leach and Beal, and 75,000 shares to each of
Messrs. Copeland, Kamradt and Wright, and
100,000 shares to Mr. Thomas. Each of the grants had
an exercise price of $12.00 per share. These grants were
made by our board of directors after the completion of the
combination transaction in February 2006, and the board
determined that, in light of the individuals performance,
it was appropriate to provide additional incentive for each of
these persons. In determining the number of shares subject to
these option grants, the primary factor considered by our
compensation committee was the prior investment by our named
executive officers in our securities. As such, the compensation
committee decided to award additional equity to certain of our
named executive officers who had previously made smaller
investments in our securities in an effort to more closely
balance the equity ownership of our named executive officers.
Ultimately, the compensation committee exercised its discretion
in determining the number of shares subject to these option
grants. In November 2007, these options were amended to increase
the exercise price to $15.40 per share. In connection with these
amendments, our named executive officers received an award of
restricted stock. In addition, certain other options granted to
our named executive officers were amended so that the subject
stock option awards would constitute deferred compensation that
is compliant with Section 409A of the Internal Revenue Code
of 1986, as amended, or to exempt such awards from the
application of Section 409A. For additional information
about these amendments and award of restricted stock, please see
Managements discussion and analysis of financial
condition and results of operations Amendment of
certain outstanding stock options.
Stock ownership guidelines have not been implemented by our
compensation committee for our named executive officers. We will
continue to periodically review best practices and re-evaluate
our position with respect to stock ownership guidelines.
101
Severance and change of control payments. All of our
named executive officers are entitled to receive severance
payments equal to a specified number of months of base salary,
as well as accelerated vesting of all existing stock options in
the event that their employment is terminated by our company
other than for cause (and not by reason of death or
disability) or if they terminate their employment following a
change in duties. Upon a termination within two
years of a change of control, each of our named executive
officers is entitled to a lump sum severance payment equal to
two years of base salary and accelerated vesting of all existing
stock option awards.
We believe these severance and change of control arrangements
mitigate some of the risk that exists for executives working in
a smaller company. These arrangements are intended to attract
and retain qualified executives that could have job alternatives
that may appear to them to be less risky absent these
arrangements. Because of recent significant acquisition activity
in the oil and gas industry, there is a possibility that we
could be acquired in the future. Accordingly, we believe that
the larger severance packages resulting from terminations
related to change of control transactions would provide an
incentive for these executives to continue to help successfully
execute such a transaction from its early stages until closing.
For a description and quantification of these severance and
change of control benefits, please see Option
exercises in the last fiscal yearEmployment, severance and
change of control arrangements.
Other benefits. Our named executive officers are
eligible to participate in all of our employee benefit plans,
such as medical, dental, vision, group life, disability, and
accidental death and dismemberment insurance and our 401(k)
plan, in each case on the same basis as other employees, subject
to applicable law. We also provide vacation and other paid
holidays to all employees, including our named executive
officers, which are comparable to those provided at peer
companies.
During 2006, we owned and operated an airplane to facilitate the
travel of senior executives in as safe a manner as possible and
with the best use of their time. Messrs. Leach and Beal are
entitled to utilize our aircraft for business travel and
reasonable personal travel in North America. Certain other named
executive officers use the corporate aircraft for business
travel and, until May 13, 2006, used such aircraft for
personal travel. The immediate family members of
Messrs. Leach and Beal are also permitted to utilize our
aircraft for their reasonable personal use in North America.
Messrs. Leach and Beal are not obligated to reimburse us
for the use of such aircraft except when their immediate family
members use such aircraft without one of Messrs. Leach or
Beal accompanying them on the flight, in which case they shall
be obligated to reimburse us for the variable costs of such use.
The amount of personal and family travel using our aircraft is
subject to annual review and adjustment by the compensation
committee.
The value of personal aircraft usage described above is based on
our direct operating cost. This methodology calculates our
incremental cost based on the average weighted cost of fuel,
on-board catering, aircraft maintenance, landing fees,
trip-related hangar and parking costs, and smaller variable
costs. Since the corporate aircraft is used primarily for
business travel, the methodology excludes fixed costs which do
not change based on usage, such as pilots and other
employees salaries, purchase costs of the aircraft and
non-trip-related hangar expenses. On occasions when an
executives spouse or other family member accompanies the
executive on a flight, no additional direct operating cost is
incurred under the foregoing methodology.
102
Tax and accounting policies. We account for equity
compensation paid to our employees under SFAS 123R, which
requires us to estimate and record an expense over the service
period of the award. Our cash compensation is recorded as an
expense at the time the obligation is accrued. We receive a tax
deduction for the compensation expense. We structure cash bonus
compensation so that it is taxable to our executives at the time
it becomes available to them. We currently intend that all cash
compensation paid will be tax deductible for us. However, with
respect to equity compensation awards, while any gain recognized
by employees from nonqualified options granted at fair market
value should be deductible, to the extent that an option
constitutes an incentive stock option, gain recognized by the
optionee will not be deductible if there is no disqualifying
disposition by the optionee. In addition, if we grant restricted
stock or restricted stock unit awards that are not subject to
performance vesting, they may not be fully deductible by us at
the time the award is otherwise taxable to employees.
Executive
compensation tables
The following table presents compensation information for the
year ended December 31, 2006 paid to or accrued for our
chief executive officer, chief financial officer and each of our
four other most highly compensated executive officers whose
aggregate salary and bonus was more than $100,000. We refer to
these executive officers as our named executive officers
elsewhere in this prospectus.
Summary
Compensation Table
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All other
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Name and principal
position
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Salary(1)
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Bonus
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Option
awards(2)
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compensation(3)
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Total
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Timothy A. Leach
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$
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333,333
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$
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$
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603,840
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$
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34,124
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$
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971,297
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Chairman and Chief Executive Officer
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Steven L. Beal
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333,333
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603,840
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18,395
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955,568
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President and Chief Operating Officer
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David W. Copeland
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233,333
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375,905
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17,951
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627,189
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Vice PresidentGeneral Counsel and Secretary
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Curt F. Kamradt
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233,333
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375,905
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13,883
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623,121
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Vice President, Chief Financial Officer and Treasurer
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E. Joseph Wright
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233,333
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375,905
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14,055
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623,293
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Vice PresidentEngineering and Operations
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David M. Thomas III
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233,333
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324,649
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15,753
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573,735
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Vice PresidentExploration and Land
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(1)
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From January 1, 2006 until the
completion of the combination transaction on February 27,
2006, our named executive officers received compensation as
officers of Concho Equity Holdings Corp., our predecessor for
accounting purposes. For their service as named executive
officers of our company from February 28, 2006 through
December 31, 2006, Messrs. Leach and Beal each earned
$283,333 and Messrs. Copeland, Kamradt, Wright and Thomas
each earned $200,000.
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(2)
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The amounts in this column
represent the dollar amount recognized for financial statement
reporting purposes with respect to the fiscal year computed in
accordance with SFAS No. 123R. Please see Note H
of the notes to our consolidated financial statements for a
discussion of all assumptions made in determining the grant date
fair values. The stock option grants are
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103
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comprised of grants on
February 23, 2006 and June 12, 2006. Grants made on
February 23, 2006 were made under the stock option plan
dated August 13, 2004, as amended and restated as of
February 27, 2006. Grants made on June 12, 2006 were
made under the 2006 Stock Incentive Plan dated June 1,
2006. Options granted February 23, 2006 vest at the end of
three years commencing on the first anniversary of the date of
grant. Options granted on June 12, 2006 vest as to
1/4
of the shares underlying the option on each of the first four
anniversaries of the grant date. Option awards reported for
Mr. Leach are comprised of $461,520 for options granted
February 23, 2006 and $142,320 for options granted
June 12, 2006. Options awards reported for Mr. Beal
are comprised of $461,520 for options granted February 23,
2006 and $142,320 for options granted June 12, 2006.
Options awards reported for Mr. Kamradt are comprised of
$205,121 for options granted February 23, 2006 and $170,784
for options granted June 12, 2006. Options awards reported
for Mr. Copeland are comprised of $205,121 for options
granted February 23, 2006 and $170,784 for options granted
June 12, 2006. Option awards reported for Mr. Thomas
are comprised of $96,938 for options granted February 23,
2006 and $227,711 for options granted June 12, 2006.
Options awards reported for Mr. Wright are comprised of
$205,121 for options granted February 23, 2006 and $170,784
for options granted June 12, 2006.
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(3)
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All other compensation reported for
Mr. Leach represents a $14,987 matching contribution by our
company to our 401(k) Plan, of which $12,615 was for the period
from February 28, 2006 through December 31, 2006; $55
for life insurance premiums, of which $46 was for the period
from February 28, 2006 through December 31, 2006; and
$19,082 for personal use of our companys airplane, of
which $16,646 was for the period from February 28, 2006
through December 31, 2006. All other compensation reported
for Mr. Beal represents a $14,998 matching contribution by
our company to our 401(k) Plan, of which $12,616 was for the
period from February 28, 2006 through December 31,
2006; $55 for life insurance premiums, of which $46 was for the
period from February 28, 2006 through December 31,
2006; and $3,342 for personal use of our companys
airplane, all of which was for the period from February 28,
2006 through December 31, 2006. All other compensation
reported for Mr. Kamradt represents a $13,828 matching
contribution by our company to our 401(k) Plan, of which $11,828
was for the period from February 28, 2006 through
December 31, 2006 and $55 for life insurance premiums, of
which $46 was for the period from February 28, 2006 through
December 31, 2006. All other compensation reported for
Mr. Copeland represents a $14,000 matching contribution by
our company to our 401(k) Plan, of which $12,000 was for the
period from February 28, 2006 through December 31,
2006; $55 for life insurance premiums, of which $46 was for the
period from February 28, 2006 through December 31,
2006; and $3,896 for personal use of our companys
airplane, of which $2,320 was for the period from
February 28, 2006 through December 31, 2006. All other
compensation reported for Mr. Thomas represents a $14,000
matching contribution by our company to our 401(k) Plan, of
which $12,000 was for the period from February 28, 2006
through December 31, 2006; $55 for life insurance premiums,
of which $46 was for the period from February 28, 2006
through December 31, 2006; and $1,698 for personal use of
our companys airplane, all of which was for the period
from February 28, 2006 through December 31, 2006. All
other compensation reported for Mr. Wright represents a
$14,000 matching contribution by our company to our 401(k) Plan,
of which $12,000 was for the period from February 28, 2006
through December 31, 2006 and $55 for life insurance
premiums, of which $46 was for the period from February 28,
2006 through December 31, 2006.
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104
Grants of
plan-based awards in last fiscal year
The following table provides information with regard to each
stock option granted to each named executive officer during 2006.
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Estimated
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fair market
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value of
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Number of
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Exercise
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common
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Grant date
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securities
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price of
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stock on
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fair value
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underlying
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option
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date of
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of option
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Name
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Grant date
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options
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awards
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grant(3)
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awards
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Timothy A. Leach
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February 23, 2006
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130,928
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(1)
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$
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8.00
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(1)
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$
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11.52
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$
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568,896
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June 12, 2006
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62,500
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(2)
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12.00
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(2)
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15.40
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493,750
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Steven L. Beal
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February 23, 2006
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130,928
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(1)
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8.00
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(1)
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11.52
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568,896
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June 12, 2006
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62,500
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(2)
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12.00
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(2)
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15.40
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493,750
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David W. Copeland
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February 23, 2006
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58,190
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(1)
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8.00
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(1)
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11.52
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252,842
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June 12, 2006
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75,000
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(2)
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12.00
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(2)
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15.40
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592,500
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Curt F. Kamradt
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February 23, 2006
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58,190
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(1)
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8.00
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(1)
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11.52
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252,842
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June 12, 2006
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75,000
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(2)
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12.00
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(2)
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15.40
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592,500
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E. Joseph Wright
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February 23, 2006
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58,190
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(1)
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8.00
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(1)
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11.52
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252,842
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June 12, 2006
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75,000
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(2)
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12.00
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(2)
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15.40
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592,500
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David M. Thomas III
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February 23, 2006
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27,500
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(1)
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8.00
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(1)
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11.52
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119,491
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June 12, 2006
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100,000
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(2)
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12.00
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(2)
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15.40
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790,000
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(1)
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On February 23, 2006, each of
our named executive officers received a stock option grant as an
executive officer of Concho Equity Holdings Corp., our
predecessor for accounting purposes. Upon completion of the
combination transaction, each outstanding option to purchase
shares of Concho Equity Holdings Corp. was converted into an
option to purchase 1.25 shares of our common stock at an
exercise price of $8.00 per share. The number of securities
underlying the option award is shown as converted to our common
stock. For each of these options, 78% of the total award
originally became vested and exercisable on February 27,
2006 and the remaining 22% originally would have become
exercisable on February 27, 2009. On November 16,
2007, we entered into an amendment to these option awards in
order to cause these option awards to constitute deferred
compensation that is compliant with Section 409A of the
Internal Revenue Code of 1986, as amended, or exempt them from
the application of Section 409A. This amendment provides
that 19.50%, 19.50%, 7.33%, 26.83% and 26.84% of these options
will become first exercisable on January 1, 2008,
January 1, 2009, February 27, 2009, January 1,
2010 and January 1, 2011, respectively. Upon the occurrence
of each of these exercise dates, the applicable portion of the
stock option will remain exercisable until the last day of the
named executive officers taxable year in which such
exercise date occurs. These options also become exercisable in
the event of (i) a separation of service from our company by the
named executive officer for reasons such as death, disability or
reasons other than cause or (ii) a change of control of our
company.
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(2)
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Each of these options become
exercisable as to 1/4 of the shares underlying the option on
each of the first four anniversaries of the grant date
commencing June 12, 2007. These options also contain
provisions that provide for accelerated vesting upon the
occurrence of certain events following a change of control of
our company, as discussed below in Option exercises
in the last fiscal yearEmployment, severance and change of
control arrangements. On November 16, 2007, we
entered into an amendment to these option awards in order to
cause these option awards to constitute deferred compensation
that is compliant with Section 409A or exempt them from the
application of Section 409A. This amendment increased the
exercise price of these option awards to $15.40 per share. On
November 19, 2007, we issued to each of the named executive
officers an award of a number of shares of restricted stock
equal to (i) the product of $3.40 and the number of shares
of common stock subject to these options issued to such named
executive officer, divided by (ii) $18.38, which was the
mean of the high and low sales price of a share of our common
stock on November 19, 2007. The shares of restricted stock
vest in 25% increments on each of January 1, 2008,
June 12, 2008, June 12, 2009 and June 12, 2010.
|
|
(3)
|
|
The estimated fair market value of
common stock on date of grant represents the per share dollar
amount recognized for financial statement reporting purposes
with respect to the fiscal year computed in accordance with SFAS
No. 123R.
|
105
Outstanding
option awards at December 31, 2006
The following table presents the outstanding option awards held
as of December 31, 2006 by each named executive officer.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of securities
|
|
|
Exercise
|
|
|
|
|
|
|
|
underlying unexercised
|
|
|
price of
|
|
|
Option
|
|
|
|
|
options(1)
|
|
|
option
|
|
|
expiration
|
Name
|
|
Grant date
|
|
Exercisable
|
|
|
Unexercisable
|
|
|
awards
|
|
|
date
|
|
|
Timothy A. Leach
|
|
August 13, 2004
|
|
|
69,630
|
(2)
|
|
|
19,639
|
(2)
|
|
|
$8.00
|
(2)
|
|
|
August 13, 2014
|
|
|
December 6, 2004
|
|
|
108,158
|
(2)
|
|
|
30,506
|
(2)
|
|
|
8.00
|
(2)
|
|
|
December 6, 2014
|
|
|
July 15, 2005
|
|
|
46,420
|
(2)
|
|
|
13,093
|
(2)
|
|
|
8.00
|
(2)
|
|
|
June 15, 2015
|
|
|
December 30, 2005
|
|
|
69,630
|
(2)
|
|
|
19,639
|
(2)
|
|
|
8.00
|
(2)
|
|
|
December 30, 2015
|
|
|
February 23, 2006
|
|
|
102,124
|
(2)
|
|
|
28,804
|
(2)
|
|
|
8.00
|
(2)
|
|
|
February 23, 2016
|
|
|
June 12, 2006
|
|
|
|
|
|
|
62,500
|
(3)
|
|
|
12.00
|
(4)
|
|
|
June 12, 2016
|
Steven L. Beal
|
|
August 13, 2004
|
|
|
69,630
|
(2)
|
|
|
19,639
|
(2)
|
|
|
$8.00
|
(2)
|
|
|
August 13, 2014
|
|
|
December 6, 2004
|
|
|
108,158
|
(2)
|
|
|
30,506
|
(2)
|
|
|
8.00
|
(2)
|
|
|
December 6, 2014
|
|
|
July 15, 2005
|
|
|
46,420
|
(2)
|
|
|
13,093
|
(2)
|
|
|
8.00
|
(2)
|
|
|
July 15, 2015
|
|
|
December 30, 2005
|
|
|
69,630
|
(2)
|
|
|
19,639
|
(2)
|
|
|
8.00
|
(2)
|
|
|
December 30, 2015
|
|
|
February 23, 2006
|
|
|
102,124
|
(2)
|
|
|
28,804
|
(2)
|
|
|
8.00
|
(2)
|
|
|
February 23, 2016
|
|
|
June 12, 2006
|
|
|
|
|
|
|
62,500
|
(3)
|
|
|
12.00
|
(4)
|
|
|
June 12, 2016
|
David W. Copeland
|
|
August 13, 2004
|
|
|
30,947
|
(2)
|
|
|
8,729
|
(2)
|
|
|
8.00
|
(2)
|
|
|
August 13, 2014
|
|
|
December 6, 2004
|
|
|
48,071
|
(2)
|
|
|
13,559
|
(2)
|
|
|
8.00
|
(2)
|
|
|
December 6, 2014
|
|
|
July 15, 2005
|
|
|
20,631
|
(2)
|
|
|
5,819
|
(2)
|
|
|
8.00
|
(2)
|
|
|
July 15, 2015
|
|
|
December 30, 2005
|
|
|
30,947
|
(2)
|
|
|
8,729
|
(2)
|
|
|
8.00
|
(2)
|
|
|
December 30, 2015
|
|
|
February 23, 2006
|
|
|
45,388
|
(2)
|
|
|
12,802
|
(2)
|
|
|
8.00
|
(2)
|
|
|
February 23, 2016
|
|
|
June 12, 2006
|
|
|
|
|
|
|
75,000
|
(3)
|
|
|
12.00
|
(4)
|
|
|
June 12, 2016
|
Curt F. Kamradt
|
|
August 13, 2004
|
|
|
30,947
|
(2)
|
|
|
8,729
|
(2)
|
|
|
8.00
|
(2)
|
|
|
August 13, 2014
|
|
|
December 6, 2004
|
|
|
48,071
|
(2)
|
|
|
13,559
|
(2)
|
|
|
8.00
|
(2)
|
|
|
December 6, 2014
|
|
|
July 15, 2005
|
|
|
20,631
|
(2)
|
|
|
5,819
|
(2)
|
|
|
8.00
|
(2)
|
|
|
July 15, 2015
|
|
|
December 30, 2005
|
|
|
30,947
|
(2)
|
|
|
8,729
|
(2)
|
|
|
8.00
|
(2)
|
|
|
December 30, 2015
|
|
|
February 23, 2006
|
|
|
45,388
|
(2)
|
|
|
12,802
|
(2)
|
|
|
8.00
|
(2)
|
|
|
February 23, 2016
|
|
|
June 12, 2006
|
|
|
|
|
|
|
75,000
|
(3)
|
|
|
12.00
|
(4)
|
|
|
June 12, 2016
|
E. Joseph Wright
|
|
August 13, 2004
|
|
|
30,947
|
(2)
|
|
|
8,729
|
(2)
|
|
|
8.00
|
(2)
|
|
|
August 13, 2014
|
|
|
December 6, 2004
|
|
|
48,071
|
(2)
|
|
|
13,559
|
(2)
|
|
|
8.00
|
(2)
|
|
|
December 6, 2014
|
|
|
July 15, 2005
|
|
|
20,631
|
(2)
|
|
|
5,819
|
(2)
|
|
|
8.00
|
(2)
|
|
|
July 15, 2015
|
|
|
December 30, 2005
|
|
|
30,947
|
(2)
|
|
|
8,729
|
(2)
|
|
|
8.00
|
(2)
|
|
|
December 30, 2015
|
|
|
February 23, 2006
|
|
|
45,388
|
(2)
|
|
|
12,802
|
(2)
|
|
|
8.00
|
(2)
|
|
|
February 23, 2016
|
|
|
June 12, 2006
|
|
|
|
|
|
|
75,000
|
(3)
|
|
|
12.00
|
(4)
|
|
|
June 12, 2016
|
David M. Thomas III
|
|
April 15, 2005
|
|
|
37,343
|
(2)
|
|
|
10,533
|
(2)
|
|
|
8.00
|
(2)
|
|
|
April 15, 2015
|
|
|
July 15, 2005
|
|
|
9,750
|
(2)
|
|
|
2,750
|
(2)
|
|
|
8.00
|
(2)
|
|
|
July 15, 2015
|
|
|
December 30, 2005
|
|
|
14,625
|
(2)
|
|
|
4,125
|
(2)
|
|
|
8.00
|
(2)
|
|
|
December 30, 2015
|
|
|
February 23, 2006
|
|
|
21,450
|
(2)
|
|
|
6,050
|
(2)
|
|
|
8.00
|
(2)
|
|
|
February 23, 2016
|
|
|
June 12, 2006
|
|
|
|
|
|
|
100,000
|
(3)
|
|
|
12.00
|
(4)
|
|
|
June 12, 2016
|
|
|
|
|
|
(1)
|
|
These options contain provisions
that provide for accelerated vesting upon the occurrence of
certain events following a change of control of our company, as
discussed below in Option exercises in the last
fiscal yearEmployment, severance and change of control
arrangements.
|
|
(2)
|
|
Prior to the completion of the
combination transaction on February 27, 2006, Concho Equity
Holdings Corp, our predecessor for accounting purposes, made
awards of stock options to our named executive officers. Upon
completion of the combination transaction, each outstanding
option to purchase shares of Concho Equity Holdings Corp. was
converted into an option to purchase 1.25 shares of our
common stock at an exercise price of $8.00 per share. The number
of securities underlying the option award is shown as converted
to our common stock. For each of these options, 78% of the total
award originally became vested and exercisable on
February 27, 2006 and the remaining 22% originally would
have become exercisable on February 27, 2009. On
November 16, 2007, we entered into an amendment to these
option awards in order to cause these option awards to
constitute deferred compensation that is compliant with
Section 409A of the Internal Revenue Code of 1986, as
amended, or exempt them from the application of
Section 409A. This amendment provides that 19.50%, 19.50%,
|
106
|
|
|
|
|
7.33%, 26.83% and 26.84% of these
options will become first exercisable on January 1, 2008,
January 1, 2009, February 27, 2009, January 1,
2010 and January 1, 2011, respectively. Upon the occurrence
of each of these exercise dates, the applicable portion of the
stock option will remain exercisable until the last day of the
named executive officers taxable year in which such
exercise date occurs. These options also become exercisable in
the event of (i) a separation of service from our company
by the named executive officer for reasons such as death,
disability or reasons other than cause or (ii) a change of
control of our company.
|
|
(3)
|
|
These options will vest in
one-fourth increments on each anniversary of the grant date,
commencing on June 12, 2007.
|
|
(4)
|
|
On November 16, 2007, we
entered into an amendment to these option awards in order to
cause these option awards to constitute deferred compensation
that is compliant with Section 409A or exempt them from the
application of Section 409A. This amendment increased the
exercise price of these option awards to $15.40 per share. On
November 19, 2007, we issued to each of the named executive
officers an award of a number of shares of restricted stock
equal to (i) the product of $3.40 and the number of shares
of common stock subject to these options issued to such named
executive officer, divided by (ii) $18.38, which was the
mean of the high and low sales price of a share of our common
stock on November 19, 2007. The shares of restricted stock
vest in 25% increments on each of January 1, 2008,
June 12, 2008, June 12, 2009 and June 12, 2010.
|
107
Option exercises
in last fiscal year
No shares were acquired pursuant to the exercise of options by
any named executive officer during 2006.
Employment,
severance and change of control arrangements
We entered into employment agreements with all of our named
executive officers, each with an effective date as of
June 1, 2006. These employment agreements are substantially
similar and have an initial term that expires three years from
the effective date, but will automatically be extended for
successive one-year terms after the initial term unless either
party gives written notice within 90 days prior to the end
of the term. Under these agreements, Mr. Leach and
Mr. Beals minimum annual base salaries are $350,000
and Messrs. Copeland, Kamradt, Wright and Thomass
minimum annual base salaries are $250,000. All of our named
executive officers are eligible to receive cash bonuses as and
when approved by our board of directors or compensation
committee. Mr. Leach and Mr. Beal are entitled to
utilize our aircraft for business use, and they and their
families are entitled to use our aircraft for reasonable
personal use and are not required to reimburse us for any cost
related to such use unless a family member travels without
either Mr. Leach or Mr. Beal.
If one of our named executive officers employment is
terminated by us without cause (and not by reason of
his death or disability), or if he terminates his employment
following a change in duties, then we will provide
him with certain severance benefits. If such a termination of
employment occurs prior to a change of control or more than two
years after a change of control, then his base salary will
continue to be paid for 12 months and we will reimburse him
for up to 12 months for the amount by which the cost of his
continued coverage under our group health plans exceeds the
employee contribution amount that we charge our active senior
executives for similar coverage. If such a termination of
employment occurs during the two-year period beginning on the
date upon which a change of control occurs (a change of
control period), then he will be entitled to a lump sum
severance amount equal to two times his annual base salary, all
of his stock options and restricted stock awards will vest in
full, and we will reimburse him for up to 18 months for the
amount by which the cost of his continued coverage under our
group health plans exceeds the employee contribution amount that
we charge our active senior executives for similar coverage. If
the total amount of payments to be provided by our company in
connection with a change in control would cause any of the named
executive officers to incur golden parachute excise
tax liability, then the payments will be reduced to the extent
necessary to leave him in a better after-tax position than if no
such reduction had occurred. The agreement does not provide for
any tax gross-up payments. We will have
cause to terminate a named executive officers
employment if he (1) has engaged in gross negligence, gross
incompetence or willful misconduct in the performance of his
duties, (2) has materially breached any material provision
of his employment agreement, corporate policy or code of conduct
established by our company, (3) has willfully engaged in
conduct that is materially injurious to our company,
(4) has committed an act of fraud, embezzlement or willful
breach of a fiduciary duty to our company, (5) has been
convicted of a crime involving fraud, dishonesty or moral
turpitude or any felony, or (6) has refused, without proper
reason, to perform his duties. Prior to a change of control or
after the expiration of a change of control period, a named
executive officer will incur a change in duties if
there is a reduction in the rank of his title as an officer of
our company, a reduction in his base salary, or a material
diminution in his employee benefits and perquisites from those
substantially similar to those provided to similarly situated
executives. During a change of control period, a named executive
officer will incur a change in duties if there is
(a) a material reduction in the nature or scope of his
authorities or duties, (b) a reduction in his base salary,
(c) a
108
diminution in his eligibility to participate in bonus, stock
option, incentive award and other compensation plans, (d) a
material diminution in his employee benefits and perquisites, or
(e) a change in the location of his principal place of
employment by more than 10 miles. In addition, each of the
employment agreements contains provisions that prohibit, with
certain limitations, the named executive officer from competing
with us; soliciting any of our customers, vendors, or
acquisition candidates; or soliciting or hiring any of our
employees or inducing any of them to terminate their employment
with us. These restrictions will generally continue for a period
of 12 months following termination of employment, except
under certain circumstances we must agree to continue to pay the
named executive officers base salary in order for the
non-competition restrictions to continue to apply.
In addition to the acceleration of vesting provisions described
above, all options to purchase common stock issued to our named
executive officers may be subject to accelerated vesting upon a
change of control as described below in the section entitled
Potential payments upon change of control under
employment agreements.
Potential
payments upon change of control under employment
agreements
The following table summarizes the potential payments to each
named executive officer assuming that one of the events
described in the table below occurs. The table assumes that the
event occurred on December 31, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
Termination of employment by our company without
|
|
|
|
cause (and not by reason of death or disability)
or
|
|
|
|
resignation following a change in duties
|
|
|
|
Prior to, or more than two
|
|
|
Within two years after a
|
|
Name
|
|
years after a change of
control
|
|
|
change of control
|
|
|
|
|
|
|
|
|
|
|
Timothy A. Leach
|
|
$
|
368,173(1
|
)
|
|
$
|
1,436,080(2
|
)
|
Steven L. Beal
|
|
|
368,173(1
|
)
|
|
|
1,436,080(2
|
)
|
David W. Copeland
|
|
|
268,173(3
|
)
|
|
|
1,107,816(4
|
)
|
Curt F. Kamradt
|
|
|
268,173(3
|
)
|
|
|
1,107,816(4
|
)
|
E. Joseph Wright
|
|
|
268,173(3
|
)
|
|
|
1,107,816(4
|
)
|
David M. Thomas III
|
|
|
268,173(3
|
)
|
|
|
1,177,460(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Includes payment of $350,000 for
the continuation of salary and $18,173 for continuation of
health benefits for a period of 12 months following such
termination.
|
|
(2)
|
|
Includes payment of $700,000 in a
lump sum payment for salary, $27,259 for continuation of health
benefits for a period of 18 months following such
termination and $708,821 for accelerated vesting of equity
awards, based on the grant date fair value of unvested stock
options as of December 31, 2006 in accordance with the
provisions of Statement of Financial Accounting Standards
(SFAS) No. 123R, Share-based
Payment.
|
|
(3)
|
|
Includes payment of $250,000 for
the continuation of salary and $18,173 for continuation of
health benefits for a period of 12 months following such
termination.
|
|
(4)
|
|
Includes payment of $500,000 in a
lump sum payment for salary, $27,259 for continuation of health
benefits for a period of 18 months following such
termination and $580,557 for accelerated vesting of equity
awards for Messrs. Copeland, Kamradt and Wright and
$650,201 for accelerated vesting of equity awards for
Mr. Thomas, based on the grant date fair value of unvested
stock options as of December 31, 2006 in accordance with
the provisions of Statement of Financial Accounting Standards
(SFAS) No. 123R, Share-based
Payment.
|
109
Director
compensation
Directors who are not employees of our company, which we refer
to as Outside Directors, receive compensation for
serving on our board of directors. Our objectives for director
compensation are to remain competitive with the compensation
paid to directors of comparable companies while adhering to
corporate governance best practices with respect to such
compensation, and to reinforce our practice of encouraging stock
ownership. Our Outside Director compensation includes:
|
|
|
an annual retainer of $35,000;
|
|
|
a meeting attendance fee of $1,000 for each board meeting
attended;
|
|
|
a committee meeting attendance fee of $500 for each board
committee meeting attended;
|
|
|
a one-time award to each new Outside Director of
5,000 shares of restricted stock under our 2006 Stock
Incentive Plan; and
|
|
|
on an annual basis, commencing with the second year of service,
an award of 2,500 shares of restricted stock under our
long-term incentive plan.
|
On June 1, 2006, the board of directors approved a one-time
award to the Outside Directors of 5,000 shares of
restricted stock under our 2006 Stock Incentive Plan, which
shares fully vested on January 2, 2007. All directors are
reimbursed for all reasonable
out-of-pocket
expenses incurred in attending meetings of the board of
directors and committees thereof. The following table presents
compensation information for the year ended December 31,
2006 paid to or accrued for our directors.
Director
compensation
|
|
|
|
|
|
|
|
|
|
|
Name(1)
|
|
Fees
|
|
Stock
Awards(2)
|
|
Total
|
|
|
Tucker S. Bridwell
|
|
$
|
17,166
|
|
$
|
77,000
|
|
$
|
94,166
|
W. Howard Keenan,
Jr.(3)
|
|
|
15,666
|
|
|
77,000
|
|
|
92,666
|
A. Wellford
Tabor(4)
|
|
|
17,166
|
|
|
77,000
|
|
|
94,166
|
G. Carl
Everett(5)
|
|
|
17,666
|
|
|
77,000
|
|
|
94,666
|
Larry V.
Kalas(5)
|
|
|
16,666
|
|
|
77,000
|
|
|
93,666
|
John A.
Knorr(5)
|
|
|
13,666
|
|
|
77,000
|
|
|
90,666
|
Bradley D.
Bartek(5)
|
|
|
14,666
|
|
|
77,000
|
|
|
91,666
|
Robert C.
Chase(5)
|
|
|
13,666
|
|
|
77,000
|
|
|
90,666
|
|
|
|
|
|
(1)
|
|
Our employee directors have been
omitted from this table because they receive no compensation for
serving on our board of directors.
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(2)
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The grant date fair value of the
equity award computed in accordance with FAS 123R for each
director reflected in the column below was $77,000. As of
December 31, 2006, each director held 5,000 restricted
stock awards in the aggregate and no option awards.
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(3)
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Mr. Keenan remits all fees
received as director compensation to Yorktown Energy Partners V,
L.P. and Yorktown Energy Partners VI, L.P. and holds all
securities received as director compensation for the benefit of
those entities. Mr. Keenan disclaims beneficial ownership
of all such securities as well as those held by those entities,
except to the extent of his pecuniary interest therein.
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(4)
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Mr. Tabor remits all fees
received as director compensation to Wachovia Capital Partners
(WCP) and holds all securities received as director
compensation for the benefit of WCP. Mr. Tabor disclaims
beneficial ownership of all such securities as well as those
held by WCP and its affiliates, except to the extent of his
pecuniary interest therein.
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(5)
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Messrs. Everett, Kalas, Knorr,
Bartek and Chase each resigned as a director on April 23,
2007.
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110
2006 Stock
Incentive Plan
The following contains a summary of the material terms of our
2006 Stock Incentive Plan, which was adopted by our board of
directors and approved by our stockholders. The description of
the 2006 Stock Incentive Plan does not describe all aspects of
the plan. For more information, we refer you to the full text of
the 2006 Stock Incentive Plan, which has been filed as an
exhibit to the registration statement of which this prospectus
is a part.
The 2006 Stock Incentive Plan permits the grant of non-qualified
stock options, incentive stock options, stock appreciation
rights issued in tandem with stock options or phantom stock
awards, restricted stock, phantom stock, performance awards and
other stock-based awards to our employees, directors and
consultants and to employees and consultants of our affiliates,
provided that incentive stock options may be granted solely to
employees. A maximum of 5,850,000 shares of common stock
may be delivered pursuant to awards under the 2006 Stock
Incentive Plan. The number of shares deliverable pursuant to
awards under the 2006 Stock Incentive Plan is subject to
adjustment as a result of mergers, consolidations,
reorganizations, stock splits, stock dividends and other similar
changes in our common stock. Shares of common stock used to pay
exercise prices and to satisfy tax withholding obligations with
respect to awards as well as shares covered by awards that
expire, terminate or lapse will again be available for awards
under the 2006 Stock Incentive Plan.
Administration. The 2006 Stock Incentive Plan is
administered by the compensation committee of the board of
directors. Our compensation committee has the sole discretion to
determine the employees, directors and consultants to whom
awards may be granted under the 2006 Stock Incentive Plan and
the manner in which such awards will vest. The compensation
committee is authorized to construe the 2006 Stock Incentive
Plan, to prescribe rules and regulations relating to the 2006
Stock Incentive Plan, and to make any other determinations that
it deems necessary or advisable for administering the 2006 Stock
Incentive Plan. Our compensation committee may correct any
defect, supply any omission or reconcile any inconsistency in
the 2006 Stock Incentive Plan in the manner and to the extent
the compensation committee deems expedient to carry the 2006
Stock Incentive Plan into effect.
Stock Options. Our compensation committee will
determine the exercise price for each stock option award.
Options must have an exercise price at least equal to the fair
market value of the common stock on the date the option is
granted. An option holder may exercise an option by written
notice and payment of the exercise price:
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in cash;
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if the option agreement so provides, by a cashless
exercise, in accordance with procedures approved by the
compensation committee; or
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if the option agreement so provides, by delivery of a number of
shares of common stock (plus cash if necessary) having a fair
market value equal to the option price.
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Stock Appreciation Rights. A stock appreciation
right permits the holder to receive an amount (in cash, common
stock, or a combination thereof) equal to the number of stock
appreciation rights exercised by the holder, multiplied by the
excess of the fair market value of common stock on the exercise
date over the stock appreciation rights exercise price.
Stock appreciation rights may be granted in connection with the
grant of an option or a phantom stock award.
111
The exercise price of stock appreciation rights granted under
the 2006 Stock Incentive Plan will be determined by the
compensation committee; provided, however, that such exercise
price cannot be less than the fair market value of a share of
common stock on a date the stock appreciation right is granted
(subject to adjustments). A stock appreciation right may be
exercised in whole or in such installments and at such times as
determined by the compensation committee.
Restricted Stock Awards. Pursuant to a restricted
stock award, shares of common stock may be granted at any time
the award is made with or without any cash payment to us, as
determined by the compensation committee; provided, however,
that such shares will be subject to certain restrictions on the
disposition thereof and certain obligations to forfeit such
shares to us as may be determined in the discretion of the
compensation committee. The compensation committee may provide
that the restrictions on disposition may lapse based upon
(a) the attainment of specific performance measures
established by the compensation committee; (b) the
participants continued service with us; (c) the
occurrence of any other event or condition specified by the
compensation committee in its sole discretion; or (d) a
combination of any of the foregoing factors. A participant may
not sell, transfer, pledge, exchange, hypothecate, or otherwise
dispose of such shares until the expiration of the restriction
period.
Transferability. Unless otherwise determined by our
compensation committee, awards granted under the 2006 Stock
Incentive Plan are not transferable other than by will or by the
laws of descent and distribution or, in some cases, pursuant to
the terms of a qualified domestic relations order. Incentive
stock options may be exercisable during the participants
lifetime only by such participant or his legal representative or
guardian.
Change of Control. In the event of a Corporate
Change (as defined in the 2006 Stock Incentive Plan), the
compensation committee may provide for:
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the substitution of similar options with respect to the stock of
the successor company;
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the acceleration of the vesting of all or any portion of certain
awards; or
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the mandatory surrender to us by selected participants of some
or all of the outstanding awards held by such participants, at
which time we will cancel such awards and cause to be paid to
each affected participant a certain amount of cash per share, as
specified in the 2006 Stock Incentive Plan.
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Amendment and Termination. Our board of directors in
its discretion may terminate the 2006 Stock Incentive Plan at
any time with respect to any shares of common stock for which
awards have not been granted. Our board of directors may alter
or amend the 2006 Stock Incentive Plan from time to time, except
that no change may be made that would impair the rights of a
participant with respect to an outstanding award without the
consent of the participant. In addition, our board of directors
may not, without approval of our stockholders:
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amend the 2006 Stock Incentive Plan to increase the maximum
aggregate number of shares that may be issued under the 2006
Stock Incentive Plan; or
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increase the maximum number of shares that may be issued under
the 2006 Stock Incentive Plan through incentive stock options or
change the class of individuals eligible to receive awards under
the 2006 Stock Incentive Plan.
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112
Indemnification
of directors and executive officers and limitation of
liability
We have also entered into indemnification agreements with each
of our named executive officers and directors. These
indemnification agreements are intended to permit
indemnification to the fullest extent now or hereafter permitted
by the General Corporation Law of the State of Delaware. It is
possible that the applicable law could change the degree to
which indemnification is expressly permitted.
The indemnification agreements cover expenses (including
attorneys fees), judgments, fines and amounts paid in
settlement incurred as a result of the fact that such person, in
his or her capacity as a director or officer, is made,
threatened or reasonably expected to be made a party to any suit
or proceeding. The indemnification agreements generally cover
claims relating to the fact that the indemnified party is or was
an officer, director, employee or agent of us or any of our
subsidiaries, or is or was serving at our request in such a
position for another entity. The indemnification agreements also
obligate us to promptly advance all expenses incurred in
connection with any claim. The indemnitee is, in turn, obligated
to reimburse us for all amounts so advanced if it is later
determined that the indemnitee is not entitled to
indemnification. The indemnification provided under the
indemnification agreements is not exclusive of any other
indemnity rights; however, double payment to the indemnitee is
prohibited.
113
Principal
and selling stockholders
The following table sets forth certain information regarding the
beneficial ownership of our common stock as of November 20,
2007 by:
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each person who will beneficially own more than 5% of our common
stock then outstanding;
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each of our named executive officers;
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each of our directors;
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all of our directors and executive officers as a group; and
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each selling stockholder.
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All information with respect to beneficial ownership has been
furnished by the respective directors, officers or stockholders,
as the case may be. The number of shares in the column
Number of shares offered represents all of the
shares that each selling stockholder will offer under this
prospectus assuming no exercise of the underwriters
over-allotment option. To our knowledge, upon the completion of
this offering, each of the persons named below will have sole
voting and investment power as to the shares shown, except as
disclosed in this prospectus or to the extent this power may be
shared with a spouse. None of the selling stockholders are
broker dealers or affiliates of broker dealers. Beneficial
ownership as shown in the table below has been determined in
accordance with the applicable rules and regulations promulgated
under the Securities Exchange Act of 1934.
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Shares beneficially
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Shares beneficially
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owned
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owned
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Number of
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after this
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prior to the offering
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shares
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offering(1)(2)
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Name of beneficial
owner
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Number
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% of class
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offered
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Number
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% of class
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Chase Oil
Corporation(3)(5)
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22,621,995
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29.8%
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5,030,320
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17,591,675
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23.2%
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Caza Energy
LLC(4)(5)
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2,019,402
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2.7%
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2,019,402
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Mack C.
Chase(5)
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24,641,397
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32.5%
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7,049,722
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17,591,675
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23.2%
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Yorktown Energy Partners V,
L.P.(6)
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3,167,226
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4.2%
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3,167,226
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4.2%
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Yorktown Energy Partners VI,
L.P.(6)
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7,502,774
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9.9%
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7,502,774
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9.9%
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Timothy A.
Leach(7)(11)
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1,075,928
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1.4%
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1,075,928
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1.4%
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Steven L.
Beal(7)(11)
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1,064,787
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1.4%
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1,064,787
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1.4%
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David W.
Copeland(7)(11)
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494,896
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*
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494,896
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*
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Curt F.
Kamradt(7)(11)
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399,896
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*
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45,000
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354,896
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*
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David M. Thomas
III(7)(11)
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68,811
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*
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68,811
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*
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E. Joseph
Wright(7)(11)
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354,896
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*
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354,896
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*
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Tucker S.
Bridwell(8)(11)
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727,220
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*
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727,220
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*
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W. Howard Keenan,
Jr.(9)(11)
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10,670,000
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14.1%
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10,670,000
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14.1%
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A. Wellford
Tabor(10)(11)
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7,500
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*
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7,500
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*
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Ray M.
Poage(11)
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5,000
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*
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5,000
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*
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The Board of Trustees of the Leland Stanford Junior
University(12)
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1,386,125
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1.8%
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1,386,125
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Other
stockholders(13)
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657,119
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*
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219,153
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437,966
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*
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All directors and executive officers as a group
(11 persons)(7)(8)(9)(10)
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14,873,670
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19.5%
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45,000
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14,828,670
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19.4%
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114
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(1)
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Assumes no exercise of the
underwriters over-allotment option to purchase an
aggregate of 1,305,000 shares, granted by Chase Oil
Corporation.
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(2)
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Based upon an aggregate of
75,833,972 shares outstanding as of November 20, 2007.
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(3)
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The address of Chase Oil
Corporation is P.O. Box 1767, Artesia, NM 88211-1767.
The directors of Chase Oil Corporation are Mack C. Chase,
Robert C. Chase and Rebecca S. Ericson.
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(4)
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The address of Caza Energy LLC is
P.O. Box 1767, Artesia, NM 88211-1767. The managers of
Caza Energy LLC are Mack C. Chase and Robert C.
Chase.
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(5)
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Mack C. Chase is the
beneficial owner of the shares owned by Caza Energy LLC, of
which Mack C. Chase is a Manager and therefore shares
voting and investment power with respect to the shares owned by
Caza Energy LLC. Mack C. Chase disclaims beneficial
ownership in the shares held by Caza Energy LLC except to the
extent of his pecuniary interest in Caza Energy LLC.
Mack C. Chase owns a majority of the voting stock of Chase
Oil Corporation and therefore may be deemed to have voting and
investment power with respect to the shares owned by Chase Oil
Corporation. Mack C. Chase disclaims beneficial ownership
in the shares owned by Chase Oil Corporation except to the
extent of his pecuniary interest in Chase Oil Corporation. The
address of Mack C. Chase is P.O. Box 693, Artesia,
NM 88211-0693.
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(6)
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The address of Yorktown Energy
Partners V, L.P. and Yorktown Energy Partners VI, L.P.
is 410 Park Avenue, 19th Floor, New York, NY 10022.
Includes 2,226 shares and 5,274 shares owned by
Yorktown Energy Partners V, L.P. and Yorktown Energy
Partners VI, L.P., respectively, received by W. Howard
Keenan, Jr. as director compensation for the benefit of those
entities.
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(7)
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The number of shares beneficially
owned includes the following shares that are subject to options
that were exercisable as of or will become exercisable within
60 days of, November 20, 2007:
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Shares subject
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Name of beneficial owner
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to options
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Timothy A. Leach
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166,838
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Steven L. Beal
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166,838
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David W. Copeland
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85,957
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Curt F. Kamradt
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85,957
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David M. Thomas III
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45,793
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E. Joseph Wright
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85,957
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(8)
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Includes 426,500 shares of
common stock owned by the Mansfeldt Concho Partners and
293,220 shares owned by the Dian Graves Owen
Foundation.
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(9)
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Includes 10,662,500 shares of
common stock owned by Yorktown Energy Partners V, L.P. and
Yorktown Energy Partners VI, L.P. W. Howard
Keenan, Jr. is a member and a manager of the general
partner of Yorktown Energy Partners V, L.P. and Yorktown
Energy Partners VI, L.P. and holds all securities received
as director compensation for the benefit of those entities.
Mr. Keenan disclaims beneficial ownership of all such
securities as well as those held by Yorktown Energy
Partners V, L.P. and Yorktown Energy Partners VI,
L.P., except to the extent of his pecuniary interest therein.
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(10)
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Mr. Tabor is a member of
Wachovia Capital Partners (WCP) and holds all
securities received as director compensation for the benefit of
WCP. Mr. Tabor disclaims beneficial ownership of all such
securities as well as those held by WCP and its affiliates,
except to the extent of his pecuniary interest therein.
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(11)
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Executive officer or director of
our company.
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(12)
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The Stanford Management Company
manages the holdings of the Board of Trustees of the Leland
Stanford Junior University.
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(13)
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Consists of twelve selling
stockholders for whom disclosure is permitted to be made on a
group basis because the aggregate holdings of the group are less
than 1% of our common stock outstanding.
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115
Certain
relationships and related party transactions
Since our inception, we have entered into the following
transactions and contractual arrangements with our officers,
directors and principal stockholders. Although we have not
historically had formal policies and procedures regarding the
review and approval of related party transactions, all
transactions outside of the ordinary course of business between
us and any of our officers, directors and principal stockholders
were approved by our board of directors. In November 2007, our
board of directors adopted a written policy that requires our
audit committee to review on an annual basis all transactions
with related parties, or in which a related party has a direct
or indirect interest, and to determine whether to ratify or
approve the transaction after consideration of the related
partys interest in the transaction and other material
facts. None of the transactions below were reviewed by our audit
committee pursuant to this written policy. We believe that the
terms of these arrangements and agreements are at least as
favorable as they would have been had we contracted with an
unrelated third party.
Transactions with
Chase Oil and its affiliates
Transition
Services Agreement
We entered into a Transition Services Agreement with Mack Energy
Corporation, an affiliate of Chase Oil, whereby it provided
services to the properties in Southeast New Mexico that we
acquired from Chase Oil and its affiliates in the combination
transaction. The Transition Services Agreement replaced our
prior Contract Operator Agreement with Mack Energy that we
entered into in connection with the initial closing of the
combination transaction. We agreed with Mack Energy to terminate
the Contract Operator Agreement in connection with the execution
of the Transition Services Agreement on April 23, 2007.
Under the Transition Services Agreement, Mack Energy provided
field level services, including pumping, well service oversight
and supervision and certain equipment for workover and
recompletion services, at costs prevailing in the area of the
subject properties, but not to exceed charges for comparable
services by and among Mack Energy and its affiliates. Mack
Energy performed substantially similar services on our behalf
under the Contract Operator Agreement prior to its termination.
During the year ended December 31, 2006 and the nine months
ended September 30, 2007, we paid Mack Energy approximately
$10.3 million and $11.9 million, respectively, for
services rendered under the Contract Operator Agreement and the
Transition Services Agreement. The Transition Services Agreement
terminated upon completion of our initial public offering in
August 2007, at which time we assumed the operation of the
subject properties.
Silver Oak
Drilling contracts
Silver Oak Drilling, LLC, an affiliate of Chase Oil, owns and
operates drilling rigs, four of which we are currently using for
a substantial portion of our operations in Southeast New Mexico.
During the year ended December 31, 2006, we spent approximately
$13.1 million with Silver Oak Drilling for drilling
services in Southeast New Mexico. We determined in January 2007
to reduce our drilling activities for the three months ended
March 31, 2007. As a result, we paid $3.0 million to
Silver Oak Drilling for contract drilling fees related to
stacked rigs subject to daywork drilling contracts. We resumed
our drilling activities in April 2007, and through
September 30, 2007 we have spent approximately
$15.1 million on exploration and development drilling in
Southeast New Mexico that was conducted by Silver Oak Drilling
under drilling contracts that will terminate on August 1,
2008.
116
Saltwater
disposal
Among the assets we acquired in the combination transaction is
an undivided interest in a saltwater gathering and disposal
system built by affiliates of Chase Oil to gather and dispose of
water produced from wells located on the Chase Group Properties
and other wells. We are the operator of the salt water gathering
and disposal system. The system is owned jointly by Chase Oil,
Mack Energy, Caza Energy LLC and us in undivided ownership
percentages, which are to be annually redetermined as of January
1 of each year on the basis of each partys percentage
contribution of the total volume of produced water disposed of
into the system during the prior calendar year. As of
January 1, 2007, we owned 90% of the system and Chase Oil,
Mack Energy and Caza Energy collectively owned 10% of the
system. Each owner has the right to dispose of produced water
into the system. Operating, repair and maintenance costs are
allocated among the owners monthly on the basis of their
respective system ownership interests at the time the charge is
incurred. The owners have agreed and acknowledged that the
system is to be owned and operated without any intent to profit,
and that any third-party income attributable to the system will
be allocated proportionately to the owners as a reduction of
operating costs. Costs of any future expansion of the system are
to be shared as agreed upon at the time. In the event that the
owners cannot agree on any such allocation, the owner proposing
an expansion shall have the right to construct such expansion at
its cost and for its exclusive use. This agreement shall
continue so long as any well located on the subject properties
is utilizing the system.
Software license
agreement
In order to obtain enhanced computer processing capabilities and
functionality for our various business processes, as of
March 1, 2006, we entered into a Software License Agreement
with Enertia Software Systems, which is an affiliate of Chase
Oil. We are using the software in the following software
functional areas: accounting and financial reporting, well
production and field data gathering, land and contracts, and
payroll processing. The Software License Agreement provides for
up to twenty concurrent users with the ability for us to upgrade
in five concurrent user increments for a one-time license fee of
$50,000 for each concurrent user increment. The initial term of
the license granted in the Software License Agreement is
99 years. The license can be terminated by either party by
providing notice to the other party at least six months prior to
the date on which the termination will be effective. We have
paid aggregate fees to the licensor to date in the amount of
$450,000, which consists of a software license fee of $300,000
and a project fee of $150,000. The project fee was to pay for
the cost of conversion of the data from our previous software
system to the new system. In addition to these initial fees, we
became obligated to pay an annual maintenance fee to the
licensor in the amount of $48,000, beginning on
September 1, 2006. During the year ended December 31,
2006, we also paid to Enertia approximately $120,000 for
consulting and programming services. During the nine months
ended September 30, 2007, we paid Enertia approximately
$69,000 for consulting and programming services.
Acquisition of
leasehold acreage from Caza Energy LLC
For the year ended December 31, 2006, we paid Caza Energy
LLC, an affiliate of Chase Oil, approximately $2.1 million
for leasehold interests in 24,579 gross (6,138 net)
acres located in Eddy and Chaves Counties, New Mexico. We
combined a portion of these interests together with other of our
interests in the area to explore the horizontal Wolfcamp play,
which is located along the northwestern rim of the Delaware
Basin in Eddy and Chaves Counties, New Mexico.
117
Other
transactions
We also conduct business with certain companies that are
affiliated with Chase Oil and Mack Energy from time to time.
Robert Chase, who was a director of our company from
February 27, 2006 until April 23, 2007, is an officer
of these companies. Most of these companies provide us with
oilfield services or supplies that we use in the ordinary course
of our operations. Our business with these companies is not
subject to any contracts or other commitments other than
arrangements entered into at the time the services are rendered
or the supplies are purchased. We are not required to purchase
products or services from these companies, and we are able to
purchase these products and services from other vendors who are
not affiliated with Chase Oil or Mack Energy. During the year
ended December 31, 2006, we incurred the following
expenditures with the following companies that are affiliated
with Chase Oil and Mack Energy:
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Activity
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Activity
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with vendor
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with vendor
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prior to the
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subsequent to the
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Total
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the combination
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the combination
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amount of
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Name of Vendor
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transaction
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transaction
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expenditures
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(in thousands)
|
|
Alliance Drillings Fluids, LLC
|
|
$
|
|
|
$
|
778
|
|
$
|
778
|
Arrowhead Pipe & Supply Co.
|
|
|
|
|
|
13,566
|
|
|
13,566
|
Catalyst Oilfield Services LLC
|
|
|
|
|
|
890
|
|
|
890
|
Deer Horn Aviation Ltd. Co.
|
|
|
67
|
|
|
240
|
|
|
307
|
Production Specialty Services, Inc.
|
|
|
57
|
|
|
960
|
|
|
1,017
|
Silver Oak Drilling, LLC
|
|
|
|
|
|
13,097
|
|
|
13,097
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
124
|
|
$
|
29,531
|
|
$
|
29,655
|
|
|
|
|
|
|
During the nine months ended September 30, 2007, we
incurred the following expenditures with the following companies
that are affiliated with Chase Oil and Mack Energy:
|
|
|
|
|
|
Total
|
|
|
amount of
|
Name of Vendor
|
|
expenditures
|
|
|
(in thousands)
|
|
Alliance Drillings Fluids, LLC
|
|
$
|
875
|
Arrowhead Pipe & Supply Co.
|
|
|
|
Catalyst Oilfield Services LLC
|
|
|
1,536
|
Deer Horn Aviation Ltd. Co.
|
|
|
330
|
Production Specialty Services, Inc.
|
|
|
14,634
|
Silver Oak Drilling, LLC
|
|
|
15,117
|
|
|
|
|
Total
|
|
$
|
32,492
|
|
|
|
|
Overriding
royalty interests
Prior to the formation of Concho Equity Holdings Corp.,
Messrs. Leach, Beal, Copeland, Kamradt and Wright acquired
working interests in 120 undeveloped acres located in Lea
County, New Mexico. In connection with the formation of Concho
Equity Holdings Corp., these working interests were sold to that
company in November 2004 for $120,000 in the aggregate, and
Messrs. Leach, Beal, Copeland, Kamradt and Wright each
retained a 0.25% overriding royalty interest in any production
attributable to this acreage. We have not drilled any wells that
are subject to the overriding royalty interest and, therefore,
no payments have been made in connection with these royalty
interests.
118
In April 2005, we acquired certain working interests in
46,861 gross (26,908 net) acres located in Culberson
County, Texas from an entity partially owned by Mr. Thomas.
In connection with this acquisition, such entity retained a 2%
overriding royalty interest in the acquired properties, which
overriding royalty interest is now owned equally by
Mr. Thomas and another employee of our company.
Mr. Thomas became an executive officer of our company
immediately following the acquisition.
We made royalty payments with respect to certain properties
located in Andrews County, Texas to a partnership in which
Tucker Bridwell, one of our directors, is the general partner
with a 3.5% partnership interest. We paid approximately $0,
$100, $72,000, $16,000 and $109,000 to this partnership during
the years ended December 31, 2004, 2005 and 2006 and the
nine months ended September 30, 2006 and 2007,
respectively. We also paid this partnership an $80,000 lease
bonus in 2006. We had no outstanding invoices payable to this
partnership as of December 31, 2006 or September 30,
2007.
Certain members of the Chase Group own overriding royalty
interests in some of the properties we operate that were
acquired in the combination transaction. The aggregate amount of
royalty payments made in connection with these overriding
royalty interests was $1.2 million during the year ended
December 31, 2006 and $1.6 million during the nine
months ended September 30, 2007.
Executive officer
promissory notes
In connection with the capitalization of Concho Equity Holdings
Corp. at various dates through February 23, 2006, that
company received limited recourse promissory notes from each of
our executive officers as partial payment for equity securities
issued to such executive officers. Interest accrued and
compounded annually on the unpaid principal amount of the
promissory notes at the rate of 6.0% per annum. Interest
was not required to be paid on these promissory notes until the
earlier of prepayment of the promissory notes or maturity of the
promissory notes. No principal or interest was paid by our
executive officers on these promissory notes until
April 23, 2007, when our executive officers repaid in full
the aggregate principal amount and accrued interest on the
promissory notes. The following table sets forth for each of our
executive officers the aggregate amount of the outstanding
principal and accrued interest as of December 31, 2006 and
as of April 23, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2006
|
|
|
As of April 23, 2007
|
|
|
Aggregate
|
|
|
|
|
Aggregate
|
|
|
|
|
principal
|
|
Accrued
|
|
|
principal
|
|
Accrued
|
Name of executive officer
|
|
amount
|
|
interest
|
|
|
amount
|
|
interest
|
|
Timothy A. Leach
|
|
$
|
2,392,665
|
|
$
|
224,953
|
|
|
$
|
2,392,665
|
|
$
|
268,091
|
Steven L. Beal
|
|
|
2,392,665
|
|
|
224,953
|
|
|
|
2,392,665
|
|
|
268,091
|
David W. Copeland
|
|
|
1,063,415
|
|
|
99,980
|
|
|
|
1,063,415
|
|
|
119,153
|
Curt F. Kamradt
|
|
|
1,063,415
|
|
|
99,978
|
|
|
|
1,063,415
|
|
|
119,151
|
David M. Thomas III
|
|
|
1,450,100
|
|
|
117,600
|
|
|
|
1,450,100
|
|
|
143,745
|
E. Joseph Wright
|
|
|
1,063,415
|
|
|
99,980
|
|
|
|
1,063,415
|
|
|
119,153
|
Escrow
agreement
In connection with the combination transaction,
430,755 shares of our common stock were deposited by
certain of our stockholders with an escrow agent subject to an
Escrow Agreement dated February 27, 2006. The escrow agent
has distributed the escrowed shares to the respective
119
registered owners that originally deposited the shares and the
Escrow Agreement has been terminated.
Wachovia Capital
Partners
Mr. Tabor, one of our directors, is a member of Wachovia Capital
Partners, the merchant banking arm of Wachovia Corporation. An
affiliate of Wachovia Capital Partners and Wachovia Corporation
is one of our stockholders but is not a selling stockholder in
this offering. Wachovia Bank, National Association, an affiliate
of Wachovia Corporation, is a lender under our revolving credit
facility.
Registration
rights agreement
Demand
registration rights
In connection with the combination transaction, we entered into
a registration rights agreement with our stockholders, including
the members of the Chase Group and the former stockholders of
Concho Equity Holdings Corp. According to the registration
rights agreement, holders of either 20% of the aggregate shares
held by the Chase Group or 20% of the aggregate shares held by
the former stockholders of Concho Equity Holdings Corp. may
request in writing that we register their shares by filing a
registration statement under the Securities Act, so long as the
anticipated aggregate offering price, net of underwriting
discounts and commissions, exceeds $50 million.
Piggy-back
registration rights
If we propose to file a registration statement under the
Securities Act relating to an offering of our common stock
(other than on a Form S-4 or a Form S-8), upon the written
request of holders of registrable securities, we will use our
commercially reasonable efforts to include in such registration,
and any related underwriting, all of the registrable securities
requested to be included, subject to customary cutback
provisions. There is no limit to the number of these
piggy-back registrations in which these holders may
request their shares to be included.
Registration
procedures and expenses
We generally will bear the registration expenses incurred in
connection with any registration, including all registration,
filing and qualification fees, printing and accounting fees, but
excluding underwriting discounts and commissions. We have agreed
to indemnify these stockholders against certain liabilities,
including liabilities under the Securities Act, in connection
with any registration effected under the registration rights
agreement. We are not obligated to effect any registration more
than one time in any six month period and these registration
rights terminate on August 7, 2017.
120
Description
of capital stock
The following summary of the capital stock and amended and
restated certificate of incorporation and by-laws of Concho
Resources Inc. does not purport to be complete and is qualified
in its entirety by reference to the provisions of applicable law
and to our amended and restated certificate of incorporation and
by-laws, forms of which are filed as exhibits to the
registration statement of which this prospectus is a part.
The authorized capital stock of Concho Resources Inc. consists
of 300,000,000 shares of common stock, $.001 par value
per share, and 10,000,000 shares of preferred stock,
$.001 par value per share.
Common
stock
As of November 20, 2007, we had 75,833,972 shares of
voting common stock outstanding, including 373,211 shares
of restricted stock. The shares of restricted stock have voting
rights, rights to receive dividends and are subject to certain
forfeiture restrictions. As of November 20, 2007, there
were 142 holders of our common stock.
Holders of our common stock will be entitled to one vote for
each share held on all matters submitted to a vote of
stockholders and do not have cumulative voting rights.
Accordingly, holders of a majority of the shares of our common
stock entitled to vote in any election of directors may elect
all of the directors standing for election.
Holders of our common stock are entitled to receive
proportionately any dividends if and when such dividends are
declared by our board of directors, subject to any preferential
dividend rights of preferred stock that may be outstanding at
the time such dividends are declared. Upon the liquidation,
dissolution or winding up of our company, the holders of our
common stock are entitled to receive ratably our net assets
available after the payment of all debts and other liabilities
and subject to the prior rights of any outstanding preferred
stock. Holders of our common stock have no preemptive,
subscription, redemption or conversion rights. The rights,
preferences and privileges of holders of our common stock are
subject to, and may be adversely affected by, the rights of the
holders of shares of any series of preferred stock that we may
designate and issue in the future.
There are no redemption or sinking fund provisions applicable to
our common stock. All outstanding shares of our common stock are
fully paid and non-assessable.
Our common stock is listed on the NYSE under the symbol
CXO.
Preferred
stock
Under the terms of our amended and restated certificate of
incorporation, our board of directors will be authorized to
designate and issue shares of preferred stock in one or more
series without further vote or action by our shareholders. Our
board of directors has the discretion to determine the rights,
preferences, privileges and restrictions, including voting
rights, dividend rights, conversion rights, redemption
privileges and liquidation preferences, of each series of
preferred stock. It is not possible to state the actual effect
of the issuance of any shares of preferred stock upon the rights
of holders of the common stock until the board of directors
determines the specific rights of the holders of the preferred
stock. However, these effects might include:
|
|
|
|
|
restricting dividends on the common stock;
|
121
|
|
|
|
|
diluting the voting power of the common stock;
|
|
|
impairing the liquidation rights of the common stock; and
|
|
|
delaying or preventing a change in control of our company.
|
We currently have no shares of preferred stock outstanding and
we have no present plans to issue any shares of preferred stock.
Anti-takeover
provisions of our certificate of incorporation and
bylaws
Our certificate of incorporation and bylaws contain several
provisions that could delay or make more difficult the
acquisition of us through a hostile tender offer, open market
purchases, proxy contest, merger or other takeover attempt that
a stockholder might consider in his or her best interest,
including those attempts that might result in a premium over the
market price of our common stock.
Written consent
of stockholders
Our certificate of incorporation and bylaws provide that any
action required or permitted to be taken by our stockholders
must be taken at a duly called meeting of stockholders and not
by written consent.
Special meetings
of stockholders
Subject to the rights of the holders of any series of preferred
stock, our bylaws provide that special meetings of the
stockholders may only be called by the chairman of the board of
directors or by the resolution of our board of directors
approved by a majority of the total number of authorized
directors. No business other than that stated in our notice may
be transacted at any special meeting.
Advance notice
procedure for director nominations and stockholder
proposals
Our bylaws provide that adequate notice must be given to
nominate candidates for election as directors or to make
proposals for consideration at annual meetings of our
stockholders. For nominations or other business to be properly
brought before an annual meeting by a stockholder, the
stockholder must have delivered a written notice to the
Secretary of our company at our principal executive offices not
less than 45 calendar days nor more than 75 calendar
days prior to the first anniversary of the date on which we
first mailed our proxy materials for the preceding years
annual meeting; provided, however, that in the event that the
date of the annual meeting is more than 30 calendar days
before or more than 30 calendar days after the first
anniversary of the date of the preceding years annual
meeting, notice by the stockholder to be timely must be so
delivered not later than the close of business on the later of
the 90th calendar day prior to such annual meeting or the
10th calendar day following the calendar day on which
public announcement, if any, of the date of such meeting is
first made by us.
Nominations of persons for election to our board of directors
may be made at a special meeting of stockholders at which
directors are to be elected pursuant to our notice of meeting
(i) by or at the direction of our board of directors, or
(ii) by any stockholder of our company who is a stockholder
of record at the time of the giving of notice of the meeting,
who is entitled to vote at the meeting and who complies with the
notice procedures set forth in our bylaws. In the event we call
a special meeting of stockholders for the purpose of electing
one or more
122
directors to our board of directors, any stockholder may
nominate a person or persons (as the case may be) for election
to such position(s) if the stockholder provides written notice
to the Secretary of our company at our principal executive
offices not earlier than the close of business on the
120th calendar day prior to such special meeting, nor later
than the close of business on the later of the
90th calendar day prior to such special meeting or the
10th calendar day following the day on which public
announcement, if any, is first made of the date of the special
meeting and of the nominees proposed by our board of directors
to be elected at such meeting.
These procedures may operate to limit the ability of
stockholders to bring business before a stockholders meeting,
including the nomination of directors and the consideration of
any transaction that could result in a change in control and
that may result in a premium to our stockholders.
Classified
board
Our certificate of incorporation divides our directors into
three classes serving staggered three-year terms. As a result,
stockholders will elect approximately one-third of the board of
directors each year. This provision, when coupled with the
provision of our restated certificate of incorporation
authorizing only the board of directors to fill vacant or newly
created directorships or increase the size of the board of
directors and the provision providing that directors may only be
removed for cause and then only by the holders of not less than
662/3%
of the voting power of all outstanding voting stock, may deter a
stockholder from gaining control of our board of directors by
removing incumbent directors or increasing the number of
directorships and simultaneously filling the vacancies or newly
created directorships with its own nominees.
Authorized
capital stock
Our certificate of incorporation contains provisions that the
authorized but unissued shares of common stock and preferred
stock are available for future issuance without shareholder
approval, subject to various limitations imposed by the New York
Stock Exchange. These additional shares may be utilized for a
variety of corporate purposes, including future public offerings
to raise additional capital, corporate acquisitions and employee
benefit plans. The existence of authorized but unissued shares
of common stock and preferred stock could make it more difficult
or discourage an attempt to obtain control of our company by
means of a proxy contest, tender offer, merger or otherwise.
Amendment of the
Bylaws
Under Delaware law, the power to adopt, amend or repeal bylaws
is conferred upon the stockholders. A corporation may, however,
in its certificate of incorporation also confer upon the board
of directors the power to adopt, amend or repeal its bylaws. Our
certificate of incorporation and bylaws grant our board the
power to adopt, amend and repeal our bylaws on the affirmative
vote of a majority of the directors then in office. Our
stockholders may adopt, amend or repeal our bylaws but only at
any regular or special meeting of stockholders by the holders of
not less than
662/3%
of the voting power of all outstanding voting stock.
123
Renouncement of
business opportunities
Certain of our stockholders, as well as members of our board of
directors other than Messrs. Leach and Beal, who received
shares of common stock in the combination transaction may from
time to time have investments in other exploration and
production companies that may compete with us. Our certificate
of incorporation and our Business Opportunities Agreement
provide that so long as any of the parties to the Business
Opportunities Agreement, which we refer to as the
Designated Parties, is serving as a member of our
board of directors, we renounce any interest or expectancy in
any business opportunity, transaction or other matter in and
that involves any aspect of the oil and gas exploration,
exploitation, development and production business, other than:
|
|
|
any business opportunity that is brought to the attention of a
Designated Party solely in such persons capacity as a
director or officer of our company and with respect to which, at
the time of such presentment, no other Designated Party has
independently received notice or otherwise identified such
opportunity; or
|
|
|
any business opportunity that is identified by a Designated
Party solely through the disclosure of information by or on
behalf of us.
|
Thus, for example, a Designated Party may pursue opportunities
in the oil and gas exploration and production industry for their
own account. Our certificate of incorporation provides that the
Designated Parties have no obligation to offer such
opportunities to us. We are not prohibited from pursuing any
business opportunity with respect to which we have renounced any
interest.
Limitation of
liability of directors
Our certificate of incorporation provides that no director shall
be personally liable to us or our stockholders for monetary
damages for breach of fiduciary duty as a director, except for
liability as follows:
|
|
|
for any breach of the directors duty of loyalty to us or
our stockholders;
|
|
|
for acts or omissions not in good faith or which involve
intentional misconduct or a knowing violation of laws;
|
|
|
for unlawful payment of a dividend or unlawful stock purchase or
stock redemption; and
|
|
|
for any transaction from which the director derived an improper
personal benefit.
|
The effect of these provisions is to eliminate our rights and
our stockholders rights, through stockholders
derivative suits on our behalf, to recover monetary damages
against a director for a breach of fiduciary duty as a director,
including breaches resulting from grossly negligent behavior,
except in the situations described above.
124
Delaware takeover
statute
We are subject to Section 203 of the Delaware General
Corporation Law, which prohibits a Delaware corporation from
engaging in any business combination with any interested
stockholder for a period of three years after the date that such
stockholder became an interested stockholder, with the following
exceptions:
|
|
|
before such date, the board of directors of the corporation
approved either the business combination or the transaction that
resulted in the stockholder becoming an interested holder;
|
|
|
upon completion of the transaction that resulted in the
stockholder becoming an interested stockholder, the interested
stockholder owned at least 85% of the voting stock of the
corporation outstanding at the time the transaction began,
excluding for purposes of determining the voting stock
outstanding (but not the outstanding voting stock owned by the
interested stockholder) those shares owned (1) by persons
who are directors and also officers and (2) employee stock
plans in which employee participants do not have the right to
determine confidentially whether shares held subject to the plan
will be tendered in a tender or exchange offer; or
|
|
|
on or after such date, the business combination is approved by
the board of directors and authorized at an annual or special
meeting of the stockholders, and not by written consent, by the
affirmative vote of at least
662/3%
of the outstanding voting stock that is not owned by the
interested stockholder.
|
In general, Section 203 defines business combination to
include the following:
|
|
|
any merger or consolidation involving the corporation and the
interested stockholder;
|
|
|
any sale, transfer, pledge or other disposition (in one
transaction or a series of transactions) of 10% or more of the
assets of the corporation involving the interested stockholder;
|
|
|
subject to certain exceptions, any transaction that results in
the issuance or transfer by the corporation of any stock of the
corporation to the interested stockholder;
|
|
|
any transaction involving the corporation that has the effect of
increasing the proportionate share of the stock or any class or
series of the corporation beneficially owned by the interested
stockholder; or
|
|
|
the receipt by the interested stockholder of the benefit of any
loss, advances, guarantees, pledges or other financial benefits
by or through the corporation.
|
125
In general, Section 203 defines an interested
stockholder as an entity or person who, together with the
persons affiliates and associates, beneficially owns, or
within three years prior to the time of determination of
interested stockholder status did own, 15% or more of the
outstanding voting stock of the corporation.
Registration
rights
In connection with the closing of the combination transaction,
we entered into a registration rights agreement with our
principal stockholders covering all of the shares of common
stock owned by our principal stockholders. For a description of
the registration rights agreement, see Certain
relationships and related party transactionsRegistration
rights agreement.
Transfer agent
and registrar
The transfer agent and registrar for our common stock is
American Stock Transfer & Trust Company.
126
Material
U.S. federal tax consequences for
non-U.S. holders
of our common stock
The following is a general discussion of the material
U.S. federal income and estate tax consequences to
non-U.S. Holders
with respect to the acquisition, ownership and disposition of
our common stock. A
Non-U.S. Holder
for purposes of this discussion is any beneficial owner of our
common stock who acquires such stock for cash pursuant to the
terms of this prospectus and who is not:
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an individual citizen or resident of the United States,
including an alien individual who is a lawful permanent resident
of the United States or meets the substantial
presence test under section 7701(b)(3) of the
Internal Revenue Code of 1986, as amended (the Code);
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a corporation (or an entity treated as a corporation for
U.S. federal income tax purposes) created or organized in
the United States or under the laws of the United States, any
state thereof, or the District of Columbia;
|
|
|
a partnership (or an entity treated as a partnership for
U.S. federal income tax purposes);
|
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|
an estate, the income of which is subject to U.S. federal
income tax regardless of its source; or
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a trust, if a U.S. court can exercise primary supervision
over the administration of the trust and one or more
U.S. persons can control all substantial decisions of the
trust, or certain other trusts that have a valid election to be
treated as a U.S. person pursuant to the applicable
Treasury Regulations.
|
This discussion is based on current provisions of the Code,
final, temporary and proposed Treasury Regulations, judicial
opinions, published positions of the Internal Revenue Service
(the IRS) and all other applicable administrative
and judicial authorities, all of which are subject to change,
possibly with retroactive effect. This discussion does not
address all aspects of U.S. federal income and estate
taxation or any aspects of state, local, or
non-U.S. taxation,
nor does it consider any specific facts or circumstances that
may apply to particular
Non-U.S. Holders
that may be subject to special treatment under the
U.S. federal income tax laws including, but not limited to,
insurance companies, persons holding our common stock as part of
a hedging or conversion transaction or a straddle or other
risk-reduction transaction, tax-exempt organizations,
pass-through entities, banks or financial institutions, brokers,
dealers in securities, and U.S. expatriates. If a
partnership or other entity treated as a partnership for
U.S. federal income tax purposes is a beneficial owner of
our common stock, the tax treatment of a partner in the
partnership will generally depend upon the status of the partner
and the activities of the partnership. This discussion assumes
that the
Non-U.S. Holder
will hold our common stock as a capital asset, which generally
is property held for investment.
Prospective investors are urged to consult their tax advisors
regarding the U.S. federal, state and local, and
non-U.S. income
and other tax considerations of acquiring, holding and disposing
of shares of common stock.
127
Dividends
We do not anticipate paying any dividends on our common stock.
Nonetheless, if any such dividends were paid, we would be
required to withhold tax from the amount of any dividend paid to
a
Non-U.S. Holder
to the extent paid out of our current or accumulated earnings
and profits, as determined under U.S. federal income tax
principles equal to 30% of the gross amount of the dividend, or
a lower rate prescribed by an applicable income tax treaty,
unless the dividend is effectively connected with a trade or
business carried on by the
Non-U.S. Holder
within the United States. In addition, because we expect to be a
United States real property holding corporation as
defined below, we may be required to withhold tax from the
amount of any dividend paid to a Non-U.S. Holder even to the
extent the amount thereof exceeds our current and accumulated
earnings and profits. Under applicable Treasury regulations, a
Non-U.S. Holder
will be required to satisfy certain certification requirements,
generally on IRS
Form W-8BEN,
or any successor form, directly or through an intermediary, in
order to claim a reduced rate of withholding under an applicable
income tax treaty. If tax is withheld in an amount in excess of
the amount applicable under an income tax treaty, a refund of
the excess amount may generally be obtained by filing an
appropriate claim for refund with the IRS.
Dividends that are effectively connected with a U.S. trade
or business (and, where an income tax treaty applies, are
attributable to a U.S. permanent establishment of the
Non-U.S. Holder)
generally will not be subject to U.S. withholding tax if
the
Non-U.S. Holder
files the properly completed required forms, such as IRS
Form W-8ECI,
or any successor form, with the payor of the dividend, but
instead generally will be subject to U.S. federal income
tax on a net income basis in the same manner as if the
Non-U.S. Holder
were a resident of the United States unless an income tax treaty
provides otherwise. A corporate
Non-U.S. Holder
that receives effectively connected dividends may be subject to
an additional branch profits tax at a rate of 30%, or a lower
rate prescribed by an applicable income tax treaty, on its
effectively connected earnings and profits, subject
to adjustments.
Gain on sale or
other disposition of common stock
In general, a
Non-U.S. Holder
will not be subject to U.S. federal income tax on any gain
realized upon the sale or other taxable disposition of the
Non-U.S. Holders shares of common stock unless:
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the gain is effectively connected with a trade or business
carried on by the
Non-U.S. Holder
within the United States (and, where an income tax treaty
applies, is attributable to a U.S. permanent establishment
of the
Non-U.S. Holder);
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|
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the
Non-U.S. Holder
is an individual who is present in the United States for
183 days or more in the taxable year of disposition and
certain other conditions are met; or
|
|
|
we are or have been a United States real property holding
corporation for U.S. federal income tax purposes and,
provided our common stock is regularly traded on an established
securities market, the Non-U.S. Holder holds or has held more
than five percent of our common stock during specified periods
as described below.
|
Except as set forth in the next paragraph, a
Non-U.S. Holder
who recognizes gain from the disposition of our common stock
meeting the description set forth in the first or third bullet
point above generally will be subject to tax on a net basis
under regular graduated U.S. federal income tax rates and,
if a
Non-U.S. Holder
described in the first bullet point is a corporation, it
128
may also be subject to the branch profits tax discussed above. A
Non-U.S. Holder
described in the second bullet point above will be subject to a
30% tax on the gain derived from the sale, which may be offset
by U.S. source capital losses.
Because of the oil and natural gas properties and other real
property assets we own, we expect that we are and will remain a
United States real property holding corporation. The
determination of whether we are a United States real property
holding corporation at any given point in time, however, is fact
specific and depends on the composition of our assets at that
time. Generally, a corporation is a United States real property
holding corporation if the fair market value of its United
States real property interests, as defined in the Internal
Revenue Code and applicable regulations, equals or exceeds 50%
of the aggregate fair market value of its worldwide real
property interests and its other assets used or held for use in
a trade or business. Even if we are or have been a United States
real property holding corporation, provided our common stock is
regularly traded on an established securities market (such as
the New York Stock Exchange), a
Non-U.S. Holder
will not be subject to U.S. federal income tax on the
disposition of our common stock unless such holder (actually or
constructively) holds or held (at anytime during the shorter of
the five year period preceding the date of disposition or the
holders entire holding period) more than five percent of
our common stock. If our common stock is not so regularly
traded, all
Non-U.S. Holders
would be subject to U.S. federal income tax on disposition
of our common stock in the event we are or have been during
relevant times a United States real property holding corporation.
You are encouraged to consult your own tax advisor regarding our
status as a United States real property holding corporation and
its possible consequences in your particular circumstances.
Information
reporting and backup withholding
Generally, we must report annually to the IRS the amount of
dividends paid, the name and address of the recipient, and the
amount, if any, of tax withheld. A similar report is sent to the
recipient. These information reporting requirements apply even
if withholding was not required because the dividends were
effectively connected dividends or withholding was reduced by an
applicable income tax treaty. Under income tax treaties or other
agreements, the IRS may make its reports available to tax
authorities in the recipients country of residence. In
addition, dividends we pay generally will be subject to backup
withholding, currently at a rate of 28% of the gross proceeds,
unless the recipient certifies as to its
non-U.S. status,
which certification generally may be made on IRS
Form W-8BEN,
or otherwise establishes an exemption.
Proceeds from the disposition of common stock effected by or
through a U.S. office of a broker will be subject to
information reporting and backup withholding unless the person
making the disposition certifies as to its
non-U.S. status
or otherwise establishes an exemption. Generally,
U.S. information reporting and backup withholding will not
apply to a payment of disposition proceeds if the transaction is
effected outside the United States by or through a
non-U.S. office.
However, exceptions apply in the event the broker has certain
connections to the United States.
Backup withholding is not an additional tax. Rather, the amount
withheld is applied as a credit to the U.S. federal income
tax liability of persons subject to backup withholding. If
backup withholding results in an overpayment of
U.S. federal income taxes, a refund may be obtained,
provided the required documents are timely filed with the IRS.
129
Estate
tax
Our common stock owned or treated as owned by an individual who
is not a citizen or resident of the United States (as
specifically defined for U.S. federal estate tax purposes)
at the time of death will be includible in the individuals
gross estate for U.S. federal estate tax purposes, unless
an applicable estate tax treaty provides otherwise.
The preceding discussion of material U.S. federal income and
estate tax considerations for non-U.S. holders of our common
stock is for general information only and should not be
considered tax advice. Each prospective investor should consult
its own tax advisor regarding the particular U.S. federal,
state, local and non-U.S. tax consequences of acquisition,
ownership and disposition of our common stock, including the
consequences of any proposed change in applicable laws.
130
J.P. Morgan Securities Inc. and Banc of America Securities
LLC are acting as joint book-runners for this offering.
We, the selling stockholders and the underwriters named below
have entered into an underwriting agreement covering the common
stock to be sold in this offering. Each underwriter has
severally agreed to purchase, and the selling stockholders have
agreed to sell to each underwriter, the number of shares of
common stock set forth opposite its name in the following table.
|
|
|
|
|
Name
|
|
Number of shares
|
|
|
J.P. Morgan Securities Inc.
|
|
|
|
Banc of America Securities LLC
|
|
|
|
Lehman Brothers Inc.
|
|
|
|
BNP Paribas Securities Corp.
|
|
|
|
Merrill Lynch, Pierce, Fenner & Smith
Incorporated
|
|
|
|
UBS Securities LLC
|
|
|
|
Wachovia Capital Markets, LLC
|
|
|
|
|
|
|
|
Total
|
|
|
8,700,000
|
|
|
|
|
|
|
The underwriting agreement provides that if the underwriters
take any of the shares presented in the table above, then they
must take all of the shares. No underwriter is obligated to take
any shares allocated to a defaulting underwriter except under
limited circumstances. The underwriting agreement provides that
the obligations of the underwriters are subject to certain
conditions precedent, including the absence of any material
adverse change in our business and the receipt of certain
certificates, opinions and letters from us, our counsel, each
selling stockholder and our independent auditors.
The underwriters are offering the shares of common stock,
subject to the prior sale of shares, and when, as and if such
shares are delivered to and accepted by them. The underwriters
will initially offer to sell shares to the public at the initial
public offering price shown on the front cover page of this
prospectus. The underwriters may sell shares to securities
dealers at a discount of up to
$ per share from the initial
public offering price. Any such securities dealers may resell
shares to certain other brokers or dealers at a discount of up
to $ per share from the
initial public offering price. After the initial public
offering, the underwriters may vary the public offering price
and other selling terms.
If the underwriters sell more shares than the total number shown
in the table above, the underwriters have the option to buy from
Chase Oil Corporation up to an additional 1,305,000 shares
of common stock. They may exercise this option during the
30-day
period from the date of this prospectus. If any shares are
purchased under this option, the underwriters will purchase
shares in approximately the same proportion as shown in the
table above. If any additional shares of common stock are
purchased, the underwriters will offer the additional shares on
the same terms as those on which the shares are being offered.
131
The following table shows the per share and total underwriting
discounts that the selling stockholders will pay to the
underwriters. These amounts are shown assuming both no exercise
and full exercise of the underwriters option to purchase
additional shares.
|
|
|
|
|
|
|
|
|
|
|
|
|
Without
|
|
|
With full
|
|
|
|
overallotment
|
|
|
overallotment
|
|
|
|
exercise
|
|
|
exercise
|
|
|
|
|
Per share
|
|
$
|
|
|
|
$
|
|
|
Total
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
The underwriters have advised us that they may make short sales
of our common stock in connection with this offering, resulting
in the sale by the underwriters of a greater number of shares
than they are required to purchase pursuant to the underwriting
agreement. The short position resulting from those short sales
will be deemed a covered short position to the
extent that it does not exceed the shares subject to the
underwriters overallotment option and will be deemed a
naked short position to the extent that it exceeds
that number. A naked short position is more likely to be created
if the underwriters are concerned that there may be downward
pressure on the trading price of the common stock in the open
market that could adversely affect investors who purchase shares
in this offering. The underwriters may reduce or close out their
covered short position either by exercising the overallotment
option or by purchasing shares in the open market. In
determining which of these alternatives to pursue, the
underwriters will consider the price at which shares are
available for purchase in the open market as compared to the
price at which they may purchase shares through the
overallotment option. Any naked short position will
be closed out by purchasing shares in the open market. Similar
to the other stabilizing transactions described below, open
market purchases made by the underwriters to cover all or a
portion of their short position may have the effect of
preventing or retarding a decline in the market price of our
common stock following this offering. As a result, our common
stock may trade at a price that is higher than the price that
otherwise might prevail in the open market.
The underwriters have advised us that, pursuant to
Regulation M under the Securities Exchange Act of 1934,
they may engage in transactions, including stabilizing bids or
the imposition of penalty bids, that may have the effect of
stabilizing or maintaining the market price of the shares of
common stock at a level above that which might otherwise prevail
in the open market. A stabilizing bid is a bid for
or the purchase of shares of common stock on behalf of the
underwriters for the purpose of fixing or maintaining the price
of the common stock. A penalty bid is an arrangement
permitting the underwriters to claim the selling concession
otherwise accruing to an underwriter or syndicate member in
connection with the offering if the common stock originally sold
by that underwriter or syndicate member is purchased by the
underwriters in the open market pursuant to a stabilizing bid or
to cover all or part of a syndicate short position. The
underwriters have advised us that stabilizing bids and open
market purchases may be effected on the New York Stock Exchange,
in the
over-the-counter
market or otherwise and, if commenced, may be discontinued at
any time.
One or more of the underwriters may facilitate the marketing of
this offering online directly or through one of its affiliates.
In those cases, prospective investors may view offering terms
and a prospectus online and, depending upon the particular
underwriter, place orders online or through their financial
advisor.
132
We estimate that our total expenses for this offering, excluding
underwriting discounts, will be approximately $900,000.
We and the selling stockholders have agreed to indemnify the
underwriters against certain liabilities, including liabilities
under the Securities Act.
We, our executive officers and directors, the selling
stockholders and certain affiliates of one of our outside
directors have agreed that, during the period beginning from the
date of this prospectus and continuing to and including the date
90 days after the date of this prospectus, none of us or
them will, directly or indirectly, offer, sell, offer to sell,
contract to sell or otherwise dispose of any shares of our
common stock without the prior written consent of
J.P. Morgan Securities Inc. and Banc of America Securities
LLC, except in limited circumstances. The foregoing limitations
will not apply to any shares of our common stock acquired by
such persons in the open market following the completion of this
offering.
In the event that (1) during the last 17 days of the
90-day
restricted period, we issue an earnings release or material news
or a material event relating to our company occurs; or
(2) prior to the expiration of the
90-day
restricted period, we announce that we will release earnings
results during the
16-day
period beginning on the last day of the
90-day
period, the restrictions described above will continue to apply
until the expiration of the
18-day
period beginning on the issuance of the earnings release or the
occurrence of the material news or material event. In no event,
however, will the restrictions described above continue more
than 124 days after the date of this prospectus.
J.P. Morgan Securities Inc. and Banc of America Securities
LLC have no present intent or understanding to release all or
any portion of the securities subject to these agreements.
We may issue shares of common stock or securities convertible
into or exchangeable or exercisable for shares of common stock
for the benefit of our employees, directors and officers under
benefit plans described in this prospectus.
Our common stock is listed on the New York Stock Exchange under
the symbol CXO.
From time to time in the ordinary course of their respective
businesses, certain of the underwriters and their affiliates
perform various financial advisory, investment banking and
commercial banking services from time to time for us and our
affiliates. For example, certain affiliates of the underwriters
to this offering are lenders under our bank credit facilities.
JPMorgan Chase Bank, N.A., an affiliate of J.P. Morgan
Securities Inc., is the administrative agent, collateral agent
and a lender under our revolving credit facility. In addition,
Banc of America Securities LLC, BNP Paribas Securities Corp. and
Wachovia Capital Markets, LLC each has an affiliate that is a
lender
and/or agent
under our revolving credit facility. In addition, Banc of
America Securities LLC served as the lead arranger and book
manager of our second lien term loan facility and each of
BNP Paribas Securities Corp. and Merrill Lynch, Pierce,
Fenner & Smith Incorporated has an affiliate that is a
lender under our second lien term loan facility.
Because more than 10% of the net proceeds of this offering are
being paid to an affiliate of J.P. Morgan Securities Inc.,
the offering is being conducted in accordance with
Rule 2710 of the NASD Conduct Rules of the Financial
Industry Regulatory Authority, Inc.
133
The validity of our shares of common stock offered by this
prospectus will be passed upon for us by Vinson &
Elkins L.L.P., Houston, Texas. Certain legal matters in
connection with this offering will be passed upon for Chase Oil
Corporation and Caza Energy LLC by Bracewell &
Giuliani LLP, Houston, Texas. Legal matters in connection with
this offering will be passed upon for the underwriters by Cahill
Gordon &
Reindel llp,
New York, New York.
The audited financial statements of Concho Resources Inc., the
Chase Group Properties and the Lowe Properties included in this
registration statement have been audited by Grant
Thornton LLP, independent registered public accountants, as
indicated in their reports with respect thereto, and are
included herein in reliance upon the authority of said firm as
experts in giving said reports.
Independent
petroleum engineers
Certain estimates of our net oil and natural gas reserves and
related information as of December 31, 2006, included in
this prospectus have been derived from engineering reports
prepared by Netherland, Sewell & Associates, Inc. and
Cawley, Gillespie & Associates, Inc. All such
information has been so included on the authority of such firms
as experts regarding the matters contained in their reports.
Where
you can find more information
We have filed with the SEC a registration statement on
Form S-1,
including exhibits, under the Securities Act with respect to the
common stock to be sold in this offering. This prospectus, which
constitutes a part of the registration statement, does not
contain all of the information set forth in the registration
statement or the exhibits that are part of the registration
statement. For further information about us and our common
stock, you should refer to the registration statement. Any
statements made in this prospectus as to the contents of any
contract, agreement or other document are not necessarily
complete. With respect to each such contract, agreement or other
document filed as an exhibit to the registration statement, you
should refer to the exhibit for a more complete description of
the matter involved, and each statement in this prospectus shall
be deemed qualified in its entirety by this reference.
You may read, without charge, and copy, at prescribed rates, all
or any portion of the registration statement or any reports,
statements or other information in the files at the public
reference facilities of the SECs principal office at 100 F
Street, N.E., Washington, D.C., 20549. You can request
copies of these documents upon payment of a duplicating fee by
writing to the SEC. You may call the SEC at
1-800-SEC-0330
for further information on the operation of its public reference
rooms. Our filings, including the registration statement, will
also be available to you on the Internet web site maintained by
the SEC at http://www.sec.gov.
We file with or furnish to the SEC periodic reports and other
information. These reports and other information may be
inspected and copied at the public reference facilities
maintained by the SEC or obtained from the SECs website as
provided above. Our website on the Internet is
134
located at http://www.conchoresources.com, and we make
our periodic reports and other information filed with or
furnished to the SEC available, free of charge, through our
website, as soon as reasonably practicable after those reports
and other information are electronically filed with or furnished
to the SEC. Information on our website or any other website is
not incorporated by reference into this prospectus and does not
constitute a part of this prospectus. You may also request a
copy of these filings at no cost, by writing or telephoning us
at the following address: Concho Resources Inc., 550 West
Texas Avenue, Suite 1300, Midland, Texas 79701,
(432) 683-7443.
We intend to furnish or make available to our stockholders
annual reports containing our audited financial statements
prepared in accordance with GAAP. We also intend to furnish or
make available to our stockholders quarterly reports containing
our unaudited interim financial information, including the
information required by
Form 10-Q,
for the first three fiscal quarters of each fiscal year.
135
The terms defined in this section are used throughout this
prospectus:
|
|
|
Bbl |
|
One stock tank barrel, of 42 U.S. gallons liquid volume,
used herein in reference to crude oil, condensate or natural gas
liquids. |
|
Bcfe |
|
One billion cubic feet of natural gas equivalent using the ratio
of one barrel of crude oil, condensate or natural gas liquids to
six Mcf of natural gas. |
|
Basin |
|
A large natural depression on the earths surface in which
sediments accumulate. |
|
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. |
|
Exploitation |
|
A drilling or other project which may target proven or unproven
reserves (such as probable or possible reserves), but which
generally is reasonably expected to have lower risk. |
|
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. |
|
Gross wells |
|
Are the number of wells in which a working interest is owned and
net wells are the total of our fractional working interests
owned in gross wells. |
|
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. |
|
MBbl |
|
One thousand barrels of crude oil, condensate or natural gas
liquids. |
|
Mcf |
|
One thousand cubic feet of natural gas. |
|
Mcfe |
|
One thousand cubic feet of natural gas equivalent. |
|
MMBbl |
|
One million barrels of crude oil, condensate or natural gas
liquids. |
|
MMBtu |
|
One million British thermal units. |
|
MMcf |
|
One million cubic feet of natural gas. |
|
MMcfe |
|
One million cubic feet of natural gas equivalent. |
|
NYMEX |
|
The New York Mercantile Exchange. |
136
|
|
|
Net acres |
|
The percentage of total acres an owner owns out of a particular
number of acres within a specified tract. An owner who has 50%
interest in 100 acres owns 50 net acres. |
|
Net revenue interest |
|
A working interest owners gross working interest in
production, less the related royalty, overriding royalty,
production payment, and net profits interests. |
|
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,
discounted to a present value using an annual discount rate of
10% in accordance with the guidelines of the SEC. |
|
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 gas
injection. |
|
Proved developed reserves |
|
Has the meaning given to such term in
Rule 4-10(a)(3)
of
Regulation S-X,
which defines proved developed reserves as: |
|
|
|
Proved developed oil and gas reserves are reserves that can be
expected to be recovered through existing wells with existing
equipment and operating methods. Additional oil and gas expected
to be obtained through the application of fluid injection or
other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as
proved developed reserves only after testing by a pilot project
or after the operation of an installed program has confirmed
through production response that increased recovery will be
achieved. |
|
Proved reserves |
|
Has the meaning given to such term in
Rule 4-10(a)(2)
of
Regulation S-X,
which defines proved reserves as: |
|
|
|
Proved oil and gas reserves are the estimated quantities of
crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future
conditions. |
|
|
|
(i) Reservoirs are considered proved if economic
producibility is supported by either actual production or
conclusive formation test. The area of a reservoir considered
proved includes (A) that portion delineated by drilling and
defined by gas-oil
and/or
oil-water contacts, if any, and (B) the immediately
adjoining
|
137
|
|
|
|
|
portions not yet drilled, but which can be reasonably judged as
economically productive on the basis of available geological and
engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir. |
|
|
|
(ii) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid
injection) are included in the proved classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
|
|
|
|
(iii) Estimates of proved reserves do not include the
following: (A) Oil that may become available from known
reservoirs but is classified separately as indicated additional
reserves; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt
because of uncertainty as to geology, reservoir characteristics,
or economic factors; (C) crude oil, natural gas, and
natural gas liquids, that may occur in undrilled prospects; and
(D) crude oil, natural gas, and natural gas liquids, that
may be recovered from oil shales, coal, gilsonite and other such
sources.
|
|
Proved undeveloped reserves |
|
Has the meaning given to such term in
Rule 4-10(a)(4)
of
Regulation S-X,
which defines proved undeveloped reserves as: |
|
|
|
Proved undeveloped oil and gas reserves are reserves that are
expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is
required for recompletion. Reserves on undrilled acreage shall
be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved
reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of
production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves
be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual
tests in the area and in the same reservoir. |
|
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. |
|
Secondary recovery |
|
The recovery of oil and gas through the injection of liquids or
gases into the reservoir, supplementing its natural energy.
Secondary |
138
|
|
|
|
|
recovery methods are often applied when production slows due to
depletion of the natural pressure. |
|
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%) of
estimated future net revenues to be generated from the
production of proved reserves net of estimated income taxes
associated with such net revenues, as determined in accordance
with Statement of Financial Accounting Standards No. 69
(using prices and costs in effect as of the period end date)
without giving effect to non-property related expenses such as
indirect general and administrative expenses, and debt service
or to depreciation, depletion and amortization. Standardized
measure does not give effect to derivative transactions. |
|
Step-out drilling |
|
The drilling of a well adjacent to existing production in an
effort to expand the aerial extent of a known producing field. |
|
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. |
|
Unit |
|
The joining of all or substantially all interests in a reservoir
or field, rather than single tracts, to provide for development
and operation without regard to separate property interests.
Also, the area covered by a unitization agreement. |
|
Wellbore |
|
The hole drilled by the bit that is equipped for oil or gas
production on a completed well. Also called well or borehole. |
|
Working interest |
|
The right granted to the lessee of a property to explore for and
to produce and own oil, gas, or other minerals. The working
interest owners bear the exploration, development, and operating
costs on either a cash, penalty, or carried basis. |
|
Workover |
|
Operations on a producing well to restore or increase production. |
139
Index
to financial statements
|
|
|
|
|
|
|
Page
|
|
Concho Resources Inc. (Historical):
|
|
|
|
|
|
|
|
F-2
|
|
|
|
|
F-3
|
|
|
|
|
F-4
|
|
|
|
|
F-5
|
|
|
|
|
F-7
|
|
|
|
|
F-9
|
|
|
|
|
|
|
Concho Resources Inc. (Pro-forma) (Unaudited):
|
|
|
|
|
|
|
|
F-68
|
|
|
|
|
F-69
|
|
|
|
|
F-71
|
|
|
|
|
|
|
Chase Group Properties:
|
|
|
|
|
|
|
|
F-73
|
|
|
|
|
F-74
|
|
|
|
|
|
|
|
|
|
F-75
|
|
|
|
|
F-76
|
|
|
|
|
F-77
|
|
|
|
|
F-78
|
|
|
|
|
|
|
Lowe Properties:
|
|
|
|
|
|
|
|
F-90
|
|
|
|
|
F-91
|
|
|
|
|
F-92
|
|
F-1
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,
formerly Concho Equity Holdings Corp., as of December 31,
2005 and 2006, and the related consolidated statements of
operations, stockholders equity and cash flows for the
period from inception (April 21, 2004) through
December 31, 2004, and for the years ended
December 31, 2005 and 2006. 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. The Company is not required to
have, nor were we engaged to perform an audit of its internal
control over financial reporting. Our audit included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purposes of expressing an opinion
on the effectiveness of the Companys internal control over
financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements, 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, 2005 and 2006, and the results of their
operations and their cash flows for the period from inception
(April 21, 2004) through December 31, 2004, and
for the years ended December 31, 2005 and 2006, in
conformity with accounting principles generally accepted in the
United States of America.
GRANT THORNTON LLP
Tulsa, Oklahoma
April 23, 2007 (except for the reverse stock split
disclosure in Note A and the effects thereof, as to which
the date is August 2, 2007)
F-2
Concho
Resources Inc. and subsidiaries consolidated balance
sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
September 30,
|
|
(in thousands, except share and per share data)
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
Assets
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
9,182
|
|
|
$
|
1,122
|
|
|
$
|
19,868
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas
|
|
|
14,040
|
|
|
|
27,304
|
|
|
|
24,793
|
|
Joint operations and other
|
|
|
11,890
|
|
|
|
22,638
|
|
|
|
16,027
|
|
Related parties
|
|
|
18,382
|
|
|
|
1,449
|
|
|
|
|
|
Derivative instruments
|
|
|
|
|
|
|
6,013
|
|
|
|
1,658
|
|
Deferred income taxes
|
|
|
3,006
|
|
|
|
82
|
|
|
|
3,625
|
|
Inventory
|
|
|
1,018
|
|
|
|
1,309
|
|
|
|
1,404
|
|
Prepaid insurance and other
|
|
|
1,674
|
|
|
|
3,848
|
|
|
|
3,618
|
|
|
|
|
|
|
|
Total current assets
|
|
|
59,192
|
|
|
|
63,765
|
|
|
|
70,993
|
|
|
|
|
|
|
|
Property and equipment, at cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, successful efforts method:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
157,787
|
|
|
|
1,159,756
|
|
|
|
1,266,890
|
|
Unproved properties
|
|
|
21,901
|
|
|
|
239,462
|
|
|
|
237,223
|
|
Accumulated depletion and depreciation
|
|
|
(14,336
|
)
|
|
|
(84,098
|
)
|
|
|
(142,981
|
)
|
|
|
|
|
|
|
Total oil and gas properties, net
|
|
|
165,352
|
|
|
|
1,315,120
|
|
|
|
1,361,132
|
|
Other property and equipment, net
|
|
|
5,231
|
|
|
|
5,535
|
|
|
|
6,894
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
170,583
|
|
|
|
1,320,655
|
|
|
|
1,368,026
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
|
1,898
|
|
|
|
|
|
|
|
|
|
Deferred loan costs, net
|
|
|
411
|
|
|
|
4,417
|
|
|
|
3,737
|
|
Other assets
|
|
|
301
|
|
|
|
1,235
|
|
|
|
751
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
232,385
|
|
|
$
|
1,390,072
|
|
|
$
|
1,443,507
|
|
|
|
|
|
|
|
Liabilities and stockholders equity
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
5,897
|
|
|
$
|
16,157
|
|
|
$
|
7,583
|
|
Related parties
|
|
|
|
|
|
|
3,593
|
|
|
|
2,941
|
|
Other current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue payable
|
|
|
7,529
|
|
|
|
9,901
|
|
|
|
4,576
|
|
Accrued drilling costs
|
|
|
10,493
|
|
|
|
17,051
|
|
|
|
27,633
|
|
Accrued interest
|
|
|
684
|
|
|
|
8,004
|
|
|
|
1,755
|
|
Other accrued liabilities
|
|
|
3,119
|
|
|
|
6,220
|
|
|
|
7,712
|
|
Derivative instruments
|
|
|
9,307
|
|
|
|
6,224
|
|
|
|
10,303
|
|
Dividends payable
|
|
|
1,410
|
|
|
|
87
|
|
|
|
|
|
Income taxes payable
|
|
|
|
|
|
|
|
|
|
|
225
|
|
Chase Group unaccredited investors asset purchase obligation
|
|
|
|
|
|
|
906
|
|
|
|
|
|
Contingent consideration
|
|
|
1,824
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt
|
|
|
|
|
|
|
400
|
|
|
|
2,000
|
|
Current asset retirement obligations
|
|
|
83
|
|
|
|
1,958
|
|
|
|
1,005
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
40,346
|
|
|
|
70,501
|
|
|
|
65,733
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
72,000
|
|
|
|
495,100
|
|
|
|
343,880
|
|
Noncurrent derivative instruments
|
|
|
8,865
|
|
|
|
|
|
|
|
1,514
|
|
Deferred income taxes
|
|
|
|
|
|
|
241,752
|
|
|
|
251,800
|
|
Asset retirement obligations and other long-term liabilities
|
|
|
1,504
|
|
|
|
7,563
|
|
|
|
7,196
|
|
Commitments and contingencies (Note K)
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Series A preferred stock, $0.01 par value;
30,000,000 shares authorized; 12,959,096 shares issued and
outstanding and 1,819,140 shares partially paid at
December 31, 2005, and zero shares issued and outstanding
at December 31, 2006 and September 30, 2007,
respectively (aggregate liquidation value $116,632 at
December 31, 2005)
|
|
|
130
|
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value; 10,000,000 shares authorized;
and zero shares issued and outstanding at December 31, 2005
and 2006 and September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock, $0.001 par value; 30,000,000, 300,000,000 and
300,000,000 shares authorized; 8,141,918 and 59,092,830 and
75,750,517 shares issued and outstanding at
December 31, 2005 and 2006 and September 30, 2007,
respectively; and 1,080,261 shares partially paid at
December 31, 2005, and zero shares partially paid at
December 31, 2006 and September 30, 2007, respectively
|
|
|
8
|
|
|
|
59
|
|
|
|
76
|
|
Additional paid-in capital
|
|
|
135,876
|
|
|
|
575,389
|
|
|
|
751,680
|
|
Notes receivable from officers and employees
|
|
|
(9,012
|
)
|
|
|
(12,858
|
)
|
|
|
(2,488
|
)
|
Retained earnings (accumulated deficit)
|
|
|
(6,272
|
)
|
|
|
12,152
|
|
|
|
30,609
|
|
Accumulated other comprehensive income (loss)
|
|
|
(11,060
|
)
|
|
|
414
|
|
|
|
(6,493
|
)
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
109,670
|
|
|
|
575,156
|
|
|
|
773,384
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
232,385
|
|
|
$
|
1,390,072
|
|
|
$
|
1,443,507
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these consolidated financial
statements.
F-3
Concho
Resources Inc. and subsidiaries
Consolidated statements of operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inception
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(April 21,
|
|
|
|
|
|
|
|
|
Nine months
|
|
|
|
2004) through
|
|
|
Year ended
|
|
|
ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
September 30,
|
|
(in thousands, except per share
amounts)
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
1,851
|
|
|
$
|
31,621
|
|
|
$
|
131,773
|
|
|
$
|
90,737
|
|
|
$
|
128,152
|
|
Natural gas sales
|
|
|
1,771
|
|
|
|
23,315
|
|
|
|
66,517
|
|
|
|
44,908
|
|
|
|
67,395
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
3,622
|
|
|
|
54,936
|
|
|
|
198,290
|
|
|
|
135,645
|
|
|
|
195,547
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
512
|
|
|
|
10,923
|
|
|
|
22,060
|
|
|
|
14,511
|
|
|
|
22,309
|
|
Oil and gas production taxes
|
|
|
234
|
|
|
|
3,712
|
|
|
|
15,762
|
|
|
|
10,831
|
|
|
|
15,616
|
|
Exploration and abandonments
|
|
|
1,850
|
|
|
|
2,666
|
|
|
|
5,612
|
|
|
|
4,717
|
|
|
|
18,110
|
|
Depreciation and depletion
|
|
|
956
|
|
|
|
11,485
|
|
|
|
60,722
|
|
|
|
42,170
|
|
|
|
55,036
|
|
Accretion of discount on asset retirement obligations
|
|
|
7
|
|
|
|
89
|
|
|
|
287
|
|
|
|
196
|
|
|
|
334
|
|
Impairments of proved oil and gas properties
|
|
|
|
|
|
|
2,295
|
|
|
|
9,891
|
|
|
|
5,762
|
|
|
|
4,577
|
|
Contract drilling fees stacked rigs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,269
|
|
General and administrative (Including non-cash stock-based
compensation of $1,128, $3,252, and $9,144 for the periods ended
December 31, 2004, 2005 and 2006, respectively, and $8,041
and $2,656 for the nine months ended September 30, 2006 and
2007, respectively)
|
|
|
4,214
|
|
|
|
11,307
|
|
|
|
21,721
|
|
|
|
16,044
|
|
|
|
16,567
|
|
Ineffective portion of cash flow hedges
|
|
|
|
|
|
|
1,148
|
|
|
|
(1,193
|
)
|
|
|
(64
|
)
|
|
|
1,134
|
|
(Gain) loss on derivatives not designated as hedges
|
|
|
(684
|
)
|
|
|
5,001
|
|
|
|
|
|
|
|
|
|
|
|
(3,088
|
)
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
7,089
|
|
|
|
48,626
|
|
|
|
134,862
|
|
|
|
94,167
|
|
|
|
134,864
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(3,467
|
)
|
|
|
6,310
|
|
|
|
63,428
|
|
|
|
41,478
|
|
|
|
60,683
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(272
|
)
|
|
|
(3,096
|
)
|
|
|
(30,567
|
)
|
|
|
(20,998
|
)
|
|
|
(29,803
|
)
|
Other, net
|
|
|
168
|
|
|
|
779
|
|
|
|
1,186
|
|
|
|
907
|
|
|
|
957
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(104
|
)
|
|
|
(2,317
|
)
|
|
|
(29,381
|
)
|
|
|
(20,091
|
)
|
|
|
(28,846
|
)
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(3,571
|
)
|
|
|
3,993
|
|
|
|
34,047
|
|
|
|
21,387
|
|
|
|
31,837
|
|
Income tax (expense) benefit
|
|
|
915
|
|
|
|
(2,039
|
)
|
|
|
(14,379
|
)
|
|
|
(8,664
|
)
|
|
|
(13,335
|
)
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(2,656
|
)
|
|
|
1,954
|
|
|
|
19,668
|
|
|
|
12,723
|
|
|
|
18,502
|
|
Preferred stock dividends
|
|
|
(804
|
)
|
|
|
(4,766
|
)
|
|
|
(1,244
|
)
|
|
|
(1,210
|
)
|
|
|
(45
|
)
|
Effect of induced conversion of preferred stock
|
|
|
|
|
|
|
|
|
|
|
11,601
|
|
|
|
11,601
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) applicable to common shareholders
|
|
$
|
(3,460
|
)
|
|
$
|
(2,812
|
)
|
|
$
|
30,025
|
|
|
$
|
23,114
|
|
|
$
|
18,457
|
|
|
|
|
|
|
|
Basic earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
|
|
$
|
(3.48
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
0.63
|
|
|
$
|
0.52
|
|
|
$
|
0.30
|
|
|
|
|
|
|
|
Shares used in basic earnings (loss) per share
|
|
|
994
|
|
|
|
4,059
|
|
|
|
47,287
|
|
|
|
44,710
|
|
|
|
60,648
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share
|
|
$
|
(3.48
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
0.59
|
|
|
$
|
0.48
|
|
|
$
|
0.29
|
|
|
|
|
|
|
|
Shares used in diluted earnings (loss) per share
|
|
|
994
|
|
|
|
4,059
|
|
|
|
50,729
|
|
|
|
47,937
|
|
|
|
62,858
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these consolidated financial
statements.
F-4
Concho
Resources Inc. and subsidiaries
Consolidated statements of stockholders equity
(Information and amounts subsequent to December 31, 2006
are unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
|
|
|
Retained
|
|
|
Accumulated
|
|
|
|
|
|
|
Series A
|
|
|
|
|
|
|
|
Additional
|
|
Receivable from
|
|
|
Earnings
|
|
|
Other
|
|
|
Total
|
|
|
|
Preferred Stock
|
|
|
Common Stock
|
|
Paid-in
|
|
Officers and
|
|
|
(Accumulated
|
|
|
Comprehensive
|
|
|
Stockholders
|
|
(in thousands)
|
|
Shares
|
|
|
Amount
|
|
|
Shares
|
|
|
Amount
|
|
Capital
|
|
Employees
|
|
|
Deficit)
|
|
|
Income (Loss)
|
|
|
Equity
|
|
|
|
|
BALANCE AT INCEPTION (APRIL 21, 2004)
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
$
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,656
|
)
|
|
|
|
|
|
|
(2,656
|
)
|
Deferred hedge gains, net of tax of $19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33
|
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,623
|
)
|
Issuance of subscribed units
|
|
|
7,689
|
|
|
|
77
|
|
|
|
3,844
|
|
|
|
4
|
|
|
76,806
|
|
|
(3,840
|
)
|
|
|
|
|
|
|
|
|
|
|
73,047
|
|
Issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
1,006
|
|
|
|
1
|
|
|
1,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,006
|
|
Stock-based compensation for stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
178
|
|
Stock-based compensation on issuance of units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
950
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
950
|
|
Accrued interestofficer & employee notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(44
|
)
|
|
|
|
|
|
|
|
|
|
|
(44
|
)
|
6% Series A Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(804
|
)
|
|
|
|
|
|
|
(804
|
)
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2004
|
|
|
7,689
|
|
|
$
|
77
|
|
|
|
4,850
|
|
|
$
|
5
|
|
$
|
78,939
|
|
$
|
(3,884
|
)
|
|
$
|
(3,460
|
)
|
|
$
|
33
|
|
|
$
|
71,710
|
|
Comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,954
|
|
|
|
|
|
|
|
1,954
|
|
Deferred hedge losses, net of tax of ($6,550)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,147
|
)
|
|
|
(12,147
|
)
|
Net settlement losses included in earnings, net of taxes of $568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,054
|
|
|
|
1,054
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,139
|
)
|
Issuance of subscribed units
|
|
|
5,270
|
|
|
|
53
|
|
|
|
2,635
|
|
|
|
2
|
|
|
53,029
|
|
|
(4,805
|
)
|
|
|
|
|
|
|
|
|
|
|
48,279
|
|
Issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
657
|
|
|
|
1
|
|
|
656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
657
|
|
Stock-based compensation for stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,506
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,506
|
|
Stock-based compensation on issuance of units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,746
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,746
|
|
Accrued interestofficer & employee notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(323
|
)
|
|
|
|
|
|
|
|
|
|
|
(323
|
)
|
6% Series A Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,766
|
)
|
|
|
|
|
|
|
(4,766
|
)
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2005
|
|
|
12,959
|
|
|
$
|
130
|
|
|
|
8,142
|
|
|
$
|
8
|
|
$
|
135,876
|
|
$
|
(9,012
|
)
|
|
$
|
(6,272
|
)
|
|
$
|
(11,060
|
)
|
|
$
|
109,670
|
|
Comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,668
|
|
|
|
|
|
|
|
19,668
|
|
Deferred hedge gains, net of tax of $4,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,736
|
|
|
|
7,736
|
|
Net settlement losses included in earnings, net of taxes of
$2,030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,738
|
|
|
|
3,738
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31,142
|
|
Issuance of subscribed units
|
|
|
4,518
|
|
|
|
45
|
|
|
|
2,259
|
|
|
|
2
|
|
|
45,329
|
|
|
(3,158
|
)
|
|
|
|
|
|
|
|
|
|
|
42,218
|
|
Issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
578
|
|
|
|
1
|
|
|
577
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
578
|
|
Conversion of preferred stock
|
|
|
(17,477
|
)
|
|
|
(175
|
)
|
|
|
13,106
|
|
|
|
13
|
|
|
162
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock for acquisition
|
|
|
|
|
|
|
|
|
|
|
34,795
|
|
|
|
35
|
|
|
384,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
384,336
|
|
Restricted stock issued as stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
214
|
|
|
|
|
|
|
1,044
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,044
|
|
Cancellation of restricted stock
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation for stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,125
|
|
Stock-based compensation on issuance of units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
975
|
|
Accrued interestofficer & employee notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(688
|
)
|
|
|
|
|
|
|
|
|
|
|
(688
|
)
|
6% Series A Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,244
|
)
|
|
|
|
|
|
|
(1,244
|
)
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2006
|
|
|
|
|
|
$
|
|
|
|
|
59,093
|
|
|
$
|
59
|
|
$
|
575,389
|
|
$
|
(12,858
|
)
|
|
$
|
12,152
|
|
|
$
|
414
|
|
|
$
|
575,156
|
|
F-5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
|
|
|
Retained
|
|
|
Accumulated
|
|
|
|
|
|
|
Series A
|
|
|
|
|
|
Additional
|
|
Receivable from
|
|
|
Earnings
|
|
|
Other
|
|
|
Total
|
|
|
|
Preferred Stock
|
|
Common Stock
|
|
Paid-in
|
|
Officers and
|
|
|
(Accumulated
|
|
|
Comprehensive
|
|
|
Stockholders
|
|
(in thousands)
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
Capital
|
|
Employees
|
|
|
Deficit)
|
|
|
Income (Loss)
|
|
|
Equity
|
|
|
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,502
|
|
|
|
|
|
|
|
18,502
|
|
Deferred hedge losses, net of tax of ($5,977)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,323
|
)
|
|
|
(8,323
|
)
|
Net settlement losses included in earnings, net of tax of $1,022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,416
|
|
|
|
1,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,595
|
|
Restricted stock issued as stock-based compensation
|
|
|
|
|
|
|
|
|
138
|
|
|
|
|
|
1,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,007
|
|
Stock-based compensation for stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,649
|
|
Issuance of common stock for acquisition obligation
|
|
|
|
|
|
|
|
|
54
|
|
|
|
|
|
650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
650
|
|
Net proceeds from initial public equity offering
|
|
|
|
|
|
|
|
|
16,466
|
|
|
17
|
|
|
172,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
173,002
|
|
Proceeds from officer and employee notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,644
|
|
|
|
|
|
|
|
|
|
|
|
10,644
|
|
Accrued interestofficer and employee notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(274
|
)
|
|
|
|
|
|
|
|
|
|
|
(274
|
)
|
6% Series A preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
|
|
|
|
|
|
(45
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT SEPTEMBER 30, 2007
|
|
|
|
|
$
|
|
|
|
75,751
|
|
$
|
76
|
|
$
|
751,680
|
|
$
|
(2,488
|
)
|
|
$
|
30,609
|
|
|
$
|
(6,493
|
)
|
|
$
|
773,384
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these consolidated financial
statements.
F-6
Concho
Resources Inc. and subsidiaries
Consolidated statements of cash flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
inception
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(April 21, 2004)
|
|
|
|
|
|
|
|
|
Nine months
|
|
|
|
through
|
|
|
Year ended
|
|
|
Year ended
|
|
|
ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
September 30,
|
|
(in thousands)
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(2,656
|
)
|
|
$
|
1,954
|
|
|
$
|
19,668
|
|
|
$
|
12,723
|
|
|
$
|
18,502
|
|
Adjustments to reconcile net income (loss) to net cash provided
by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and depletion
|
|
|
956
|
|
|
|
11,485
|
|
|
|
60,722
|
|
|
|
42,170
|
|
|
|
55,036
|
|
Impairments of proved oil and gas properties
|
|
|
|
|
|
|
2,295
|
|
|
|
9,891
|
|
|
|
5,762
|
|
|
|
4,577
|
|
Accretion of discount on asset retirement obligations
|
|
|
7
|
|
|
|
89
|
|
|
|
287
|
|
|
|
196
|
|
|
|
334
|
|
Exploration expense, including dry holes
|
|
|
1,636
|
|
|
|
1,549
|
|
|
|
3,387
|
|
|
|
3,204
|
|
|
|
17,117
|
|
Non-cash compensation expense
|
|
|
1,128
|
|
|
|
3,252
|
|
|
|
9,144
|
|
|
|
8,041
|
|
|
|
2,656
|
|
Gas imbalances
|
|
|
|
|
|
|
(37
|
)
|
|
|
82
|
|
|
|
(7
|
)
|
|
|
33
|
|
Ineffective portion of cash flow hedges
|
|
|
|
|
|
|
1,148
|
|
|
|
(1,193
|
)
|
|
|
(64
|
)
|
|
|
1,134
|
|
Deferred rent liability
|
|
|
10
|
|
|
|
11
|
|
|
|
262
|
|
|
|
49
|
|
|
|
33
|
|
Deferred income taxes
|
|
|
(915
|
)
|
|
|
1,974
|
|
|
|
12,618
|
|
|
|
7,603
|
|
|
|
11,460
|
|
Interest accrued on officer and employee notes
|
|
|
(44
|
)
|
|
|
(323
|
)
|
|
|
(688
|
)
|
|
|
(510
|
)
|
|
|
(274
|
)
|
Amortization of deferred loan costs
|
|
|
9
|
|
|
|
134
|
|
|
|
1,494
|
|
|
|
1,157
|
|
|
|
3,251
|
|
Amortization of discount on long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
480
|
|
(Gain) loss on sale of other property and equipment
|
|
|
(18
|
)
|
|
|
21
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
(Gain) loss on derivatives not designated as hedges
|
|
|
(684
|
)
|
|
|
5,001
|
|
|
|
|
|
|
|
|
|
|
|
(3,088
|
)
|
Dedesignated cash flow hedges reclassed from AOCI
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(722
|
)
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(4,732
|
)
|
|
|
(15,621
|
)
|
|
|
(27,683
|
)
|
|
|
(25,943
|
)
|
|
|
11,355
|
|
Prepaid insurance and other
|
|
|
(126
|
)
|
|
|
(1,548
|
)
|
|
|
(2,465
|
)
|
|
|
(1,752
|
)
|
|
|
135
|
|
Other assets
|
|
|
(12
|
)
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
2,445
|
|
|
|
3,452
|
|
|
|
13,853
|
|
|
|
2,373
|
|
|
|
(9,230
|
)
|
Revenue payable
|
|
|
166
|
|
|
|
6,958
|
|
|
|
2,372
|
|
|
|
(289
|
)
|
|
|
(5,325
|
)
|
Accrued liabilities
|
|
|
443
|
|
|
|
2,786
|
|
|
|
3,101
|
|
|
|
204
|
|
|
|
1,492
|
|
Accrued interest
|
|
|
194
|
|
|
|
490
|
|
|
|
7,320
|
|
|
|
4,024
|
|
|
|
(6,249
|
)
|
Income taxes payable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
225
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
(2,193
|
)
|
|
|
25,070
|
|
|
|
112,181
|
|
|
|
58,941
|
|
|
|
102,932
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures on oil and gas properties
|
|
|
(6,450
|
)
|
|
|
(52,768
|
)
|
|
|
(182,389
|
)
|
|
|
(122,839
|
)
|
|
|
(113,936
|
)
|
Acquisition of oil and gas properties and other assets
|
|
|
(114,649
|
)
|
|
|
(2,855
|
)
|
|
|
(413,229
|
)
|
|
|
(413,842
|
)
|
|
|
(256
|
)
|
Additions to other property and equipment
|
|
|
(1,374
|
)
|
|
|
(4,061
|
)
|
|
|
(1,234
|
)
|
|
|
(1,249
|
)
|
|
|
(2,218
|
)
|
Proceeds from the sale of oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
96
|
|
Proceeds from other assets
|
|
|
|
|
|
|
817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlements (paid) received on derivatives not designated as
hedges
|
|
|
|
|
|
|
(3,035
|
)
|
|
|
|
|
|
|
|
|
|
|
1,286
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(122,473
|
)
|
|
|
(61,902
|
)
|
|
|
(596,852
|
)
|
|
|
(537,930
|
)
|
|
|
(115,028
|
)
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt
|
|
|
53,000
|
|
|
|
63,400
|
|
|
|
664,993
|
|
|
|
563,005
|
|
|
|
283,600
|
|
Payments of long-term debt
|
|
|
|
|
|
|
(44,400
|
)
|
|
|
(241,493
|
)
|
|
|
(150,000
|
)
|
|
|
(433,700
|
)
|
Proceeds from issuance of subscribed units and common stock
|
|
|
74,053
|
|
|
|
30,621
|
|
|
|
61,178
|
|
|
|
61,178
|
|
|
|
173,002
|
|
Payments of preferred stock dividends
|
|
|
|
|
|
|
(4,160
|
)
|
|
|
(2,567
|
)
|
|
|
(2,542
|
)
|
|
|
(132
|
)
|
Proceeds from notes payableaffiliate
|
|
|
4,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments of notes payableaffiliate
|
|
|
(4,100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
inception
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(April 21, 2004)
|
|
|
|
|
|
|
|
|
Nine months
|
|
|
|
through
|
|
|
Year ended
|
|
|
Year ended
|
|
|
ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
September 30,
|
|
(in thousands)
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
Proceeds from repayment of officer and employee notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,644
|
|
Payments for loan origination costs
|
|
|
(450
|
)
|
|
|
(103
|
)
|
|
|
(5,500
|
)
|
|
|
(5,500
|
)
|
|
|
(2,572
|
)
|
Bank overdrafts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,666
|
|
|
|
|
|
Premiums paid on derivatives not designated as hedges
|
|
|
(1,281
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
125,322
|
|
|
|
45,358
|
|
|
|
476,611
|
|
|
|
469,807
|
|
|
|
30,842
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
656
|
|
|
|
8,526
|
|
|
|
(8,060
|
)
|
|
|
(9,182
|
)
|
|
|
18,746
|
|
BEGINNING CASH AND CASH EQUIVALENTS
|
|
|
|
|
|
|
656
|
|
|
|
9,182
|
|
|
|
9,182
|
|
|
|
1,122
|
|
|
|
|
|
|
|
ENDING CASH AND CASH EQUIVALENTS
|
|
$
|
656
|
|
|
$
|
9,182
|
|
|
$
|
1,122
|
|
|
$
|
|
|
|
$
|
19,868
|
|
|
|
|
|
|
|
SUPPLEMENTAL CASH FLOWS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest and fees, net of $0, $370, $2,129, $1,415
and $2,160 capitalized
|
|
$
|
67
|
|
|
$
|
2,449
|
|
|
$
|
23,881
|
|
|
$
|
11,294
|
|
|
$
|
28,233
|
|
|
|
|
|
|
|
Cash paid for income taxes
|
|
$
|
|
|
|
$
|
100
|
|
|
$
|
1,725
|
|
|
$
|
100
|
|
|
$
|
2,050
|
|
|
|
|
|
|
|
NON-CASH INVESTING AND FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock in acquisition of oil and gas
properties and other assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
384,336
|
|
|
$
|
384,336
|
|
|
$
|
650
|
|
Deferred tax effect of acquired oil and gas properties
|
|
$
|
|
|
|
$
|
|
|
|
$
|
227,735
|
|
|
$
|
227,537
|
|
|
$
|
|
|
Issuance of notes receivable in connection with capital options
|
|
$
|
3,840
|
|
|
$
|
4,805
|
|
|
$
|
3,158
|
|
|
$
|
3,158
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these consolidated financial
statements.
F-8
Concho
Resources Inc. and subsidiaries
Notes to consolidated financial statements
(Information as of and for the
nine months ended September 30, 2006 and 2007 is
unaudited)
Note A. Organization
and nature of operations
Concho Resources Inc. (Resources) is a Delaware
corporation formed by Concho Equity Holdings Corp.
(CEHC) on February 22, 2006, for purposes of
effecting the combination of CEHC, Chase Oil Corporation, Caza
Energy LLC (Caza) and certain other parties thereto
(collectively with Chase Oil Corporation and Caza, the
Chase Group). Pursuant to the Combination Agreement
dated February 24, 2006, Resources acquired working
interests in oil and natural gas properties from the Chase Group
and issued shares of its common stock to certain stockholders of
CEHC in exchange for their capital stock of CEHC. CEHC is a
Delaware corporation formed on April 21, 2004 by certain
individuals and private equity investors. CEHC commenced
substantial oil and gas operations in December 2004 upon its
acquisition of certain oil and gas properties located in
Southeast New Mexico and West Texas. The combination transaction
described above (the Combination) was accounted for
as an acquisition by CEHC of the Chase Group Properties and a
simultaneous reorganization of Resources such that CEHC is now a
wholly owned subsidiary of Resources. Prior to the Combination,
Resources had no assets, operations or net equity. Upon the
closing of the Combination, the executive officers of CEHC
became the executive officers of Resources. Resources and its
wholly owned subsidiaries are hereafter collectively referred to
as the Company.
CEHCs shareholders received 23,767,691 shares of
common stock of Resources in exchange for their preferred and
common shares of CEHC, excluding eighteen holders owning an
aggregate of 254,621 shares of CEHC 6% Series A
Preferred Stock and 127,313 shares of CEHC common
stock, as discussed in Note G
Stockholders equity and stock issued subject to limited
recourse notes. In addition, the Chase Group transferred
their ownership in certain oil and gas properties in Southeast
New Mexico to Resources in exchange for cash in the aggregate
amount of approximately $409 million and
34,794,638 shares of Resources common stock. As of
December 31, 2006 and September 30, 2007, this
ownership of the Chase Group represents approximately
59 percent and 37 percent, respectively, of the total
outstanding common stock ownership of the Company.
The Companys principal business is the acquisition,
development, exploitation and exploration of oil and gas
properties in the Permian Basin region of Southeast New Mexico
and West Texas.
Initial public offering. On
August 7, 2007, the Company completed an initial public
offering (the IPO) of its common stock. The Company
sold 13,332,851 shares and certain shareholders, including
our executive officers and members of the Chase Group, sold
7,554,256 shares of Resources common stock, in each case,
at $11.50 per share. After deducting underwriting discounts of
approximately $9.6 million and offering expenses of
approximately $4.5 million, the Company received net
proceeds of approximately $139.2 million. In conjunction
with the IPO, the underwriters were granted an option to
purchase 3,133,066 additional shares of Resources common stock.
The underwriters fully exercised this option and purchased the
additional shares on August 9, 2007. After deducting
underwriting discounts of approximately $2.2 million, the
Company received net proceeds of approximately
$33.8 million. The aggregate net proceeds of approximately
$173.0 million received by the Company at closing on
August 7, 2007 and August 9, 2007 were utilized in
equal amounts to repay a portion of its term loan facility on
F-9
August 9, 2007, and to prepay a portion of its revolving
credit facility on August 20, 2007. See further discussion
in Note JLong-term debt.
Reverse stock split. A one-for-two reverse
stock split of the Companys outstanding common stock,
which was approved by the Companys shareholders, became
effective upon the completion of the Companys initial
public offering. All common shares and per share amounts in the
accompanying consolidated financial statements and notes to the
consolidated financial statements have been retroactively
adjusted for all periods presented to give effect to the reverse
stock split.
Note B. Summary
of significant accounting policies
Principles of consolidation. Prior to the
Combination, the consolidated financial statements of Resources
represent the accounts of CEHC and its wholly owned
subsidiaries. After the Combination, the consolidated financial
statements of Resources include the accounts of Resources and
its wholly owned subsidiaries, including CEHC. All material
intercompany balances and transactions have been eliminated.
Interim financial statements. The financial
statements as of September 30, 2007 and for the nine months
ended September 30, 2006 and 2007 included herein have been
prepared, without audit, pursuant to the rules and regulations
of the Securities and Exchange Commission. The interim financial
statements reflect all adjustments, which are, in the opinion of
the Companys management, necessary for a fair presentation
of the Companys results for the interim periods. Such
adjustments are considered to be of a normal recurring nature.
Results of operations for the nine months ended
September 30, 2007 are not necessarily indicative of the
results of operations that will be realized for the year ending
December 31, 2007.
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 and
depreciation of oil and gas properties are determined using
estimates of proved oil and gas reserves. There are numerous
uncertainties inherent in the estimation of quantities of proved
reserves and in the projection of future rates of production and
the timing of development expenditures. Similarly, evaluations
for impairment of proved and unproved oil and gas properties are
subject to numerous uncertainties including, among others,
estimates of future recoverable reserves and commodity price
outlooks. Other significant estimates include, but are not
limited to, the asset retirement obligations, fair value of
derivative financial instruments, purchase price allocations 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 counter-party risks are minimal based on the
reputation and history of the institutions selected.
Accounts receivable. The Company sells oil
and gas to various customers and participates with other parties
in the drilling, completion and operation of oil and gas wells.
Joint interest and oil
F-10
and gas sales receivables related to these operations are
generally unsecured. The Company determines joint interest
operations accounts receivable allowances based on
managements assessment of the creditworthiness of the
joint interest owners and the Companys ability to realize
the receivables through netting of anticipated future production
revenues. Receivables are considered past due if full payment is
not received by the contractual due date. Past due accounts are
generally written off against the allowance for doubtful
accounts only after all collection attempts have been exhausted.
The Company had no allowance for doubtful accounts at
December 31, 2005, December 31, 2006 or
September 30, 2007.
Inventory. Inventory consists primarily of
tubular goods that the Company plans to utilize in its ongoing
exploration and development activities and is carried at the
lower of cost or market value.
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 $411,000, $4,417,000 and $3,737,000, net
of accumulated amortization of $142,000, $1,083,000 and
$4,335,000, as of December 31, 2005, December 31, 2006
and September 30, 2007, respectively.
On February 24, 2006, in conjunction with the Combination,
the Company replaced its prior revolving credit facility with a
new revolving credit facility. The remaining net deferred loan
costs of $376,000 associated with the retired debt, were written
off and included in Interest expense in 2006. In
addition, on July 6, 2006, the Company entered into a term
loan facility. The new deferred loan costs on these facilities
are being amortized over the life of the loans, which mature
February 24, 2010 and July 7, 2011, respectively.
On March 27, 2007, the Company amended its 1st lien
revolving credit facility, repaid its existing 2nd lien
term loan credit facility and entered into a new 2nd lien
term loan credit facility. The Company paid an arrangement fee
of $2.5 million at the date of closing of the new
2nd lien term loan credit facility. This fee will be
amortized to Interest expense over the five-year term of
the facility beginning in April 2007. The amendment of the
1st lien revolving credit facility on March 27, 2007
resulted in a $100 million, or 21 percent, reduction
of the borrowing base on such facility. As such, the prorata
portion of the remaining debt issuance costs associated with the
1st lien revolving credit facility, totaling approximately
$766,000, were written off and included in Interest expense
in the three months ended March 31, 2007. The remaining
debt issuance costs of $433,000 associated with the existing
2nd lien term loan credit facility repaid in full on
March 27, 2007 were written off and included in Interest
expense during the three months ended March 31, 2007.
Future amortization expense as of December 31, 2006 for
each of the years ended December 31, 2007, 2008, 2009, 2010
and 2011 was approximately $1,350,000, $1,350,000, $1,350,000,
$308,000 and $50,000, respectively.
Future amortization expense as of September 30, 2007 for
the remaining three months ending December 31, 2007 and
each of the years ended December 31, 2008, 2009, 2010, 2011
and 2012 is approximately $311,000, $1,258,000, $1,280,000,
$470,000, $331,000 and $87,000, respectively.
Oil and gas properties. The Company utilizes
the successful efforts method of accounting for its oil and gas
properties under the provisions of Financial Accounting
Standards Board (FASB) Statement of Financial
Accounting Standards (SFAS) No. 19,
Financial Accounting and Reporting by Oil and Gas
Producing Companies. Under this method all costs
associated with
F-11
productive wells and nonproductive development wells are
capitalized, while nonproductive exploration costs are expensed.
Capitalized acquisition costs relating to proved properties are
depleted on a field basis using the unit-of-production method
based on proved reserves. The depreciation of capitalized
exploratory drilling and development costs is based on the
unit-of-production method using proved developed reserves on a
field basis.
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 and
depreciation. Generally, no gain or loss is recognized until the
entire amortization base is sold. However, gain or loss is
recognized from the sale of less than an entire amortization
base if the disposition is significant enough to materially
impact the depletion rate of the remaining properties in the
amortization base. Ordinary maintenance and repair costs are
generally expensed as incurred.
Costs of significant nonproducing properties, wells in the
process of being drilled and development projects are excluded
from depletion until such time as the related project is
developed and proved reserves are established or impairment is
determined. The Company capitalizes interest, if debt is
outstanding, on expenditures for significant development
projects until such projects are ready for their intended use.
In addition to the amounts of unproved properties, at
December 31, 2005, December 31, 2006 and
September 30, 2007, the Company had excluded
$11.8 million, $33.6 million and $35.7 million,
respectively, of proved property costs from depletion and had
capitalized interest of $370,000, $2,129,000 and $2,160,000
during the years ended December 31, 2005 and 2006 and the
nine months ended September 30, 2007, respectively.
In accordance with SFAS No. 144, Accounting for
the Impairment or Disposal of Long-Lived Assets, the
Company reviews its long-lived assets to be held and used,
including proved oil and gas properties, whenever events or
circumstances indicate that the carrying value of those assets
may not be recoverable. An impairment loss is indicated if the
sum of the expected future cash flows is less than the carrying
amount of the assets. In this circumstance, the Company
recognizes an impairment loss for the amount by which the
carrying amount of the asset exceeds the estimated fair value of
the asset. The Company reviews its oil and gas properties by
amortization base (field) or by individual well for those wells
not constituting part of an amortization base. For each property
determined to be impaired, an impairment loss equal to the
difference between the carrying value of the properties and the
estimated fair value (discounted future cash flows) of the
properties would be recognized at that time. Estimating future
cash flows involves the use of judgments, including estimation
of the proved and unproved oil and gas reserve quantities,
timing of development and production, expected future commodity
prices, capital expenditures and production costs. The Company
recognized impairment expense of $0, $2.3 million and
$9.9 million during the periods ended December 31,
2004, 2005 and 2006, respectively, and $5.8 million and
$4.6 million during the nine months ended
September 30, 2006 and 2007, respectively, related to its
proved oil and gas properties.
Unproved oil and gas properties are each periodically assessed
for impairment by considering future drilling plans, the results
of exploration activities, commodity price outlooks, planned
future sales or expiration of all or a portion of such projects.
During the periods ended December 31, 2004, 2005 and 2006,
the Company recognized a non-cash charge against earnings of
$376,000, $199,000 and $196,000, respectively, and $32,000 and
$895,000 during the nine months ended September 30, 2006
and 2007, respectively, related to abandoned prospects, which
F-12
is included in Exploration and abandonments in the
accompanying consolidated statements of operations.
Exploratory well costs. Costs of drilling
exploratory wells are capitalized, pending managements
determination of whether the wells have found proved reserves.
If proved reserves are found, the costs remain capitalized. If
proved reserves are not found, the capitalized costs of drilling
the well are charged to expense. Management makes this
determination as soon as possible after completion of drilling
considering the guidance provided in SFAS No. 19 and
FASB Staff Position (FSP)
No. 19-1
Accounting for Suspended Well Costs.
SFAS No. 19 provided that such costs should not be
carried as an asset for more than one year following completion
of drilling unless the well has found oil and gas reserves in an
area requiring a major capital expenditure before production
could begin. In that case, the costs of such exploratory well
would continue to be carried as an asset pending determination
of whether proved reserves had been found only as long as the
well had found a sufficient quantity of reserves to justify its
completion as a producing well if the required capital
expenditure was made and drilling of the additional exploratory
wells was under way or firmly planned for the near future. If
both those conditions were not met, the well costs were charged
to expense.
The Company adopted the provisions of
FSP No. 19-1
effective January 1, 2006.
FSP 19-1
amends SFAS No. 19 to provide that in those situations
where exploration drilling has been completed and oil and gas
reserves have been found, but such reserves cannot be classified
as proved when drilling is complete, the drilling costs may be
capitalized if the well has found a sufficient quantity of
reserves to justify its completion as a producing well and the
enterprise is making sufficient progress assessing the reserves
and the economic and operating viability of the project. If
either of the criteria is not met, the well is assumed to be
impaired and the costs charged to expense. Any well that has not
found reserves is charged to expense. Management performs this
evaluation on a quarterly basis. The adoption of
FSP No. 19-1
had no impact on the Companys consolidated financial
position or results of operations.
The following table provides an aging as of December 31,
2005, December 31, 2006 and September 30, 2007 of
capitalized exploratory well costs based on the date the
drilling was completed:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
September 30,
|
(In thousands)
|
|
2005
|
|
2006
|
|
2007
|
|
|
Wells in progress
|
|
$
|
1,190
|
|
$
|
916
|
|
$
|
3,104
|
Capitalized exploratory well costs that have been capitalized
for a period of one year or less
|
|
|
2,765
|
|
|
14,042
|
|
|
15,398
|
Capitalized exploratory well costs that have been capitalized
for a period greater than one year
|
|
|
|
|
|
4,915
|
|
|
3,329
|
|
|
|
|
|
|
Total exploratory well costs
|
|
$
|
3,955
|
|
$
|
19,873
|
|
$
|
21,831
|
|
|
|
|
|
|
|
|
During 2006 and 2007, the Company drilled four vertical
exploration wells in the Western Delaware Basin of Texas. One of
the four wells is currently flowing gas to sales. Below is a
description of the status of the remaining three wells.
F-13
As of June 30, 2007, the first well drilled had been
completed in two of the four prospective formations that are
being tested in the project area and had found both zones
capable of producing gas in the vertical well bores; however,
quantities found were not commercial. The evaluation conducted
on this well in the third quarter was to determine the viability
of another one of the four prospective formations which is
deeper than the formations to which the well had previously been
completed. This formation is a shale formation which is present
and productive in another of the Companys exploratory
wells located in the Western Delaware Basin. The evaluation of
this formation indicated that conditions were unfavorable for
commercial success. This well was temporarily abandoned, and the
Company expensed the costs associated with this well in the
third quarter of 2007, which were approximately
$6.8 million. Such expense is included in Exploration
and abandonments in the accompanying consolidated statement
of operations for the nine months ended September 30, 2007.
The second well drilled in the project area, which reached total
depth in September 2006, was completed and flowing gas to sales
during its initial evaluation stage during the six months ended
June 30, 2007; however, quantities found were not
commercial. The Company has begun testing a deeper formation in
this well bore. The Company is still evaluating the commercial
viability of the deeper zone. As such, the Company recognized
exploratory dry hole expense of approximately $1.8 million
which represents the intangible drilling and completion costs
incurred to drill to the shallower formations which were not
commercial. Such expense is included in Exploration and
abandonments in the accompanying consolidated statement of
operations for the nine months ended September 30, 2007.
Remaining accumulated capitalized exploratory costs on this well
of approximately $3.3 million related to the drilling of
the deeper formation currently being evaluated are included
above in Capitalized exploratory well costs that have been
capitalized for a period greater than one year.
During 2007, a third well in the Western Delaware Basin was
drilled to a shallower, previously untested, prospective
formation. During June 2007, the Company determined that the
well had not found sufficient reserves to justify its completion
or its inclusion in the evaluation of the viability of any
additional prospective formations in the project area. The well
was temporarily abandoned, and the Company has recognized
exploratory dry hole expense of approximately $3.0 million.
Such expense is included in Exploration and abandonments
in the accompanying consolidated statement of operations for
the nine months ended September 30, 2007.
The remaining capitalized exploratory wells in progress and
exploratory well costs of approximately $18.5 million have
been deferred for a period of one year or less and are related
primarily to the Companys New Mexico Shelf and New Mexico
Basin properties.
F-14
The changes in capitalized exploratory well costs were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inception
|
|
|
|
|
|
|
|
|
(April 21, 2004)
|
|
|
|
|
|
|
|
|
through
|
|
Year ended
|
|
|
Year ended
|
|
|
|
December 31,
|
|
December 31,
|
|
|
December 31,
|
|
(in thousands)
|
|
2004
|
|
2005
|
|
|
2006
|
|
|
|
|
Beginning capitalized exploratory well costs
|
|
$
|
|
|
$
|
2,149
|
|
|
$
|
3,955
|
|
Additions to exploratory well costs pending the determination of
proved reserves
|
|
|
2,149
|
|
|
5,556
|
|
|
|
41,956
|
|
Reclassifications due to determination of proved reserves
|
|
|
|
|
|
(3,749
|
)
|
|
|
(25,762
|
)
|
Exploratory well costs charged to expense
|
|
|
|
|
|
(1
|
)
|
|
|
(276
|
)
|
|
|
|
|
|
|
Ending capitalized exploratory well costs
|
|
$
|
2,149
|
|
$
|
3,955
|
|
|
$
|
19,873
|
|
|
|
|
|
|
|
|
|
Other property and equipment. Other capital
assets include buildings, vehicles, computer equipment and
software, telecommunications equipment and furniture and
fixtures. These items are recorded at cost and are depreciated
using the straight-line method based on expected lives of the
individual assets or group of assets ranging from two to
15 years.
Environmental. The Company is subject to
extensive Federal, state and local environmental laws and
regulations. These laws, which are often changing, regulate the
discharge of materials into the environment and may require the
Company to remove or mitigate the environmental effects of the
disposal or release of petroleum or chemical substances at
various sites. Environmental expenditures are expensed.
Expenditures that relate to an existing condition caused by past
operations and that have no future economic benefits are
expensed. Liabilities for expenditures of a noncapital nature
are recorded when environmental assessment
and/or
remediation is probable and the costs can be reasonably
estimated. Such liabilities are generally undiscounted unless
the timing of cash payments is fixed and readily determinable.
Management believes no liabilities of this nature existed at
December 31, 2005, December 31, 2006 or
September 30, 2007.
Oil and gas sales and imbalances. The
Companys principal revenue source is the sale of crude oil
and natural gas. In general, the amount recorded as revenue from
the sale of such products represents the estimated amount due
based on the Companys interest in the properties and the
agreements with the respective purchasers. The amount reported
as revenue in the accompanying statements of operations is also
affected by the results of oil and gas hedging activities, as
discussed below. Oil and gas revenues are recorded at the time
of delivery of such products to pipelines for the account of the
purchaser or at the time of physical transfer of such products
to the purchaser. The Company follows the sales method of
accounting for oil and gas sales, recognizing revenues based on
the Companys share of actual proceeds from the oil and gas
sold to purchasers. Oil and gas imbalances are generated on
properties for which two or more owners have the right to take
production in-kind and, in doing so, take more or
less than their respective entitled percentage. Imbalances are
tracked by well, but the Company does not record any receivable
to or payable from the other owners unless the imbalance has
reached a level whereby 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
F-15
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 Company had no gas imbalance liabilities or assets recorded
prior to 2005. At December 31, 2005, the Company had a gas
imbalance liability, included in Asset retirement obligations
and other long-term liabilities in the accompanying
consolidated balance sheets of approximately $446,000 related to
the Companys overtake position of 70,249 Mcf on
certain wells and a gas imbalance receivable, included in
Other assets in the accompanying consolidated balance
sheets of approximately $289,000 related to the Companys
undertake position of 64,176 Mcf on certain wells. A net
overtake of 18,765 Mcf, valued at approximately $194,000,
was assumed by the Company with the December 7, 2004
acquisition of interests in certain oil and gas properties and
was, therefore, reflected as a 2005 adjustment to the purchase
price allocation as discussed in
Note DAcquisitions and business combinations.
The remaining net undertake of 12,692 Mcf that arose in
2005, valued at approximately $37,000, was recorded net in
Oil and gas production expense in the accompanying
consolidated statements of operations for the year ended
December 31, 2005.
At December 31, 2006, the Company had a gas imbalance
liability, included in Asset retirement obligations and other
long-term liabilities in the accompanying consolidated
balance sheets of approximately $539,000 related to the
Companys overtake position of 85,348 Mcf on certain
wells and a gas imbalance receivable, included in Other
assets, net in the accompanying consolidated balance sheets
of approximately $299,000 related to the Companys
undertake position of 66,438 Mcf on certain wells. The net
overtake of 12,837 Mcf that arose in 2006, valued at
approximately $83,000, was recorded net as an increase to Oil
and gas production expense in the accompanying consolidated
statement of operations for the year ended December 31,
2006.
At September 30, 2007, the Company had a gas imbalance
liability, included in Asset retirement obligations and other
long-term liabilities in the accompanying consolidated
balance sheets of approximately $610,000 related to the
Companys overtake position of 94,601 Mcf on certain wells
and a gas imbalance receivable, included in Other assets
in the accompanying consolidated balance sheets of
approximately $337,000 related to the Companys undertake
position of 74,985 Mcf on certain wells. The net undertake of
11,775 Mcf that arose in 2007, valued at approximately $50,000,
was recorded net as a decrease to Oil and gas production
expense in the accompanying consolidated statement of
operations for the nine months ended September 30, 2007.
Derivative instruments and hedging. The
Company applies the provisions of SFAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities, as amended. This statement requires the
recognition of all derivative instruments as either assets or
liabilities measured at fair value. The Company netted the fair
value of derivative instruments by counterparty in the
accompanying consolidated balance sheets where the right of
offset exists as permitted by FASB Interpretation
(FIN) No. 39, Offsetting of Amounts Related to
Certain Contracts.
Under the provisions of SFAS No. 133, the Company may
designate a derivative instrument as hedging the exposure to
changes in the fair value of an asset or a liability or an
identified portion thereof that is attributable to a particular
risk (a fair value hedge) or as hedging the exposure
to variability in expected future cash flows that are
attributable to a particular risk (a cash flow
hedge). Special accounting for qualifying hedges allows
the effective portion of a derivative instruments gains
and losses to offset related results on the hedged item in the
statement of operations and requires that a company formally
document, designate and assess the effectiveness of the
transactions that receive hedge accounting treatment. Both at
the inception of a hedge and on an ongoing basis, a hedge must
be expected to be highly effective
F-16
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 income
(loss) 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 hedge effectiveness at the end
of each quarter.
In accordance with SFAS No. 133, changes in the fair
value of derivative instruments that are fair value hedges are
offset against changes in the fair value of the hedged assets,
liabilities or firm commitments, through earnings. Effective
changes in the fair value of derivative instruments that are
cash flow hedges are recognized in Accumulated other
comprehensive income (loss) and reclassified into earnings
in the period in which the hedged item affects earnings.
Ineffective portions of a derivative instruments change in
fair value are immediately recognized in earnings. Derivative
instruments that do not qualify, or cease to qualify, as hedges
must be adjusted to fair value and the adjustments are recorded
through net income (loss).
Asset retirement obligations. The Company
accounts for the obligation in accordance with
SFAS No. 143, Asset Retirement
Obligations. SFAS No. 143 requires entities to
record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related
long-lived asset. Subsequently, the asset retirement cost
included in the carrying amount of the related asset is
allocated to expense through depreciation of the asset. Changes
in the liability due to passage of time are recognized as an
increase in the carrying amount of the liability and as
corresponding accretion expense.
In March 2005, the FASB issued FIN No. 47, Accounting
for Conditional Asset Retirement Obligations, an interpretation
of FASB Statement No. 143. FIN 47 clarifies that
conditional asset retirement obligations meet the definition of
liabilities and should be recognized when incurred if their fair
values can be reasonably estimated. The interpretation was
adopted by the Company on December 31, 2005 with no impact
on the Companys financial position or results of
operations.
General and administrative expense. The
Company receives fees for the operation of jointly owned oil and
gas properties and records such reimbursements as reductions of
General and administrative expense. Such fees totaled
approximately $38,000, $591,000 and $799,000 for the periods
ended December 31, 2004, 2005 and 2006, respectively, and
$602,000 and $852,000 for the nine months ended
September 30, 2006 and 2007, respectively.
Stock-based compensation. In December 2004,
the FASB issued SFAS No. 123R, Share-Based
Payment. SFAS No. 123R addresses the accounting
for transactions in which an enterprise exchanges its valuable
equity instruments for employee services. It also addresses
transactions in which an enterprise incurs liabilities that are
based on the fair value of the enterprises equity
instruments or that may be settled by the issuance of those
equity instruments in exchange for employee services. The cost
of employee services received in exchange for equity
instruments, including employee stock options, would be measured
based on the grant-date fair value of those instruments. That
cost would be recognized as compensation expense over the
requisite service period (often the vesting period). Generally,
no compensation cost would be recognized for equity instruments
that do not vest. The Company adopted SFAS No. 123R in
2005 and applied the modified retrospective application method
to all prior periods. The Company previously utilized the method
of accounting for stock based compensation prescribed by
Accounting Principles Board Opinion No. 25 Accounting
for Stock Issued to Employees and
F-17
included disclosures in the footnotes to the consolidated
financial statements which illustrated the results the Company
would have recorded had it utilized the fair value method
prescribed by SFAS No. 123 Accounting for
Stock-Based Compensation in its primary financial
statements.
Interest and other income. The Company
collects rental income on its commercial building from lessees.
Rental revenue is recognized on a straight-line basis over the
term of the rental agreement.
As discussed more fully in Note G
Stockholders equity and stock issued subject to limited
recourse notes, the Company accrues interest income on notes
receivable from officers and employees.
Income taxes. The Company accounts for income
taxes in accordance with the provisions of
SFAS No. 109, Accounting for Income Taxes.
Under the asset and liability method of SFAS No. 109,
deferred tax assets and liabilities are recognized for the
future tax consequences attributable to differences between the
financial statement carrying amounts of existing assets and
liabilities and their respective tax bases. Deferred tax assets
and liabilities are measured using enacted tax rates expected to
apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. Under
SFAS No. 109, the effect on deferred tax assets and
liabilities of a change in tax rate is recognized in income in
the period that includes the enactment date. A valuation
allowance is established to reduce deferred tax assets if it is
more likely than not that the related tax benefits will not be
realized.
Note C. Disclosures
about fair value of financial instruments
Cash and cash equivalents, accounts receivable, other
current assets, accounts payable, interest payable and other
current liabilities. The carrying amounts
approximate fair value due to the short maturity of these
instruments.
Notes receivableofficers and
employees. The carrying amounts approximate fair
value due to the comparability of the interest rate to
risk-adjusted rates for similar financial instruments.
Line of credit and term note. The carrying
amount of borrowings outstanding under the Companys
revolving credit facility and term note, as discussed in
Note J Long-term debt, approximate fair
value because the instruments bear interest at variable market
rates.
Commodity price collars and price swaps. The
fair value of commodity price collars and price swaps are
estimated by management considering various factors, including
closing exchange and
over-the-counter
quotations and the time value of the underlying commitments.
Managements estimated fair value represents the estimated
amounts that the Company would expect to receive or pay to
settle the derivative contracts. See Note I
Derivative financial instruments for a discussion of
commodity price collars and price swaps.
Note D. Acquisitions
and business combinations
Acquisition of interests in oil and gas properties and
other assets. On December 7, 2004 one of the
Companys wholly owned subsidiaries, COG Oil &
Gas LP (COG LP), acquired interests in several
producing crude oil and natural gas fields and non-producing
leasehold acreage in the Permian Basin region of Southeast New
Mexico and West Texas from a privately-held company, Lowe
Partners, LP (the Seller) (the Lowe
Acquisition). In conjunction with this transaction, a
separate wholly owned subsidiary of the Company, COG Realty LLC
(Realty), acquired 100 percent ownership in two
buildings in Midland, Texas from an affiliate of the Seller.
This entire acquisition was accounted for using the purchase
method of accounting. At the time of purchase, there was no
difference in the book and tax basis of the acquired properties.
F-18
One property acquired was subject to a preferential right to
purchase, giving a third party the right to acquire the
Sellers interest in such property. This preferential right
was not fully exercised by its holder until after the closing of
the Lowe Acquisition. As a result, COG LP acquired the property
interests at closing and subsequently sold the subject interest
to the holder of the preferential right on February 2, 2005
for the same amount as COG LP paid for the property interest at
closing of the Lowe Acquisition, which was $2.21 million.
Similar to the properties acquired by COG LP in the Lowe
Acquisition, the sales price received has been adjusted, in
accordance with the governing purchase and sale agreement, for
property revenue, expense and other items related to periods
prior to the effective date of September 1, 2004. This
post-closing adjustment, in which COG LP paid the buyer
approximately $247,000, was completed and settled on
July 25, 2005.
The purchase price paid at closing of the Lowe Acquisition was
adjusted, in accordance with the governing purchase and sale
agreement, for property revenue, expense and other items related
to periods from the effective date of September 1, 2004 to
the post-closing date. This post-closing adjustment, in which
the Seller paid COG LP approximately $948,000, was completed and
settled on May 24, 2005.
The purchase and sale agreement governing the Lowe Acquisition
provided for possible additional consideration (Contingent
Consideration). COG LP paid Contingent Consideration of
approximately $1,824,000 for each of the second, third and
fourth quarters of 2005, aggregating approximately $5,473,000.
These amounts were added to the allocation of the original
purchase price of proved oil and gas properties. Similarly, in
the settlement of the one property subject to a preferential
right to purchase, the buyer owed COG LP approximately $35,000
of Contingent Consideration for each of the second, third and
fourth quarters of 2005. These amounts aggregating $105,000 were
included in the final allocation of purchase price of proved oil
and gas properties at December 31, 2005. All three payments
were received prior to December 31, 2005.
Effective July 25, 2005, Realty sold one of the buildings
for cash in the amount of $850,000, prior to adjustment for
closing costs. This building was deducted from the purchase
price allocation.
As disclosed in Note B Summary of
significant accounting policies, in the Oil and gas sales
and imbalances section, the Company assumed natural gas and
oil imbalances related to certain of the wells acquired. As
such, the net overtake of 18,765 Mcf, valued at
approximately $194,000, was included in the determination of the
final allocated purchase price to the proved oil and gas
properties.
F-19
The following table summarizes the final allocated net purchase
price of the Lowe Acquisition:
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
106,485
|
|
Unproved oil and gas properties
|
|
|
7,904
|
|
Commercial real estate
|
|
|
1,672
|
|
Assets held for sale preferential rights
|
|
|
2,209
|
|
Vehicles and other
|
|
|
42
|
|
|
|
|
|
|
Total assets acquired
|
|
|
118,312
|
|
|
|
|
|
|
Net gas imbalance liability
|
|
|
(194
|
)
|
Asset retirement obligations
|
|
|
(883
|
)
|
|
|
|
|
|
Total liabilities assumed
|
|
|
(1,077
|
)
|
|
|
|
|
|
Net purchase price
|
|
$
|
117,235
|
|
|
|
|
|
|
|
|
Business combination. On February 27,
2006, the Company closed a Combination Agreement with the Chase
Group whereby ownership in certain oil and gas properties and
non-producing leasehold acreage in Southeast New Mexico (the
Chase Group Properties) were merged with the
properties previously owned by CEHC. The results of the Chase
Group Properties have been included in the consolidated
financial statements since that date.
The Chase Group received cash in the aggregate amount of
approximately $409 million and 34,794,638 shares of
Resources common stock valued at $384 million for an
aggregate purchase price of $796 million including
transaction costs. The value of the Resources common stock
shares issued was determined based on an agreed upon fair market
value of the assets purchased evaluated using reserve
engineering estimates. This entire transaction was accounted for
using the purchase method of accounting. At the time of the
Combination, due to a difference in book and tax basis of the
acquired properties, the Company recognized a deferred tax
liability of approximately $227.7 million.
The following table summarizes the final allocated net purchase
price of the Combination, including capitalized transaction
costs:
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
830,540
|
|
Unproved oil and gas properties
|
|
|
200,000
|
|
|
|
|
|
|
Total assets acquired
|
|
|
1,030,540
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
(6,158
|
)
|
Chase investors asset purchase obligation
|
|
|
(906
|
)
|
Deferred tax liability
|
|
|
(227,735
|
)
|
|
|
|
|
|
Total liabilities assumed
|
|
|
(234,799
|
)
|
|
|
|
|
|
Net purchase price
|
|
$
|
795,741
|
|
|
|
|
|
|
|
|
As discussed in Note K Commitments and
contingencies, the Company was obligated under the
Combination Agreement to offer to purchase additional working
interests in the Chase Group
F-20
Properties from nine individuals within the Chase Group for
total consideration of approximately $906,000. In April 2007,
the Company satisfied this obligation by paying $256,000 in cash
and issuing 54,230 shares of common stock. This aggregate
purchase price is reflected in Proved properties and the
related obligation is reflected in Chase Group unaccredited
investors asset purchase obligation in the accompanying
consolidated balance sheet as of December 31, 2006.
The following table represents pro forma consolidated statements
of operations as though the Combination had been completed as of
January 1, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma
|
|
|
Pro forma
|
|
Nine months
|
|
|
Year ended December 31,
|
|
ended September 30,
|
(in thousands, except per share
data) (unaudited)
|
|
2005
|
|
2006
|
|
2006
|
|
|
Operating revenues
|
|
$
|
174,614
|
|
$
|
219,746
|
|
$
|
157,101
|
Net income applicable to common shareholders
|
|
$
|
19,006
|
|
$
|
23,451
|
|
$
|
16,951
|
Earnings per common share:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.42
|
|
$
|
0.43
|
|
$
|
0.31
|
Diluted
|
|
$
|
0.42
|
|
$
|
0.41
|
|
$
|
0.30
|
|
|
On February 27, 2006, the Company signed a contract
operator agreement with Mack Energy Corporation
(MEC), an affiliate of the Chase Group, whereby the
Company engaged MEC as contract operator to provide certain
services with respect to the Chase Group Properties. This
agreement was replaced with a Transition Services Agreement on
April 23, 2007. See further discussion in
Note O Related parties.
Note E. New
accounting pronouncements
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurement. This statement defines fair
value, establishes a framework for measuring fair value and
expands disclosures about fair value measurements. This
statement is effective for financial statements issued for
fiscal years beginning after November 15, 2007. The Company
will adopt SFAS No. 157 effective January 1,
2008. The Company is currently evaluating the impact of
SFAS No. 157.
In February 2007, the FASB issued SFAS No. 159,
The Fair Value Option for Financial Assets and Financial
Liabilities, Including an Amendment of FASB Statement
No. 115, which will become effective in 2008.
SFAS No. 159 permits entities to measure eligible
financial assets, financial liabilities and firm commitments at
fair value, on an
instrument-by-instrument
basis, that are otherwise not permitted to be accounted for at
fair value under other generally accepted accounting principles.
The fair value measurement election is irrevocable and
subsequent changes in fair value must be recorded in earnings.
The Company will adopt this statement January 1, 2008, and
the Company does not expect that it will elect the fair value
option for any of its eligible financial instruments and other
items.
In June 2007, the FASB ratified a consensus opinion reached by
the Emerging Issues Task Force (EITF) on EITF Issue
06-11,
Accounting for Income Tax Benefits of Dividends on
Share-Based Payment Awards. EITF Issue
06-11
requires an employer to recognize tax benefits realized from
dividends or dividend equivalents paid to employees for certain
share-based payment awards as an increase to additional paid-in
capital and include such amounts in the pool of excess tax
benefits available to absorb future tax deficiencies on
share-based payment awards. If an entitys estimate of
forfeitures increases (or actual forfeitures exceed the
entitys estimates), or if an
F-21
award is no longer expected to vest, entities should reclassify
the dividends or dividend equivalents paid on that award from
retained earnings to compensation cost. However, the tax
benefits from dividends that are reclassified from additional
paid-in capital to the income statement are limited to the
entitys pool of excess tax benefits available to absorb
tax deficiencies on the date of reclassification. The consensus
in EITF Issue
06-11 is
effective for fiscal years, and interim periods within those
fiscal years, beginning after December 15, 2007.
Retrospective application of EITF Issue
06-11 is not
permitted. Early adoption is permitted; however, the Company
does not intend to adopt EITF Issue
06-11 prior
to the required effective date of January 1, 2008. The
Company does not expect the adoption of EITF Issue
06-11 to
have a significant effect on its financial statements since the
Company historically has accounted for the income tax benefits
of dividends paid for share-based payment awards in the manner
described in the consensus.
In May 2007, the FASB issued FSP
FIN No. 48-1,
Definition of Settlement in FASB Interpretation
No. 48, to clarify when a tax position is effectively
settled. This guidance is important in determining the proper
timing for recognizing tax benefits and applying the new
information relevant to the technical merits of a tax position
obtained during a tax authority examination. The FSP provides
criteria to determine whether a tax position is effectively
settled after completion of a tax authority examination, even if
the potential legal obligation remains under the statute of
limitations. The Company adopted FIN No. 48
Accounting for Uncertainty in Income Taxes an
Interpretation of FASB Statement 109 effective
January 1, 2007. Its adoption and subsequent application of
FIN No. 48 is consistent with the provisions of FSP
FIN No. 48-1.
Note F. Asset
retirement obligations
The Companys asset retirement obligations represent the
estimated present value of the estimated cash flows the Company
will incur to plug, abandon and remediate its producing
properties at the end of their production lives, in accordance
with applicable state laws. The Company does not provide for a
market risk premium associated with asset retirement obligations
because a reliable estimate cannot be determined. The Company
has no assets that are legally restricted for purposes of
settling asset retirement obligations.
The following table summarizes the Companys asset
retirement obligation transactions recorded in accordance with
the provisions of SFAS No. 143 during the years ended
December 31, 2005 and 2006 and the nine months ended
September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
September 30,
|
|
(in thousands)
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
|
Asset retirement obligations, beginning of period
|
|
$
|
890
|
|
|
$
|
1,120
|
|
|
$
|
8,700
|
|
Liability incurred upon acquiring and drilling wells
|
|
|
196
|
|
|
|
7,443
|
|
|
|
309
|
|
Accretion expense
|
|
|
89
|
|
|
|
287
|
|
|
|
334
|
|
Liabilities settled upon plugging and abandoning wells
|
|
|
(2
|
)
|
|
|
|
|
|
|
(34
|
)
|
Revisions to estimated cash flows
|
|
|
(53
|
)
|
|
|
(150
|
)
|
|
|
(2,032
|
)
|
|
|
|
|
|
|
Asset retirement obligations, end of period
|
|
$
|
1,120
|
|
|
$
|
8,700
|
|
|
$
|
7,277
|
|
|
|
|
|
|
|
|
|
F-22
|
|
Note G.
|
Stockholders
equity and stock issued subject to limited recourse
notes
|
Equity commitments. Pursuant to a stock
purchase agreement (the Stock Purchase Agreement)
entered into on August 13, 2004, the Company obtained
private equity commitments totaling $202.5 million,
comprised of equity commitments from fourteen private investors
(the Private Investors) of approximately
$188.9 million and equity commitments from the five
original officers (the Officers) of the Company in
the aggregate amount of $13.6 million. The original
commitments were subject to call by a vote of the Board of
Directors over a four year period beginning August 13, 2004
(the Take-Down Period), with the first date on which
capital was called being August 13, 2004. Subsequent calls
were made on November 11, 2004, June 22, 2005,
December 7, 2005 and February 10, 2006. The percentage
of total commitments called per capital call date was
approximately 15.0 percent, 23.3 percent, 10.0 percent, 15.0
percent and 22.0 percent, respectively. In conjunction with the
exchange of CEHC common stock for Resources common stock as of
the date of the Combination, the remaining 14.7 percent of these
private equity commitments was terminated.
The Private Investors agreed to make their investment for cash
in the form of 18.9 million preferred unit (Preferred
Unit) purchases for $10 each. Each Preferred Unit
consisted of one share of 6% Series A Preferred Stock with
a stated value of $9 per share, and a one-half share of
CEHC common stock with a stated value of $1 per half share.
The per unit price remained constant throughout the Take-Down
Period.
The Officers committed to purchase 1.1 million Preferred
Units for a fixed price of $10 per unit, with 15 percent of
the purchase price paid in cash and the remaining 85 percent of
the purchase price paid by issuing notes payable to the Company
with recourse only to any equity security of the Company held by
the respective officer (the Purchase Notes). In
addition, the Officers agreed to purchase 5.3 million
shares of CEHC common stock (2.387 shares of CEHC common
stock for each Preferred Unit purchased) at a fixed price of
$1.00 per share to be paid in cash. The one Preferred Unit
and 2.387 shares of CEHC common stock are hereafter
collectively referred to as a Bundled Unit. The
purchase commitments for the Officers Bundled Units were
to be fulfilled as called by the Board of Directors over the
Take-Down Period proportionate to the committed equity purchases
made by the Private Investors described above. The
Officers commitments for Bundled Units totaled
$13.6 million, consisting of $11.0 million for
Preferred Units and $2.6 million for CEHC common stock. The
portion of Preferred Units to be financed with Purchase Notes
was $9.4 million.
In addition to this arrangement between the Private Investors
and the Officers, certain employees of the Company entered into
separate subscription agreements with the Company to purchase
Preferred Units. These subscription agreements had similar terms
to the Stock Purchase Agreement and were entered into over
various dates on dates beginning (for the original employees) on
August 13, 2004 and extending to employees who committed to
purchase shares and joined the Company through January 1,
2006. For subscription agreements entered into through
April 15, 2005, the per unit price was $10. Subsequent to
that date, the per unit price was $15. Notable differences
between the Officers subscription agreements and the
employees subscription agreements were: (i) the
amount of the purchase price required to be paid in cash by most
employees was 25 percent of the Preferred Unit price and the
amount of the Purchase Note was 75 percent of the Preferred Unit
price (rather than the 15 percent and 85 percent, respectively,
required of the Officers), and (ii) the employees did not
have the right or obligation to purchase CEHC common shares in
addition to the Preferred Units. The total commitments made by
employees through individual subscription agreements were to
purchase 0.5 million Preferred Units for an aggregate value
of $5.7 million, of which $4.5 million could be
financed with Purchase Notes.
F-23
The arrangements described above (the Stock Purchase Agreement
and the individual employee subscription agreements) are
hereinafter referred to as the Subscription
Agreements.
Capital calls. On August 13, 2004, the
Company completed an initial capital call of 2,833,500 Preferred
Units from the Private Investors for $28,335,000 in cash. The
second capital call on November 11, 2004, principally
funded December 6, 2004, called for 4,401,370 Preferred
Units from the Private Investors for $44,014,000 in cash. The
Companys third capital call on June 22, 2005, funded
on July 1, July 15 and July 21, 2005, called for
1,889,000 Preferred Units from the Private Investors for
$18,890,000 in cash. The Companys fourth capital call on
December 7, 2005, completed on December 30, 2005,
called for an aggregate of 2,833,500 Preferred Units from the
Private Investors for an aggregate consideration of $28,335,000.
Of this amount, $9,953,000 had been received by the Company on
December 31, 2005 and the remaining $18 million was
included in Accounts receivablerelated parties in
the accompanying consolidated balance sheet at December 31,
2005. This receivable was collected in full by January 9,
2006. The Companys fifth capital call on February 10,
2006, principally funded February 23, 2006, called for
4,155,800 Preferred Units from the Private Investors for
$41,558,000 in cash.
Additionally, on August 13, 2004, the Officers and certain
employees of the Company purchased 394,001 shares of CEHC
common stock and 177,750 Preferred Units for consideration
consisting of $668,000 in cash and Purchase Notes in the
aggregate principal amount of $1,504,000. For the second capital
call, principally funded December 6, 2004, the Officers and
certain employees of the Company purchased an additional
611,859 shares of CEHC common stock and 276,105 Preferred
Units for consideration consisting of $1,037,000 in cash and
Purchase Notes in the aggregate principal amount of $2,336,000.
For the third capital call, funded on July 1 and
July 15, 2005, the Officers and certain employees of the
Company purchased 262,601 shares of CEHC common stock and
147,750 Preferred Units for consideration consisting of $500,000
in cash and Purchase Notes in the aggregate principal amount of
$1,248,000. For the fourth capital call, completed
December 30, 2005, the Officers and employees of the
Company purchased 393,901 shares of CEHC common stock and
an aggregate of 234,378 Preferred Units for consideration of
$798,000 in cash and Purchase Notes in the aggregate principal
amount of $2,015,000. Of the cash amount, $464,000 had been
received by the Company prior to December 31, 2005 and the
remaining $334,000 was included in Accounts
receivablerelated parties in the accompanying
consolidated balance sheet at December 31, 2005. This
receivable was collected in full by February 2, 2006. For
the Companys fifth capital call, principally funded
February 23, 2006, the Officers and certain employees
purchased 577,721 shares of CEHC common stock and 351,670
Preferred Units for consideration consisting of $1,200,000 in
cash and Purchase Notes in the aggregate principal amount of
$3,044,000.
Eleven employees of the Company, hired at various dates during
the year ended December 31, 2005, purchased when hired, an
aggregate of 165,743 Preferred Units for consideration
consisting of $412,000 in cash and Purchase Notes in the
aggregate principal amount of $1,543,000. Of the cash amount,
$364,000 had been received by the Company prior to
December 31, 2005 and the remaining $48,000 was included in
Accounts receivablerelated parties in the
accompanying consolidated balance sheet at December 31,
2005. This receivable was collected in full by February 23,
2006. Two additional employees, hired as of January 1,
2006, purchased when hired an aggregate of 10,128 Preferred
Units for consideration consisting of $38,000 in cash and
Purchase Notes in the aggregate principal amount of $114,000.
Through February 23, 2006, the Private Investors purchased
16,113,170 Preferred Units for $161.1 million in cash. The
Officers had purchased 2,240,083 CEHC common shares and 938,303
F-24
Preferred Units for $3.6 million in cash and Purchase Notes
totaling $8.0 million. Certain employees purchased 425,221
Preferred Units for $1.0 million in cash and Purchase Notes
totaling $3.8 million.
Series A preferred stock. The preferred
stock of the Company consists of 30 million authorized
shares of 6% Series A Preferred Stock with a stated value
of $9.00 per share and par value of $0.01 per share.
Such shares bear a 6 percent dividend, payable annually in
arrears with accrual of such dividend commencing on the date of
issue. The Company may elect to pay the dividend in whole or in
part in cash or in additional Units. Upon liquidation, the 6%
Series A Preferred Stock would be ranked senior to all
other classes of shares.
Preferred stock dividends are generally paid on the anniversary
of date of issue. Preferred stock dividends of $4,160,000 and
$2,567,000 were paid during the years ended December 31,
2005 and 2006, respectively. Preferred stock dividends of
$2,542,000 and $132,000 were paid during the nine months ended
September 30, 2006 and 2007, respectively. As discussed in
Note AOrganization and nature of operations
and below, the majority of the CEHC preferred stock was
converted into Resources common stock on the Combination date.
Final dividend payments on converted CEHC 6% Series A
Preferred Stock were paid in March 2006.
Dividend payments continued to be made to the eighteen employee
shareholders that did not convert their shares of CEHC preferred
stock to Resources common stock through April 16, 2007. On
April 16, 2007, these CEHC preferred shares were exchanged
for 190,972 shares of the Companys common stock. These
shares are reported as if converted on the Combination date.
Preferred stock. The Board of Directors is
authorized to issue up to 10,000,000 shares of preferred stock
with a par value of $0.001 per share (Preferred
Stock). The Board of Directors will determine for each
series of issuance:
|
|
|
the number of shares in any series
|
|
|
voting powers, if any
|
|
|
redemption provisions, if any
|
|
|
dividend rate and other dividend attributes and
|
|
|
convertible features or attached rights, if any.
|
As of September 30, 2007, no shares of Preferred Stock had
been issued.
Notes receivable from Officers and certain
employees. At December 31, 2005,
December 31, 2006, and September 30, 2007, the Company
had Purchase Notes receivable from the Officers and certain
employees of approximately $9,012,000, $12,858,000 and
$2,488,000, respectively. These amounts were comprised of
aggregate principal amounts of $8,645,000, $11,803,000 and
$2,214,000, respectively, and accrued interest of $367,000,
$1,055,000 and $274,000, respectively. The maturity date of the
Purchase Notes, five years from the date of issuance, range from
August 13, 2009 to January 1, 2011, and the stated
annual interest rate on all Purchase Notes is 6 percent.
Interest is compounded annually; all accrued and unpaid interest
on the Purchase Notes is due and payable at maturity.
Performance of the Officers and all but one of the
employees obligations under these Purchase Notes is
secured by security interests granted by each of the Officers
and certain employees of the Company in all equity securities of
the Company purchased. Additionally, with respect to one
employee, the Company has full recourse against the assets of
the employee for collection of amounts due upon the occurrence
of a default that is not remedied.
F-25
On April 23, 2007, the executive officers repaid their
Purchase Notes in full, including principal of $9,426,000 and
accrued interest of $1,037,000. The agreements to sell stock to
the executive officers of the Company subject to Purchase Notes
were accounted for as the issuance of options. As such, the
repayment of the executive officer Purchase Notes represents the
full exercise of the options on the Bundled Capital Options (as
defined below) the Officers held as well as the Capital Options
(as defined below) of one certain employee who is currently an
executive officer.
Accounting for issuances to Officers and certain
employees. Based on guidance contained in
SFAS No. 123R, the agreements to sell stock to the
Officers and certain employees subject to Purchase Notes are
accounted for as the issuance of options (Capital
Options) on the dates that the various Subscription
Agreements were signed and the purchase commitments were made.
Factors that led to the Companys determination of this
accounting treatment included (i) the non-recourse nature
of the Purchase Notes, (ii) the ability of the Officers or
certain employees to elect not to purchase the CEHC common stock
or Preferred Units, and (iii) the absence of substantial
penalties for choosing not to participate in capital calls,
other than the inability to participate in subsequent capital
calls.
In the case of committed equity issuances to the Officers, the
Company also considered the close relationship between the
Preferred Units and the CEHC common shares. As discussed above,
the CEHC common shares were (and all equity securities of the
Company held by the Officers now are) additional security for
the Purchase Notes, and the Officer could not choose to purchase
one security without fulfilling his associated commitment to
purchase the other. As a result, the commitment to purchase
Preferred Units and CEHC common shares by the Officers is
treated as one bundled Capital Option (Bundled
Capital Option). Discussions in these financial statements
about Capital Options include Bundled Capital Options unless a
separate breakdown between Capital Options and Bundled Capital
Options is provided.
The Capital Options issued to certain employees and the Officers
were considered to vest based upon performance criteria, which
the Company determined to be the action of the CEHC Board of
Directors in making a capital call. Compensation expense was
recorded based on the grant date fair value of Capital Options
vested at each date vesting occurred by approval of a capital
call by the CEHC Board of Directors. Consequently, no
compensation expense will be recorded for Capital Options which
were not vested by a capital call.
Valuation of stock issuances treated as Capital
Options. As discussed in
Note BSummary of significant accounting
policies, effective January 1, 2005, the Company
adopted the provisions of SFAS No. 123R, using the
modified retrospective basis to account for its stock-based
compensation plans. In calculating the grant date fair value and
compensation expense for the issuances treated as grants of
Capital Options, the Company estimated the fair value of each
grant using
F-26
the Black-Scholes option-pricing model. The weighted average
assumptions utilized in the model were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
2005
|
|
2006
|
|
|
Risk-free interest rates
|
|
|
3.14%
|
|
|
3.76%
|
|
|
4.37%
|
Expected life
|
|
|
4.00 years
|
|
|
3.28 years
|
|
|
2.61 years
|
Expected volatility
|
|
|
43.30%
|
|
|
34.99%
|
|
|
34.33%
|
Expected dividend yield
|
|
|
0%
|
|
|
0%
|
|
|
0%
|
|
|
The expected life of each Capital Option was based on an initial
expected term of four years beginning on August 13, 2004.
This four year term was determined by management based on
experience with similarly organized companies and the
expectation of either a public offering of the Companys
stock or the sale of the Company or its assets during that time
period, leading to an expected exercise of all options.
Volatilities are based on historical volatilities of publicly
traded securities of similarly sized domestic exploration and
production companies.
There are no tax benefits related to either the Bundled Capital
Options or the Capital Options.
The following table summarizes the Bundled Capital Options
granted to the Officers for the period from Inception
(April 21, 2004) through December 31, 2004, the
years ended December 31, 2005 and 2006 and the nine months
ended September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
Weighted
|
|
|
|
|
Bundled Capital
|
|
average
|
|
Grant date
|
|
|
Options
|
|
exercise price
|
|
fair value
|
|
|
Period from inception (April 21, 2004)
|
|
|
|
|
|
|
|
|
|
through December 31, 2004
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of period
|
|
|
|
|
$
|
|
|
|
|
Bundled Capital Options granted
|
|
|
1,100,000
|
|
$
|
9.52
|
|
$
|
2,310,000
|
Cancelled / forfeited
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
1,100,000
|
|
$
|
9.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested outstanding at end of period
|
|
|
421,299
|
|
$
|
9.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2005
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of period
|
|
|
1,100,000
|
|
$
|
9.52
|
|
|
|
Bundled Capital Options granted
|
|
|
|
|
$
|
|
|
$
|
|
Cancelled / forfeited
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
1,100,000
|
|
$
|
9.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested outstanding at end of period
|
|
|
696,303
|
|
$
|
9.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-27
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Weighted
|
|
|
Bundled Capital
|
|
|
average
|
|
|
Options
|
|
|
exercise price
|
|
|
Year ended December 31, 2006
|
|
|
|
|
|
|
|
Outstanding at beginning of period
|
|
|
1,100,000
|
|
|
$
|
9.52
|
Cancelled / forfeited
|
|
|
(161,697
|
)
|
|
$
|
9.52
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
938,303
|
|
|
$
|
9.52
|
|
|
|
|
|
|
|
|
Vested outstanding at end of period
|
|
|
938,303
|
|
|
$
|
9.52
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2007
|
|
|
|
|
|
|
|
Outstanding at beginning of period
|
|
|
938,303
|
|
|
$
|
9.52
|
|
|
|
|
|
|
|
|
Bundled Capital Options exercised
|
|
|
(938,303
|
)
|
|
$
|
9.52
|
Outstanding at end of period
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
Vested outstanding at end of period
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Subsequent to February 27, 2006, each Bundled Capital
Option is exercisable for 3.637 shares of Resources common
stock.
The following table summarizes information about the
Companys Vested Bundled Capital Options outstanding and
exercisable at December 31, 2006 and September 30,
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested Bundled Capital Options Outstanding and Exercisable
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Number
|
|
average
|
|
Weighted
|
|
|
|
|
outstanding,
|
|
remaining
|
|
average
|
|
|
|
|
vested and
|
|
contractual
|
|
exercise
|
|
Intrinsic
|
Date
|
|
exercisable
|
|
life
|
|
price
|
|
value
|
|
|
December 31, 2006
|
|
|
938,303
|
|
3.45 years
|
|
$
|
9.52
|
|
$
|
45,655,000
|
The total amount of cash and Purchase Notes delivered for each
Bundled Unit during the capital call period of CEHC was $12.39
consisting of $10.00 for each Preferred Unit which included a
one-half CEHC common share and one CEHC preferred share, and
$1.00 per bundled CEHC common share (2.387 CEHC common
shares per bundle totaling $2.39 per Bundled Unit). Each
Bundled Unit issued to the Officers also required a cash payment
of $3.89
per-unit
which includes 15 percent of the $10.00 Preferred Unit
price or $1.50 plus the $2.39 for the additional common shares
included in the Bundled Unit. The weighted average exercise
price is derived from the per Bundled Unit amount of the
Purchase Notes (85 percent of the $10.00 Preferred Unit
price or $8.50) adjusted for interest on such Purchase Notes and
dividends on CEHC preferred shares included in the Bundled Unit
through the estimated Purchase Note repayment or
exercise date.
As mentioned above, Bundled Capital Options issued to the
Officers vested upon the action of the CEHC Board of Directors
in making a capital call. As of the date of the Combination, all
remaining capital commitments were terminated; therefore, there
will be no future CEHC capital calls. As a result, no
compensation expense will be recognized on the unvested 161,697
Bundled Capital Options because they were terminated on
February 27, 2006. The grant date fair value associated
with the unvested options was $339,000.
F-28
The following table summarizes the Capital Options granted to
certain employees for the period from Inception (April 21,
2004) through December 31, 2004, the years ended
December 31, 2005 and 2006 and the nine months ended
September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Weighted
|
|
|
|
|
Capital
|
|
|
average
|
|
Grant date
|
|
|
Options
|
|
|
exercise price
|
|
fair value
|
|
|
Period from inception (April 21, 2004)
|
|
|
|
|
|
|
|
|
|
|
through December 31, 2004
|
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of period
|
|
|
|
|
|
$
|
|
|
|
|
$10 Capital Options granted
|
|
|
85,000
|
|
|
$
|
8.40
|
|
$
|
169,000
|
Cancelled / forfeited
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
85,000
|
|
|
$
|
8.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested outstanding at end of period
|
|
|
32,555
|
|
|
$
|
8.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of period
|
|
|
85,000
|
|
|
$
|
8.40
|
|
|
|
$10 Capital Options granted
|
|
|
277,500
|
|
|
$
|
9.05
|
|
$
|
1,528,000
|
$15 Capital Options granted
|
|
|
120,000
|
|
|
$
|
12.28
|
|
$
|
251,000
|
Cancelled / forfeited
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
482,500
|
|
|
$
|
9.74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested outstanding at end of period
|
|
|
305,422
|
|
|
$
|
9.74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of period
|
|
|
482,500
|
|
|
$
|
9.74
|
|
|
|
$10 Capital Options granted
|
|
|
|
|
|
$
|
|
|
$
|
|
$15 Capital Options granted
|
|
|
16,000
|
|
|
$
|
12.13
|
|
$
|
45,000
|
Cancelled / forfeited
|
|
|
(73,279
|
)
|
|
$
|
9.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
425,221
|
|
|
$
|
9.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested outstanding at end of period
|
|
|
425,221
|
|
|
$
|
9.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of period
|
|
|
425,221
|
|
|
$
|
9.81
|
|
|
|
$10 Capital Options exercised
|
|
|
(179,557
|
)
|
|
$
|
9.30
|
|
|
|
$15 Capital Options exercised
|
|
|
(8,530
|
)
|
|
$
|
12.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
237,134
|
|
|
$
|
10.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested outstanding at end of period
|
|
|
237,134
|
|
|
$
|
10.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsequent to February 27, 2006, each Capital Option is
exercisable for 1.25 shares of Resources common stock.
F-29
The following table summarizes information about the
Companys vested Capital Options outstanding and
exercisable at December 31, 2006 and September 30,
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested Capital Options Outstanding and Exercisable
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
Number
|
|
average
|
|
Weighted
|
|
|
|
|
|
|
outstanding,
|
|
remaining
|
|
average
|
|
|
|
|
Exercise
|
|
vested and
|
|
contractual
|
|
exercise
|
|
Intrinsic
|
Date
|
|
prices
|
|
exercisable
|
|
life
|
|
price
|
|
value
|
|
|
December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
10.00
|
|
|
309,213
|
|
|
3.61 years
|
|
$
|
8.90
|
|
$
|
3,268,000
|
|
|
$
|
15.00
|
|
|
116,008
|
|
|
3.83 years
|
|
$
|
12.26
|
|
$
|
633,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
425,221
|
|
|
|
|
$
|
9.81
|
|
$
|
3,901,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
10.00
|
|
|
129,656
|
|
|
2.79 years
|
|
$
|
8.33
|
|
$
|
970,000
|
|
|
$
|
15.00
|
|
|
107,478
|
|
|
3.07 years
|
|
$
|
12.27
|
|
$
|
237,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
237,134
|
|
|
|
|
$
|
10.12
|
|
$
|
1,207,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Each Preferred Unit issued to employees also required a cash
payment of approximately 25 percent of the total unit
price, resulting in a weighted average per unit cash payment of
$2.06, $2.37 and $2.36 per unit for total Capital Options
granted in 2004, 2005 and 2006, respectively. The weighted
average exercise price is derived from the per unit amount of
the Purchase Note adjusted for interest on such notes and
dividends on CEHC preferred shares included in the unit through
the estimated repayment or exercise date.
As mentioned above, Capital Options issued to certain employees
vested upon the action of the CEHC Board of Directors in making
a capital call. Upon the closing of the Combination, all
remaining capital commitments were terminated; therefore, there
will be no future capital calls. As a result, no compensation
expense will be recognized on the unvested 73,279 Capital
Options because they were terminated on February 27, 2006.
The grant date fair value associated with the unvested options
was $293,000.
The following table summarizes the stock-based compensation for
all Capital Options and is included in General and
administrative expense in the accompanying consolidated
statement of
F-30
operations for the periods ended December 31, 2004, 2005
and 2006 and for the nine months ended September 30, 2006
and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inception
|
|
|
|
|
|
|
|
|
|
|
(April 21, 2004)
|
|
|
|
|
|
|
|
|
|
|
through
|
|
Year ended
|
|
Year ended
|
|
Nine months ended
|
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
September 30,
|
|
|
2004
|
|
2005
|
|
2006
|
|
2006
|
|
2007
|
|
|
Stock-based compensation expense from Capital Options:
|
|
$
|
950,000
|
|
$
|
1,746,000
|
|
$
|
975,000
|
|
$
|
975,000
|
|
$
|
|
|
|
|
|
|
|
Bundled Capital Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense
|
|
$
|
885,000
|
|
$
|
578,000
|
|
$
|
508,000
|
|
$
|
508,000
|
|
$
|
|
Options vesting during period
|
|
|
421,299
|
|
|
275,004
|
|
|
242,000
|
|
|
242,000
|
|
|
|
Weighted average grant date fair value per option
|
|
$
|
2.10
|
|
$
|
2.10
|
|
$
|
2.10
|
|
$
|
2.10
|
|
$
|
|
Capital Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense
|
|
$
|
65,000
|
|
$
|
1,168,000
|
|
$
|
467,000
|
|
$
|
467,000
|
|
$
|
|
Options vesting during period
|
|
|
32,555
|
|
|
272,867
|
|
|
119,799
|
|
|
119,799
|
|
|
|
Weighted average grant date fair value per option
|
|
$
|
2.00
|
|
$
|
4.28
|
|
$
|
3.90
|
|
$
|
3.90
|
|
$
|
|
|
|
Conversion of CEHC 6% Series A Preferred Stock and
CEHC common stock. On February 27, 2006,
concurrent with the closing of the Combination described in
Note AOrganization and nature of operations
and Note DAcquisitions and business
combinations, the majority of the shares of CEHC preferred
stock and shares of CEHC common stock outstanding were converted
to shares of Resources common stock, as described below.
A total of 17,222,073 shares of CEHC preferred stock
outstanding and held by the Private Investors, the Officers and
one employee were converted to shares of Resources common stock
at the ratio of 0.75 shares of Resources common stock for
each share of CEHC preferred stock, resulting in the issuance of
12,916,564 shares of Resources common stock. Dividends
accrued through the date of conversion in the amount of
$2,491,000 were paid to the holders of the CEHC preferred stock
who were subject to the conversion. A total of 10,851,126 shares
of CEHC common stock outstanding and held by the Officers and
one employee were converted to shares of Resources common stock
at the ratio of 1:1.
Eighteen employee shareholders owning an aggregate of
254,621 shares of CEHC preferred stock and 127,313 shares
of CEHC common stock did not convert their shares to Resources
common stock at the date of the Combination. On April 16,
2007, these remaining shares of CEHC were exchanged for
318,285 shares of the Companys common stock. These
shares are reported as if converted on the Combination date. In
addition, CEHC made a final dividend payment to these eighteen
employee shareholders on their CEHC preferred stock in the
aggregate amount of $98,511 on April 16, 2007.
Also in conjunction with the Combination described in
Note AOrganization and nature of operations
and Note DAcquisitions and business
combinations and the conversion of CEHC preferred stock into
Resources common stock at the ratio of 0.75:1, the CEHC Bundled
Capital Options were converted into Resources Bundled Capital
Options and CEHC Capital Options were converted into Resources
Capital Options. The Resources Bundled Capital Options are each
considered to be exercisable for 3.637 shares of Resources
common stock and the Resources Capital Options are considered to
be exercisable for 1.25 shares of Resources common stock.
F-31
The following table summarizes the conversion of the Bundled
Capital Options and Capital Options in conjunction with the
Combination:
Officer
group:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bundled Capital Option
|
|
Bundled Capital Option
|
|
|
|
|
|
|
Preferred
Unit(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
CEHC preferred
|
|
|
|
|
|
|
Bundled
|
|
|
|
|
|
stock to
|
|
Total
|
|
Total
|
|
|
Capital
|
|
Common
|
|
Common
|
|
Resources
|
|
common
|
|
preferred
|
|
|
Options(b)
|
|
stock(c)
|
|
stock
|
|
common stock
|
|
stock
|
|
stock
|
|
|
CEHC vested
|
|
|
938,303
|
|
|
4,480,157
|
|
|
938,303
|
|
|
938,303
|
|
|
5,418,460
|
|
|
938,303
|
Conversion ratios
|
|
|
1.00
|
|
|
0.50
|
|
|
0.50
|
|
|
0.75
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources vested
|
|
|
938,303
|
|
|
2,240,083
|
|
|
469,156
|
|
|
703,730
|
|
|
3,412,969
|
|
|
|
|
|
|
|
|
|
|
|
Certain employees
group:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Option
|
|
Capital Option
|
|
|
|
|
Preferred
Unit(a)
|
|
|
|
|
|
|
|
|
|
|
CEHC preferred
|
|
|
|
|
|
|
|
|
|
|
stock to
|
|
Total
|
|
Total
|
|
|
Capital
|
|
Common
|
|
Resources
|
|
common
|
|
preferred
|
|
|
Options(d)
|
|
stock
|
|
common stock
|
|
stock
|
|
stock
|
|
|
CEHC vested
|
|
|
425,221
|
|
|
425,221
|
|
|
425,221
|
|
|
425,221
|
|
|
425,221
|
Conversion ratios
|
|
|
1.00
|
|
|
0.50
|
|
|
0.75
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources vested
|
|
|
425,221
|
|
|
212,613
|
|
|
318,923
|
|
|
531,536
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Each Preferred Unit reflects one
share of CEHC preferred stock and one-half of a share of CEHC
common stock. Each share of CEHC preferred stock can be
converted into 0.75 shares of Resources common stock.
|
|
(b)
|
|
Each Bundled Capital Option
reflects 2.387 shares of CEHC common stock and one
Preferred Unit. Each Bundled Capital Option can be converted
into 3.637 shares of Resources common stock.
|
|
(c)
|
|
The Officers agreed to purchase
2.387 shares of CEHC common stock for each Preferred Unit
purchased.
|
|
(d)
|
|
Each Capital Option reflects one
Preferred Unit. Each Capital Option can be converted into
1.25 shares of Resources common stock.
|
Common stock held in escrow. On
February 27, 2006 the Company entered into an agreement
with certain stockholders of the Company in which certain of the
Companys shareholders placed 430,755 shares of
Resources common stock in an escrow account (the Escrow
Agreement). The Escrow Agreement provided that if, on or
before February 27, 2007 (the Initial Period),
the Company consummated one of two specified transactions, the
shares held in escrow would be released to the Company for
reissuance to Messrs. Leach, Beal, Copeland, Kamradt and
Wright. Neither of those specified transactions occurred in the
Initial Period. However, the Escrow Agreement specified that if
neither of the two specified transactions occurred during the
Initial Period, a sale of the Company in a business combination
on or before August 26, 2007 where the per share valuation
of the Companys common stock in such sale was equal to or
greater than $28.00 per share would result in the release of the
shares held in escrow to the Company for reissuance to
Messrs. Leach, Beal, Copeland, Kamradt and Wright.
F-32
These shares have been treated as issued and outstanding in the
consolidated financial statements at December 31, 2006.
Because this condition did not occur, the escrow agent
distributed the escrowed shares to the registered owners thereof
that originally deposited the shares.
Registration rights agreement. In
connection with the Combination, the Company entered into a
registration rights agreement with the current stockholders of
Resources. According to the registration rights agreement,
holders of either 20 percent of the aggregate shares held
by the Chase Group or 20 percent of the aggregate shares
held by the former stockholders of CEHC may request in writing
that the Company register their shares by filing a registration
statement under the Securities Act of 1933 (the Securities
Act), so long as the anticipated aggregate offering price,
net of underwriting discounts and commissions, exceeds
$50 million.
If the Company proposes to file a registration statement under
the Securities Act relating to an offering of Resources common
stock, upon the written request of holders of registrable
securities, the Company is required to use its commercially
reasonable efforts to include in such registration, and any
related underwriting, all of the registrable securities
requested to be included, subject to customary cutback
provisions. There is no limit to the number of these
piggy-back registrations in which these holders may
request their shares to be included.
The Company generally will bear the registration expenses
incurred in connection with any registration, including all
registration, filing and qualification fees, printing and
accounting fees, but excluding underwriting discounts and
commissions. The Company has agreed to indemnify these
stockholders against certain liabilities, including liabilities
under the Securities Act, in connection with any registration
effected under the registration rights agreement. The Company is
not obligated to affect any registration more than one time in
any six month period and these registration rights terminate
10 years after the date of closing of the initial offering.
Note H.
Stock incentive plan
On August 13, 2004, the Board of Directors approved a stock
option plan (the Stock Option Plan) that is
administered by the Boards Compensation Committee and
provides for the granting of incentive awards in the form of
stock options to employees of the Company. Prior to the
Combination, the options granted were to purchase Preferred
Units in CEHC. As of February 27, 2006, in conjunction with
the conversion of the CEHC preferred stock and CEHC common stock
into Resources common stock, the Company adopted and restated
the Stock Option Plan to reflect such events (the Amended
and Restated Stock Option Plan). The option holders and
the Company had the same rights in the Amended and Restated
Stock Option Plan as they did in the Stock Option Plan. The
Amended and Restated Stock Option Plan changed the option
exercise prices to reflect the conversion and exchange
transactions, and changed the vesting schedule for all
outstanding stock options.
Effective June 1, 2006, the Board of Directors approved the
2006 Stock Incentive Plan (together with applicable option
agreements and restricted stock agreements, the
Plan) that provides for granting stock options and
restricted stock awards to employees and individuals associated
with the Company. The Plan generally supersedes the Amended and
Restated Stock Option Plan. The Plan, administered by the
Compensation Committee, may grant stock options, restricted
stock awards or any combination thereof not to exceed an
aggregate maximum number of 5,850,000 shares of common
stock.
F-33
Restricted stock awards. On June 1,
2006, the Compensation Committee approved the issuance of
restricted stock to eight of the Companys directors. Under
the Plan, the Company issued 40,000 shares of common stock,
subject to certain restrictions as set forth in the Plan. These
restrictions lapsed with respect to 100 percent of the
restricted shares on January 2, 2007.
On June 28, 2006, the Company issued 155,764 shares of
common stock to certain non-officer employees, subject to
certain restrictions as set forth in the Plan. Provided that the
employee has been continuously employed by the Company from the
date of grant through the lapse date, the restrictions will
lapse with respect to 100 percent of the restricted shares
on the earlier of (i) the third annual anniversary of the
date of grant, (ii) the date upon which a change of
control, as defined in the Plan, occurs, or (iii) the date
upon which the employees employment with the Company is
terminated by reason of death, disability or involuntary
termination, as defined in the Plan. During the third and fourth
quarters of 2006, as defined in the Plan, the Company issued
16,340 and 1,480 additional shares, respectively, of common
stock to new employees, subject to the same restrictions
described above.
On April 23, 2007, the Company issued a total of
20,000 shares of restricted common stock comprised of
2,500 shares to each of the eight outside directors subject
to certain restrictions as set forth in the Plan. These
restrictions lapsed with respect to 100 percent of the
restricted shares on April 23, 2007, the date of grant. The
grant date fair value of the stock was estimated to be
approximately $340,000 which the Company recognized as
stock-based compensation expense in April 2007.
In August 2007, the Companys board of directors appointed
a new director who was granted 5,000 shares of restricted
common stock by the Compensation Committee of the Companys
board of directors in accordance with the Companys
director compensation plan, subject to certain restrictions as
set forth in the Plan and a restricted stock agreement between
the Company and such director. These restrictions lapse with
respect to 100 percent of the restricted shares twelve
months from the date of grant. The grant date fair value of the
stock was estimated by the Company to be approximately $64,000,
which the Company will recognize as stock-based compensation
expense over twelve months beginning August 2007.
In September 2007, the Compensation Committee of the
Companys board of directors approved the grant of
112,540 shares of restricted common stock to the
non-officer employees of the Company, subject to certain
restrictions as set forth in the Plan and respective restricted
stock agreements between the Company and each such employee.
These restrictions lapse with respect to 100 percent of the
restricted shares three years from the date of grant. The grant
date fair value of the stock was estimated by the Company to be
approximately $1,629,000 which the Company will recognize as
stock-based compensation expense over the next three years
beginning September 2007.
All restricted shares are treated as issued and outstanding in
the accompanying consolidated balance sheets. If an employee
terminates employment prior the lapse date, the awarded shares
are forfeited and cancelled and are no longer considered issued
and outstanding. A summary of
F-34
the Companys restricted stock awards during the year ended
December 31, 2006 and the nine months ended
September 30, 2007 is presented below:
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Grant date
|
|
|
common shares
|
|
|
fair value
|
|
|
Restricted stock:
|
|
|
|
|
|
|
|
Outstanding at January 1, 2006
|
|
|
|
|
|
|
|
Shares granted
|
|
|
213,584
|
|
|
$
|
3,289,000
|
Shares canceled / forfeited
|
|
|
(1,368
|
)
|
|
|
|
Lapse of restrictions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006
|
|
|
212,216
|
|
|
|
|
Shares granted
|
|
|
137,540
|
|
|
$
|
2,033,000
|
Shares cancelled / forfeited
|
|
|
|
|
|
|
|
Lapse of restrictions
|
|
|
(60,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2007
|
|
|
289,756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company recorded stock-based compensation for restricted
stock of $1,044,000 and $1,007,000, which is recognized in
General and administrative expense in the accompanying
consolidated statement of operations, for the year ended
December 31, 2006 and the nine months ended
September 30, 2007, respectively. Future stock-based
compensation expense related to restricted stock outstanding at
December 31, 2006 for the years ended December 31,
2007, 2008 and 2009 is approximately $882,000, $882,000, and
$454,000 respectively. Future stock-based compensation expense
related to restricted stock outstanding at September 30,
2007 for the remaining three months of 2007 and the years ended
December 31, 2008 and 2009 is approximately $370,000,
$1,420,000, 992,000 and $403,000 respectively. The income tax
benefit recognized in the accompanying statement of operations
for restricted stock was approximately $407,000 and $422,000 for
the year ended December 31, 2006 and the nine months ended
September 30, 2007.
Stock option awards. The stock options
granted from August 13, 2004 through February 23, 2006 under the
Stock Option Plan were to purchase Preferred Units. A portion of
the options vested based upon passage of time (Time
Vesting) and a portion of the options vested based upon
the Company obtaining certain results related to a liquidation
value (Performance Vesting). Seventy-eight percent
of the aggregate options granted were vested based on Time
Vesting, in which they vested one-third each year for a three
year period, which would result in approximately
61 percent, 28 percent and 11 percent of their
total grant date fair value being expensed in the first, second
and third years, respectively, commencing on the first
anniversary of the date of grant. The remaining 22 percent
of the aggregate options granted were vested based on
Performance Vesting. Performance Vesting was considered to be
achieved when the Company attained a liquidation valuation which
resulted in a 25 percent internal rate of return and a
return on investment of two times the total dollars invested by
the original shareholders of the Company, upon the occurrence of
one of the following events:
(i) the liquidation, dissolution or winding up of the
affairs of the Company,
(ii) a sale of all or substantially all of the assets of
the Company and a distribution to the shareholders of the
proceeds of such sale, or
F-35
(iii) any merger, consolidation or other transaction
resulting in at least 50 percent of the voting securities
of the Company being owned by a single person or a group.
As a result of the Combination, event (iii) listed above
occurred, which resulted in a change of control as defined in
the Stock Option Plan. As such, the 78 percent of the
aggregate options which vested based on Time Vesting were
immediately vested as of the date of the Combination.
CEHCs Board of Directors determined that, based upon the
value received by the CEHC shareholders in the Combination, the
thresholds for internal rate of return and return on investment
which determined the portion of vesting based on Performance
Vesting, were not met and that 22 percent portion of the
options were not vested.
The CEHC Board of Directors later decided that CEHC would vest
the 22 percent of aggregate stock options based on
Performance Vesting for only the stock option holders who were
non-officers. The CEHC Board of Directors also determined CEHC
would vest the 22 percent of aggregate stock options based
on Performance Vesting for the officers at the end of three
years, which will result in approximately 33 percent,
33 percent and 34 percent of their total grant date
fair value being expensed in the first, second, and third years,
respectively, commencing on the first anniversary of the date of
grant.
A summary of CEHCs stock option activity, under the Stock
Option Plan, for the period from April 21, 2004 (CEHC
inception date) to December 31, 2004, the year ended
December 31, 2005 and the period ended February 27,
2006 (Combination date) is presented below. The amounts shown
are immediately prior to the conversion of CEHC stock options to
Resources stock options as a result of the Combination:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inception
|
|
|
|
|
|
|
(April 21, 2004)
|
|
|
|
January 1, 2006
|
|
|
through
|
|
Year ended
|
|
through February 27,
|
|
|
December 31, 2004
|
|
December 31, 2005
|
|
2006
|
|
|
|
|
Weighted
|
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
|
Number of
|
|
average
|
|
Number of
|
|
|
average
|
|
Number of
|
|
average
|
|
|
units(a)
|
|
price
|
|
units(a)
|
|
|
price
|
|
units(a)
|
|
price
|
|
|
Stock options for Preferred Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of period
|
|
|
|
|
$
|
|
|
|
724,257
|
|
|
$
|
10.00
|
|
|
1,365,075
|
|
$
|
10.32
|
Options granted
|
|
|
724,257
|
|
$
|
10.00
|
|
|
665,247
|
|
|
$
|
10.66
|
|
|
514,267
|
|
$
|
10.68
|
Options forfeited
|
|
|
|
|
$
|
|
|
|
(24,429
|
)
|
|
$
|
10.00
|
|
|
|
|
$
|
|
Options exercised
|
|
|
|
|
$
|
|
|
|
|
|
|
$
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
724,257
|
|
$
|
10.00
|
|
|
1,365,075
|
|
|
$
|
10.32
|
|
|
1,879,342
|
|
$
|
10.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period
|
|
|
|
|
$
|
|
|
|
182,033
|
|
|
$
|
10.00
|
|
|
1,562,770
|
|
$
|
10.51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Each option Unit can be exercised
for one Preferred Unit which is comprised of one-half of a share
of CEHC common stock and one share of CEHC preferred stock.
|
Also in conjunction with the Combination described in
Note AOrganization and nature of operations
and Note DAcquisitions and business
combinations and the conversion of CEHC preferred stock into
Resources common stock at the ratio of 0.75:1, the CEHC unit
options were
F-36
converted into Resources stock options. Each CEHC unit option,
(considered to be exchangeable for one share of CEHC preferred
stock and one-half of a share of CEHC common stock), was
converted into 1.25 options to purchase common stock of
Resources. Each Resources stock option is considered to be
exchangeable for one share of Resources common stock. The
following table summarizes the conversion of the CEHC unit
options in conjunction with the Combination:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CEHC
|
|
CEHC
|
|
|
|
Resources
|
|
|
Unit Option
|
|
Unit
|
|
Conversion
|
|
Option
|
|
Resources
|
Exercise Price
|
|
Options
|
|
Rate
|
|
Exercise Price
|
|
Options
|
|
|
$
|
10.00
|
|
|
1,721,010
|
|
|
1.25:1
|
|
$
|
8.00
|
|
|
2,151,129
|
$
|
15.00
|
|
|
158,332
|
|
|
1.25:1
|
|
$
|
12.00
|
|
|
197,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,879,342
|
|
|
|
|
|
Total
|
|
|
2,349,113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Under the Plan, effective June 12, 2006, the Companys
Board of Directors approved the issuance of 450,000 stock
options to the current officers of the Company, which is
comprised of the CEHC Officers and one certain employee. These
options have an exercise price of $12, a contractual term of
10 years from the date of grant, and vest using a four year
graded vesting schedule which will result in approximately
52 percent, 27 percent, 15 percent and
6 percent of their total grant date fair value being
expensed in the first, second, third and fourth years,
respectively, commencing on the first anniversary of the date of
grant. In November 2007, these stock options were modified
in order to comply with Section 409A of the Internal
Revenue Code. See further discussion in
Note RSubsequent events.
On August 15, 2007, the Companys board of directors
approved the issuance of 200,000 stock options to a newly
appointed officer of the Company and 15,000 stock options to a
non-officer employee of the Company under the Plan. These
options have an exercise price of $12.85, a contractual term of
10 years from the date of grant, and vest using a four year
graded vesting schedule.
In calculating the compensation expense for these options, the
Company has estimated the fair value of each grant using the
Black-Scholes option-pricing model. Assumptions utilized in the
model are shown below.
|
|
|
|
|
|
Risk-free interest rate
|
|
|
4.47
|
%
|
Expected term (years)
|
|
|
6.25
|
|
Expected volatility
|
|
|
37.33
|
%
|
Expected dividend yield
|
|
|
0.00
|
%
|
|
|
F-37
A summary of the Companys stock option activity under the
Plan, for the period from February 27, 2006 through
December 31, 2006 and the nine months ended
September 30, 2007 is presented below. The amounts shown
below are on a post-combination and post-conversion basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
February 27, 2006
|
|
Nine months ended
|
|
|
through December 31,
|
|
September 30,
|
|
|
2006
|
|
2007
|
|
|
|
|
|
Weighted
|
|
|
|
|
Weighted
|
|
|
Number of
|
|
|
average
|
|
Number of
|
|
|
average
|
|
|
options(a)
|
|
|
price
|
|
options(a)
|
|
|
price
|
|
|
Stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of period
|
|
|
2,349,113
|
|
|
$
|
8.34
|
|
|
2,797,997
|
|
|
$
|
8.93
|
Options granted
|
|
|
450,000
|
|
|
$
|
12.00
|
|
|
215,000
|
|
|
$
|
12.85
|
Options forfeited
|
|
|
(1,116
|
)
|
|
$
|
10.88
|
|
|
(1,275
|
)
|
|
$
|
8.00
|
Options exercised
|
|
|
|
|
|
$
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
2,797,997
|
|
|
$
|
8.93
|
|
|
3,011,722
|
|
|
$
|
9.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period
|
|
|
1,952,274
|
|
|
$
|
8.40
|
|
|
2,063,499
|
|
|
$
|
8.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
One option can be exercised for one
share of Resources common stock.
|
The following table summarizes information about the
Companys vested stock options outstanding and exercisable
at December 31, 2006 and September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested options outstanding and exercisable
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
Number
|
|
average
|
|
Weighted
|
|
|
|
|
|
|
outstanding,
|
|
remaining
|
|
average
|
|
|
|
|
Exercise
|
|
vested and
|
|
contractual
|
|
exercise
|
|
Intrinsic
|
Date
|
|
prices
|
|
exercisable
|
|
life
|
|
price
|
|
value
|
|
|
December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
8.00
|
|
|
1,755,094
|
|
|
8.47 years
|
|
$
|
8.00
|
|
$
|
15,099,000
|
|
|
$
|
12.00
|
|
|
197,180
|
|
|
8.86 years
|
|
$
|
12.00
|
|
$
|
769,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,952,274
|
|
|
|
|
$
|
8.40
|
|
$
|
15,868,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
8.00
|
|
|
1,753,819
|
|
|
7.72 years
|
|
$
|
8.00
|
|
$
|
11,944,000
|
|
|
$
|
12.00
|
|
|
309,680
|
|
|
8.33 years
|
|
$
|
12.00
|
|
$
|
870,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,063,499
|
|
|
|
|
$
|
8.60
|
|
$
|
12,814,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-38
As discussed in Note B Summary of
significant accounting policies, effective January 1,
2005, the Company adopted SFAS No. 123R using the
modified retrospective basis to account for its stock-based
compensation plans. The following table summarizes information
about stock-based compensation for options which is recognized
in General and administrative expense in the accompanying
consolidated statement of operations for the period from
inception (April 21, 2004) through December 31,
2004, years ended December 31, 2005 and 2006 and the nine
months ended September 30, 2006 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inception
|
|
|
|
|
|
Nine
|
|
|
(April 21, 2004)
|
|
Year ended
|
|
months ended
|
|
|
through December 31,
|
|
December 31,
|
|
September 30,
|
|
|
2004
|
|
2005
|
|
2006
|
|
2006
|
|
2007
|
|
|
Grant date fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time vesting
options(a)
|
|
$
|
2,013,000
|
|
$
|
2,891,000
|
|
$
|
1,931,000
|
|
$
|
1,931,000
|
|
$
|
87,000
|
Performance vesting options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Officers(b)
|
|
|
557,000
|
|
|
606,000
|
|
|
500,000
|
|
|
500,000
|
|
|
|
Certain
employee(b)
|
|
|
|
|
|
91,000
|
|
|
31,000
|
|
|
31,000
|
|
|
|
Non-officers(c)
|
|
|
107,000
|
|
|
278,000
|
|
|
142,000
|
|
|
142,000
|
|
|
|
Current officer stock
options(d)
|
|
|
|
|
|
|
|
|
3,555,000
|
|
|
3,555,000
|
|
|
1,156,000
|
|
|
|
|
|
|
Total
|
|
$
|
2,677,000
|
|
$
|
3,866,000
|
|
$
|
6,159,000
|
|
$
|
6,159,000
|
|
$
|
1,243,000
|
|
|
|
|
|
|
Stock-based compensation expense from stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time vesting
options(a)
|
|
$
|
178,000
|
|
$
|
1,506,000
|
|
$
|
5,085,000
|
|
$
|
5,085,000
|
|
$
|
6,000
|
Performance vesting options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Officers(b)
|
|
|
|
|
|
|
|
|
477,000
|
|
|
335,000
|
|
|
420,000
|
Certain
employee(b)
|
|
|
|
|
|
|
|
|
34,000
|
|
|
24,000
|
|
|
|
Non-officers(c)
|
|
|
|
|
|
|
|
|
505,000
|
|
|
505,000
|
|
|
30,000
|
Current officer stock
options(d)
|
|
|
|
|
|
|
|
|
1,024,000
|
|
|
558,000
|
|
|
1,193,000
|
|
|
|
|
|
|
Total
|
|
$
|
178,000
|
|
$
|
1,506,000
|
|
$
|
7,125,000
|
|
$
|
6,507,000
|
|
$
|
1,649,000
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Options granted prior to
February 27, 2006, vested immediately as of the date of the
Combination, as a result of a change of control. Options granted
thereafter vest using a four year graded vesting schedule by
approval from the Board of Directors.
|
|
(b)
|
|
Options granted prior to
February 27, 2006, vest using a three year cliff vesting
schedule by approval from CEHCs Board of Directors.
|
|
(c)
|
|
Vested as of the date of the
Combination by approval from CEHCs Board of Directors.
|
|
(d)
|
|
Vest using a four year graded
vesting schedule by approval from the Board of Directors.
|
Future stock-based compensation expense related to incentive
stock options outstanding at December 31, 2006 for the
years ended December 31, 2007, 2008, 2009 and 2010 is
approximately $1,962,000, $1,322,000, $443,000, and $99,000
respectively. Future stock-based compensation expense related to
incentive stock options outstanding at September 30, 2007
for the remaining three months ending December 31, 2007 and
the years ended December 31, 2008, 2009 and 2010 is
approximately $558,000, $1,853,000, $720,000, $240,000 and
$48,000 respectively.
Income tax benefit recognized in the income statement for these
stock-based compensation arrangements was $63,000, $528,000,
$2,779,000, $2,538,000 and $691,000 for the period inception
(April 21, 2004) through December 31, 2004, the
years ended December 31, 2005 and 2006 and the nine months
ended September 30, 2006 and 2007, respectively. No amounts
have
F-39
been treated as deductions to the Companys current taxable
income for the period inception (April 21,
2004) through December 31, 2004, the years ended
December 31, 2005 and 2006 and the nine months ended
September 30, 2006 and 2007, since no options have been
exercised. In calculating the compensation expense for options,
the Company has estimated the fair value of each grant using the
Black-Scholes option-pricing model. Assumptions utilized in the
model are shown below. Amounts shown are assumptions under the
Plan for options exercisable for Resources common stock at a
rate of 1:1:
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
2005
|
|
2006
|
|
|
Risk-free interest rates
|
|
|
3.29%
|
|
|
4.12%
|
|
|
4.81%
|
Expected term
|
|
|
3.81 years
|
|
|
2.89 years
|
|
|
2.87 years
|
Expected volatility
|
|
|
40.24%
|
|
|
34.87%
|
|
|
37.12%
|
Expected dividend yield
|
|
|
|
|
|
|
|
|
|
|
|
Note I. Derivative
financial instruments
Cash flow hedges. The Company, from time to
time, uses derivative financial instruments as cash flow hedges
of its commodity price risks. Commodity hedges are used to
(a) reduce the effect of the volatility of price changes on
the natural gas and crude oil the Company produces and sells and
(b) support the Companys annual capital budgeting and
expenditure plans.
During 2004, the Company entered into three natural gas zero
cost price collars and three crude oil zero cost price collars
to hedge a portion of its estimated natural gas and crude oil
production for calendar years 2005, 2006 and 2007. The Company
designated these contracts as cash flow hedges. The natural gas
and crude oil derivative contracts that hedged the 2005
production expired on December 31, 2005. The Company did
not enter into any new derivative contracts in 2005. During
2006, the Company entered into two natural gas zero cost price
collars and three crude oil price swaps to hedge a portion of
its estimated natural gas and crude oil production for calendar
years 2006, 2007 and 2008.
On February 8, 2007, the Company entered into one natural
gas price swap to hedge an additional portion of its estimated
natural gas production for the period of March through December
2007. The contract is for 2,100 MMBtu per day at a fixed
index price of $7.40 per MMBtu. The index price is based on
the Inside FERCEl Paso Permian Basin spot price at
the first of each month. The Company has designated this
derivative instrument as a cash flow hedge.
The fair market value of the cash flow hedges was a net
liability of approximately $18,172,000 and a net asset of
approximately $725,000 at December 31, 2005 and
December 31, 2006 respectively.
F-40
The following table sets forth the Companys outstanding
natural gas and crude oil zero cost collars and swaps as of
December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
Hedged period
|
As of December 31,
2006:
|
|
2007
|
|
|
2008
|
|
|
Natural gas price collars:
|
|
|
|
|
|
|
|
Volume (MMBtu/day)
|
|
|
16,000
|
|
|
|
13,500
|
Index price per
MMBtu(a)
|
|
|
$5.98$9.75
|
(c)
|
|
|
$6.50$9.35
|
Crude oil price collars:
|
|
|
|
|
|
|
|
Volume (Bbl/day)
|
|
|
650
|
|
|
|
|
NYMEX price per
Bbl(b)
|
|
|
$37.95$41.75
|
|
|
|
|
Crude oil price swaps:
|
|
|
|
|
|
|
|
Volume (Bbl/day)
|
|
|
2,300
|
|
|
|
2,600
|
NYMEX price per
Bbl(b)
|
|
|
$67.85
|
|
|
|
$67.50
|
|
|
|
|
|
(a)
|
|
The index prices for the natural
gas price collars are based on the Inside FERC-El Paso
Natural Gas Permian Basin
first-of-the-month
spot price.
|
|
(b)
|
|
The index prices for the crude oil
price collars and price swaps are based on the NYMEX-West Texas
Intermediate monthly average spot price.
|
|
(c)
|
|
Amounts disclosed represent
weighted average prices.
|
The Companys reported oil and gas revenue and average oil
and gas prices includes the effects of oil quality and Btu
content, gathering and transportation costs, gas processing and
shrinkage, and the net effect of the commodity hedges. There
were no gains or losses reclassified into earnings as there were
no cash settlements during the period ended December 31,
2004. The Company reclassified into earnings losses of
$1,622,000 and $5,768,000 as a result of periodic contractual
cash settlements for the years ended December 31, 2005 and
December 31, 2006 respectively, related to the commodity
financial instruments, that were previously reported in
Accumulated other comprehensive income (loss)
(AOCI).
There was no significant hedge ineffectiveness for the period
ended December 31, 2004. The amount of hedge
ineffectiveness recognized in Ineffective portion of cash
flow hedges on the consolidated statements of operations was
a loss of approximately $1,148,000 and gain of approximately
$1,193,000 for the years ended December 31, 2005 and 2006,
respectively.
During the three months ended September 30, 2007, the
Company determined that all of its natural gas commodity
contracts no longer qualified as hedges under the requirements
of SFAS No. 133, for the reason stated in the following
paragraph. These contracts are referred to as dedesignated
hedges.
A key requirement for designation of derivative instruments as
cash flow hedges is that at both the inception of the hedge and
on an ongoing basis, the hedging relationship is expected to be
highly effective in achieving offsetting cash flows attributable
to the hedged risk during the term of the hedge. Generally, the
hedging relationship can be considered to be highly effective if
there is a high degree of historical correlation between the
hedging instrument and the forecasted transaction. In prior
quarters, prices received for the Companys natural gas
have been highly correlated with the Inside FERCEl Paso
Natural Gas index (the Index)the Index
referenced in all of the Companys natural gas derivative
instruments. However, during the
F-41
quarter ended September 30, 2007, this historical
relationship has not met the criteria as being highly
correlated. Natural gas produced from the Companys New
Mexico Shelf assets has a substantial component of natural gas
liquids. Prices received for natural gas liquids are not highly
correlated to the price of natural gas, but are more closely
correlated to the price of oil. During the third quarter of
2007, the price of oil and natural gas liquids, and therefore,
the prices the Company received for its natural gas (including
natural gas liquids) have risen substantially and at a
significantly higher rate than the corresponding change in the
Index. This has resulted in a decrease in correlation between
the prices received and the Index below the level required for
cash flow hedge accounting. According to SFAS No. 133, an
entity shall discontinue prospectively hedge accounting for an
existing hedge if the hedge is no longer highly effective. Hedge
accounting must be discontinued regardless of whether the
Company believes the hedge will be prospectively highly
effective. The hedge must be discontinued during the period the
hedges became ineffective. As a result, any changes in fair
value must be recorded in earnings under (Gain) loss on
derivatives not designated as hedges. Because the gas and
liquids prices fluctuate at different rates over time, the loss
of effectiveness does not relate to any single date.
Therefore, June 30, 2007, is considered the last date the
Companys natural gas hedges were highly effective, and the
Company must discontinue hedge accounting during the three
months ended September 30, 2007 and all periods thereafter.
Mark-to-market adjustments related to these dedesignated hedges
will be recorded each period to (Gain) loss on derivatives
not designated as hedges. Effective portions of dedesignated
hedges, previously recorded in AOCI as of June 30,
2007, will remain in AOCI and be reclassified into
earnings under Natural gas revenues, during the periods
which the hedged forecasted transaction affects earnings.
Derivatives not designated as cash flow
hedges. On September 20, 2007, the Company
entered into four crude oil price swaps to hedge an additional
portion of its estimated crude oil production for the calendar
years 2008 and 2009. The contracts are for 1,000 Bbls per
day each with various fixed prices. The Company has not
designated these derivative instruments as cash flow hedges.
Mark-to-market adjustments related to these derivative
instruments will be recorded each period to (Gain) loss on
derivatives not designated as hedges.
F-42
The following table sets forth the Companys outstanding
crude oil and natural gas zero cost price collars and price
swaps at September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Market Value
|
|
Aggregate
|
|
|
|
|
|
|
|
|
|
|
|
Asset/(Liability)
|
|
remaining
|
|
|
Daily
|
|
|
Index
|
|
|
Contract
|
|
|
(in thousands)
|
|
volume
|
|
|
volume
|
|
|
price
|
|
|
period
|
|
|
Cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar
|
|
$
|
(2,278)
|
|
|
59,800
|
|
|
|
650
|
|
|
$
|
37.95$41.75
|
(a)
|
|
|
10/1/0712/31/07
|
Price swap
|
|
|
(2,570)
|
|
|
211,600
|
|
|
|
2,300
|
|
|
$
|
67.85
|
(a)
|
|
|
10/1/0712/31/07
|
Price swap
|
|
|
(7,668)
|
|
|
951,600
|
|
|
|
2,600
|
|
|
$
|
67.50
|
(a)
|
|
|
1/1/0812/31/08
|
Cash flow hedges dedesignated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collar
|
|
|
735
|
|
|
1,472,000
|
|
|
|
16,000
|
|
|
$
|
5.98$9.75
|
(b)(c)
|
|
|
10/1/0712/31/07
|
Price collar
|
|
|
1,740
|
|
|
4,941,000
|
|
|
|
13,500
|
|
|
$
|
6.50$9.35
|
(b)
|
|
|
1/1/0812/31/08
|
Price swap
|
|
|
257
|
|
|
193,200
|
|
|
|
2,100
|
|
|
$
|
7.40
|
(b)
|
|
|
10/1/0712/31/07
|
Derivatives not designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (volumes in Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price swap
|
|
|
(33)
|
|
|
732,000
|
|
|
|
2,000
|
|
|
$
|
75.78
|
(a)(c)
|
|
|
1/1/0812/31/08
|
Price swap
|
|
|
71
|
|
|
730,000
|
|
|
|
2,000
|
|
|
$
|
72.84
|
(a)(c)
|
|
|
1/1/0912/31/09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net liability
|
|
$
|
(9,746)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
The index prices for the oil price
collars and price swaps are based on the NYMEXWest Texas
Intermediate monthly average futures prices.
|
|
(b)
|
|
The index prices for the natural
gas price collars and price swaps are based on the Inside
FERCEl Paso Permian Basin first-of-the-month spot price.
|
|
(c)
|
|
Amounts disclosed represent
weighted average prices.
|
F-43
The Companys reported oil and gas revenue and average oil
and gas prices includes the effects of oil quality and Btu
content, gathering and transportation costs, gas processing and
shrinkage, and the net effect of the commodity hedges. The
following table summarizes the gains and losses reported in
earnings related to the commodity financial instruments and the
net change in AOCI:
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended
|
|
|
September 30,
|
(in thousands)
|
|
2006
|
|
2007
|
|
|
Effect of derivatives included in oil and gas revenue:
|
|
|
|
|
|
|
|
|
Cash payments on cash flow hedges in oil sales
|
|
$
|
(7,456
|
)
|
|
$
|
(3,347
|
)
|
Cash receipts from cash flow hedges in gas sales
|
|
|
114
|
|
|
|
187
|
|
Dedesignated cash flow hedges reclassed from AOCI
|
|
|
|
|
|
|
722
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas revenue from derivatives
|
|
$
|
(7,342
|
)
|
|
$
|
(2,438
|
)
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as cash flow
hedges:
|
|
|
|
|
|
|
|
|
Mark-to-market
|
|
$
|
|
|
|
$
|
1,802
|
|
Cash receipts on dedesignated derivatives
|
|
|
|
|
|
|
1,286
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivatives not designated as cash flow
hedges
|
|
$
|
|
|
|
$
|
3,088
|
|
|
|
|
|
|
|
|
|
|
Ineffective portion of cash flow hedges
|
|
$
|
64
|
|
|
$
|
(1,134
|
)
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
Cash flow hedges:
|
|
|
|
|
|
|
|
|
Mark-to-market of cash flow hedges gain (loss)
|
|
$
|
5,552
|
|
|
$
|
(14,300
|
)
|
Reclassification adjustment for (gains) losses included in net
income
|
|
|
7,342
|
|
|
|
3,160
|
|
Net AOCI upon dedesignation at June 30, 2007
|
|
|
|
|
|
|
(407
|
)
|
|
|
|
|
|
|
|
|
|
Net change, before taxes
|
|
|
12,894
|
|
|
|
(11,547
|
)
|
Tax effect
|
|
|
(4,518
|
)
|
|
|
4,822
|
|
|
|
|
|
|
|
|
|
|
Net change, net of tax
|
|
$
|
8,376
|
|
|
$
|
(6,725
|
)
|
|
|
|
|
|
|
|
|
|
Dedesignated cash flow hedges:
|
|
|
|
|
|
|
|
|
Net AOCI upon dedesignation at June 30, 2007
|
|
$
|
|
|
|
$
|
407
|
|
Reclassification adjustment for (gains) losses included in net
income
|
|
|
|
|
|
|
(722
|
)
|
|
|
|
|
|
|
|
|
|
Total net change in AOCI (loss), net tax
|
|
|
|
|
|
|
(315
|
)
|
Tax effect
|
|
|
|
|
|
|
133
|
|
|
|
|
|
|
|
|
|
|
Net change, net of tax
|
|
$
|
|
|
|
$
|
(182
|
)
|
|
|
|
|
|
|
|
|
|
Total changes in accumulated other comprehensive income (loss),
net of tax
|
|
$
|
8,376
|
|
|
$
|
(6,907
|
)
|
Net income
|
|
|
12,723
|
|
|
|
18,502
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
$
|
21,099
|
|
|
$
|
11,595
|
|
|
|
|
|
|
|
|
|
|
|
|
All of the Companys derivatives are expected to settle by
January 8, 2010. Based on futures prices as of
December 31, 2006, the Company expected a pre-tax loss of
$211,000 to be reclassified into earnings during the year ended
December 31, 2007. Based on futures prices as of
September 30, 2007, the Company expects a pre-tax loss of
$9,644,000 and pre-tax gain of $121,000 to be reclassified out
of AOCI into earnings during the twelve months ended
September 30, 2008 related to the cash flow hedges and the
dedesignated cash flow hedges, respectively.
F-44
Note J. Long-term
debt
On February 24, 2006, in conjunction with the Combination,
the Company replaced its prior revolving credit facility and its
prior term loan facility with a new revolving credit facility,
as described below. A portion of the initial advance from the
new revolving credit facility was used to repay all funds
borrowed under the prior revolving and term credit facilities.
Remaining unamortized fees paid in connection with the issuance
of the prior revolving and term credit facilities were fully
expensed into Interest expense in the accompanying
consolidated statement of operations for the year ended
December 31, 2006 when the prior revolving and term credit
facilities were replaced.
1st Lien Credit Facility. As of
February 24, 2006, the Company entered into a credit
agreement with a syndicate of banks (the 1st Lien
Banks) which provides for a revolving credit facility (the
1st Lien Credit Facility) with commitments from
the 1st Lien Banks aggregating $475 million, subject
to a borrowing base. The borrowing base is calculated based on
the Companys oil and gas reserves. The maturity date of
the 1st Lien Credit Facility is February 24, 2010. The
Company may also request the issuance of letters of credit up to
$20 million. The borrowing commitment is reduced by any
outstanding letters of credit. The initial advance on the 1st
Lien Credit Facility made on February 27, 2006 was
$421 million. The proceeds from this initial advance were
used as follows:
|
|
|
|
|
Cash payment to the Chase Group in the Combination
|
|
$
|
400,000,000
|
Repay balance on prior revolving credit facility
|
|
|
15,900,000
|
Bank fees and legal costs
|
|
|
5,100,000
|
|
|
|
|
|
|
$
|
421,000,000
|
|
|
|
|
|
|
The initial borrowing base is $475 million. The borrowing
base components are redetermined semiannually as of January 1
and June 30 of each year. In addition to the regular
redetermination dates listed above, the 1st Lien Credit Facility
required a special redetermination as of April 30, 2006.
This special redetermination was conducted during the quarter
ended June 30, 2006 by the 1st Lien Banks and both the
borrowing base and the conforming borrowing base were affirmed
at their current amounts. In addition to the scheduled
redeterminations, the Company and the 1st Lien Banks are
each provided the option to request an additional
redetermination once between the scheduled redeterminations. The
borrowing base remains at $475 million at December 31,
2006. The Company entered into the Second Amendment to the
1st Lien Credit Facility on March 27, 2007. The
amendment allowed for the incurrence of additional indebtedness
in the form of a $200 million second lien term loan. The
amendment also redetermined the borrowing base at
$375 million.
Advances on the 1st Lien Credit Facility bear interest, at
the Companys option, based on (a) the prime rate of
JPMorgan Chase Bank (JPM Prime Rate) (8.25 percent
at December 31, 2006) or (b) a Eurodollar rate
(substantially equal to the London Interbank Offered Rate). The
interest rates of Eurodollar rate advances and JPM Prime Rate
advances vary, with interest margins ranging from 100
-
225 basis points and 0 - 125 basis points,
respectively, per annum depending on the available borrowing
base utilized. The Company pays commitment fees on the unused
portion of the borrowing base ranging from 25
- 50 basis
points per annum depending on the available borrowing base
utilized. The amount outstanding under this facility at
December 31, 2006 was $455.7 million, of which
$432 million was at the Eurodollar rate and
$23.7 million was
F-45
at the JPM Prime Rate. The Company used a portion of the net
proceeds from its initial public offering that was completed in
August 2007 to retire outstanding borrowings under the
1st
Lien Credit Facility totaling $86.5 million. The amount
outstanding under this facility at September 30, 2007 was
$234.0 million, of which $216.0 million was at the
Eurodollar rate and $18.0 million was at the JPM Prime Rate.
The 1st Lien Credit Facility also includes a
same-day
advance facility under which the Company may borrow funds on a
daily basis from the 1st Lien Banks administrative
agent. Advances made on this
same-day
basis 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. There
were no amounts outstanding on this facility at
December 31, 2006 and September 30, 2007.
The Companys obligations under the 1st Lien Credit
Facility are secured by substantially all of the Companys
oil and gas properties. In addition, all but one of the
Companys subsidiaries are guarantors, and all subsidiary
general partners, limited partners and membership interests
owned by the Company and its subsidiaries have been pledged as
collateral in the credit agreement. The credit agreement
contains various restrictive covenants and compliance
requirements which include (a) maintenance of certain
financial ratios (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 no
greater than 3.5 to 1.0, amended to 4.0 to 1.0 as of
March 27, 2007 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, to be no less than 1.0 to 1.0,
(b) limits on the incurrence of additional indebtedness and
certain types of liens and (c) restrictions as to merger
and sale or transfer of assets. The Company was in compliance
with all covenants of the Credit Facility at December 31,
2006 and September 30, 2007.
On July 6, 2006, the Company entered into the First
Amendment to the 1st Lien Credit Facility. The Amendment
allowed the Company to obtain additional financing in the form
of a $40 million second lien term loan.
2nd Lien Credit Facility. On
July 6, 2006, the Company entered into an additional credit
agreement arranged by Banc of America Securities LLC for a term
loan facility in the amount of $40 million (the
2nd Lien Credit Facility). The full amount of
this facility was funded on the closing date to reduce the
amount outstanding under the 1st Lien Credit Facility by
$32.1 million, with the remaining $7.9 million used
for general corporate purposes.
The 2nd Lien Credit Facility provides a $40 million
term loan, which bears interest, at the Companys option,
based on (a) the prime rate of Bank of America, N.A.
(BOA Prime Rate) (8.25 percent at December 31,
2006) or (b) a Eurodollar rate (substantially equal to
the London Interbank Offered Rate). The interest rates of
Eurodollar Rate advances and BOA Prime Rate advances vary, with
interest margins of 400 basis points and 250 basis
points, respectively. The Company may select interest periods on
Eurodollar Rate advances of one, two, three, six, nine and
twelve months, subject to availability. Interest is payable at
the end of the selected interest period, but no less frequently
than quarterly.
The Company is required to repay $100,000 of the 2nd Lien Credit
Facility on the last day of each calendar quarter beginning
September 30, 2006. The maturity date of the 2nd Lien
Credit Facility is July 5, 2011. The Company has the right
to prepay the outstanding balance under the 2nd Lien Credit
Facility at any time, provided, however, that the Company incurs
a one percent
F-46
prepayment penalty on any principal amount prepaid prior to
July 5, 2007. The amount outstanding under this facility at
December 31, 2006 was $39.8 million. The portion of
this facility which is due within the next twelve months,
$400,000, is reflected in Current portion of long-term
debt in the accompanying consolidated balance sheet as of
December 31, 2006. On March 27, 2007, the amount
outstanding under 2nd Lien Credit Facility was repaid in
full.
Borrowings under the 2nd Lien Credit Facility are secured
by a second lien on the same assets as are securing our
1st Lien Credit Facility, which lien is subordinated to
liens securing the 1st Lien Credit Facility. The
2nd Lien Credit Facility contains various restrictive
covenants including (a) maintenance of certain financial
ratios including (i) maintenance of a quarterly ratio of
total debt to consolidated earnings before interest expense,
income taxes, depletion, depreciation, and amortization,
exploration expense and other noncash income and expenses of
less than 4.5 to 1.0, (ii) maintenance of a ratio of
current assets to current liabilities, excluding noncash assets
and liabilities related to financial derivatives and asset
retirement obligations, to be greater than 1.0 to 1.0 and
(iii) maintenance of a ratio, as of January 1 and
June 30 of each year, of the net present value of the
Companys oil and gas properties to total debt to be
greater than 1.5 to 1.0. (b) limits on the incurrence of
additional indebtedness and certain types of liens and
(c) restrictions as to merger and sale or transfer of
assets. The Company was in compliance with all covenants at
December 31, 2006.
The Company paid an arrangement fee of $500,000 at the date of
closing of the 2nd Lien Credit Facility. This fee will be
amortized over the five-year term of the facility beginning in
July 2006.
Refinancing of debt facilities. As of
March 27, 2007, the Company amended the 1st Lien
Credit Facility, repaid the 2nd Lien Credit Facility and
entered into a new 2nd lien credit facility (the New
2nd Lien Credit Facility). This refinancing was done
to provide additional availability on the Companys
1st Lien Credit Facility and satisfy the requirement of
equalizing the borrowing base and the conforming borrowing base.
The Company entered into the Second Amendment to the
1st Lien Credit Facility on March 27, 2007. The
amendment allowed for the incurrence of additional indebtedness
in the form of a $200 million second lien term loan. The
amendment also redetermined the borrowing base at
$375 million and increased the maximum allowable quarterly
ratio of total debt to consolidated earnings before interest
expense, income taxes, depletion, depreciation, and
amortization, exploration expense and other non-cash income and
expenses from 3.5 to 1.0 to 4.0 to 1.0.
On March 27, 2007, the Company entered into the New
2nd Lien Credit Facility, arranged by Banc of America
Securities LLC, for a term loan facility in the amount of
$200 million. The full amount of the facility was funded on
the closing date. The New 2nd Lien Credit Facility was
issued at a discount of 0.5 percent; thus, the Company
received proceeds of $199.0 million. The proceeds from the
borrowing were used to repay the 2nd Lien Credit Facility
in full in the amount of $39.8 million without penalty,
reduce the amount outstanding under the 1st Lien Credit
Facility by $154.0 million, with the remaining
$5.2 million used to pay loan fees, accrued interest and
for general corporate purposes. The Company used a portion of
the net proceeds from its initial public offering that was
completed in August 2007 to retire outstanding borrowings under
the
2nd
Lien Credit Facility totaling $86.5 million.
The New 2nd Lien Credit Facility provides a
$200 million term loan, which bears interest, at the
Companys option, based on (a) the BOA Prime Rate
(8.25 percent at December 31, 2006 and 7.75 percent at
September 30, 2007) or (b) a Eurodollar rate
(substantially equal to the London Interbank Offered Rate). The
interest rates of Eurodollar rate advances and prime rate
advances
F-47
vary, with interest margins of 375 basis points and
225 basis points, respectively, until the completion of the
companys initial public offering on August 7, 2007,
at which time interest margins on Eurodollar rate advances and
prime rate advances became 425 basis points and
275 basis points, respectively. The Company may select
interest periods on Eurodollar rate advances of one, two, three,
six, nine and twelve months, subject to availability. Interest
is payable at the end of the selected interest period, but no
less frequently than quarterly.
The Company is required to repay $0.5 million of the New
2nd Lien Credit Facility on the last day of each calendar
quarter beginning June 30, 2007. The maturity date of the
term loan facility is March 27, 2012. The Company has the
right to prepay the outstanding balance under the term loan
facility at any time. The Company will not incur a prepayment
penalty on any principal amount prepaid during the first twelve
months of the loan. A two percent prepayment penalty will be
incurred on any principal amount prepaid during the second year
following the closing and one percent penalty will be incurred
during the third year. After the third year, no prepayment
penalty will be incurred.
Borrowings under the New 2nd Lien Credit Facility are
secured by a second lien on the same assets as are securing the
1st Lien Credit Facility. The second lien is subordinated
to liens securing the 1st Lien Credit Facility. The New
2nd Lien Credit Facility contains various restrictive
covenants including (a) maintenance of certain financial
ratios including (i) maintenance of a quarterly ratio of
total debt to consolidated earnings before interest expense,
income taxes, depletion, depreciation, and amortization,
exploration expense and other non-cash income and expenses of
less than 4.5 to 1.0, (ii) maintenance of a ratio of
current assets to current liabilities, excluding non-cash assets
and liabilities related financial derivatives and asset
retirement obligations, to be greater than 1.0 to 1.0 and
(iii) maintenance of a ratio, as of January 1 and
June 30 of each year, of the net present value of the
Companys oil and gas properties to total debt to be
greater than 1.5 to 1.0. (b) limits on the incurrence
of additional indebtedness and certain types of liens and
(c) restrictions as to merger and sale or transfer of
assets.
The amount outstanding under New 2nd Lien Credit Facility
at September 30, 2007 was $111.9 million, net of a
discount of $0.5 million, all of which was at the BOA
Prime Rate. The Company was in compliance with all covenants of
the New 2nd Lien Credit Facility at September 30, 2007.
The Company paid an arrangement fee of $2.5 million at the
date of closing. This fee will be amortized to Interest
expense over the five-year term of the facility beginning in
April 2007.
The amendment of the 1st Lien Credit Facility on
March 27, 2007, resulted in a $100 million, or
21 percent, reduction of the borrowing base. As such, the
pro rata portion of the remaining debt issuance costs associated
with the 1st Lien Credit Facility, totaling approximately
$766,000, will be written off and included in Interest
expense in the first quarter of 2007. The remaining debt
issuance costs of $433,000 associated with the 2nd Lien
Credit Facility repaid in full on March 27, 2007, were
written off and included in Interest expense in the first
quarter of 2007.
F-48
Principal maturities. Principal maturities of
long-term debt outstanding at December 31, 2006, for the
years ended December 31, 2007, 2008, 2009, 2010 and 2011,
are as follows:
|
|
|
|
|
(in thousands)
|
|
|
|
|
2007
|
|
$
|
400
|
2008
|
|
|
400
|
2009
|
|
|
400
|
2010
|
|
|
456,100
|
2011
|
|
|
38,200
|
|
|
|
|
Total
|
|
$
|
495,500
|
|
|
|
|
|
|
Principal maturities of long-term debt outstanding at
September 30, 2007 for the three months ended
December 31, 2007 and the years ending December 31,
2008, 2009, 2010 and 2011 and thereafter, are as follows:
|
|
|
|
|
(in thousands)
|
|
|
|
|
2007
|
|
$
|
500
|
2008
|
|
|
2,000
|
2009
|
|
|
2,000
|
2010
|
|
|
236,000
|
2011
|
|
|
2,000
|
2012 and thereafter
|
|
|
103,900
|
|
|
|
|
Total
|
|
$
|
346,400
|
|
|
|
|
|
|
Note K. Commitments
and contingencies
Operating leases. The Company is party to a
non-cancelable operating lease for office space for its
corporate headquarters in Midland, Texas through
October 31, 2013.
Future minimum lease commitments under the amended lease at
December 31, 2006 were as follows:
|
|
|
|
|
(in thousands)
|
|
|
|
|
2007
|
|
$
|
438
|
2008
|
|
|
439
|
2009
|
|
|
449
|
2010
|
|
|
458
|
2011
|
|
|
468
|
2012 and thereafter
|
|
|
873
|
|
|
|
|
Total future minimum lease commitments
|
|
$
|
3,125
|
|
|
|
|
|
|
F-49
Future minimum lease commitments under the amended lease at
September 30, 2007 were as follows:
|
|
|
|
|
(in thousands)
|
|
|
|
|
2007
|
|
$
|
115
|
2008
|
|
|
464
|
2009
|
|
|
474
|
2010
|
|
|
484
|
2011
|
|
|
494
|
2012 and thereafter
|
|
|
921
|
|
|
|
|
Total future minimum lease commitments
|
|
$
|
2,952
|
|
|
|
|
|
|
The Company recognizes expense on a straight-line basis in equal
amounts over the lease term. Rent expense of $176,000, $316,000
and $685,000 for the periods ended December 31, 2004, 2005
and 2006, respectively, and $352,000 and $406,000 for the nine
months ended September 30, 2006 and 2007, is included in
the accompanying consolidated statements of operations.
Daywork drilling contract
commitments. The Company signed two daywork
drilling contracts with a drilling contractor (Contractor
A), on November 14, 2005, that provides the Company
exclusive use of two rigs for a term ending 365 days from
the date the rigs moved to the first wells. The Company may
direct the rigs to locations located within the Permian Basin
region as needed. The Company is solely responsible and assumes
liability for all consequences of operations by both parties
while on a daywork basis, with the exception that Contractor A
is liable for its employees, subcontractors and invitees. In
addition, Contractor A is responsible for pollution or
contamination from their equipment. Contractor A will release
the Company of any liability for negligence of any party in
connection with Contractor A. The operating day rate is $18,000.
The operating day rate can be revised to reflect changes in
costs incurred by Contractor A for labor
and/or fuel.
The contract allows an early termination by the Company with at
least a thirty day notice and a payment of the lump sum
termination amount equal to the current operating day rate less
$7,000, multiplied by the days remaining through the end of the
contract term. However, if Contractor A secures work for the
subject rig with a new customer prior to the end of the contract
term, Contractor A will rebate the Company the difference
between the current operating day rate pursuant to the contract
and the operating day rate received from the new customer. The
Company fully utilized both of the rigs in order to complete its
2006 drilling budget. These contracts expired on
December 31, 2006.
The Company signed a daywork drilling contract with a drilling
contractor (Contractor B) on July 20, 2006,
that provides the Company exclusive use of one rig for a term
that commenced on August 1, 2006 and ends on June 15,
2007. The Company may direct the rig to locations located within
the West Texas Permian Basin region as needed. The Company is
solely responsible and assumes liability for all consequences of
operations by both parties while on a daywork basis, with the
exception that Contractor B is liable for its employees,
subcontractors and invitees. In addition, Contractor B is
responsible for pollution or contamination from their equipment.
Contractor B will release the Company of any liability for
negligence of any party in connection with Contractor B. The
operating day rate is $15,500. The operating day rate can be
revised to reflect changes in costs incurred by Contractor B for
labor and/or
fuel. The contract allows an early termination by the Company
with at least a thirty day notice and a payment of the lump sum
termination amount equal to the current operating day rate less
$6,000, multiplied by the days remaining through the end of the
contract term. However, if Contractor B secures work for
F-50
the subject rig with a new customer prior to the end of the
contract term, Contractor B will rebate the Company the
difference between the current operating day rate pursuant to
the contract and the operating day rate received from the new
customer. During February 2007, management decided to stack this
rig due to budget modifications. The Company incurred costs of
approximately $1,296,000 during the nine months ended
September 30, 2007. These costs were minimized as
Contractor B secured work for the rig and refunded the Company
the difference between the current operating day rate pursuant
to the contract and the operating day rate received from the new
customer. The Company utilized the rig in the second quarter of
2007 in order to drill one well included in its 2007 drilling
budget.
The Company signed a new daywork drilling contract with
Contractor B on June 26, 2007, that provides the Company
exclusive use of one rig for a term that commenced on
July 3, 2007 and ends on January 3, 2008. The Company
may direct the rig to locations within the Permian Basin region
as needed. The Company is solely responsible and assumes
liability for all consequences of operations by both parties
while on a daywork basis, with the exception that Contractor B
is liable for its employees, subcontractors and invitees. In
addition, Contractor B is responsible for pollution or
contamination from their equipment. Contractor B will release
the Company of any liability for negligence of any party in
connection with Contractor B. The operating day rate is $14,000.
The operating day rate can be revised to reflect changes in
costs incurred by Contractor B for labor
and/or fuel.
The contract allows an early termination by the Company with at
least a thirty day notice and a payment of the lump sum
termination amount equal to the current operating day rate less
$6,000, multiplied by the days remaining through the end of the
contract term. However, if Contractor B secures work for the
subject rig with a new customer prior to the end of the contract
term, Contractor B will rebate the Company the difference
between the current operating day rate pursuant to the contract
and the operating day rate received from the new customer.
The Company signed daywork drilling contracts with Silver Oak
Drilling, LLC (Silver Oak), an affiliate of the
Chase Group, on August 1, 2006, that provides the Company
use of four drilling rigs for a term that commenced on
August 1, 2006 and ends on July 31, 2007. The Company
may direct the rig to locations located in New Mexico as needed.
If the Company moves the rig out of certain New Mexico counties
specified in the contract, all effective daywork rates will be
increased by an additional $2,000 per day. The Company is
solely responsible and assumes liability for all consequences of
operations by both parties while on a daywork basis, with the
exception that Silver Oak is liable for its employees,
subcontractors and invitees. In addition, Silver Oak is
responsible for pollution or contamination from their equipment.
Silver Oak will release the Company of any liability for
negligence of any party connected to Silver Oak. The operating
day rate is $14,500 for two of the contracts and $13,500 for the
other two contracts. The operating day rate can be revised to
reflect changes in costs incurred by more than 5 percent by
Silver Oak for labor, insurance premiums, fuel,
and/or an
increase in the number of Silver Oaks personnel needed.
Under the contract, the Company must pay the full operating day
rate for each day during the contract term. Although there is no
early termination provision in the contract, Silver Oak has a
duty to mitigate damages to the Company by reasonably attempting
to secure replacement contracts for the rigs if they are
released by the Company or if any contract is terminated by
Silver Oak prior to the expiration of the term of the contract.
The Company will then be entitled to a 75 percent credit for
any revenues received by Silver Oak. Even if the Company
releases the rigs, the Company, with 20 days notice, may
withdraw its release and reactivate the contract for the
remainder of the term to the extent the rig has not been
committed to a third party in mitigation of the Companys
damages. During February 2007, management decided to stack these
four rigs due to budget modifications. The Company
F-51
incurred costs of approximately $2,973,000 during the nine
months ended September 30, 2007 based on the drilling
agreement described above. As of April 1, 2007, the Company
began to utilize all four rigs, in order to proceed with its
2007 drilling budget.
The Company signed new daywork drilling contracts with Silver
Oak on June 19, 2007, that provides the Company use of four
drilling rigs for a term that commenced on August 1, 2007
and is in effect until drilling operations are completed on
specified wells or for a term of 1 year. If any well
commenced during the term of the contract is drilling at the
expiration of the one year primary term, drilling will continue
under the terms of the contract until drilling operations for
that well have been completed. The Company may direct the rig to
locations located in New Mexico as needed. The Company is solely
responsible and assumes liability for all consequences of
operations by both parties while on a daywork basis, with the
exception that Silver Oak is liable for its employees,
subcontractors and invitees. In addition, Silver Oak is
responsible for pollution or contamination from their equipment.
Silver Oak will release the Company of any liability for
negligence of any party connected to Silver Oak. The operating
day rate is $14,500 for two of the contracts and $13,500 for the
other two contracts. The operating day rate can be revised to
reflect changes in costs incurred by more than 5 percent by
Silver Oak for labor, insurance premiums, fuel,
and/or an
increase in the number of Silver Oaks personnel needed.
Under the contract, the Company must pay the full operating day
rate for each day during the contract term. Although there is no
early termination provision in the contract, Silver Oak has a
duty to mitigate damages to the Company by reasonably attempting
to secure replacement contracts for the rigs if they are
released by the Company or if any contract is terminated by
Silver Oak prior to the expiration of the term of the contract.
The Company will then be entitled to a 75 percent credit
for any revenues received by Silver Oak. Even if the Company
releases the rigs, the Company, with 20 days notice, may
withdraw its release and reactivate the contract for the
remainder of the term to the extent the rig has not been
committed to a third party in mitigation of the Companys
damages.
Oil & gas lease extension
payment. The Company is party to an agreement
which, in part, governs the exploration activities on the
Companys acreage in the Western Delaware Basin shale play
in Culberson County, Texas. The agreement contains a three-well
drilling requirement. In addition to the drilling well
requirement, the agreement requires the Company to pay an
additional $2.1 million ($150 per net acre for
13,952 net acres) in order to maintain its leasehold
position. This payment will be required within 90 days
after the completion of the drilling of the third of the
Companys three-well drilling commitment, should it decide
to extend these leases. Failure to complete the three-well
commitment by January 1, 2007, or failure to make the
additional payment for the acreage, would result in forfeiture
of the Companys leasehold rights, except to the extent of
the then-existing proration units, and the Company would be
obligated to make a liquidated damages payment of $750,000 for
any well not drilled.
As of January 1, 2007, the Company had drilled or was
drilling all three of these wells. The last of the three wells
drilled reached total depth on January 19, 2007. On
April 17, 2007, the Company made the payment of
$2.1 million described above.
Chase Group accredited and unaccredited investors asset
purchase obligation. As discussed in
Note D Acquisitions and business
combinations, on February 27, 2006, as required by the
Combination Agreement, the Company agreed to purchase working
interests in the Chase Group Properties from certain individuals
within the Chase Group. On May 18, 2006, the Company
purchased interests in the Chase Group Properties from ten
individuals within the Chase Group who were accredited investors
in exchange for $8.9 million in cash and
F-52
111,323 shares of Resources common stock valued at
$1.4 million for an aggregate purchase price of
$10.3 million. The value of the common shares issued was
$6 per share, as required by the Combination Agreement. The
aggregate purchase price is reflected in Proved properties
in the accompanying consolidated balance sheet at
December 31, 2006. This transaction is included in the
aggregate purchase price disclosed in
Note DAcquisitions and business combinations.
The Company was further obligated to offer to purchase
additional interests in the Chase Group Properties from nine
individuals within the Chase Group. In April 2007, the Company
satisfied this obligation by paying $256,000 in cash and issuing
54,230 shares of common stock. The aggregate purchase price
is reflected in Proved properties and the related
obligation is reflected in Chase Group unaccredited investors
asset purchase obligation in the accompanying consolidated
balance sheet at December 31, 2006. This transaction is
included in the aggregate purchase price disclosed in
Note DAcquisitions and business combinations.
Employment agreements. In connection
with the Combination, each of the Companys named executive
officers entered into a separate employment agreement with the
Company, each with an effective date of June 1, 2006. The
agreements are substantially similar and have an initial term
that expires three years from the effective date, but will
automatically be extended for successive one-year terms after
the initial term unless either party gives written notice within
90 days prior to the end of the term.
Under these agreements, Mr. Leach and Mr. Beals
minimum annual base salaries are $350,000 and
Messrs. Copeland, Kamradt, Wright and Thomass minimum
annual base salaries are $250,000. Mr. Leach and
Mr. Beal are entitled to utilize the Companys
aircraft for business use, and they and their families are
entitled to use the Companys aircraft for reasonable
personal use and are not required to reimburse the Company for
any cost related to such use unless a family member travels
without either Mr. Leach or Mr. Beal.
If one of the Companys named executive officers
employment is terminated by the Company without cause, as
defined in the agreements, or if he terminates his employment
following a change in duties, as defined in the agreements, then
the Company will provide him with certain severance benefits. If
such a termination of employment occurs prior to a change of
control or more than two years after a change of control, then
his base salary will continue to be paid for 12 months and
the Company will reimburse him for up to 12 months for the
amount by which the cost of his continued coverage under the
Companys group health plans exceeds the employee
contribution amount that the Company charges its active senior
executives for similar coverage. If such a termination of
employment occurs during the two-year period beginning on the
date upon which a change of control, as defined in the
agreements, occurs, then he will be entitled to a lump sum
severance amount equal to two times his annual base salary, all
of his stock options and restricted stock awards will vest in
full, and the Company will reimburse him for up to
18 months for the amount by which the cost of his continued
coverage under the Companys group health plans exceeds the
employee contribution amount that the Company charges its active
senior executives for similar coverage. If the total amount of
payments to be provided by the Company in connection with a
change in control would cause any of the named executive
officers to incur golden parachute excise tax
liability, the payments will be reduced to the extent necessary
to leave him in a better after-tax position than if no such
reduction had occurred. The agreement does not provide for any
tax gross-up payments.
F-53
Note L.
Regulatory matters
From 1984 through 1997, the owners of the Grayburg-Jackson West
Cooperative Unit (GJ Unit), a group of
formations and intervals unitized by state regulatory
authorities, compromised of approximately 2,400 acres in
Eddy County, New Mexico and which comprises a portion of the
Chase Group Properties, drilled or deepened approximately
70 wells that produced from zones below a depth approved as
the unitized formation. The owners of the working interests in
the GJ Unit possessed the ownership rights entitling them to
produce hydrocarbons from the subject producing intervals below
the unitized formation, but had not obtained the necessary
regulatory approval (1) as to certain wells, to drill or
deepen below the base of the unitized formation or (2) to
produce hydrocarbons from intervals below the base of the
unitized formation and to commingle such production with
production from the unitized formation. In connection with the
failure to obtain the required regulatory approval to produce on
a commingled basis from these deeper intervals, the operators
filed incorrect perforation and completion reports with state
regulatory authorities, and filed monthly production reports
that did not disclose that hydrocarbons had been produced from
intervals below the unitized formation and that hydrocarbons
produced from these deeper intervals were improperly commingled
with production from the unitized formation (although the
reports apparently reflected the actual volumes produced by the
wells). As a result, a unit royalty interest owner in the
unitized formation was overpaid and the State of New Mexico,
which was the owner of the royalty interest in the subject
producing intervals below the unitized formation, was underpaid
for several years.
On November 15, 2005, MEC filed an application with the New
Mexico Oil Conservation Division (NMOCD) to expand
the vertical limit of the unitized formation to include the
deeper intervals that had been accessed, produced and commingled
without obtaining regulatory approval. A hearing on the
application was originally scheduled for December 15, 2005,
but was continued at the request of MEC. On February 27,
2006, the combination transaction occurred and, as a result, the
Company acquired the GJ Unit.
On April 13, 2006, the NMOCD held a hearing on MECs
application to expand the vertical limit of the unitized
formation. Representatives of MEC, acting under the Contract
Operator Agreement with MEC, participated in the hearing and
presented testimony during that hearing that intervals below the
unitized formation had not been tested or developed. Based on
the application submitted by MEC and the evidence and testimony
presented at the hearing, on June 13, 2006, the NMOCD
approved the application and entered its order expanding the
vertical limit of the unitized formation to include certain
deeper intervals, including one of those that had previously
been produced and commingled without regulatory approval.
Over the course of developing our drilling program for the Chase
Group Properties in July and August 2006, the Company discovered
the existence of these violations and this testimony. Following
further investigation by the Companys employees and
discussions with a representative of Chase Oil and MEC and the
Companys counsel, the Company reported these developments
to the Companys board of directors. Because this matter
related to ongoing regulatory violations by entities that were
under the control of certain members of the Companys board
of directors, the Companys board of directors determined
on September 6, 2006, to form a special committee of the
board of directors that consisted of independent and
disinterested non-management directors for the purpose of
investigating the matters identified by the Companys
management relating to the GJ Unit. The special committee
engaged separate legal counsel to assist it with its
investigation of this matter. Also, in September 2006,
representatives of MEC and the Company met with relevant
regulatory authorities from the State of New
F-54
Mexico, and voluntarily self-reported the matters related to the
GJ Unit, and the Company filed amended reports to correct prior
reporting inaccuracies.
As a result of these actions, the Company, along with MEC,
entered into a settlement agreement with the New Mexico State
Land Office on November 2, 2006 related to the underpayment
of royalties arising from these circumstances. Under the terms
of the settlement agreement, MEC paid $615,444 to the State of
New Mexico for underpayment of royalties and interest thereon.
The Company was not required to make any payments under the
settlement agreement. Further, on January 22, 2007, the
State of New Mexico advised the Company that there was no basis
for a compliance and enforcement proceeding against the Company
and no evidence of a knowing and willful violation of applicable
law by the Company. On January 19, 2007, MEC entered into
an Agreed Compliance Order and agreed to pay a penalty of
$250,000 for its violations of applicable rules, regulations and
statutes. Finally, the NMOCD approved the Companys
correction of the prior records related to the GJ Unit and, in
February 2007, approved the Companys application to expand
the vertical limit of the unitized formation below the depth of
the intervals that had previously been improperly produced and
commingled with production from the unitized formation and to
bring all of the wells in the GJ Unit into compliance with all
applicable rules, regulations and statutes.
The special committee of the board of directors examined
relevant documents provided by the Company and its regulatory
counsel in New Mexico, conducted interviews of members of
management and heard a presentation from a representative of
Chase Oil and MEC. The special committee also monitored the
activities of the Company and the Companys legal counsel
during the discussions and proceedings with relevant New Mexico
regulatory authorities. Based on its review of this matter, the
special committee recommended the adoption of certain policies
and procedures governing the operation of all legal proceedings
involving the Company as well as a review of the due diligence
processes associated with future acquisitions of properties. The
special committee also recommended certain actions to address
corporate governance matters at the Company. Finally, the
special committee reviewed the conduct of the Companys
officers and directors to determine whether any such conduct
would indicate that an officer or director was unsuitable to
continue in their position, and the special committee did not
determine that any officer or director was unsuitable to
continue in their position with the Company.
Note M.
Income taxes
The Company accounts for income taxes in accordance with the
provisions of SFAS No. 109, Accounting for
Income Taxes. The Company and its subsidiaries file
federal corporate income tax returns on a consolidated basis.
The tax returns and the amount of taxable income or loss are
subject to examination by United States federal and state taxing
authorities. No current or estimated tax payments were made in
2004. The Company made estimated tax payments of $100,000,
$1,725,000 and $1,650,000 for the years ended December 31,
2005 and 2006 and for the nine months ended September 30, 2007,
respectively.
SFAS No. 109 requires that the Company continually
assess both positive and negative evidence to determine whether
it is more likely than not that deferred tax assets can be
realized prior to their expiration. Management monitors
Company-specific, oil and gas industry and worldwide economic
factors and assesses the likelihood that the Companys net
operating loss carryforwards (NOLs) and other
deferred tax attributes in the United States, state, and local
tax jurisdictions will be utilized prior to their expiration. As
of December 31, 2005, December 31, 2006 and
September 30, 2007, the Company had no valuation allowances
related to its deferred tax assets.
F-55
The Company adopted the provisions of FIN No. 48, on
January 1, 2007. FIN No. 48 clarifies the
accounting for uncertainty in income taxes recognized in an
enterprises financial statements in accordance with
SFAS No. 109, and prescribes a recognition threshold
and measurement process for financial statement recognition and
measurement of a tax position taken or expected to be taken in a
tax return. FIN No. 48 also provides guidance on
derecognition, classification, interest and penalties,
accounting in interim periods, disclosure and transition.
Based on the Companys evaluation, the Company has
concluded that there are no significant uncertain tax positions
requiring recognition in the financial statements. The
Companys evaluation was performed for the tax periods
ended December 31, 2004, 2005 and 2006, which are the tax
periods which remain subject to examination by major tax
jurisdictions.
The components of income tax expense (benefit) are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Periods ending
|
|
Nine months ending
|
|
|
December 31,
|
|
September 30,
|
(In thousands)
|
|
2004
|
|
|
2005
|
|
2006
|
|
2006
|
|
2007
|
|
|
Current income tax expense federal and state
|
|
$
|
|
|
|
$
|
65
|
|
$
|
1,761
|
|
$
|
1,061
|
|
$
|
1,875
|
Deferred income tax expense (benefit) federal and state
|
|
|
(915
|
)
|
|
|
1,974
|
|
|
12,618
|
|
|
7,603
|
|
|
11,460
|
|
|
|
|
|
|
Income tax expense (benefit)
|
|
$
|
(915
|
)
|
|
$
|
2,039
|
|
$
|
14,379
|
|
$
|
8,664
|
|
$
|
13,335
|
|
|
|
|
|
|
|
|
The reconciliation between the tax expense (benefit) computed by
multiplying pretax income (loss) by the U.S. federal
statutory rate and the reported amounts of income tax benefit is
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Periods ending
|
|
Nine months ending
|
|
|
December 31,
|
|
September 30,
|
(In thousands)
|
|
2004
|
|
|
2005
|
|
2006
|
|
2006
|
|
2007
|
|
|
Income (loss) at U.S. federal statutory rate
|
|
$
|
(1,214
|
)
|
|
$
|
1,358
|
|
$
|
11,916
|
|
$
|
7,485
|
|
$
|
11,143
|
State income taxes
|
|
|
(34
|
)
|
|
|
70
|
|
|
2,083
|
|
|
894
|
|
|
2,192
|
Stock-based compensation
|
|
|
333
|
|
|
|
611
|
|
|
380
|
|
|
285
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)
|
|
$
|
(915
|
)
|
|
$
|
2,039
|
|
$
|
14,379
|
|
$
|
8,664
|
|
$
|
13,335
|
|
|
|
|
|
|
|
|
F-56
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,
|
|
|
September 30,
|
|
(In thousands)
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
|
Deferred tax asset:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal net operating loss
|
|
$
|
3,192
|
|
|
$
|
|
|
|
$
|
|
|
Stock-based compensation
|
|
|
590
|
|
|
|
3,776
|
|
|
|
|
|
Financial instruments
|
|
|
6,365
|
|
|
|
|
|
|
|
3,625
|
|
Other
|
|
|
95
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
10,242
|
|
|
|
4,077
|
|
|
|
3,625
|
|
|
|
|
|
|
|
Deferred tax liability:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, principally due to differences in basis
resulting from acquisitions and depletion and the deduction of
intangible drilling costs for tax purposes
|
|
|
(5,338
|
)
|
|
|
(245,464
|
)
|
|
|
(252,261
|
)
|
Financial instruments
|
|
|
|
|
|
|
(283
|
)
|
|
|
461
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(5,338
|
)
|
|
|
(245,747
|
)
|
|
|
(251,800
|
)
|
|
|
|
|
|
|
Net deferred tax asset (liability)
|
|
$
|
4,904
|
|
|
$
|
(241,670
|
)
|
|
$
|
(248,175
|
)
|
|
|
|
|
|
|
|
|
As of December 31, 2006 and September 30, 2007, there
were no remaining deferred tax assets for net operating losses
as they were fully utilized in 2006.
Texas margins tax. On May 18, 2006, the
Governor of Texas signed into law House
Bill 3 (HB-3)
which modifies the existing franchise tax law. The modified
franchise tax will be computed by subtracting either costs of
goods sold or compensation expense, as defined in HB-3, from
gross revenue to arrive at a gross margin. The resulting gross
margin will be taxed at a one percent rate. HB-3 has also
expanded the definition of tax paying entities to include
limited partnerships. HB-3 becomes effective for activities
occurring on or after January 1, 2007. The portion of
deferred tax expense attributable to the enactment of the Texas
margin tax was $515,000 at December 31, 2006.
Note N.
Major customers and derivative counterparties
Sales to major customers. The Companys
share of oil and gas production is sold to various purchasers.
The Company is of the opinion that the loss of any one purchaser
would not have a material adverse effect on the ability of the
Company to sell its oil and gas production.
Navajo Refining Company, L.P. accounted for 36 percent,
38 percent and 52 percent of the oil and gas revenues
of the Company during the periods ended December 31, 2004,
2005 and 2006, respectively, and 57 percent and
54 percent during the nine months ended September 30,
2006 and 2007, respectively. DCP Midstream LP, formerly Duke
Energy Field Services, accounted for 9 percent,
8 percent and 17 percent of the oil and gas revenues
of the Company during the periods ended December 31, 2004,
2005 and 2006, respectively, and 15 percent and
26 percent during the nine months ended September 30,
2006 and 2007, respectively.
F-57
At December 31, 2006, the Company had receivables from
Navajo Refining Company, L.P. and DCP Midstream LP of
$11.0 million and $8.6 million, respectively, which
are reflected in Accounts receivable Oil and
gas in the accompanying consolidated balance sheet.
At September 30, 2007, the Company had receivables from
Navajo Refining Company, L.P. and DCP Midstream LP of
$20.6 million and $8.5 million, respectively, which
are reflected in Accounts receivableOil and gas in
the accompanying consolidated balance sheet.
Derivative counterparties. The Company uses
credit and other financial criteria to evaluate the credit
standing of, and to select, counterparties to its derivative
instruments. The Companys credit facility agreements
require that the senior unsecured debt ratings of the
Companys derivative counterparties be not less than either
A− by Standard & Poors Rating Group rating
system or A3 by Moodys Investors Service, Inc. rating
system. At December 31, 2006 and September 30, 2007,
the counterparties with whom the Company had outstanding
derivative contracts met or exceeded the required ratings.
Although the Company does not obtain collateral or otherwise
secure the fair value of its derivative instruments, management
believes the associated credit risk is mitigated by the
Companys credit risk policies and procedures and by the
credit rating requirements of the Companys credit facility
agreements. There was no derivative receivable at
December 31, 2005. At December 31, 2006 and
September 30, 2007, the Company had $6.9 million and
$2.1 million, respectively, of derivative receivables
representing amounts due from counterparties. Approximately
$6 million and $1.7 million of short-term derivative
receivables are reflected in Derivative instruments in
the accompanying consolidated balance sheets at
December 31, 2006 and September 30, 2007,
respectively. At December 31, 2006 and September 30,
2007, approximately $0.9 million and $0.4 million,
respectively, of long-term derivative receivables are reflected
in Other assets in the accompanying consolidated balance
sheets. At December 31, 2005, December 31, 2006 and
September 30, 2007, the Company had $18.2 million,
$6.2 million and $11.8 million derivative liabilities
representing amounts owed to counterparties, respectively. The
fair market value of the cash flow hedges were a net liability
of approximately $18.2 million, a net asset of
approximately $725,000 and a net liability of approximately
$9.7 million at December 31, 2005, December 31,
2006 and September 30, 2007, respectively.
Note O.
Related parties
Contract operator agreement. On
February 27, 2006, the Company signed a contract operator
agreement with MEC, an affiliate of the Chase Group, whereby the
Company engaged MEC as contract operator to provide certain
services with respect to the Chase Group Properties. The initial
term of the contract operator agreement was 5 years
commencing on March 1, 2006 and ending on February 28,
2011. The Company and MEC entered into a Transition Services
Agreement on April 23, 2007, which terminated the contract
operator agreement and under which MEC provided certain field
level operating services on the Chase Group Properties.
Transition Services Agreement. On
April 23, 2007, the Company entered into a Transition
Services Agreement with MEC whereby it provided services to the
properties in Southeast New Mexico that the Company
acquired from Chase Oil and its affiliates in the Combination.
The Transition Services Agreement replaced the prior contract
operator agreement with MEC. Under the Transition Services
Agreement, MEC provided field level services, including pumping,
well service oversight and supervision and certain equipment for
workover and recompletion services, at costs prevailing in the
area of the subject properties, but not to exceed charges for
comparable services by and among MEC and its affiliates. MEC
performed substantially similar
F-58
services on behalf of the Company under the prior contract
operator agreement prior to its termination. The Transition
Services Agreement terminates upon the earlier to occur of
(i) February 28, 2011; (ii) the date on which the
Company completes the initial sale of its shares of common stock
to the public pursuant to a registration statement filed under
the Securities Act of 1933, as amended; or (iii) a change
of control, as defined, or sooner as otherwise provided in the
agreement or mutually agreed upon by the parties. The Transition
Services Agreement was terminated effective August 7, 2007
upon the Companys completion of its initial public
offering. Accordingly, upon termination, the Company assumed the
operation of the subject properties.
The Company incurred charges from MEC of approximately
$10.3 million for the year ended December 31, 2006 for
services rendered under the contract operator agreement.
The Company incurred charges from MEC of approximately
$11.9 million for the nine months ended September 30,
2007 for services rendered under the contract operator agreement
and Transition Services Agreement.
At December 31, 2006, the Company had outstanding invoices
payable to MEC of approximately $1.8 million which are
reflected in Accounts payablerelated parties in the
accompanying consolidated balance sheet.
At September 30, 2007, the Company had outstanding invoices
payable to MEC of approximately $0.7 million which are
reflected in Accounts payablerelated parties in the
accompanying consolidated balance sheet.
Other related party transactions. The Company
also has engaged in transactions with certain other affiliates
of the Chase Group, including Silver Oak, an oilfield services
company, a supply company, a drilling fluids supply company, a
pipe and tubing supplier, a fixed base operator of aircraft
services, and a software company.
The Company incurred charges from these related party vendors of
approximately $32.4 million for the year ended
December 31, 2006 for services rendered.
At December 31, 2006, the Company had outstanding invoices
payable to the other related party vendors mentioned above of
approximately $1.8 million which are reflected in
Accounts payablerelated parties in the accompanying
consolidated balance sheet.
The Company incurred charges from these related party vendors of
approximately $35.6 million for the nine months ended
September 30, 2007, for services rendered. There were no
amounts paid to these related party vendors during the nine
months ended September 30, 2006, for services rendered.
At September 30, 2007, the Company had outstanding invoices
payable to the other related party vendors identified above of
approximately $2.2 million which are reflected in
Accounts payablerelated parties in the accompanying
consolidated balance sheets.
Overriding royalty and royalty
interests. Certain members of the Chase Group own
overriding royalty interests in certain of the Chase Group
Properties. The amount paid attributable to such interests was
approximately $1.2 million for the year ended
December 31, 2006 and $1.6 million for the nine months
ended September 30, 2007.
Royalties are paid on certain properties located in Andrews
County, Texas to a partnership of which one of the
Companys directors is the General Partner, and who also
owns a 3.5%
F-59
partnership interest. The Company paid approximately $0, $100,
$72,000, $16,000 and $109,000 to this entity during the periods
ended December 31, 2004, 2005 and 2006 and the nine months
ended September 30, 2006 and 2007, respectively. The
Company also paid this entity an $80,000 lease bonus in 2006.
The Company has no outstanding invoices payable to this entity
as of December 31, 2006 or September 30, 2007.
In April 2005, the Company acquired certain working interests in
46,861 gross (26,908 net) acres located in Culberson
County, Texas from an entity partially owned by a person who
became an executive officer of the Company immediately following
such acquisition. In connection with this acquisition, such
entity retained a 2% overriding royalty interest in the acquired
properties, which overriding royalty interest is now owned
equally by such officer and a non-officer employee of the
Company. During the nine months ended September 30, 2006,
no payments were made related to this overriding royalty
interest. The amount attributable to such interest during the
nine months ended September 30, 2007, was approximately
$3,000.
Prospect participation. Subsequent to the
closing of the Combination, the Company acquired working
interests from Caza in certain lands in New Mexico in which Caza
owns an interest.
The Company paid Caza approximately $2.1 million for the
year ended December 31, 2006 for these interests.
Approximately all of the costs were capital prospect costs which
are reflected in Unproved properties in the accompanying
consolidated balance sheet at December 31, 2006.
At December 31, 2006, the Company had no outstanding
invoices owed to Caza.
The Company paid Caza approximately $1,798,000 for the nine
months ended September 30, 2006 for these interests.
Approximately all of the costs were capital prospect costs which
are reflected in Unproved properties in the accompanying
consolidated balance sheet at December 31, 2006.
The Company paid Caza approximately $3,000 for the nine months
ended September 30, 2007 for delay rentals which are
reflected in Unproved properties in the accompanying
consolidated balance sheet at September 30, 2007.
At September 30, 2007, the Company had no outstanding
invoices owed to Caza.
Note P.
Defined contribution plan
The Company sponsors a 401(k) defined contribution plan for the
benefit of substantially all employees. The Company matches in
cash 100 percent of employee contributions, not to exceed
6 percent of the employees annual salary. Company
contributions to the plan for the periods ended
December 31, 2004, 2005 and 2006 were approximately
$73,000, $203,000, and $321,000, respectively, and $217,000, and
$305,000 for the nine months ended September 30, 2006 and
2007, respectively.
Note Q.
Net Income (loss) per share
Basic 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.
As discussed in Note GStockholders equity
and stock issued subject to limited recourse notes,
agreements to sell stock to the Officers and certain employees
subject to Purchase Notes are accounted for as options
(Bundled Capital Options and Capital
Options, respectively). As
F-60
a result, Bundled Capital Options and Capital Options are
excluded from the weighted average number of common shares
treated as outstanding during each period.
The computation of diluted income per share reflects the
potential dilution that could occur if securities or other
contracts to issue common stock that are dilutive to income were
exercised or converted into common stock or resulted in the
issuance of common stock that would then share in the earnings
of the Company. These amounts include Bundled Capital Options,
Capital Options, stock options (as issued under the Stock Option
Plan of CEHC adopted in 2004 and the Plan of CRI adopted in
2006, both as described in Note HStock incentive
plan) and restricted stock. Potentially dilutive effects are
calculated using the treasury stock method.
The CEHC 6% Series A Preferred Stock were entitled to
receive an amount equal to its stated value ($9.00) plus any
unpaid dividends upon occurrence of a liquidation event, as
defined. In connection with the Combination on February 24,
2006, a liquidation event occurred. Instead of receiving the
stated value, the holders of the CEHC 6% Series A Preferred
Stock agreed to accept 0.75 shares of Resources common
stock in exchange for each share of CEHC 6% Series A
Preferred Stock. This was considered to be an induced
conversion, as defined in the FASB Emerging Issues Task Force
Topic D-42, The Effect on the Calculation of Earnings per
Share for the Redemption or Induced Conversion of Preferred
Stock. The excess of the carrying amount of the CEHC 6%
Series A Preferred Stock over the fair value of the
Resources common stock issued is required to be added to 2006
net income to arrive at 2006 net income applicable to common
shareholders for the year ended December 31, 2006 and the
nine months ended September 30, 2006.
The following table is a reconciliation of the basic weighted
average common shares outstanding to diluted weighted average
common shares outstanding for the periods ended
December 31, 2004, 2005, and 2006 and the nine months ended
September 30, 2006 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended
|
|
|
For the years ended December 31,
|
|
September 30,
|
(in thousands)
|
|
2004
|
|
2005
|
|
2006
|
|
2006
|
|
2007
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
994
|
|
|
4,059
|
|
|
47,287
|
|
|
44,710
|
|
|
60,648
|
Dilutive Bundled Capital Options
|
|
|
|
|
|
|
|
|
2,516
|
|
|
2,443
|
|
|
1,130
|
Dilutive Capital Options
|
|
|
|
|
|
|
|
|
192
|
|
|
174
|
|
|
163
|
Dilutive common stock options
|
|
|
|
|
|
|
|
|
714
|
|
|
602
|
|
|
852
|
Dilutive restrictive stock
|
|
|
|
|
|
|
|
|
20
|
|
|
8
|
|
|
65
|
|
|
|
|
|
|
Diluted
|
|
|
994
|
|
|
4,059
|
|
|
50,729
|
|
|
47,937
|
|
|
62,858
|
|
|
|
|
|
|
|
|
For the years ended December 31, 2004 and 2005, the effects
of all securities (including Bundled Capital Options, Capital
Options and stock options) were excluded from the computation of
diluted earnings per share because the Company had a net loss
applicable to common
F-61
shareholders and, therefore, the effects would have been
antidilutive. Securities excluded are summarized below:
|
|
|
|
|
|
|
|
|
|
December 31,
|
(in thousands)
|
|
2004
|
|
2005
|
|
|
Series A preferred stock
|
|
|
7,235
|
|
|
11,957
|
Bundled Capital
Options(a)
|
|
|
1,100
|
|
|
1,100
|
Capital
Options(a)
|
|
|
85
|
|
|
483
|
Common stock
options(a)
|
|
|
362
|
|
|
683
|
|
|
|
|
|
(a)
|
|
For unit options, this excludes the
preferred stock portion.
|
Since the Company had net income applicable to common
shareholders for the year ended December 31, 2006 and for
the nine months ended September 30, 2006 and 2007, the
effects of all potentially dilutive securities including Bundled
Capital Options, Capital Options, incentive stock options and
unvested restricted stock were considered in the computation of
diluted earnings per share. Because the exercise prices of
certain incentive stock options were greater than the average
market price of the common shares and would be anti-dilutive,
incentive stock options to purchase 450,000 shares of
common stock for the year ended December 31, 2006 and for
the nine months ended September 30, 2006 and incentive
stock options to purchase 665,000 shares of common stock
for the nine months ended September 30, 2007 were
outstanding but not included in the computations of diluted
income per share from continuing operations.
Note R.
Subsequent events (unaudited)
Stock option modifications. On
November 8, 2007, the Compensation Committee of the Board
of Directors authorized and approved amendments to certain
outstanding agreements related to options to purchase the
Companys common stock that were previously awarded to
certain of the Companys executive officers and employees
in order to amend such award agreements so that the subject
stock option award would constitute deferred compensation that
is compliant with Section 409A of the Internal Revenue Code
of 1986, as amended (the Code), or exempt
from the application of Code Section 409A. As the offer to
amend outstanding stock option agreements previously issued to
certain of the Companys employees may constitute a tender
offer under the Securities Exchange Act of 1934, on
November 8, 2007, the Board of Directors of the Company has
authorized commencement of a tender offer to amend the
applicable outstanding stock option award agreements in the form
approved by the Compensation Committee.
Generally, the amendments provide that the employee stock
options, which had previously vested in connection with the
Combination, will become exercisable in 25% increments over a
four year period beginning in 2008 and continuing through 2011
or upon the occurrence of certain specified events. Any affected
employee who decides to amend their stock option award agreement
will receive a cash payment equal to $0.50 for each share of
common stock subject to the amendment on January 2, 2008.
Assuming all affected employees elect to amend their options
subject to the offer, the Company expects to make aggregate cash
payments of approximately $275,000 to such employees. The
Companys affected executive officers received and accepted
a similar offer to amend their stock option awards issued prior
to the Combination
F-62
on substantially the same terms, except such officers were not
offered the $0.50 per share payment.
In addition, the Companys named executive officers
received stock option awards in June 2006 to purchase
450,000 shares of common stock, in the aggregate, at a
purchase price of $12.00 per share. The Company
subsequently determined that the fair market value of a share of
common stock as of the date of the award was $15.40. As a
result, the Compensation Committee has 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.
If an executive officer accepts this offer, the Company has
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.
Based on the Companys preliminary estimates, which are
subject to change depending on the timing of acceptance of the
Companys offers by the subject employees and executive
officers, the Company has determined that its aggregate
compensation expense resulting from these proposed modifications
of approximately $1.2 million will be recorded during the
remainder of the year ending December 31, 2007 and during
the years ending December 31, 2008, 2009 and 2010.
On November 16, 2007, the Companys named executive
officers signed an Amendment to Nonstatutory Stock Option
Agreement. These amendments modify the stock options in
accordance with the proposed modifications listed above. The
modifications to the stock option awards issued prior to the
combination transaction was to establish mandatory exercise
dates beginning in 2008 and continuing through 2011. Regarding
the modifications to the June 2006 options, the strike price has
been reset to $15.40 per share from the original strike
price of $12.00 per share. The vesting of these stock
options has not changed from the original schedule of one
quarter per year beginning June 12, 2007 through
June 12, 2010. There are no mandatory exercise dates
associated with this group of options. To compensate for the
$3.40 increase in the strike price, the Companys named
executive officers were granted 83,242 shares of restricted
stock on November 19, 2007 with a grant date fair market
value of $18.38, for an aggregate value of approximately
$1.5 million. This represents incremental value of
approximately $0.9 million above the value of the June 2006
options. Such incremental value will be recognized in General
and administrative expense in the consolidated statement of
operations beginning in November 2007 and continuing through the
final dates of the lapse of forfeiture restrictions. The grant
price used to determine the number of restricted shares issued
was the mean of the high and the low trading prices on the New
York Stock Exchange on the date of grant. The lapse of
forfeiture restrictions of this restricted stock is in 25%
increments on the lapse dates of January 1, 2008;
June 12, 2008; June 12, 2009; and June 12, 2010
or upon the occurrence of certain specified events.
Borrowing base redetermination on
1st
Lien Credit Facility. As discussed in
Note JLong-term debt, regular redeterminations
are scheduled under the Second Amendment to the
1st
Lien Credit Facility on January 1 and June 30 of each
year. In conjunction with the scheduled redetermination as of
June 30, 2007 we requested an increase in the borrowing
base in the amount of $50 million. Such request was
approved by all the lenders and the borrowing base was
redetermined at $425 million effective November 21,
2007.
F-63
Exploratory dry holeWestern Delaware
Basin. As discussed in
Note CExploratory well costs, the Company was
testing a deeper formation in the second well drilled in the
Western Delaware Basin project area and was evaluating the
commercial viability of the deeper zone as of September 30,
2007. In November 2007 the Company completed its evaluation of
this formation which indicated that conditions were unfavorable
for commercial success. The well was temporarily abandoned. As a
result, the Company will expense all remaining capitalized costs
of approximately $3.3 million during the fourth quarter of
2007. These costs, combined with the approximate
$1.8 million recognized as exploratory dry hole expense
during the quarter ended September 30, 2007, represent all
drilling the completion costs incurred on this unsuccessful well.
Note S.
Supplementary information
Costs incurred
for oil and gas producing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
April 21, 2004
|
|
|
|
|
|
|
|
|
|
|
|
(inception)
|
|
|
|
|
|
|
|
|
|
|
|
through
|
|
Years ended
|
|
Nine months ended
|
|
|
|
December 31,
|
|
December 31,
|
|
September 30,
|
|
(in thousands)
|
|
2004
|
|
2005
|
|
2006
|
|
2006
|
|
2007
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
99,382
|
|
$
|
7,834
|
|
$
|
824,382
|
|
$
|
822,810
|
|
$
|
11,801
|
|
Unproved
|
|
|
10,112
|
|
|
14,694
|
|
|
217,788
|
|
|
218,848
|
|
|
(2,239
|
)
|
Exploration
|
|
|
3,198
|
|
|
7,301
|
|
|
49,394
|
|
|
27,912
|
|
|
70,973
|
|
Development
|
|
|
1,931
|
|
|
38,727
|
|
|
126,089
|
|
|
85,235
|
|
|
44,253
|
|
Capitalized asset retirement obligations
|
|
|
883
|
|
|
141
|
|
|
7,293
|
|
|
6,274
|
|
|
(1,951
|
)
|
|
|
|
|
|
|
Total costs incurred for oil and gas properties
|
|
$
|
115,506
|
|
$
|
68,697
|
|
$
|
1,224,946
|
|
$
|
1,161,079
|
|
$
|
122,837
|
|
|
|
|
|
|
|
|
|
Reserve quantity
information (unaudited)
The estimates of proved oil and gas reserves, which are located
primarily in the Permian Basin region of West Texas and Eastern
New Mexico were prepared by Netherland, Sewell &
Associates, Inc. and Cawley, Gillespie & Associates,
Inc., independent petroleum engineers. Reserves were estimated
in accordance with guidelines established by the Securities and
Exchange Commission, which require that reserve estimates be
prepared under existing economic and operating conditions with
no provision for price and cost escalations except by
contractual arrangements. Future production costs include the
Companys estimate of the portion of its headquarters
general and administrative overhead expenses necessary to
operate the properties. The reserve estimates for 2005 utilize
the year-end West Texas Intermediate futures oil price of
$61.04 per Bbl and the year-end Henry Hub spot market gas
price of $10.08 per MMbtu. The reserve estimates for 2006
utilize the year-end West Texas Intermediate posted oil price of
$57.75 per Bbl and the year-end Henry Hub spot market gas
price of $5.635 per MMbtu. Commodity prices utilized for
the reserve estimates were adjusted for location, grade and
quality.
F-64
Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved
reserves and in the projection of future rates of production and
the timing of development expenditures. The accuracy of such
estimates is a function of the quality of available data and of
engineering and geological interpretation and judgment. Results
of subsequent drilling, testing and production may cause either
upward or downward revision of previous estimates. Further, the
volumes considered to be commercially recoverable fluctuate with
changes in prices and operating costs. The Company emphasizes
that reserve estimates are inherently imprecise and that
estimates of new discoveries are more imprecise than those of
currently producing oil and gas properties. Accordingly, these
estimates are expected to change as additional information
becomes available in the future.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
|
Oil and
|
|
|
Natural
|
|
|
Oil and
|
|
|
Natural
|
|
|
Oil and
|
|
|
Natural
|
|
|
|
condensate
|
|
|
gas
|
|
|
condensate
|
|
|
gas
|
|
|
condensate
|
|
|
gas
|
|
(in thousands)
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
|
|
Total proved reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, January 1
|
|
|
|
|
|
|
|
|
|
|
6,553
|
|
|
|
35,464
|
|
|
|
9,658
|
|
|
|
49,530
|
|
Purchase of
minerals-in-place
|
|
|
6,191
|
|
|
|
32,609
|
|
|
|
191
|
|
|
|
1,095
|
|
|
|
27,163
|
|
|
|
137,963
|
|
New discoveries and extensions
|
|
|
407
|
|
|
|
3,146
|
|
|
|
3,256
|
|
|
|
15,864
|
|
|
|
10,226
|
|
|
|
39,427
|
|
Revisions of previous estimates
|
|
|
|
|
|
|
|
|
|
|
257
|
|
|
|
511
|
|
|
|
(430
|
)
|
|
|
(16,595
|
)
|
Production from continuing operations
|
|
|
(45
|
)
|
|
|
(291
|
)
|
|
|
(599
|
)
|
|
|
(3,404
|
)
|
|
|
(2,295
|
)
|
|
|
(9,507
|
)
|
|
|
|
|
|
|
Balance, December 31
|
|
|
6,553
|
|
|
|
35,464
|
|
|
|
9,658
|
|
|
|
49,530
|
|
|
|
44,322
|
|
|
|
200,818
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1
|
|
|
|
|
|
|
|
|
|
|
4,536
|
|
|
|
24,366
|
|
|
|
6,502
|
|
|
|
34,160
|
|
December 31
|
|
|
4,536
|
|
|
|
24,366
|
|
|
|
6,502
|
|
|
|
34,160
|
|
|
|
23,443
|
|
|
|
112,423
|
|
|
|
Although the Company believes it has increased its proved
reserves during 2007 based on the Companys internally
prepared reserve engineering estimates, there have been no
individually significant discoveries or other favorable or
adverse events in 2007 that caused a material change from the
proved reserve information presented as of December 31,
2006, other than any changes to quantities of proved reserves
that may result from the Companys ongoing drilling program
and changes in the market prices for oil and gas.
Purchase of
minerals-in-place. During
the period ended December 31, 2004, the Company completed
the Lowe Acquisition. During the year ended December 31,
2006, the Company completed the Combination of the Chase Group
Properties. See Note D Acquisitions and
business combinations for a detailed discussion of the Lowe
Acquisition and the Combination of the Chase Group Properties.
New discoveries and extensions. The additions to the
Companys proved reserves through new discoveries and
extensions result from (i) extensions of the proved acreage
of previously
F-65
discovered reservoirs through additional drilling of development
wells and (ii) discovery of new fields with proved reserves
through drilling of exploratory wells.
The additions to the Companys proved reserves through new
discoveries and extensions result from (i) extensions of
the proved acreage of previously discovered reservoirs through
additional drilling of development wells and (ii) discovery
of new fields with proved reserves through drilling of
exploratory wells.
The Companys New discoveries and extensions for the
period ended December 31, 2004 were added through the
drilling of six productive wells. Of the six productive wells
initiated during 2004, all six were located in the Permian Basin
region. Of these six productive wells drilled for the period
ended December 31, 2004, three were development wells and
three were exploratory wells. During the period ended
December 31, 2004, one development well was successfully
completed as a producing well and two were actively drilling at
year end 2004. During 2004, three exploratory wells were
successfully completed as producing wells or were wells awaiting
completion.
The Companys New discoveries and extensions for the
year ended December 31, 2005 were added through the
drilling of 49 productive wells. Of the 49 productive
wells initiated during 2005, 48 were located in the Permian
Basin region and one was located in the Texas Panhandle Area. Of
the 49 productive wells drilled for the period ended
December 31, 2005, 41 were development wells and eight were
exploratory wells. During the period ended December 31,
2005, 41 development wells were successfully completed as
producing wells and eight exploratory wells were successfully
completed as producing wells or were wells awaiting completion.
The Companys New discoveries and extensions for the
years ended December 31, 2006 were added through the
drilling of 112 productive wells. Of the
112 productive wells initiated during 2006, 107 were
located in the Permian Basin region, three were located in the
South Texas Area, and two were located in North Dakota. Of these
112 productive wells drilled for the period ended
December 31, 2006, 75 were development wells and 37 were
exploratory wells. During the period ended December 31,
2006, 75 development wells were successfully completed as
producing wells and 37 exploratory wells were successfully
completed as producing wells or were wells awaiting completion.
Revisions of previous estimates. The downward
revision in estimates for the year ended December 31, 2006,
was primarily due to a decrease in natural gas prices resulting
in a downward revision of proved developed and undeveloped
reserves.
Standardized
measure of discounted future net cash flows
(unaudited)
The standardized measure of discounted future net cash flows is
computed by applying year-end prices of oil and gas (with
consideration of price changes only to the extent provided by
contractual arrangements) to the estimated future production of
proved oil and gas reserves less estimated future expenditures
(based on year-end costs) to be incurred in developing and
producing the proved reserves, discounted using a rate of
10 percent per year to reflect the estimated timing of the
future cash flows. Future income taxes are calculated by
comparing undiscounted future cash flows to the tax basis of oil
and gas properties plus available carryforwards and credits and
applying the current tax rates to the difference.
F-66
Discounted future cash flow estimates like those shown below are
not intended to represent estimates of the fair value of oil and
gas properties. Estimates of fair value would also consider
probable and possible reserves, anticipated future oil and gas
prices, interest rates, changes in development and production
costs and risks associated with future production. Because of
these and other considerations, any estimate of fair value is
necessarily subjective and imprecise.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
|
|
Oil and gas producing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
479,083
|
|
|
$
|
972,662
|
|
|
$
|
3,560,326
|
|
Future production costs
|
|
|
(175,319
|
)
|
|
|
(289,938
|
)
|
|
|
(995,335
|
)
|
Future development and abandonment costs
|
|
|
(26,371
|
)
|
|
|
(62,275
|
)
|
|
|
(484,462
|
)
|
Future income tax expense
|
|
|
(59,849
|
)
|
|
|
(186,539
|
)
|
|
|
(530,212
|
)
|
|
|
|
|
|
|
Future net cash flows
|
|
|
217,544
|
|
|
|
433,910
|
|
|
|
1,550,317
|
|
10% annual discount factor
|
|
|
(83,244
|
)
|
|
|
(210,148
|
)
|
|
|
(839,968
|
)
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
$
|
134,300
|
|
|
$
|
223,762
|
|
|
$
|
710,349
|
|
|
|
|
|
|
|
|
|
Changes in
standardized measure of discounted future net cash flows
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
|
|
Purchases of
minerals-in-place
|
|
$
|
140,598
|
|
|
$
|
7,612
|
|
|
$
|
795,072
|
|
Extensions and discoveries
|
|
|
12,074
|
|
|
|
98,826
|
|
|
|
156,266
|
|
Net changes in prices and production costs
|
|
|
|
|
|
|
99,041
|
|
|
|
(109,264
|
)
|
Oil and gas sales, net of production costs
|
|
|
(2,876
|
)
|
|
|
(40,301
|
)
|
|
|
(160,468
|
)
|
Changes in future development costs
|
|
|
|
|
|
|
(1,649
|
)
|
|
|
(6,085
|
)
|
Revisions of previous quantity estimates
|
|
|
|
|
|
|
7,302
|
|
|
|
(51,147
|
)
|
Accretion of discount
|
|
|
|
|
|
|
14,933
|
|
|
|
17,317
|
|
Changes in production rates, timing and other
|
|
|
(471
|
)
|
|
|
(12,596
|
)
|
|
|
(10,119
|
)
|
|
|
|
|
|
|
Change in present value of future net revenues
|
|
|
149,325
|
|
|
|
173,168
|
|
|
|
631,572
|
|
Net change in present value of future income taxes
|
|
|
(15,025
|
)
|
|
|
(83,706
|
)
|
|
|
(144,985
|
)
|
|
|
|
|
|
|
|
|
|
134,300
|
|
|
|
89,462
|
|
|
|
486,587
|
|
Balance, beginning of year
|
|
|
|
|
|
|
134,300
|
|
|
|
223,762
|
|
|
|
|
|
|
|
Balance, end of year
|
|
$
|
134,300
|
|
|
$
|
223,762
|
|
|
$
|
710,349
|
|
|
|
|
|
|
|
|
|
F-67
CONCHO
RESOURCES INC. AND SUBSIDIARIES
UNAUDITED PRO FORMA COMBINED
STATEMENTS OF OPERATIONS
The unaudited pro forma combined statements of operations have
been prepared to assist in the analysis of the historical
financial results of Concho Resources Inc.
(Resources or the Company) subsequent to
the Combination (meaning the combination of Resources, Concho
Equity Holdings Corp. and the Chase Group Properties which was
consummated on February 27, 2006) and the
Companys initial public offering of common stock that
occurred in August 2007. The Chase Group Properties consists of:
Chase Oil Corporation (Chase Oil); Caza Energy LLC
(Caza Energy); Robert Chase, Richard Chase, Dianne
Crouch (collectively, the Working Interest Group);
and twenty-one other related parties (collectively, the
Employee Group). The unaudited pro forma combined
statements of operations have been prepared to illustrate pro
forma operating results as if the Combination and the
Companys initial public offering had taken place on
January 1, 2006.
The unaudited pro forma statements of operations and related
notes are presented for illustrative purposes only. If the
Combination and the Companys initial public offering had
occurred in the past, Resources operating results might
have been different from those presented in the unaudited pro
forma information. The unaudited pro forma information should
not be relied upon as an indication of operating results that
Resources would have achieved if the Combination and the
Companys initial public offering had taken place on the
specified date. You should also not rely on the unaudited pro
forma information as an indication of the future results that
Resources will achieve. In addition, future results may vary
significantly from the results reflected in the accompanying
unaudited pro forma combined statements of operations because of
normal production declines, changes in product prices, future
acquisitions and divestitures and other factors.
The following unaudited pro forma combined statements of
operations and related notes should be read in conjunction with
the consolidated financial statements and related notes of
Resources and the combined statements of revenues and expenses
of the Chase Group Properties.
F-68
Concho Resources
Inc. and subsidiaries
Unaudited pro forma combined statement of operations
Year ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chase Group
|
|
|
|
|
|
|
|
|
|
|
|
Properties
|
|
|
|
|
|
|
|
|
|
|
|
historical
|
|
|
|
|
|
|
|
|
|
|
|
for the two
|
|
|
|
|
|
|
|
|
|
|
|
months ended
|
|
Pro Forma
|
|
|
|
|
|
|
Resources
|
|
|
February 28,
|
|
adjustments
|
|
|
|
|
(in thousands, except per share amounts)
|
|
historical
|
|
|
2006
|
|
(Notes B & C)
|
|
|
Pro forma
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
131,773
|
|
|
$
|
13,940
|
|
|
|
|
|
$
|
145,713
|
|
Natural gas sales
|
|
|
66,517
|
|
|
|
7,516
|
|
|
|
|
|
|
74,033
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
198,290
|
|
|
|
21,456
|
|
|
|
|
|
|
219,746
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
22,060
|
|
|
|
2,396
|
|
|
|
|
|
|
24,456
|
|
Oil and gas production taxes
|
|
|
15,762
|
|
|
|
1,840
|
|
|
|
|
|
|
17,602
|
|
Exploration and abandonments
|
|
|
5,612
|
|
|
|
|
|
|
|
|
|
|
5,612
|
|
Depreciation and depletion
|
|
|
60,722
|
|
|
|
2,217
|
|
|
3,211
|
(a)
|
|
|
66,150
|
|
Accretion of discount on asset retirement obligations
|
|
|
287
|
|
|
|
83
|
|
|
|
|
|
|
370
|
|
Impairments of proved oil and gas properties
|
|
|
9,891
|
|
|
|
1
|
|
|
|
|
|
|
9,892
|
|
General and administrative (including non-cash stock-based
compensation)
|
|
|
21,721
|
|
|
|
284
|
|
|
|
|
|
|
22,005
|
|
Ineffective portion of cash flow hedges
|
|
|
(1,193
|
)
|
|
|
|
|
|
|
|
|
|
(1,193
|
)
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
134,862
|
|
|
|
6,821
|
|
|
|
|
|
|
144,894
|
|
|
|
|
|
|
|
Income from operations
|
|
|
63,428
|
|
|
|
14,635
|
|
|
|
|
|
|
74,852
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(30,567
|
)
|
|
|
|
|
|
(5,020
|
)(b)
|
|
|
(21,677
|
)
|
|
|
|
|
|
|
|
|
|
|
13,837
|
(e)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73
|
(f)
|
|
|
|
|
Other, net
|
|
|
1,186
|
|
|
|
|
|
|
(550
|
)(g)
|
|
|
636
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(29,381
|
)
|
|
|
|
|
|
|
|
|
|
(21,041
|
)
|
|
|
|
|
|
|
Income before income taxes
|
|
|
34,047
|
|
|
|
14,635
|
|
|
|
|
|
|
53,811
|
|
Income tax expense
|
|
|
(14,379
|
)
|
|
|
|
|
|
(7,707
|
)(h)
|
|
|
(22,086
|
)
|
|
|
|
|
|
|
Net income
|
|
|
19,668
|
|
|
|
14,635
|
|
|
|
|
|
|
31,725
|
|
Preferred stock dividends
|
|
|
(1,244
|
)
|
|
|
|
|
|
1,244
|
(c)
|
|
|
|
|
Effect of induced conversion of preferred stock
|
|
|
11,601
|
|
|
|
|
|
|
(11,601
|
)(d)
|
|
|
|
|
|
|
|
|
|
|
Net income applicable to common shareholders
|
|
$
|
30,025
|
|
|
$
|
14,635
|
|
|
|
|
|
$
|
31,725
|
|
|
|
|
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
|
|
$
|
0.63
|
|
|
|
|
|
|
|
|
|
$
|
0.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in basic earnings per share
|
|
|
47,287
|
|
|
|
|
|
|
23,347
|
|
|
|
70,634
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
|
|
$
|
0.59
|
|
|
|
|
|
|
|
|
|
$
|
0.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in diluted earnings per share
|
|
|
50,729
|
|
|
|
|
|
|
23,443
|
|
|
|
74,172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of the above unaudited pro forma combined
statement of operations.
F-69
Concho Resources
Inc. and subsidiaries
Unaudited pro forma combined statement of operations
Nine months ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma
|
|
|
|
|
|
|
Resources
|
|
|
adjustments
|
|
|
|
|
(in thousands, except per share amounts)
|
|
historical
|
|
|
(Note C)
|
|
|
Pro forma
|
|
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
128,152
|
|
|
|
|
|
|
$
|
128,152
|
|
Natural gas sales
|
|
|
67,395
|
|
|
|
|
|
|
|
67,395
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
195,547
|
|
|
|
|
|
|
|
195,547
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
22,309
|
|
|
|
|
|
|
|
22,309
|
|
Oil and gas production taxes
|
|
|
15,616
|
|
|
|
|
|
|
|
15,616
|
|
Exploration and abandonments
|
|
|
18,110
|
|
|
|
|
|
|
|
18,110
|
|
Depreciation and depletion
|
|
|
55,036
|
|
|
|
|
|
|
|
55,036
|
|
Accretion of discount on asset retirement obligations
|
|
|
334
|
|
|
|
|
|
|
|
334
|
|
Impairments of proved oil and gas properties
|
|
|
4,577
|
|
|
|
|
|
|
|
4,577
|
|
Contract drilling fees-stacked rigs
|
|
|
4,269
|
|
|
|
|
|
|
|
4,269
|
|
General and administrative (including non-cash
stock-based compensation)
|
|
|
16,567
|
|
|
|
|
|
|
|
16,567
|
|
Ineffective portion of cash flow hedges
|
|
|
1,134
|
|
|
|
|
|
|
|
1,134
|
|
Gain on derivatives not designated as hedges
|
|
|
(3,088
|
)
|
|
|
|
|
|
|
(3,088
|
)
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
134,864
|
|
|
|
|
|
|
|
134,864
|
|
|
|
|
|
|
|
Income from operations
|
|
|
60,683
|
|
|
|
|
|
|
|
60,683
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(29,803
|
)
|
|
|
8,959
|
(e)
|
|
|
(20,819
|
)
|
|
|
|
|
|
|
|
25
|
(f)
|
|
|
|
|
Other, net
|
|
|
957
|
|
|
|
(170
|
)(g)
|
|
|
787
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(28,846
|
)
|
|
|
|
|
|
|
(20,032
|
)
|
|
|
|
|
|
|
Income before income taxes
|
|
|
31,837
|
|
|
|
|
|
|
|
40,651
|
|
Income tax expenses
|
|
|
(13,335
|
)
|
|
|
(3,696
|
)(h)
|
|
|
(17,031
|
)
|
|
|
|
|
|
|
Net income
|
|
|
18,502
|
|
|
|
|
|
|
|
23,620
|
|
Preferred stock dividends
|
|
|
(45
|
)
|
|
|
45
|
(c)
|
|
|
|
|
|
|
|
|
|
|
Net income applicable to common shareholders
|
|
$
|
18,457
|
|
|
|
|
|
|
$
|
23,620
|
|
|
|
|
|
|
|
Basic earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
|
|
$
|
0.30
|
|
|
|
|
|
|
$
|
0.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in basic earnings per share
|
|
|
60,648
|
|
|
|
16,466
|
|
|
|
77,114
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
|
|
$
|
0.29
|
|
|
|
|
|
|
$
|
0.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in diluted earnings per share
|
|
|
62,858
|
|
|
|
16,466
|
|
|
|
79,324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of the above unaudited pro forma combined
statement of operations.
F-70
Concho
Resources Inc. and subsidiaries
Notes to unaudited pro forma
combined statement of operations
Note A.
Basis of presentation
Following is a description of the individual columns included in
the unaudited pro forma combined statement of operations:
ResourcesRepresents the operating results of Resources as
the accounting successor to Concho Equity Holdings Corp
(CEHC).
Chase Group PropertiesRepresents operating results of the
properties contributed to Concho Resources by the Chase Group,
which consists of: Chase Oil Corporation (Chase
Oil); Caza Energy LLC (Caza Energy); Robert
Chase, Richard Chase, Dianne Crouch (collectively, the
Working Interest Group); and twenty-one other
related parties (collectively, the Employee Group).
The following table summarizes the final allocated net purchase
price of the Chase Group Properties acquisition including
capitalized transaction costs:
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
830,540
|
|
Unproved oil and gas properties
|
|
|
200,000
|
|
|
|
|
|
|
Total assets acquired
|
|
$
|
1,030,540
|
|
|
|
|
|
|
Asset requirement obligations
|
|
|
(6,158
|
)
|
Chase investors asset purchase obligation
|
|
|
(906
|
)
|
Deferred tax liability
|
|
|
(227,735
|
)
|
|
|
|
|
|
Total liabilities assumed
|
|
$
|
(234,799
|
)
|
|
|
|
|
|
Net purchase price
|
|
$
|
795,741
|
|
|
|
|
|
|
|
Pro forma AdjustmentsPro forma adjustments to reflect the
combination of Resources and the Chase Group properties (the
Combination) and the Companys initial public
offering of common shares in August 2007 as if they occurred on
January 1, 2006. See Notes B and C for a description of the
pro forma adjustments.
Note B.
Pro forma adjustments related to the
Combination
The lettered pro forma adjustments made to the Companys
unaudited combined financial statements are described as follows:
|
|
|
(a) |
|
To adjust depreciation and depletion for the Chase Group
Properties for the acquisition cost recorded by Resources. |
F-71
|
|
|
(b) |
|
To adjust interest expense for borrowings of approximately
$411 million under Resources bank credit facility to
effect the Combination calculated at the Resources borrowing
rate of 7.85% at December 31, 2006. If the Companys
borrowing rate at December 31, 2006 increased 1/8%, the
Company would incur an additional $514,000 of annual interest
expense, and if the rate decreased 1/8%, the Company would incur
$514,000 less of interest expense. |
|
(c) |
|
To adjust preferred stock dividends accrued from January 1,
2005 on Series A preferred shares of CEHC which were
converted to Resources common shares as of the date of the
Combination and to adjust for preferred stock dividends accrued
from January 1, 2006 on Series A preferred shares of
CEHC for employees who exchanged their common and preferred
shares of CEHC for common shares of Resources on April 16,
2007. |
|
(d) |
|
To eliminate the effects of the induced conversion of preferred
stock on February 23, 2006. |
Note C.
Pro forma adjustments related to the Companys initial
public offering
The lettered pro forma adjustments made to the Companys
unaudited combined financial statements are described as follows:
|
|
|
(e) |
|
To reduce pro forma interest expense resulting from the pro
forma repayment and elimination of $173.0 million
indebtedness with net proceeds of the Companys initial
public offering and the repayment of Notes receivable from
officers. |
|
(f) |
|
To reduce the amortization of deferred loan fees included in
interest expense for the effect of the elimination of deferred
loan fees associated with our 2nd Lien Credit Facility as
if the Companys initial public offering had taken place on
January 1, 2006. |
|
|
|
The Company applied a portion of the proceeds received from its
initial public offering as partial repayment of its New 2nd Lien
Credit Facility in 2007. As a result, the Company wrote-off
approximately $1.0 million in deferred loan fees and
original issue discount associated with such credit facility.
This write-off has not been included in the pro forma combined
statements of operations. |
|
(g) |
|
To reduce pro forma interest income, classified in the statement
of operations as Other income, resulting from the pro
forma repayment and elimination of $10.4 million Notes
receivable from officers with their share of net proceeds
from the Companys initial public offering. Proceeds from
the repayment of Notes receivable from officers are
applied to the repayment of a portion of the Companys
1st Lien Credit Facility. |
|
(h) |
|
To adjust income taxes for the Combination of the Chase Group
Properties and the Companys initial public offering at its
effective income tax rate. |
Pro forma earnings per share amounts (both primary and fully
diluted) are computed as if the Combination had taken place on
January 1, 2006 and the 16,465,917 shares of common stock
sold by the Company in its initial public offering had been
issued on January 1, 2006.
F-72
REPORT
OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Concho Resources Inc.
We have audited the accompanying combined statements of assets
and liabilities of the Chase Group Properties which consists of
the assets and liabilities contributed by the Chase Group (as
defined in Note A) as provided for in the Combination
Agreement dated February 24, 2006 among Concho Resources,
Inc., Concho Equity Holdings Corp. (Concho
Holdings), the stockholders of Concho Holdings, and the
Chase Group as of December 31, 2004 and 2005, and the
related combined statements of revenues and expenses, net
investment, and cash flows for each of the three years in the
period ended December 31, 2005 (collectively, the
Special-Purpose Carve-Out Combined Financial
Statements). These Special-Purpose Carve-Out Combined
Financial Statements are the responsibility of the Chase Group
Properties management. Our responsibility is to express an
opinion on these Special-Purpose Carve-Out Combined Financial
Statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the Special-Purpose Carve-Out
Combined Financial Statements are free of material misstatement.
The Chase Group Properties are not required to have, nor were we
engaged to perform an audit of its internal control over
financial reporting. Our audit included consideration of
internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Chase Group Properties
internal control over financial reporting. Accordingly, we
express no such opinion. An audit also includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the Special-Purpose Carve-Out Combined Financial Statements,
assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
Special-Purpose Carve-Out Combined Financial Statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the Special-Purpose Carve-Out Combined Financial
Statements present fairly, in all material respects, the
financial position of the Chase Group Properties as of
December 31, 2004, and 2005, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2005, in conformity with
accounting principles generally accepted in the United States of
America.
As discussed in Note A, the Chase Group Properties are a
group of related assets and liabilities in the form of leasehold
interests owned by the Chase Group in certain producing and
non-producing oil and gas properties and are not a stand-alone
entity. The Special-Purpose Carve-Out Combined Financial
Statements of the Chase Group Properties reflect the assets,
liabilities, revenues, and expenses directly attributable to the
Chase Group Properties, as well as allocations deemed reasonable
by management, to present the combined financial position,
results of operations, changes in net investment, and cash flows
of the Chase Group Properties on a stand-alone basis and do not
necessarily reflect the combined financial position, results of
operations, changes in net investment, and cash flows of the
Chase Group Properties in the future or what they would have
been had the Chase Group Properties been a separate, stand-alone
entity during the periods presented.
GRANT THORNTON LLP
Kansas City, Missouri
April 23, 2007
F-73
The Chase Group
Properties
Combined
statements of assets and liabilities
|
|
|
|
|
|
|
|
|
|
|
DECEMBER 31, (in
thousands)
|
|
2004
|
|
|
2005
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
CURRENT ASSETS:
|
|
|
|
|
|
|
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
9,532
|
|
|
$
|
3,949
|
|
Oil and gas related party
|
|
|
|
|
|
|
7,224
|
|
Derivative instruments
|
|
|
|
|
|
|
1,577
|
|
|
|
|
|
|
|
Total current assets
|
|
|
9,532
|
|
|
|
12,750
|
|
OIL AND GAS PROPERTIES, SUCCESSFUL EFFORTS METHOD:
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
238,544
|
|
|
|
270,453
|
|
Unproved properties
|
|
|
1,078
|
|
|
|
1,042
|
|
Salt water disposal system
|
|
|
966
|
|
|
|
1,214
|
|
Accumulated depletion, depreciation and amortization
|
|
|
(105,020
|
)
|
|
|
(123,667
|
)
|
|
|
|
|
|
|
Total oil and gas properties, net
|
|
|
135,568
|
|
|
|
149,042
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
145,100
|
|
|
$
|
161,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND NET INVESTMENT
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
352
|
|
|
$
|
2,153
|
|
Related party
|
|
|
45
|
|
|
|
277
|
|
Current portion of asset retirement obligations
|
|
|
245
|
|
|
|
402
|
|
Derivative instruments
|
|
|
3,263
|
|
|
|
|
|
Accrued liabilities
|
|
|
567
|
|
|
|
615
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
4,472
|
|
|
|
3,447
|
|
ASSET RETIREMENT OBLIGATIONS, LESS CURRENT PORTION
|
|
|
6,614
|
|
|
|
7,531
|
|
COMMITMENTS AND CONTINGENCIES (note K)
|
|
|
|
|
|
|
|
|
NET INVESTMENT
|
|
|
134,014
|
|
|
|
150,814
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND NET INVESTMENT
|
|
$
|
145,100
|
|
|
$
|
161,792
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these combined financial statements.
F-74
The Chase Group
Properties
Combined
statements of revenues and expenses
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, (in
thousands)
|
|
2003
|
|
2004
|
|
2005
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
62,016
|
|
$
|
66,529
|
|
$
|
73,132
|
Gas sales
|
|
|
41,486
|
|
|
41,247
|
|
|
46,546
|
|
|
|
|
|
|
|
|
|
103,502
|
|
|
107,776
|
|
|
119,678
|
COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
9,868
|
|
|
11,762
|
|
|
12,979
|
Oil and gas production taxes
|
|
|
8,815
|
|
|
9,202
|
|
|
10,298
|
Depreciation, depletion and amortization
|
|
|
19,475
|
|
|
20,196
|
|
|
18,646
|
Impairments of proved properties
|
|
|
2,065
|
|
|
3,233
|
|
|
194
|
Abandonment expense
|
|
|
2,116
|
|
|
179
|
|
|
|
Accretion of discount on asset retirement obligations
|
|
|
168
|
|
|
263
|
|
|
446
|
General and administrative
|
|
|
1,246
|
|
|
1,387
|
|
|
1,702
|
Loss on derivatives not designated as hedges
|
|
|
576
|
|
|
7,936
|
|
|
1,062
|
|
|
|
|
|
|
|
|
|
44,329
|
|
|
54,158
|
|
|
45,327
|
|
|
|
|
|
|
Revenues in excess of expenses
|
|
$
|
59,173
|
|
$
|
53,618
|
|
$
|
74,351
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these combined financial statements.
F-75
The Chase Group
Properties
Combined
statement of net investment
|
|
|
|
|
|
|
Years Ended December 31,
2003, 2004, and 2005 (in thousands)
|
|
Total
|
|
|
|
|
BALANCE AT JANUARY 1, 2003
|
|
$
|
127,821
|
|
Net change in investment
|
|
|
(52,441
|
)
|
Revenues in excess of expenses
|
|
|
59,173
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2003
|
|
|
134,553
|
|
Net change in investment
|
|
|
(54,157
|
)
|
Revenues in excess of expenses
|
|
|
53,618
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2004
|
|
|
134,014
|
|
Net change in investment
|
|
|
(57,551
|
)
|
Revenues in excess of expenses
|
|
|
74,351
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2005
|
|
$
|
150,814
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of this combined financial statement.
F-76
The Chase Group
Properties
Combined
statements of cash flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, (in
thousands)
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues in excess of expenses
|
|
$
|
59,173
|
|
|
$
|
53,618
|
|
|
$
|
74,351
|
|
Adjustments to reconcile revenues in excess of expenses to net
cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
19,475
|
|
|
|
20,196
|
|
|
|
18,646
|
|
Impairments of proved properties
|
|
|
2,065
|
|
|
|
3,233
|
|
|
|
194
|
|
Abandonment expense
|
|
|
2,116
|
|
|
|
179
|
|
|
|
|
|
Accretion of discount on asset retirement obligations
|
|
|
168
|
|
|
|
263
|
|
|
|
446
|
|
Loss on derivative instruments not designated as hedges
|
|
|
576
|
|
|
|
7,936
|
|
|
|
1,062
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
704
|
|
|
|
(1,219
|
)
|
|
|
(1,641
|
)
|
Accounts payable
|
|
|
(45
|
)
|
|
|
(12
|
)
|
|
|
113
|
|
Accrued liabilities
|
|
|
33
|
|
|
|
36
|
|
|
|
48
|
|
Cash settlements of asset retirement obligations
|
|
|
(1
|
)
|
|
|
(28
|
)
|
|
|
(57
|
)
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
84,264
|
|
|
|
84,202
|
|
|
|
93,162
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash settlements on derivative instruments
|
|
|
(2,374
|
)
|
|
|
(4,673
|
)
|
|
|
(5,902
|
)
|
Additions to oil and gas properties
|
|
|
(29,449
|
)
|
|
|
(25,372
|
)
|
|
|
(29,709
|
)
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(31,823
|
)
|
|
|
(30,045
|
)
|
|
|
(35,611
|
)
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in investment
|
|
|
(52,441
|
)
|
|
|
(54,157
|
)
|
|
|
(57,551
|
)
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(52,441
|
)
|
|
|
(54,157
|
)
|
|
|
(57,551
|
)
|
|
|
|
|
|
|
Net change in cash
|
|
|
|
|
|
|
|
|
|
|
|
|
BEGINNING CASH
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ENDING CASH
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these combined financial statements.
F-77
The Chase Group
Properties
Notes to
special-purpose carve-out combined financial statements
December 31, 2003, 2004, and 2005
Note A.
Organization and Basis of Presentation
On February 24, 2006, Concho Resources, Inc.
(Concho) and certain other parties, entered into a
combination agreement with the Chase Group, which consists of:
Chase Oil Corporation (Chase Oil); Caza Energy LLC
(Caza Energy); Robert Chase, Richard Chase, Dianne
Crouch (collectively, the Working Interest Group);
and twenty-one other related parties (collectively, the
Employee Group), for the purpose of acquiring from
the Chase Group a group of related assets and liabilities in the
form of leasehold interests owned by the Chase Group in certain
producing and non-producing oil and gas properties (the
Chase Group Properties). The closing with Chase Oil,
Caza Energy, and the Working Interest Group occurred on
February 27, 2006 and, in exchange, Concho provided
consideration of $400 million in cash and 69.4 million
shares of Concho common stock for the properties contributed at
the closing, which included 767 producing wells, related leases,
and undeveloped acreage, located in Chaves, Eddy, and Lea
counties in New Mexico. In addition, Concho agreed to
subsequently acquire from the Employee Group their individual
ownership interests in the Chase Group Properties for
consideration of $11.2 million, payable in the form of, at
the option of the individuals in the Employee Group, shares of
Concho common stock , cash, or a combination of both Concho
common stock and cash. Through December 31, 2006,
$10.3 million of the $11.2 million has closed. The
accompanying financial statements include the assets,
liabilities, revenues and expenses of the Chase Group Properties
as of December 31, 2004 and 2005 and for each of the three
years in the period ended December 31, 2005 combined with
the subsequent purchase of interests by Concho.
Note B.
Summary of Significant Accounting Policies
Use of Estimates in the Preparation of Financial
Statements. Preparation of financial statements in
conformity with accounting principles generally accepted 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,
depreciation, and amortization of oil and gas properties are
determined using estimates of proved oil and gas reserves. There
are numerous uncertainties inherent in the estimation of
quantities of proved reserves and in the projection of future
rates of production and the timing of development expenditures.
Similarly, evaluations for impairment of proved and unproved oil
and gas properties are subject to numerous uncertainties
including, among others, estimates of future recoverable
reserves and commodity price outlooks. Other significant
estimates include, but are not limited to, the asset retirement
obligations, and fair values of derivative financial instruments.
Oil and Gas Properties. The financial statements
utilize the successful efforts method of accounting for oil and
gas properties as promulgated by Statement of Financial
Accounting Standards (SFAS) No. 19,
Financial Accounting and Reporting by Oil and Gas
Producing Companies. Under this method all costs
associated with productive wells and nonproductive development
wells are capitalized, while nonproductive exploration costs are
expensed. Capitalized acquisition costs relating to proved
properties are depleted using the
unit-of-production
method based on proved reserves on a field basis. The
depreciation of capitalized exploratory drilling and
F-78
development costs is based on the
unit-of-production
method using proved developed reserves on a field basis.
Capitalized costs of individual properties abandoned or retired
are charged to accumulated depletion, depreciation and
amortization. Proceeds from sales of individual properties are
credited to property costs. No gain or loss is recognized until
the entire amortization base (field) is sold or abandoned.
Ordinary maintenance and repair costs are generally expensed as
incurred.
Costs of significant nonproducing properties, wells in the
process of being drilled and development projects are excluded
from depletion until such time as the related project is
developed and proved reserves are established or impairment is
determined. Interest is capitalized, if debt is outstanding, on
expenditures for significant development projects until such
projects are ready for their intended use. For the years ended
December 31, 2003, 2004 and 2005, no outstanding debt nor
capitalized interest was allocated to the Chase Group Properties
(see Note H).
In accordance with SFAS No. 144, Accounting for
the Impairment or Disposal of Long-Lived Assets,
management reviews its long-lived assets to be held and used,
including proved oil and gas properties accounted for under the
successful efforts method of accounting, 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, an impairment loss
is recognized for the amount by which the carrying amount of the
asset exceeds the estimated fair value of the asset. Management
reviews its oil and gas properties by amortization base (field).
For each property determined to be impaired, an impairment loss
equal to the difference between the carrying value of the
properties and the 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 unproven oil and gas reserve
quantities, timing of development and production, expected
future commodity prices, capital expenditures, and production
costs. A charge against earnings of approximately $2,065,000,
$3,233,000 and $194,000 was recognized during the years ended
December 31, 2003, 2004 and 2005, respectively, related to
impairment of its proved oil and gas properties.
Unproved oil and gas properties are each periodically assessed
for impairment by comparing their cost to their estimated value
on a
project-by-project
basis. The estimated value is affected by the results of
exploration activities, commodity price outlooks, planned future
sales or expiration of all or a portion of such projects. If the
quantity of potential reserves determined by such evaluations is
not sufficient to fully recover the cost invested in each
project, an impairment loss will be at that time. During the
years ended December 31, 2003, and 2004, impairments on
unproved oil and gas properties of approximately $2,116,000 and
$179,000, respectively, were recorded. There were no impairments
during the year ended December 31, 2005.
Concho operates a salt water well disposal system in which salt
water from Chase Group wells or from third parties are disposed
of into the well. Management has capitalized the costs to
acquire and drill these salt water wells and these costs are
being depreciated over the average life of the contributed
properties from fields that produce the water to be disposed of,
which has been calculated at approximately 14 years for
proved properties.
F-79
Exploration Drilling Costs. Costs of drilling
exploratory wells are capitalized as part of proved costs
pending managements determination of whether the wells
have found proved reserves. Management makes this determination
as soon as possible after completion of drilling considering the
guidance provided in SFAS No. 19 Financial
Accounting and Reporting by Oil and Gas Producing
Companies. SFAS No. 19 provides that such costs
should not be carried as an asset for more than one year
following completion of drilling unless the well has found oil
and gas reserves in an area requiring a major capital
expenditure before production could begin. In that case, the
costs of such exploratory wells continue to be carried as an
asset pending determination of whether proved reserves have been
found only as long as the well has found a sufficient quantity
of reserves to justify its completion as a producing well if the
required capital expenditure is made and drilling of the
additional exploratory wells is under way or firmly planned for
the near future. If both those conditions are not met, the well
costs are charged to expense. Management performs this
evaluation on a quarterly basis. As of December 31, 2004
and 2005, no pending exploratory well costs were recorded.
Income Taxes. Income and expenses from the financial
statements are combined with the income and expenses of the
beneficial owners of properties from other sources and reported
in the beneficial owners individual federal and state
income tax returns. The Chase Group Properties are not a
taxpaying entity for purposes of federal and state income taxes.
Accordingly, no income taxes have been recorded in the financial
statements.
Environmental. The Chase Group Properties are
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
removal or mitigation of the environmental effects of the
disposal or release of petroleum or chemical substances at
various sites. Environmental expenditures are expensed.
Expenditures that relate to an existing condition caused by past
operations and that have no future economic benefits are
expensed. Liabilities for expenditures of a noncapital nature
are recorded when environmental assessment
and/or
remediation is probable, and the costs can be reasonably
estimated. Such liabilities are generally undiscounted unless
the timing of cash payments is fixed and readily determinable.
Management believes no significant liabilities of this nature
existed at December 31, 2004 and 2005.
Oil and Gas Sales. Oil and gas sales revenues are
recognized when delivery has occurred and title to the products
has transferred to the purchaser.
Accounts Receivable. The Chase Group Properties sell
oil and gas to various customers and participates with other
parties in the drilling, completion and operation of oil and gas
wells. Joint interest and oil and gas sales receivables related
to these operations are generally unsecured. Management
determines joint interest operations accounts receivable
allowances based on managements assessment of the credit
worthiness of the joint interest owners and the 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. No allowance for doubtful accounts was recorded at
December 31, 2004 and 2005.
Derivatives and Hedging. The financial statements
apply the provisions of SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities as
amended. This statement requires the recognition of all
derivative instruments as either assets or liabilities measured
at
F-80
fair value. The Chase Group Properties derivative
instruments do not qualify as hedges and are adjusted to fair
value with a gain or loss recognized through net income.
Asset Retirement Obligations. The financial
statements account for obligations in accordance with
SFAS No. 143, Accounting for Asset Retirement
Obligations. SFAS No. 143 requires entities to
record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related
long-lived asset. Subsequently, the asset retirement cost
included in the carrying amount of the related asset is
allocated to expense through depreciation of the asset. Changes
in the liability due to passage of time are recognized as an
increase in the carrying amount of the liability and as
corresponding accretion expense.
General and Administrative Expenses. The Chase Group
Properties do not have any employees. All general and
administrative functions are performed by Mack Energy
Corporation, a related-party operator. Accordingly, the
accompanying carve out financial statements include an
allocation of such costs that directly relate to the Chase Group
Properties, including personnel costs of those personnel that
work solely for the Chase Group Properties and an allocation of
corporate salaries and benefits and other costs that management
believes reasonably reflects the portion of the related
employees time that benefits the Chase Group Properties. Amounts
allocated were approximately $1,246,000, $1,387,000 and
$1,702,000 for the years ended December 31, 2003, 2004 and
2005, respectively.
Net Investment in the Chase Group Properties. The
net investment in the Chase Group Properties represents a net
cumulative balance as the result of transactions between the
Chase Group and Mack Energy Corporation, and other related
entities and oil and gas properties not included in the Chase
Group Properties. There are no terms of settlement or interest
charges associated with this balance. The balance also includes
the net result of the Chase Group Properties participation in
the overall central cash management and treasury program of the
Chase Group, Mack Energy Corporation, and other related entities
and oil and gas properties not included in the Chase Group
Properties.
Note C.
Related Party
The Chase Group Properties are billed for services and supplies
provided by related entities. In addition, the Chase Group
Properties are billed by Mack Energy Corporation, as operator,
for services performed by outside parties in which Chase Group
Properties benefit from the services or supplies. Total billings
for the year ended December 31, 2003, 2004 and 2005 from
Mack Energy Corporation to the Chase Group Properties were
approximately $41,039,000, $35,365,000 and $46,288,000,
respectively. Total billings for the year ended
December 31, 2004 and 2005 from Alliance Drilling Fluids,
LLC were approximately $109,000 and $365,000, respectively.
Total billings for the year ended December 31, 2005 from
Catalyst Oilfield Services were approximately $161,000.
The Chase Group Properties has receivables from Mack Energy
Corporation of approximately $7,224,000 at December 31,
2005 relating to oil and gas sales receivables. The Chase Group
Properties has payables of approximately $45,000 and $277,000 to
related parties at December 31, 2004 and 2005,
respectively, for services and supplies provided.
F-81
Note D.
Disclosures About Fair Value of Financial
Instruments
Accounts Receivable and Accounts Payable. The
carrying amounts approximate fair value due to the short
maturity of these instruments.
Commodity Price Collar Contracts. The fair value of
derivative instruments is estimated by management considering
various factors, including closing exchange and
over-the-counter
quotations, and the time value of the underlying commitments and
represents the estimated amounts that the Chase Group Properties
would expect to receive or pay to settle the derivative
contracts. (See Note G)
Note E.
New Accounting Pronouncements
On December 16, 2004, the Financial Accounting Standards
Board (FASB) issued SFAS No. 153,
Exchanges of Nonmonetary AssetsAn Amendment of APB
Opinion No. 29. SFAS No. 153 amends APB
Opinion No. 29, Accounting for Monetary
Transactions that was issued in 1973. The amendments are
based on the principle that exchanges of nonmonetary assets
should be measured based on the fair value of the assets
exchanged. Further, the amendments eliminate the narrow
exception for nonmonetary exchanges of similar productive assets
and replace it with a broader exception for exchanges of
nonmonetary assets that do not have commercial
substance. Previously, APB No. 29 required that the
accounting for an exchange of a productive asset for a similar
productive asset or an equivalent interest in the same or
similar productive asset should be based on the recorded amount
of the asset relinquished. The provisions in
SFAS No. 153 are effective for nonmonetary asset
exchanges occurring in fiscal periods beginning after
June 15, 2005 and must be applied prospectively. The
adoption of SFAS No. 153 did not have a significant
impact on the financial position or results of operations of the
Chase Group Properties.
The FASB issued Staff Position (FSP) Nos.
141-1 and
142-1. As a
result of the March 1718, 2004, Emerging Issues Task Force
(EITF) meeting, after the EITF reached a consensus
on EITF Issue
No. 04-2,
Whether Mineral Rights are Tangible or Intangible
Assets, and concluded that mineral rights, as defined in
this issue, are tangible assets. These FSPs addressed the
inconsistency between consensus and the characterization of
mineral rights as intangible assets in SFAS No. 141,
Business Combinations and SFAS No. 142,
Goodwill and Other Intangible Assets. The guidance
in these FSPs is applicable to the first reporting period
beginning after April 29, 2004, and therefore effective for
the Chase Group January 1, 2005. Management adopted these
FSPs effective January 1, 2005. The adoption of these FSPs
did not have any impact on the financial position or results of
operations of the Chase Group Properties.
In March 2005, the FASB published FASB Interpretation
(FIN) No. 47, Accounting for Conditional Asset
Retirement Obligations, which requires companies to record
a liability for those asset retirement obligations in which the
timing or amount of settlement of the obligation are uncertain.
These conditional obligations were not addressed by
SFAS No. 143. FIN No. 47 will require the
Chase Group to accrue a liability when a range of scenarios can
be determined. Management adopted
FIN No. 47 December 31, 2005. The adoption
of FIN No. 47 did not have an impact on the financial
position or results of operations of the Chase Group Properties.
The FASB issued FSP
No. 19-1,
Accounting for Suspended Well Costs, which amends
SFAS No. 19 to provide that in those situations where
exploration drilling has been completed and oil and gas reserves
have been found, but such reserves cannot be classified as
proved when drilling is
F-82
complete, the drilling costs may be capitalized if the well has
found a sufficient quantity of reserves to justify its
completion as a producing well and the enterprise is making
sufficient progress assessing the reserves and the economic and
operating viability of the project. If either of the criteria is
not met, the well is assumed to be impaired and the costs
charged to expense. Any well that has not found reserves is
charged to expense. The adoption of this pronouncement is not
expected to have a significant impact on the oil and gas
properties contained in these special purpose carve-out combined
financial statements.
In July 2006, the FASB issued FIN No. 48
Accounting for Uncertainty in Income Taxesan
Interpretation of FASB Statement 109.
FIN No. 48 clarifies that an entitys tax
benefits recognized in tax returns must be more likely than not
of being sustained prior to recording the related tax benefit in
the financial statements. The adoption of this pronouncement is
not expected to have a significant impact on the oil and gas
properties contained in these special purpose carve-out combined
financial statements.
Note F.
Asset Retirement Obligations
The asset retirement obligations represent the present value of
the estimated cash flows that will be incurred to plug, abandon
and remediate producing properties at the end of their
production lives, in accordance with applicable state laws. The
following is a reconciliation of the changes in the asset
retirement obligations for December 31, 2003, 2004 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
|
|
Asset retirement obligations, beginning of year
|
|
$
|
4,805
|
|
|
$
|
5,538
|
|
|
$
|
6,859
|
|
Liability incurred upon acquiring and drilling wells
|
|
|
663
|
|
|
|
991
|
|
|
|
790
|
|
Liability settled upon plugging and abandoning wells
|
|
|
(1
|
)
|
|
|
(28
|
)
|
|
|
(57
|
)
|
Revisions to estimated cash flows
|
|
|
(97
|
)
|
|
|
95
|
|
|
|
(105
|
)
|
Accretion expense
|
|
|
168
|
|
|
|
263
|
|
|
|
446
|
|
|
|
|
|
|
|
Asset retirement obligations, end of year
|
|
$
|
5,538
|
|
|
$
|
6,859
|
|
|
$
|
7,933
|
|
|
|
|
|
|
|
|
|
Note G.
Derivative Financial Instruments
During 2004 and 2005, the Chase Group Properties had certain
derivative instruments that did not qualify as hedges under
SFAS No. 133 Accounting for Derivative
Instruments and Hedging Activities. As such, the net
change in their fair value has been recognized in the statements
of income.
In April 2004, management purchased an oil collar contract for
the period of May 2004 through April 2005 with a floor of $28.00
a barrel and a ceiling of $37.00 a barrel on a daily notional
volume of 2,000 barrels.
Additionally, in 2004 management purchased an oil collar
contract in May 2004 for the period of June 2004 through May
2005 with a floor of $31.00 and a ceiling of $40.00 on a daily
notional volume of 2,000 barrels. In December 2005, management
purchased a Gas Swap contract for the period of January 2006
through December 2006 for a fixed price of $10.73 on a daily
notional volume of 5,000 MMBtu.
F-83
The following table sets forth the outstanding natural gas swap
agreement and the crude oil zero cost collar option agreements
as of December 31, 2004 and 2005.
|
|
|
|
|
|
|
|
|
|
Contract Period
|
As of December 31,
2005
|
|
2005
|
|
2006
|
|
|
Daily gas production:
|
|
|
|
|
|
|
Swap:
|
|
|
|
|
|
|
Volume (MMBtu/day)
|
|
|
|
|
|
5,000
|
Index price per MMBtu
|
|
|
|
|
$
|
10.73
|
NYMEX price per
MMBtu(a)
|
|
|
|
|
$
|
8.66
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Period
|
As of December 31,
2004
|
|
2005
|
|
2006
|
|
|
Daily oil production:
|
|
|
|
|
|
|
Collar Options:
|
|
|
|
|
|
|
Volume (Bbl/day)
|
|
|
2,000
|
|
|
|
NYMEX price per
Bbl(b)
|
|
$
|
50.40
|
|
|
|
Floor
|
|
$
|
28.00
|
|
|
|
Ceiling
|
|
$
|
37.00
|
|
|
|
Collar Options:
|
|
|
|
|
|
|
Volume (Bbl/day)
|
|
|
2,000
|
|
|
|
NYMEX price per
Bbl(b)
|
|
$
|
50.40
|
|
|
|
Floor
|
|
$
|
31.00
|
|
|
|
Ceiling
|
|
$
|
40.00
|
|
|
|
|
|
|
|
|
(a)
|
|
Amount disclosed represents U.S.
Natural Gas Wellhead price monthly average spot price.
|
|
(b)
|
|
Amount disclosed represents NYMEX
West Texas Intermediate monthly average spot price.
|
The Chase Group Properties had derivative instruments not
designated as cash flow hedges in 2003, 2004, and 2005 in which
the following losses were recorded for each of the following
years of the derivative instruments:
|
|
|
|
2003
|
|
$
|
576,000
|
2004
|
|
|
7,936,000
|
2005
|
|
|
1,062,000
|
|
|
The losses were recorded as Loss on derivatives not
designated as hedges in the statements of revenues and
expenses in the respective year.
Note H.
Debt
For the periods ending December 31, 2003, 2004, and 2005,
Chase Oil Corporation and Caza Energy maintained a joint credit
facility that had a maximum face amount of $200,000,000 with JP
Morgan Chase Bank as Administrative Agent and Bank of Scotland
and Frost Bank as participating banks. The facility was secured
by substantially all of the assets of Chase Oil
F-84
Corporation and Caza Energy which consisted of primarily oil and
gas properties including the Chase Group Properties. The
facilities contained cross default provisions in addition to
guaranties to and from various related parties including
principal shareholders of Chase Oil Corporation and Caza Energy
and other affiliated operating companies, namely Mack C. Chase
Trust and Mack Energy Corporation. The availability under the
agreement was subject to semi-annual borrowing base
redeterminations of the oil and gas properties. The agreement
contained terms and conditions similar to other oil and gas
facilities provided by the lenders including minimum current
ratio and maximum debt to earnings before interest, taxes,
depreciation, depletion, amortization and capital expenditures.
Advances to and investments in related parties were also
restricted by the agreement and adjusted at each
redetermination. Interest on borrowings was determined based on
the ratio of total amounts outstanding to total amounts
available under the facility and the interest rate varied from
JP Morgan Chase Bank Prime Rate less 50 to 75 basis points,
or at the option of Chase Oil Corporation and Caza Energy, the
London Interbank Offered Rate (LIBOR) plus 150 to 225 basis
points. The balances due to the lenders at December 31,
2003, 2004 and 2005 were approximately $57,350,000, $77,183,000
and $105,600,000, respectively. Upon the closing of the
Combination Agreement, the outstanding balance was retired and
the availability was reduced to $10,000,000. The Chase Group
Properties provided the primary collateral support for this
facility. Due to the maturity and the quality of the Chase Group
Properties, they required an insignificant amount of capital
expense to maintain predictable production rates. Therefore,
borrowings under this line were primarily used for acquisition
and development of oil and gas properties outside of the Chase
Group Properties and for permitted advances to and investments
in related parties. Advances to related parties bore interest at
JP Morgan Chase Bank Prime rate less 50 basis points. The
balances due from the Chase related parties at December 31,
2003, 2004 and 2005 were approximately $46,042,000, $73,543,000
and $110,075,000, respectively. Since borrowings under the
facility were used primarily to fund activities not related to
the Chase Group Properties and the borrowings were substantially
offset by amounts due from related parties, no debt or interest
has been allocated to the Chase Group Properties in the
accompanying financial statements.
The parties in the Working Interest Group each maintained
separate credit facilities with Frost National Bank under
similar terms and conditions as Chase Oil Corporation and Caza
Energy. The individuals in the Employee Group have utilized
credit facilities with lenders based on their individual
financial needs and credit worthiness. The combination agreement
required assets transferred to Concho be free and clear of any
liens other than permitted liens.
Note I.
Major Customers and Derivative Counterparties
Sales to major customers. Navajo Refining Company
accounted for approximately 51%, 52% and 52% of the oil and gas
revenues of the Chase Group Properties during the years ended
December 31, 2003, 2004 and 2005, respectively.
Duke Energy Field Services accounted for approximately 28%, 30%
and 31% of the oil and gas revenues of the Chase Group
Properties during the years ended December 31, 2003, 2004
and 2005, respectively.
Navajo Refining Company accounted for approximately 50% and 47%
of total accounts receivable of the Chase Group Properties
during the years ended December 31, 2004 and 2005,
respectively.
F-85
Duke Energy Field Services account for approximately 25% and 27%
of total accounts receivable of the Chase Group Properties
during the years ended December 31, 2004 and 2005,
respectively.
Derivative counterparties. Management uses credit
and other financial criteria to evaluate the credit standing of,
and to select, counterparties to its derivative instruments. The
revolving credit facility agreement requires that the senior
unsecured debt ratings of the derivative counterparties is not
less than A- by JP Morgan Chase Bank. At December 31, 2004
and 2005, the counterparties met or exceeded the required
ratings. Although Management does not obtain collateral or
otherwise secure the fair value of its derivative instruments,
management believes the associated credit risk is mitigated by
credit risk policies and procedures and by the credit rating
requirements of the credit facility agreement. At
December 31, 2004, the Chase Group Properties had
approximately $3.26 million derivative liabilities
representing amounts owed to counterparties. At
December 31, 2005, the Chase Group Properties had
approximately $1.58 million derivative assets owed by
counterparties.
Note J.
Supplementary Information
Capitalized
costs.
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
December 31, 2004
|
|
|
December 31, 2005
|
|
|
|
|
Oil and gas properties:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
238,544
|
|
|
$
|
270,453
|
|
Unproved
|
|
|
1,078
|
|
|
|
1,042
|
|
Less accumulated depletion, depreciation, and amortization
|
|
|
(105,020
|
)
|
|
|
(123,667
|
)
|
|
|
|
|
|
|
Net capitalized costs for oil and gas properties
|
|
$
|
134,602
|
|
|
$
|
147,828
|
|
|
|
|
|
|
|
|
|
Costs incurred
for oil and gas producing activities.
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
Year Ended
|
(In thousands)
|
|
December 31, 2004
|
|
December 31, 2005
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
Proved
|
|
$
|
1,277
|
|
$
|
8,283
|
Unproved
|
|
|
333
|
|
|
|
Development
|
|
|
22,755
|
|
|
23,384
|
Asset retirement costs
|
|
|
1,086
|
|
|
685
|
|
|
|
|
|
|
Costs incurred for oil and gas properties
|
|
$
|
25,451
|
|
$
|
32,352
|
|
|
|
|
|
|
|
|
Reserve quantity information (unaudited). The
estimates of proved oil and gas reserves, which are located
primarily in the Permian Basin region of Eastern New Mexico were
prepared by the Chase Group Properties engineers. These reserve
estimates were reviewed and confirmed by Cawley, Gillespie and
Associates, Inc. Reserves were estimated in accordance with
guidelines established by the SEC, which require that reserve
estimates be prepared under existing economic and operating
conditions with no provision for price and cost escalations
except by
F-86
contractual arrangements. The reserve estimates for 2003, 2004
and 2005 utilize NYMEX oil price of $32.55, $43.46, and
$61.04 per bbl, respectively, and a NYMEX gas price of
$5.83, $6.19 and $10.08 per Mcf, respectively, as adjusted
for location, grade and quality. These prices approximate actual
prices being realized at the respective year ends.
Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved
reserves and in the projection of future rates of production and
the timing of development expenditures. The accuracy of such
estimates is a function of the quality of available data and of
engineering and geological interpretation and judgment. Results
of subsequent drilling, testing and production may cause either
upward or downward revision of previous estimates. Further, the
volumes considered to be commercially recoverable fluctuate with
changes in prices and operating costs. Management emphasizes
that reserve estimates are inherently imprecise and that
estimates of new discoveries are more imprecise than those of
currently producing oil and gas properties. Accordingly, these
estimates are expected to change as additional information
becomes available in the future.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
|
Oil and
|
|
|
Natural
|
|
|
Oil and
|
|
|
Natural
|
|
|
Oil and
|
|
|
Natural
|
|
|
|
Condensate
|
|
|
Gas
|
|
|
Condensate
|
|
|
Gas
|
|
|
Condensate
|
|
|
Gas
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
|
|
Total Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year
|
|
|
28,234
|
|
|
|
139,362
|
|
|
|
27,520
|
|
|
|
140,464
|
|
|
|
26,692
|
|
|
|
139,118
|
|
Purchase of
minerals-in-place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
733
|
|
|
|
1,457
|
|
New discoveries and extensions
|
|
|
147
|
|
|
|
433
|
|
|
|
85
|
|
|
|
150
|
|
|
|
1,118
|
|
|
|
2,438
|
|
Revisions of previous estimates
|
|
|
1,264
|
|
|
|
9,327
|
|
|
|
838
|
|
|
|
6,140
|
|
|
|
719
|
|
|
|
5,031
|
|
Production
|
|
|
(2,125
|
)
|
|
|
(8,658
|
)
|
|
|
(1,751
|
)
|
|
|
(7,636
|
)
|
|
|
(1,429
|
)
|
|
|
(6,636
|
)
|
|
|
|
|
|
|
Balance, end of year
|
|
|
27,520
|
|
|
|
140,464
|
|
|
|
26,692
|
|
|
|
139,118
|
|
|
|
27,833
|
|
|
|
141,408
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
14,915
|
|
|
|
77,934
|
|
|
|
14,104
|
|
|
|
79,802
|
|
|
|
13,318
|
|
|
|
78,121
|
|
End of year
|
|
|
14,104
|
|
|
|
79,802
|
|
|
|
13,318
|
|
|
|
78,121
|
|
|
|
13,365
|
|
|
|
77,331
|
|
|
|
Standardized measure of discounted future net cash flows
(unaudited). The standardized measure of discounted
future net cash flows is computed by applying year-end prices of
oil and gas (with consideration of price changes only to the
extent provided by contractual arrangements) to the estimated
future production of proved oil and gas reserves less estimated
future expenditures (based on year-end costs) to be incurred in
developing and producing the proved reserves, discounted using a
rate of 10 percent per year to reflect the estimated timing
of the future cash flows.
Discounted future cash flow estimates like those shown below are
not intended to represent estimates of the fair value of oil and
gas properties. Estimates of fair value would also consider
probable and possible reserves, anticipated future oil and gas
prices, interest rates, changes in
F-87
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
(In thousands)
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
|
|
Oil and gas producing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
1,586,671
|
|
|
$
|
1,895,936
|
|
|
$
|
2,980,762
|
|
Future production costs, abandonment and taxes
|
|
|
(446,938
|
)
|
|
|
(503,389
|
)
|
|
|
(677,934
|
)
|
Future development costs
|
|
|
(203,403
|
)
|
|
|
(255,054
|
)
|
|
|
(302,331
|
)
|
|
|
|
|
|
|
Future net cash flows
|
|
|
936,330
|
|
|
|
1,137,493
|
|
|
|
2,000,497
|
|
10% annual discount factor
|
|
|
(478,073
|
)
|
|
|
(591,352
|
)
|
|
|
(998,521
|
)
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
$
|
458,257
|
|
|
$
|
546,141
|
|
|
$
|
1,001,976
|
|
|
|
|
|
|
|
|
|
Changes in
standardized measure of discounted future net cash flows
(unaudited).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
(In thousands)
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
|
|
Purchases of
minerals-in-place
|
|
$
|
|
|
|
$
|
|
|
|
$
|
12,380
|
|
Extensions and discoveries
|
|
|
2,000
|
|
|
|
1,114
|
|
|
|
17,706
|
|
Net changes in prices and production costs
|
|
|
79,426
|
|
|
|
139,744
|
|
|
|
411,692
|
|
Oil and gas sales, net of production costs
|
|
|
(84,819
|
)
|
|
|
(86,812
|
)
|
|
|
(96,401
|
)
|
Revisions of previous quantity estimates
|
|
|
31,036
|
|
|
|
25,440
|
|
|
|
34,010
|
|
Accretion of discount
|
|
|
40,195
|
|
|
|
45,826
|
|
|
|
54,614
|
|
Development costs changes
|
|
|
(22,269
|
)
|
|
|
(31,502
|
)
|
|
|
(18,275
|
)
|
Changes in production rates, timing and other
|
|
|
10,735
|
|
|
|
(5,926
|
)
|
|
|
40,109
|
|
|
|
|
|
|
|
Change in present value of future net revenues
|
|
|
56,304
|
|
|
|
87,884
|
|
|
|
455,835
|
|
Balance, beginning of year
|
|
|
401,953
|
|
|
|
458,257
|
|
|
|
546,141
|
|
|
|
|
|
|
|
Balance, end of year
|
|
$
|
458,257
|
|
|
$
|
546,141
|
|
|
$
|
1,001,976
|
|
|
|
|
|
|
|
|
|
Note K.
Settlement Agreement
From 1984 thru May 1997, certain owners of the Chase Group
Properties and their predecessors drilled or deepened
approximately 70 wells and completed and produced from
zones below a depth approved by the New Mexico Oil Conservation
Division (NMOCD). The companies that owned the
applicable Chase Group Properties possessed the ownership rights
entitling them to produce hydrocarbons from any zone, but did
not have the required regulatory approvals. In December 2005,
the NMOCD issued approvals that encompass 63 of the
approximately 70 wells and in January 2007, the NMOCD
issued approvals that encompass the remaining nine wells. The
drilling and completion reports filed with the NMOCD relating to
these wells were incorrect and the monthly production reports
did not reflect that production was obtained from outside
F-88
the depth approved by the NMOCD. As a result, a unit royalty
owner in the unitized formation was overpaid and the State of
New Mexico, which was the owner of the royalty interest outside
the unitized formation, was underpaid for several years. In
November 2006, Mack Energy Corporation entered into a settlement
agreement with the State of New Mexico whereby it paid all
unpaid royalties for prior years production plus accrued
interest. Chase Oil Corporation, as the lessee of the property,
had the fiduciary duty of ensuring the lessors were properly
paid, therefore the accompanying financial statements include in
oil and gas production expense the additional royalty and
interest expense, aggregating, $32,925, $36,549 and $47,951 in
2003, 2004 and 2005, respectively. In January 2007, Mack Energy
Corporation paid the NMOCD a penalty of $250,000 for false
reporting and the NMOCD released Mack Energy Corporation and its
officers, directors and employees from liability for this
matter. This penalty was the responsibility of Mack Energy
Corporation, as operator, and is not reflected in the
accompanying financial statements. Management believes that all
required completion records and production records affecting the
properties included in the accompanying financial statements
have been corrected and submitted to the NMOCD.
F-89
REPORT
OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
The Shareholders of
Concho Equity Holdings Corp.:
We have audited the accompanying statements of revenues and
direct operating expenses of Lowe Partners, LPs interests
in certain oil and gas properties acquired by Concho Equity
Holdings Corp. (Company) for the year ended
December 31, 2003 and for the period from January 1,
2004 to November 30, 2004. These statements of revenues and
direct operating expenses are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these statements of revenues and direct operating
expenses 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. The Company is not required to
have, nor were we engaged to perform an audit of its internal
control over financial reporting. Accordingly, we express no
such opinion. Our audit included 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.
The accompanying statements were prepared for the purpose of
complying with the rules and regulations of the Securities and
Exchange Commission (for inclusion in the registration statement
on
Form S-1
of the Company) as described in Note A to the statements
and are not intended to be a complete presentation of Lowe
Partners, LPs revenues and expenses.
In our opinion, the statements of revenues and direct operating
expenses referred to above present fairly, in all material
respects, the revenues and direct operating expenses of Lowe
Partners, LPs interest in the properties acquired by the
Company for the year ended December 31, 2003 and for the
period from January 1, 2004 to November 30, 2004 in
conformity with accounting principles generally accepted in the
United States of America.
GRANT THORNTON LLP
Dallas, Texas,
May 17, 2006
F-90
Statements of revenues and
direct operating expenses
For the year ended December 31, 2003 and period from
January 1, 2004 to November 30, 2004
|
|
|
|
|
|
|
|
|
|
|
|
11 months
|
|
|
Year ended
|
|
ended
|
|
|
December 31,
|
|
November 30,
|
(in thousands)
|
|
2003
|
|
2004
|
|
|
Revenues:
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
31,392
|
|
$
|
33,753
|
Interest and other
|
|
|
979
|
|
|
910
|
|
|
|
|
|
|
Total revenues
|
|
|
32,371
|
|
|
34,663
|
Direct operating expenses:
|
|
|
|
|
|
|
Lease operating expense
|
|
|
6,652
|
|
|
6,983
|
Production taxes
|
|
|
2,023
|
|
|
2,159
|
Other expenses
|
|
|
435
|
|
|
461
|
|
|
|
|
|
|
Total direct operating expenses
|
|
|
9,110
|
|
|
9,603
|
|
|
|
|
|
|
Revenues in excess of direct operating expenses
|
|
$
|
23,261
|
|
$
|
25,060
|
|
|
|
|
|
|
|
|
See accompanying notes to statements of revenues and direct
operating expenses.
F-91
Lowe Partners,
LP
Notes
to statements of revenues and
direct operating expenses
For the year ended December 31, 2003 and
period from January 1, 2004 to November 30,
2004
Note A Summary
of significant events and accounting policies
Basis of
presentation
Concho Equity Holdings Corp. (Concho or the
Company) is a Delaware corporation formed on
April 21, 2004. The Companys principal business is
the acquisition and exploitation of oil and gas properties in
the Permian Basin region of West Texas and Eastern New Mexico.
On December 7, 2004 one of the Companys wholly-owned
subsidiaries, COG Oil & Gas LP (COG LP),
acquired interests in several producing crude oil and natural
gas fields in the Permian Basin region of Eastern New Mexico and
West Texas from the privately-held company, Lowe Partners, LP
(Seller). In conjunction with this same transaction,
a separate wholly-owned subsidiary of the Company, COG Realty
LLC (Realty), acquired 100% ownership in two
commercial real estate buildings in Midland, Texas from an
affiliate of the Seller. The rental income and expenses
associated with the buildings are reflected in Interest
and other and Other expenses on the Statements.
The accompanying statements of operating revenues and direct
operating expenses were derived from the historical accounting
records of the Seller and are presented on the accrual basis of
accounting. Such amounts may not be representative of future
operations. The statements do not include depreciation,
depletion and amortization, general and administrative expenses,
income taxes or interest expense as these costs may not be
comparable to the expenses expected to be incurred by the
Company on a prospective basis.
Historical financial statements reflecting financial position,
results of operations and cash flows required by accounting
principles generally accepted in the United States of America
are not presented as such information is not readily available
on an individual property basis and not meaningful to the Lowe
Partners, LP properties acquired. Accordingly, the historical
statements of revenues and direct operating expenses are
presented in lieu of the financial statements required under
Rule 3-05
of the Securities and Exchange Commission
Regulation S-X.
Use of
estimates
The preparation of the accompanying financial statements in
conformity with generally accepted accounting principles
requires the Companys management to make estimates and
assumptions that affect the reported amounts of revenues and
direct operating expenses during the reporting period. The
estimates include oil and gas reserve quantities. Management
emphasizes that reserve estimates are inherently imprecise and
that estimates of more recent reserve discoveries are more
imprecise than those for properties with long production
histories. Actual results could materially differ from these
estimates.
F-92
Revenue
recognition
Title to the produced quantities transfers to the purchaser at
the time the purchaser collects or receives the quantities.
Prices for such production are defined in the sales contracts.
Risks and
uncertainties
Historically, the market for oil and natural gas has experienced
significant price fluctuations. Prices are impacted by supply
and demand, both domestic and international, seasonal variations
caused by changing weather conditions, political conditions,
governmental regulations, the availability, proximity and
capacity of gathering systems for natural gas, and numerous
other factors. Increases or decreases in prices received could
have a significant impact on the Companys future results
of operations, reserves estimates and financial position.
Estimating oil and gas reserves is complex and is not exact
because of the numerous uncertainties inherent in the process.
The process relies on interpretations of available geological,
geophysical, petrophysical, engineering and production data. The
extent, quality and reliability of both the data and the
associated interpretations of that data can vary. The process
also requires certain economic assumptions, including, but not
limited to, oil and gas prices, drilling and operating expenses,
capital expenditures, and taxes. Actual future production, oil
and gas prices, revenues, taxes, development expenditures,
operating expenses and quantities of recoverable oil and gas
most likely will vary from the Companys estimates. Any
significant variance could materially affect the Companys
future results of operations, reserves estimates and financial
position.
Note B Supplemental
capital expenditure and oil and gas reserve information
(unaudited)
Capital
expenditures
Capital expenditures for the year ended December 31, 2003
and the period from January 1, 2004 to November 30,
2004, were $7.0 million and $2.2 million, respectively.
Reserve quantity
information
The estimates of proved oil and gas reserves, which are located
primarily in the Permian Basin region of West Texas and Eastern
New Mexico were prepared by the Companys engineers.
Reserves were estimated in accordance with guidelines
established by the Securities and Exchange Commission and the
Financial Accounting Standards Board, which require that reserve
estimates be prepared under existing economic and operating
conditions with no provision for price and cost escalations
except by contractual arrangements. Future production costs
exclude overhead charges for Company operated properties.
Average wellhead prices in effect at November 30, 2004,
inclusive of adjustments for quality and location used in
determining future net revenue related to the standardized
measure calculation, were $49.13 per barrel of oil and
$7.62 per Mcf of gas.
Estimates of proved reserves of the Lowe Partners, LP properties
are not available prior to November 30, 2004. For purposes
of determining proved reserves at December 31, 2003, the
Company estimated reserves using the November 30, 2004
reserves run at an average wellhead price at December 31,
2003 of $32.52 and $6.19 for oil and gas, respectively, adding
back current period production and then reducing it by the
reserves identified as new extensions and
F-93
discoveries in 2004. For proved reserves at December 31,
2002, the Company estimated reserves using the November 30,
2004 reserves run at an average wellhead price at
December 31, 2002 of $31.17 and $4.75 for oil and gas
respectively, adding back current year production and then
reducing it by the reserves identified as new extensions and
discoveries in 2003.
Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved
reserves and in the projection of future rates of production and
the timing of development expenditures. The accuracy of such
estimates is a function of the quality of available data and of
engineering and geological interpretation and judgment. Results
of subsequent drilling, testing and production may cause either
upward or downward revision of previous estimates. Further, the
volumes considered to be commercially recoverable fluctuate with
changes in prices and operating costs. The Company emphasizes
that reserve estimates are inherently imprecise and that
estimates of new discoveries are more imprecise than those of
currently producing oil and gas properties. Accordingly, these
estimates are expected to change as additional information
becomes available in the future.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
|
|
|
11 months ended
|
|
|
|
December 31, 2003
|
|
|
November 30, 2004
|
|
|
|
Oil and
|
|
|
Natural
|
|
|
Oil and
|
|
|
Natural
|
|
|
|
condensate
|
|
|
gas
|
|
|
condensate
|
|
|
gas
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
|
|
Total Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at beginning of period
|
|
|
6,186
|
|
|
|
34,596
|
|
|
|
5,763
|
|
|
|
33,455
|
|
New discoveries and extensions
|
|
|
88
|
|
|
|
1,872
|
|
|
|
31
|
|
|
|
91
|
|
Revisions of previous estimates
|
|
|
55
|
|
|
|
45
|
|
|
|
928
|
|
|
|
1,557
|
|
Production from continuing operations
|
|
|
(566
|
)
|
|
|
(3,058
|
)
|
|
|
(483
|
)
|
|
|
(2,778
|
)
|
|
|
|
|
|
|
Balance at end of period
|
|
|
5,763
|
|
|
|
33,455
|
|
|
|
6,239
|
|
|
|
32,325
|
|
|
|
|
|
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of period
|
|
|
4,179
|
|
|
|
25,434
|
|
|
|
4,497
|
|
|
|
23,562
|
|
|
|
|
|
|
|
|
|
Standardized
measure of discounted future net cash flows
The standardized measure of discounted future net cash flows is
computed by applying year-end prices of oil and gas (with
consideration of price changes only to the extent provided by
contractual arrangements) to the estimated future production of
proved oil and gas reserves less estimated future expenditures
(based on year-end costs) to be incurred in developing and
producing the proved reserves, discounted using a rate of
10 percent per year to reflect the estimated timing of the
future cash flows. Income taxes are excluded because the
property interests included in the Lowe Partners, LP acquisition
represent only a portion of a business for which income taxes
are not estimable.
Discounted future cash flow estimates like those shown below are
not intended to represent estimates of the fair value of oil and
gas properties. Estimates of fair value would also consider
probable and possible reserves, anticipated future oil and gas
prices, interest rates, changes in
F-94
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11 months
|
|
|
|
9 Year ended
|
|
|
ended
|
|
|
|
December 31,
|
|
|
November 30,
|
|
|
|
2003
|
|
|
2004
|
|
|
|
(in thousands)
|
|
|
(in thousands)
|
|
|
|
|
Oil and gas producing activities:
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
316,376
|
|
|
$
|
517,956
|
|
Future production costs
|
|
|
(128,943
|
)
|
|
|
(177,881
|
)
|
Future development and abandonment costs
|
|
|
(29,729
|
)
|
|
|
(22,115
|
)
|
|
|
|
|
|
|
Future net cash flows
|
|
|
157,704
|
|
|
|
317,960
|
|
10% annual discount factor
|
|
|
(78,094
|
)
|
|
|
(149,811
|
)
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
$
|
79,610
|
|
|
$
|
168,149
|
|
|
|
|
|
|
|
|
|
Changes in
standardized measure of discounted future net cash
flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11 months
|
|
|
|
Year ended
|
|
|
ended
|
|
|
|
December 31,
|
|
|
November 30,
|
|
|
|
2003
|
|
|
2004
|
|
|
|
(in thousands)
|
|
|
(in thousands)
|
|
|
|
|
Purchases of minerals in place
|
|
$
|
|
|
|
$
|
|
|
Extensions and discoveries, less related cost
|
|
|
5,987
|
|
|
|
994
|
|
Net changes in prices and production costs
|
|
|
(4,241
|
)
|
|
|
65,771
|
|
Oil and gas sales, net of production costs
|
|
|
(22,717
|
)
|
|
|
(24,611
|
)
|
Revisions of previous quantity estimates
|
|
|
437
|
|
|
|
16,149
|
|
Accretion of discount
|
|
|
7,362
|
|
|
|
7,961
|
|
Changes in production rates, timing and other
|
|
|
19,159
|
|
|
|
22,275
|
|
|
|
|
|
|
|
Change in present value of future net revenues
|
|
|
5,987
|
|
|
|
88,539
|
|
Balance, beginning of year
|
|
|
73,623
|
|
|
|
79,610
|
|
|
|
|
|
|
|
Balance, end of year
|
|
$
|
79,610
|
|
|
$
|
168,149
|
|
|
|
|
|
|
|
|
|
F-95
January 31, 2007
Mr. E. Joseph
Wright
COG Oil & Gas LP
Fasken Center, Tower II
Suite 1300
550 West Texas Avenue
Midland, Texas 79701
Dear Mr. Wright:
In accordance with your request, we have estimated the proved
reserves and future revenue, as of December 31, 2006, to
the COG Oil & Gas LP (Concho) interest in certain
oil and gas properties located in Louisiana, New Mexico, North
Dakota, and Texas. This report has been prepared using constant
prices and costs, as discussed in subsequent paragraphs of this
letter. The estimates of reserves and future revenue in this
report conform to the guidelines of the U.S. Securities and
Exchange Commission (SEC).
As presented in the accompanying summary projections, Tables I
through IV, we estimate the net reserves and future net revenue
to the Concho interest in these properties, as of
December 31, 2006, to be:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Reserves
|
|
|
Future Net Revenue ($)
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
|
|
Present Worth
|
|
Category
|
|
(Barrels)
|
|
|
(MCF)
|
|
|
Total
|
|
|
at 10%
|
|
|
|
|
Proved Developed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing
|
|
|
7,025,581
|
|
|
|
28,408,884
|
|
|
|
304,584,100
|
|
|
|
169,222,500
|
|
Non-Producing
|
|
|
577,258
|
|
|
|
5,311,605
|
|
|
|
39,230,900
|
|
|
|
14,646,900
|
|
Proved Undeveloped
|
|
|
3,610,267
|
|
|
|
11,328,375
|
|
|
|
125,088,200
|
|
|
|
45,328,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
|
11,213,106
|
|
|
|
45,048,864
|
|
|
|
468,903,200
|
|
|
|
229,198,100
|
|
The oil reserves shown include crude oil and condensate. Oil
volumes are expressed in barrels that are equivalent to 42
United States gallons. Gas volumes are expressed in thousands of
cubic feet (MCF) at standard temperature and pressure bases.
The estimates shown in this report are for proved developed
producing, proved developed non-producing, and proved
undeveloped reserves. In accordance with SEC guidelines, our
estimates do not include any probable or possible reserves that
may exist for these properties. This report
|
|
4500
Thanksgiving Tower 1601 Elm Street Dallas, Texas
75201-4754
Ph:
214-969-5401
Fax:
214-969-5411
|
nsai@nsai-petro.com
|
|
|
1221
Lamar Street, Suite 1200 Houston, Texas
77010-3072
Ph:
713-654-4950
Fax:
713-654-4951
|
netherlandsewell.com
|
A-1
does not include any value that could be attributed to interests
in undeveloped acreage beyond those tracts for which undeveloped
reserves have been estimated. Reserve categorization conveys the
relative degree of certainty; the estimates of reserves and
future revenue included herein have not been adjusted for risk.
Definitions of reserve categories are presented immediately
following this letter.
Future gross revenue to the Concho interest is prior to
deducting state production taxes and ad valorem taxes. Future
net revenue is after deductions for these taxes, future capital
costs, and operating expenses but before
consideration of federal income taxes. In accordance with SEC
guidelines, the future net revenue has been discounted at an
annual rate of 10 percent to determine its present
worth. The present worth is shown to indicate the effect
of time on the value of money and should not be construed as
being the fair market value of the properties.
For the purposes of this report, we did not perform any field
inspection of the properties, nor did we examine the mechanical
operation or condition of the wells and their related
facilities. We have not investigated possible environmental
liability related to the properties; therefore, our estimates do
not include any costs due to such possible liability. Also, our
estimates do not include any salvage value for the lease and
well equipment or the cost of abandoning the properties.
Oil prices used in this report are based on a December 31,
2006, West Texas Intermediate posted price of $57.75 per barrel
and are adjusted by lease for quality, transportation fees, and
regional price differentials. Gas prices used in this report are
based on a December 31, 2006, Henry Hub spot market price
of $5.635 per MMBTU and are adjusted by lease for energy
content, transportation fees, and regional price differentials.
All prices are held constant in accordance with SEC guidelines.
Lease and well operating costs used in this report are based on
operating expense records of Concho. For nonoperated properties,
these costs include the per-well overhead expenses allowed under
joint operating agreements along with estimates of costs to be
incurred at and below the district and field levels. As
requested, lease and well operating costs for the operated
properties include direct lease- and field-level costs and
Conchos estimate of the portion of its headquarters
general and administrative overhead expenses necessary to
operate the properties. Lease and well operating costs are held
constant in accordance with SEC guidelines. Capital costs are
included as required for workovers, new development wells, and
production equipment.
We have made no investigation of potential gas volume and value
imbalances resulting from overdelivery or underdelivery to the
Concho interest. Therefore, our estimates of reserves and future
revenue do not include adjustments for the settlement of any
such imbalances; our projections are based on Concho receiving
its net revenue interest share of estimated future gross gas
production.
The reserves shown in this report are estimates only and should
not be construed as exact quantities. The reserves may or may
not be recovered; if they are recovered, the revenues therefrom
and the costs related thereto could be more or less than the
estimated amounts. Because of governmental policies and
uncertainties of supply and demand, the sales rates, prices
received for the reserves, and costs incurred in recovering such
reserves may vary from
A-2
assumptions made while preparing this report. Also, estimates of
reserves may increase or decrease as a result of future
operations.
In evaluating the information at our disposal concerning this
report, we have excluded from our consideration all matters as
to which the controlling interpretation may be legal or
accounting, rather than engineering and geologic. As in all
aspects of oil and gas evaluation, there are uncertainties
inherent in the interpretation of engineering and geologic data;
therefore, our conclusions necessarily represent only informed
professional judgment.
The titles to the properties have not been examined by
Netherland, Sewell & Associates, Inc., nor has the
actual degree or type of interest owned been independently
confirmed. The data used in our estimates were obtained from COG
Oil & Gas LP, other interest owners, various operators
of the properties, public data sources, and the nonconfidential
files of Netherland, Sewell & Associates, Inc. and
were accepted as accurate. Supporting geologic, field
performance, and work data are on file in our office. We are
independent petroleum engineers, geologists, geophysicists, and
petrophysicists; we do not own an interest in these properties
and are not employed on a contingent basis.
Very truly yours,
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
|
|
By:
|
/s/ C.H.
(Scott) Rees III, P.E.
|
C.H. (Scott) Rees III, P.E.
President and Chief Operating Officer
|
|
|
|
By:
|
/s/ G.
Lance Binder, P.E.
|
G. Lance Binder, P.E.
Executive Vice President
Date Signed: January 31, 2007
GLB:KBD
A-3
DEFINITIONS OF
OIL AND GAS RESERVES
Adapted
from Securities and Exchange Commission
Regulation S-X
Rule 4-10(a)
The following definitions of proved reserves are set forth in
Securities and Exchange Commission (SEC)
Regulation S-X
Section 210.4-10(a).
Also included (in italics) are certain subsequent
interpretations set forth in the SECs Corporate Finance
Accounting Interpretations and Guidance [SEC Interpretations];
SEC Staff Accounting Bulletins: Topic 12
[SEC Topic 12]; and the 1997 reserves definitions
approved by the Society of Petroleum Engineers and World
Petroleum Council [SPE/WPC Definitions].
Proved Oil and Gas Reserves. Proved oil and
gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering
data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the date the
estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but
not on escalations based upon future conditions.
The determination of reasonable certainty is generated by
supporting geological and engineering data. There must be data
available which indicate that assumptions such as decline rates,
recovery factors, reservoir limits, recovery mechanisms and
volumetric estimates, gas-oil ratios or liquid yield are valid.
If the area in question is new to exploration and there is
little supporting data for decline rates, recovery factors,
reservoir drive mechanisms etc., a conservative approach is
appropriate until there is enough supporting data to justify the
use of more liberal parameters for the estimation of proved
reserves. The concept of reasonable certainty implies that, as
more technical data becomes available, a positive, or upward,
revision is much more likely than a negative, or downward,
revision.
Existing economic and operating conditions are the product
prices, operating costs, production methods, recovery
techniques, transportation and marketing arrangements, ownership
and/or entitlement terms and regulatory requirements that are
extant on the effective date of the estimate. An anticipated
change in conditions must have reasonable certainty of
occurrence; the corresponding investment and operating expense
to make that change must be included in the economic feasibility
at the appropriate time. These conditions include estimated net
abandonment costs to be incurred and duration of current
licenses and permits.
If oil and gas prices are so low that production is actually
shut-in because of uneconomic conditions, the reserves
attributed to the shut-in properties can no longer be classified
as proved and must be subtracted from the proved reserve data
base as a negative revision. Those volumes may be included as
positive revisions to a subsequent years proved reserves
only upon their return to economic status. [SEC
Interpretations]
Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation
test. The area of a reservoir considered proved includes
(A) that portion delineated by drilling and defined by
gas-oil and/or oil-water contacts, if any; and
A-4
DEFINITIONS OF
OIL AND GAS RESERVES
Adapted
from Securities and Exchange Commission
Regulation S-X
Rule 4-10(a)
(B) the immediately adjoining portions not yet drilled, but
which can be reasonably judged as economically productive on the
basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir.
Proved reserves may be attributed to a prospective zone if a
conclusive formation test has been performed or if there is
production from the zone at economic rates. It is clear to the
SEC staff that wireline recovery of small volumes (e.g.
100 cc) or production of a few hundred barrels per day
in remote locations is not necessarily conclusive. Analyses of
open-hole well logs which imply that an interval is productive
are not sufficient for attribution of proved reserves. If there
is an indication of economic producibility by either formation
test or production, the reserves in the legal and technically
justified drainage area around the well projected down to a
known fluid contact or the lowest known hydrocarbons, or LKH may
be considered to be proved.
In order to attribute proved reserves to legal locations
adjacent to such a well (i.e. offsets), there must be
conclusive, unambiguous technical data which supports reasonable
certainty of production of such volumes and sufficient legal
acreage to economically justify the development without going
below the shallower of the fluid contact or the LKH. In the
absence of a fluid contact, no offsetting reservoir volume below
the LKH from a well penetration shall be classified as
proved.
Upon obtaining performance history sufficient to reasonably
conclude that more reserves will be recovered than those
estimated volumetrically down to LKH, positive reserve revisions
should be made. [SEC Interpretations]
Economic producibility of estimated proved reserves can be
supported to the satisfaction of the Office of Engineering if
geological and engineering data demonstrate with reasonable
certainty that those reserves can be recovered in future years
under existing economic and operating conditions. The relative
importance of the many pieces of geological and engineering data
which should be evaluated when classifying reserves cannot be
identified in advance. In certain instances, proved reserves may
be assigned to reservoirs on the basis of a combination of
electrical and other type logs and core analyses which indicate
the reservoirs are analogous to similar reservoirs in the same
field which are producing or have demonstrated the ability to
produce on a formation test. [SEC Topic 12]
Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are
included in the proved classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
If an improved recovery technique which has not been verified
by routine commercial use in the area is to be applied, the
hydrocarbon volumes estimated to be recoverable cannot be
A-5
DEFINITIONS OF
OIL AND GAS RESERVES
Adapted
from Securities and Exchange Commission
Regulation S-X
Rule 4-10(a)
classified as proved reserves unless the technique has been
demonstrated to be technically and economically successful by a
pilot project or installed program in that specific rock volume.
Such demonstration should validate the feasibility study leading
to the project. [SEC Interpretations]
Estimates of proved reserves do not include the following:
|
|
|
|
(A)
|
oil that may become available from known reservoirs but is
classified separately as indicated additional
reserves;
|
|
|
|
|
(B)
|
crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as
to geology, reservoir characteristics, or economic factors;
|
|
|
(C)
|
crude oil, natural gas, and natural gas liquids, that may occur
in undrilled prospects; and
|
|
|
|
|
(D)
|
crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such
sources.
|
Geologic and reservoir characteristic uncertainties such as
those relating to permeability, reservoir continuity, sealing
nature of faults, structure and other unknown characteristics
may prevent reserves from being classified as proved. Economic
uncertainties such as the lack of a market (e.g. stranded
hydrocarbons), uneconomic prices and marginal reserves that do
not show a positive cash flow can also prevent reserves from
being classified as proved. Hydrocarbons
manufactured through extensive treatment of
gilsonite, coal and oil shales are mining activities reportable
under Industry Guide 7. They cannot be called proved oil
and gas reserves. However, coal bed methane gas can be
classified as proved reserves if the recovery of such is shown
to be economically feasible.
In developing frontier areas, the existence of wells with a
formation test or limited production may not be enough to
classify those estimated hydrocarbon volumes as proved reserves.
Issuers must demonstrate that there is reasonable certainty that
a market exists for the hydrocarbons and that an economic method
of extracting, treating and transporting them to market exists
or is feasible and is likely to exist in the near future. A
commitment by the company to develop the necessary production,
treatment and transportation infrastructure is essential to the
attribution of proved undeveloped reserves. Significant lack of
progress on the development of such reserves may be evidence of
a lack of such commitment. Affirmation of this commitment may
take the form of signed sales contracts for the products;
request for proposals to build facilities; signed acceptance of
bid proposals; memos of understanding between the appropriate
organizations and governments; firm plans and timetables
established; approved authorization for expenditures to build
facilities; approved loan documents to finance the required
infrastructure; initiation of construction of facilities;
approved environmental permits etc. Reasonable certainty of
procurement of project
A-6
DEFINITIONS OF
OIL AND GAS RESERVES
Adapted
from Securities and Exchange Commission
Regulation S-X
Rule 4-10(a)
financing by the company is a requirement for the attribution
of proved reserves. An inordinately long delay in the schedule
of development may introduce doubt sufficient to preclude the
attribution of proved reserves.
The history of issuance and continued recognition of permits,
concessions and commercially agreements by regulatory bodies and
governments should be considered when determining whether
hydrocarbon accumulations can be classified as proved reserves.
Automatic renewal of such agreements cannot be expected if the
regulatory body has the authority to end the agreement unless
there is a long and clear track record which supports the
conclusion that such approvals and renewal are a matter of
course. [SEC Interpretations]
Companies should report reserves of natural gas liquids which
are net to their leasehold interests, i.e., that portion
recovered in a processing plant and allocated to the leasehold
interest. It may be appropriate in the case of natural gas
liquids not clearly attributable to leasehold interests
ownership to follow instructions to Item 3 of Securities
Act Industry Guide 2 and report such reserves separately and
describe the nature of the ownership.
[SEC Topic 12]
Proved Developed Oil and Gas Reserves. Proved
developed oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment
and operating methods. Additional oil and gas expected to be
obtained through the application of fluid injection or other
improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as
proved developed reserves only after testing by a
pilot project or after the operation of an installed program has
confirmed through production response that increased recovery
will be achieved.
Currently producing wells and wells awaiting minor sales
connection expenditure, recompletion, additional perforations or
bore hole stimulation treatment would be examples of properties
with proved developed reserves since the majority of the
expenditures to develop the reserves has already been spent.
Proved developed reserves from improved recovery techniques
can be assigned after either the operation of an installed pilot
program shows a positive production response to the technique or
the project is fully installed and operational and has shown the
production response anticipated by earlier feasibility studies.
In the case with a pilot, proved developed reserves can be
assigned only to that volume attributable to the pilots
influence. In the case of the fully installed project, response
must be seen from the full project before all the proved
developed reserves estimated can be assigned. If a project is
not following original forecasts, proved developed reserves can
only be assigned to the extent actually supported by the current
performance. An important point here is that attribution of
incremental proved developed reserves from the application of
improved recovery techniques requires the installation of
facilities and a production increase. [SEC Interpretations]
A-7
DEFINITIONS OF
OIL AND GAS RESERVES
Adapted
from Securities and Exchange Commission
Regulation S-X
Rule 4-10(a)
Proved Developed Producing
Reserves. Reserves subcategorized as
producing 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. Reserves subcategorized as
non-producing 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 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 the start of production. [SPE/WPC
Definitions]
Proved Undeveloped Reserves. Proved
undeveloped oil and gas reserves are reserves that are expected
to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required
for recompletion. Reserves on undrilled acreage shall be limited
to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be
demonstrated with certainty that there is continuity of
production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves
be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual
tests in the area and in the same reservoir.
The SEC staff points out that this definition contains no
mitigating modifier for the word certainty. Also, continuity of
production requires more than the technical indication of
favorable structure alone (e.g. seismic data) to meet the test
for proved undeveloped reserves. Generally, proved undeveloped
reserves can be claimed only for legal and technically justified
drainage areas offsetting an existing productive well (but
structurally no lower than LKH). If there are at least two wells
in the same reservoir which are separated by more than one legal
location and which show communication (reservoir continuity),
proved undeveloped reserves could be claimed between the two
wells, even though the location in question might be more than
an offset well location away from any of the wells. In this
illustration, seismic data could be used to help support this
claim by showing reservoir continuity between the wells, but the
required data would be the conclusive evidence of communication
from production or pressure tests. The SEC staff emphasizes that
proved reserves cannot be claimed more than one offset location
away from a productive well if there are no other wells in the
reservoir, even though seismic data may exist. The use of
high-quality, well calibrated seismic data can improve reservoir
description for performing volumetrics (e.g. fluid contacts).
However, seismic data is not an indicator of continuity of
production and, therefore, can not be the sole indicator of
additional proved reserves
A-8
DEFINITIONS OF
OIL AND GAS RESERVES
Adapted
from Securities and Exchange Commission
Regulation S-X
Rule 4-10(a)
beyond the legal and technically justified drainage areas of
wells that were drilled. Continuity of production would have to
be demonstrated by something other than seismic data.
In a new reservoir with only a few wells, reservoir
simulation or application of generalized hydrocarbon recovery
correlations would not be considered a reliable method to show
increased proved undeveloped reserves. With only a few wells as
data points from which to build a geologic model and little
performance history to validate the results with an acceptable
history match, the results of a simulation or material balance
model would be speculative in nature. The results of such a
simulation or material balance model would not be considered to
be reasonably certain to occur in the field to the extent that
additional proved undeveloped reserves could be recognized. The
application of recovery correlations which are not specific to
the field under consideration is not reliable enough to be the
sole source for proved reserve calculations.
Reserves cannot be classified as proved undeveloped reserves
based on improved recovery techniques until such time that they
have been proved effective in that reservoir or an analogous
reservoir in the same geologic formation in the immediate area.
An analogous reservoir is one having at least the same values or
better for porosity, permeability, permeability distribution,
thickness, continuity and hydrocarbon saturations,
|
|
|
|
(g)
|
Topic 12 of Accounting Series Release No. 257 of
the Staff Accounting Bulletins states: In certain
instances, proved reserves may be assigned to reservoirs on the
basis of a combination of electrical and other type logs and
core analyses which indicate the reservoirs are analogous to
similar reservoirs in the same field which are producing or have
demonstrated the ability to produce on a formation test.
|
If the combination of data from open-hole logs and core
analyses is overwhelmingly in support of economic producibility
and the indicated reservoir properties are analogous to similar
reservoirs in the same field that have produced or demonstrated
the ability to produce on a conclusive formation test, the
reserves may be classified as proved. This would probably be a
rare event especially in an exploratory situation. The essence
of the SEC definition is that in most cases there must at least
be a conclusive formation test in a new reservoir before any
reserves can be considered to be proved. [SEC
Interpretations]
A-9
Summary
projection of reserves and revenue
As of
12-31-6
|
|
Cog
Oil & Gas LP Interest
|
Summary
All Properties
|
Louisiana, New Mexico,
North Dakota, and Texas
Total Proved
Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Incl Prod+Adval Taxes
|
|
|
Prod+Av
|
|
|
Net Cap
|
|
|
Operating
|
|
|
Net
|
|
|
Cum P.W.
|
|
Period
|
|
Oil/cond
|
|
|
Oil/cond
|
|
|
Gas
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Taxes
|
|
|
Cost
|
|
|
Expense
|
|
|
Revenue
|
|
|
10.000%
|
|
Ending
|
|
MBBL
|
|
|
MBBL
|
|
|
MMCF
|
|
|
MMCF
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31- 7
|
|
|
3199.669
|
|
|
|
823.536
|
|
|
|
24450.690
|
|
|
|
4005.191
|
|
|
|
46680.9
|
|
|
|
19275.9
|
|
|
|
65956.8
|
|
|
|
6064.6
|
|
|
|
23522.6
|
|
|
|
8878.0
|
|
|
|
27491.6
|
|
|
|
25765.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31- 8
|
|
|
3212.573
|
|
|
|
824.063
|
|
|
|
23094.982
|
|
|
|
3952.675
|
|
|
|
46744.2
|
|
|
|
18993.7
|
|
|
|
65737.9
|
|
|
|
6041.2
|
|
|
|
35131.1
|
|
|
|
9215.5
|
|
|
|
15350.1
|
|
|
|
38927.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31- 9
|
|
|
3282.296
|
|
|
|
891.661
|
|
|
|
22269.744
|
|
|
|
3839.593
|
|
|
|
50466.4
|
|
|
|
18488.8
|
|
|
|
68955.2
|
|
|
|
6322.4
|
|
|
|
11428.3
|
|
|
|
9576.7
|
|
|
|
41627.8
|
|
|
|
71695.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-10
|
|
|
2968.204
|
|
|
|
803.848
|
|
|
|
19825.327
|
|
|
|
3295.627
|
|
|
|
45342.7
|
|
|
|
15823.0
|
|
|
|
61165.7
|
|
|
|
5562.6
|
|
|
|
2018.8
|
|
|
|
9668.6
|
|
|
|
43915.7
|
|
|
|
103203.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-11
|
|
|
2676.701
|
|
|
|
695.398
|
|
|
|
16985.892
|
|
|
|
2783.567
|
|
|
|
39210.3
|
|
|
|
13363.4
|
|
|
|
52573.7
|
|
|
|
4774.2
|
|
|
|
622.4
|
|
|
|
9611.8
|
|
|
|
37565.3
|
|
|
|
127704.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-12
|
|
|
2483.810
|
|
|
|
626.504
|
|
|
|
14881.742
|
|
|
|
2420.963
|
|
|
|
35372.7
|
|
|
|
11692.7
|
|
|
|
47065.4
|
|
|
|
4276.9
|
|
|
|
1653.2
|
|
|
|
9507.5
|
|
|
|
31627.8
|
|
|
|
146438.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-13
|
|
|
2312.396
|
|
|
|
573.578
|
|
|
|
13148.341
|
|
|
|
2116.431
|
|
|
|
32410.9
|
|
|
|
10277.8
|
|
|
|
42688.7
|
|
|
|
3878.9
|
|
|
|
310.3
|
|
|
|
9352.5
|
|
|
|
29147.0
|
|
|
|
162152.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-14
|
|
|
2112.708
|
|
|
|
516.919
|
|
|
|
11622.560
|
|
|
|
1858.132
|
|
|
|
29184.4
|
|
|
|
9008.5
|
|
|
|
38192.9
|
|
|
|
3459.5
|
|
|
|
385.3
|
|
|
|
9004.0
|
|
|
|
25344.1
|
|
|
|
174567.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-15
|
|
|
1942.136
|
|
|
|
470.228
|
|
|
|
10387.162
|
|
|
|
1661.131
|
|
|
|
26525.7
|
|
|
|
8046.2
|
|
|
|
34571.9
|
|
|
|
3127.2
|
|
|
|
349.7
|
|
|
|
8670.2
|
|
|
|
22424.8
|
|
|
|
184556.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-16
|
|
|
1817.021
|
|
|
|
434.486
|
|
|
|
9504.547
|
|
|
|
1544.437
|
|
|
|
24494.4
|
|
|
|
7470.0
|
|
|
|
31964.4
|
|
|
|
2892.1
|
|
|
|
457.4
|
|
|
|
8580.5
|
|
|
|
20034.4
|
|
|
|
192666.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-17
|
|
|
1731.750
|
|
|
|
404.446
|
|
|
|
8727.324
|
|
|
|
1430.286
|
|
|
|
22787.0
|
|
|
|
6918.6
|
|
|
|
29705.6
|
|
|
|
2685.2
|
|
|
|
386.8
|
|
|
|
8503.0
|
|
|
|
18130.6
|
|
|
|
199339.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-18
|
|
|
1661.803
|
|
|
|
378.513
|
|
|
|
8353.596
|
|
|
|
1414.999
|
|
|
|
21306.6
|
|
|
|
6858.6
|
|
|
|
28165.2
|
|
|
|
2547.4
|
|
|
|
349.9
|
|
|
|
8302.9
|
|
|
|
16965.0
|
|
|
|
205016.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-19
|
|
|
1575.032
|
|
|
|
351.499
|
|
|
|
7510.065
|
|
|
|
1247.434
|
|
|
|
19752.6
|
|
|
|
6043.8
|
|
|
|
25796.4
|
|
|
|
2317.8
|
|
|
|
299.7
|
|
|
|
8022.3
|
|
|
|
15156.6
|
|
|
|
209626.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-20
|
|
|
1478.254
|
|
|
|
325.439
|
|
|
|
6800.844
|
|
|
|
1124.854
|
|
|
|
18279.7
|
|
|
|
5453.8
|
|
|
|
23733.5
|
|
|
|
2128.1
|
|
|
|
188.3
|
|
|
|
7881.7
|
|
|
|
13535.4
|
|
|
|
213369.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-21
|
|
|
1288.768
|
|
|
|
297.743
|
|
|
|
6043.443
|
|
|
|
1019.599
|
|
|
|
16709.3
|
|
|
|
4936.0
|
|
|
|
21645.3
|
|
|
|
1940.8
|
|
|
|
77.7
|
|
|
|
7515.9
|
|
|
|
12110.9
|
|
|
|
216415.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUBTOTAL
|
|
|
33743.121
|
|
|
|
8417.861
|
|
|
|
203606.259
|
|
|
|
33714.919
|
|
|
|
475267.8
|
|
|
|
162650.8
|
|
|
|
637918.6
|
|
|
|
58018.9
|
|
|
|
77181.5
|
|
|
|
132291.1
|
|
|
|
370427.1
|
|
|
|
216415.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REMAING
|
|
|
8799.659
|
|
|
|
2795.245
|
|
|
|
62534.918
|
|
|
|
11333.945
|
|
|
|
157538.4
|
|
|
|
54598.1
|
|
|
|
212136.5
|
|
|
|
19011.3
|
|
|
|
887.7
|
|
|
|
93761.4
|
|
|
|
98476.1
|
|
|
|
229198.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL OF 65.0 YRS
|
|
|
42542.780
|
|
|
|
11213.106
|
|
|
|
266141.177
|
|
|
|
45048.864
|
|
|
|
632806.2
|
|
|
|
217248.9
|
|
|
|
850055.1
|
|
|
|
77030.2
|
|
|
|
78069.2
|
|
|
|
226052.5
|
|
|
|
468903.2
|
|
|
|
229198.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CUM PROD
|
|
|
96643.548
|
|
|
|
|
|
|
|
1244209.325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ULTIMATE
|
|
|
139186.328
|
|
|
|
|
|
|
|
1510350.502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASED ON CONSTANT PRICES AND COSTS
PRESENT WORTH PROFILE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
8.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
256230.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
12.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
207055.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
15.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
180500.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
20.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
148144.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
25.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
125216.3
|
|
Table I
All estimates and exhibits
herein are part of this NSAI report and are subject to its
parameters and conditions.
A-10
Summary
projection of reserves and revenue
As of
12-31-6
|
|
Cog
Oil & Gas LP Interest
|
Summary All Properties
|
Louisiana, New Mexico,
North Dakota, and Texas
Proved Developed
Producing Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Incl Prod+Adval Taxes
|
|
|
Prod+Av
|
|
|
Net Cap
|
|
|
Operating
|
|
|
Net
|
|
|
Cum P.W.
|
|
Period
|
|
Oil/cond
|
|
|
Oil/cond
|
|
|
Gas
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Taxes
|
|
|
Cost
|
|
|
Expense
|
|
|
Revenue
|
|
|
10.000%
|
|
Ending
|
|
MBBL
|
|
|
MBBL
|
|
|
MMCF
|
|
|
MMCF
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31- 7
|
|
|
2762.958
|
|
|
|
670.536
|
|
|
|
21341.080
|
|
|
|
3203.759
|
|
|
|
37977.3
|
|
|
|
15413.2
|
|
|
|
53390.5
|
|
|
|
4893.8
|
|
|
|
0.0
|
|
|
|
8475.2
|
|
|
|
40021.5
|
|
|
|
38278.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31- 8
|
|
|
2342.335
|
|
|
|
549.859
|
|
|
|
17133.873
|
|
|
|
2480.192
|
|
|
|
31124.8
|
|
|
|
11968.8
|
|
|
|
43093.6
|
|
|
|
3937.4
|
|
|
|
0.0
|
|
|
|
8354.8
|
|
|
|
30801.4
|
|
|
|
65031.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31- 9
|
|
|
2082.950
|
|
|
|
480.240
|
|
|
|
14693.301
|
|
|
|
2104.968
|
|
|
|
27180.6
|
|
|
|
10175.3
|
|
|
|
37355.9
|
|
|
|
3405.7
|
|
|
|
0.0
|
|
|
|
8174.5
|
|
|
|
25775.7
|
|
|
|
85376.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-10
|
|
|
1884.684
|
|
|
|
430.692
|
|
|
|
12967.634
|
|
|
|
1858.733
|
|
|
|
24373.9
|
|
|
|
8994.7
|
|
|
|
33368.6
|
|
|
|
3040.8
|
|
|
|
0.0
|
|
|
|
8094.2
|
|
|
|
22233.6
|
|
|
|
101328.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-11
|
|
|
1694.589
|
|
|
|
388.017
|
|
|
|
11599.098
|
|
|
|
1664.089
|
|
|
|
21950.1
|
|
|
|
8057.6
|
|
|
|
30007.7
|
|
|
|
2739.2
|
|
|
|
0.0
|
|
|
|
8021.9
|
|
|
|
19246.6
|
|
|
|
113881.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-12
|
|
|
1559.214
|
|
|
|
356.997
|
|
|
|
10457.550
|
|
|
|
1502.883
|
|
|
|
20190.2
|
|
|
|
7277.4
|
|
|
|
27467.6
|
|
|
|
2504.7
|
|
|
|
0.0
|
|
|
|
7873.5
|
|
|
|
17089.4
|
|
|
|
124014.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-13
|
|
|
1435.576
|
|
|
|
330.782
|
|
|
|
9480.021
|
|
|
|
1354.603
|
|
|
|
18702.0
|
|
|
|
6565.6
|
|
|
|
25267.6
|
|
|
|
2299.4
|
|
|
|
0.0
|
|
|
|
7709.3
|
|
|
|
15258.9
|
|
|
|
132238.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-14
|
|
|
1316.163
|
|
|
|
305.889
|
|
|
|
8567.040
|
|
|
|
1222.115
|
|
|
|
17286.6
|
|
|
|
5926.3
|
|
|
|
23212.9
|
|
|
|
2111.2
|
|
|
|
0.0
|
|
|
|
7379.3
|
|
|
|
13722.4
|
|
|
|
138961.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-15
|
|
|
1208.778
|
|
|
|
283.731
|
|
|
|
7732.036
|
|
|
|
1101.372
|
|
|
|
16026.8
|
|
|
|
5341.7
|
|
|
|
21368.5
|
|
|
|
1942.2
|
|
|
|
0.0
|
|
|
|
7037.4
|
|
|
|
12388.9
|
|
|
|
144480.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-16
|
|
|
1123.511
|
|
|
|
266.177
|
|
|
|
7096.232
|
|
|
|
1012.323
|
|
|
|
15031.4
|
|
|
|
4911.9
|
|
|
|
19943.3
|
|
|
|
1811.1
|
|
|
|
0.0
|
|
|
|
6930.2
|
|
|
|
11202.0
|
|
|
|
149015.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-17
|
|
|
1045.095
|
|
|
|
250.172
|
|
|
|
6519.186
|
|
|
|
933.088
|
|
|
|
14124.8
|
|
|
|
4529.4
|
|
|
|
18654.2
|
|
|
|
1692.1
|
|
|
|
0.0
|
|
|
|
6847.4
|
|
|
|
10114.7
|
|
|
|
152738.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-18
|
|
|
971.997
|
|
|
|
233.709
|
|
|
|
5969.685
|
|
|
|
853.534
|
|
|
|
13194.5
|
|
|
|
4154.6
|
|
|
|
17349.1
|
|
|
|
1572.0
|
|
|
|
0.0
|
|
|
|
6662.4
|
|
|
|
9114.7
|
|
|
|
155789.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-19
|
|
|
900.907
|
|
|
|
217.416
|
|
|
|
5486.989
|
|
|
|
782.153
|
|
|
|
12273.8
|
|
|
|
3813.1
|
|
|
|
16086.9
|
|
|
|
1452.2
|
|
|
|
0.0
|
|
|
|
6424.9
|
|
|
|
8209.8
|
|
|
|
158286.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-20
|
|
|
838.336
|
|
|
|
203.943
|
|
|
|
5028.201
|
|
|
|
721.817
|
|
|
|
11514.4
|
|
|
|
3527.2
|
|
|
|
15041.6
|
|
|
|
1356.9
|
|
|
|
0.0
|
|
|
|
6321.2
|
|
|
|
7363.5
|
|
|
|
160323.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-21
|
|
|
704.656
|
|
|
|
187.389
|
|
|
|
4484.484
|
|
|
|
665.744
|
|
|
|
10569.5
|
|
|
|
3251.4
|
|
|
|
13820.9
|
|
|
|
1247.1
|
|
|
|
0.0
|
|
|
|
5974.4
|
|
|
|
6599.4
|
|
|
|
161982.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUBTOTAL
|
|
|
21871.749
|
|
|
|
5155.549
|
|
|
|
148556.410
|
|
|
|
21461.373
|
|
|
|
291520.7
|
|
|
|
103908.2
|
|
|
|
395428.9
|
|
|
|
36005.8
|
|
|
|
0.0
|
|
|
|
110280.6
|
|
|
|
249142.5
|
|
|
|
161982.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REMAING
|
|
|
4860.515
|
|
|
|
1870.032
|
|
|
|
43555.071
|
|
|
|
6947.511
|
|
|
|
105960.0
|
|
|
|
34444.3
|
|
|
|
140404.3
|
|
|
|
12556.5
|
|
|
|
0.0
|
|
|
|
72406.2
|
|
|
|
55441.6
|
|
|
|
169222.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL OF 50.0 YRS
|
|
|
26732.264
|
|
|
|
7025.581
|
|
|
|
192111.481
|
|
|
|
28408.884
|
|
|
|
397480.7
|
|
|
|
138352.5
|
|
|
|
535833.2
|
|
|
|
48562.3
|
|
|
|
0.0
|
|
|
|
182686.8
|
|
|
|
304584.1
|
|
|
|
169222.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CUM PROD
|
|
|
96643.225
|
|
|
|
|
|
|
|
1243502.217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ULTIMATE
|
|
|
123375.489
|
|
|
|
|
|
|
|
1435613.698
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASED ON CONSTANT PRICES AND COSTS
PRESENT WORTH PROFILE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
8.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
184710.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
12.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
156474.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
15.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
141071.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
20.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
122050.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
25.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
108305.0
|
|
Table II
All estimates and exhibits
herein are part of this NSAI report and are subject to its
parameters and conditions.
A-11
Summary
projection of reserves and revenue
As of
12-31-6
|
|
Cog
Oil & Gas LP Interest
|
Summary
All Properties
|
Louisiana, New Mexico,
North Dakota, and Texas
Proved Developed
Non-producing Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Incl Prod+Adval Taxes
|
|
|
Prod+Av
|
|
|
Net Cap
|
|
|
Operating
|
|
|
Net
|
|
|
Cum P.W.
|
|
Period
|
|
Oil/cond
|
|
|
Oil/cond
|
|
|
Gas
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Taxes
|
|
|
Cost
|
|
|
Expense
|
|
|
Revenue
|
|
|
10.000%
|
|
Ending
|
|
MBBL
|
|
|
MBBL
|
|
|
MMCF
|
|
|
MMCF
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31- 7
|
|
|
99.185
|
|
|
|
37.564
|
|
|
|
1854.805
|
|
|
|
455.414
|
|
|
|
2108.0
|
|
|
|
2160.6
|
|
|
|
4268.6
|
|
|
|
401.2
|
|
|
|
3406.3
|
|
|
|
129.9
|
|
|
|
331.2
|
|
|
|
185.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31- 8
|
|
|
106.263
|
|
|
|
35.476
|
|
|
|
1752.726
|
|
|
|
424.279
|
|
|
|
2008.3
|
|
|
|
2032.4
|
|
|
|
4040.7
|
|
|
|
379.8
|
|
|
|
842.2
|
|
|
|
174.2
|
|
|
|
2644.5
|
|
|
|
2484.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31- 9
|
|
|
98.650
|
|
|
|
34.416
|
|
|
|
1349.869
|
|
|
|
335.515
|
|
|
|
1961.4
|
|
|
|
1621.6
|
|
|
|
3583.0
|
|
|
|
342.5
|
|
|
|
34.8
|
|
|
|
212.5
|
|
|
|
2993.2
|
|
|
|
4849.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-10
|
|
|
73.116
|
|
|
|
25.770
|
|
|
|
961.269
|
|
|
|
243.176
|
|
|
|
1462.1
|
|
|
|
1173.8
|
|
|
|
2635.9
|
|
|
|
249.0
|
|
|
|
0.0
|
|
|
|
212.4
|
|
|
|
2174.5
|
|
|
|
6411.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-11
|
|
|
62.574
|
|
|
|
21.942
|
|
|
|
746.019
|
|
|
|
194.949
|
|
|
|
1243.8
|
|
|
|
939.3
|
|
|
|
2183.1
|
|
|
|
205.4
|
|
|
|
90.0
|
|
|
|
216.3
|
|
|
|
1671.4
|
|
|
|
7501.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-12
|
|
|
72.013
|
|
|
|
24.883
|
|
|
|
646.164
|
|
|
|
170.997
|
|
|
|
1424.6
|
|
|
|
829.9
|
|
|
|
2254.5
|
|
|
|
207.6
|
|
|
|
39.5
|
|
|
|
231.4
|
|
|
|
1776.0
|
|
|
|
8550.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-13
|
|
|
68.130
|
|
|
|
24.256
|
|
|
|
535.695
|
|
|
|
145.893
|
|
|
|
1393.5
|
|
|
|
714.2
|
|
|
|
2107.7
|
|
|
|
191.3
|
|
|
|
0.0
|
|
|
|
230.5
|
|
|
|
1685.9
|
|
|
|
9459.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-14
|
|
|
58.326
|
|
|
|
21.491
|
|
|
|
462.845
|
|
|
|
128.693
|
|
|
|
1232.2
|
|
|
|
626.9
|
|
|
|
1859.1
|
|
|
|
168.2
|
|
|
|
75.0
|
|
|
|
224.7
|
|
|
|
1391.2
|
|
|
|
10139.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-15
|
|
|
49.890
|
|
|
|
18.785
|
|
|
|
411.633
|
|
|
|
116.478
|
|
|
|
1074.9
|
|
|
|
564.0
|
|
|
|
1638.9
|
|
|
|
148.6
|
|
|
|
50.0
|
|
|
|
226.4
|
|
|
|
1213.9
|
|
|
|
10681.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-16
|
|
|
47.714
|
|
|
|
17.624
|
|
|
|
482.087
|
|
|
|
141.279
|
|
|
|
1007.7
|
|
|
|
672.3
|
|
|
|
1680.0
|
|
|
|
155.1
|
|
|
|
143.3
|
|
|
|
238.7
|
|
|
|
1142.9
|
|
|
|
11142.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-17
|
|
|
46.586
|
|
|
|
16.808
|
|
|
|
507.471
|
|
|
|
148.457
|
|
|
|
960.8
|
|
|
|
707.7
|
|
|
|
1668.5
|
|
|
|
156.2
|
|
|
|
72.7
|
|
|
|
245.4
|
|
|
|
1194.2
|
|
|
|
11582.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-18
|
|
|
51.964
|
|
|
|
18.973
|
|
|
|
829.471
|
|
|
|
246.915
|
|
|
|
1075.4
|
|
|
|
1192.9
|
|
|
|
2268.3
|
|
|
|
216.8
|
|
|
|
50.2
|
|
|
|
250.9
|
|
|
|
1750.4
|
|
|
|
12167.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-19
|
|
|
59.107
|
|
|
|
21.976
|
|
|
|
605.882
|
|
|
|
181.651
|
|
|
|
1228.8
|
|
|
|
875.1
|
|
|
|
2103.9
|
|
|
|
193.9
|
|
|
|
0.0
|
|
|
|
252.9
|
|
|
|
1657.1
|
|
|
|
12672.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-20
|
|
|
50.202
|
|
|
|
18.880
|
|
|
|
483.510
|
|
|
|
146.235
|
|
|
|
1054.4
|
|
|
|
702.5
|
|
|
|
1756.9
|
|
|
|
161.0
|
|
|
|
0.0
|
|
|
|
243.7
|
|
|
|
1352.2
|
|
|
|
13046.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-21
|
|
|
45.772
|
|
|
|
16.794
|
|
|
|
416.188
|
|
|
|
125.140
|
|
|
|
938.7
|
|
|
|
598.6
|
|
|
|
1537.3
|
|
|
|
140.8
|
|
|
|
25.0
|
|
|
|
241.4
|
|
|
|
1130.1
|
|
|
|
13330.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUBTOTAL
|
|
|
989.492
|
|
|
|
355.638
|
|
|
|
12045.634
|
|
|
|
3205.071
|
|
|
|
20174.6
|
|
|
|
15411.8
|
|
|
|
35586.4
|
|
|
|
3317.4
|
|
|
|
4829.0
|
|
|
|
3331.3
|
|
|
|
24108.7
|
|
|
|
13330.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REMAING
|
|
|
453.475
|
|
|
|
221.620
|
|
|
|
9427.261
|
|
|
|
2106.534
|
|
|
|
12537.5
|
|
|
|
9955.8
|
|
|
|
22493.3
|
|
|
|
2084.7
|
|
|
|
887.7
|
|
|
|
4398.7
|
|
|
|
15122.2
|
|
|
|
14646.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL OF 65.0 YRS
|
|
|
1442.967
|
|
|
|
577.258
|
|
|
|
21472.895
|
|
|
|
5311.605
|
|
|
|
32712.1
|
|
|
|
25367.6
|
|
|
|
58079.7
|
|
|
|
5402.1
|
|
|
|
5716.7
|
|
|
|
7730.0
|
|
|
|
39230.9
|
|
|
|
14646.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CUM PROD
|
|
|
0.323
|
|
|
|
|
|
|
|
707.108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ULTIMATE
|
|
|
1443.290
|
|
|
|
|
|
|
|
22180.003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASED ON CONSTANT PRICES AND COSTS
PRESENT WORTH PROFILE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
8.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
16750.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
12.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
12998.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
15.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
11095.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
20.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
8866.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
25.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
7331.3
|
|
Table III
All estimates and exhibits
herein are part of this NSAI report and are subject to its
parameters and conditions.
A-12
Summary
projection of reserves and revenue
As of
12-31-6
|
|
Cog
Oil & Gas LP Interest
|
Summary
All Properties
|
Louisiana, New Mexico,
North Dakota, and Texas
Proved
Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Incl Prod+Adval Taxes
|
|
|
Prod+Av
|
|
|
Net Cap
|
|
|
Operating
|
|
|
Net
|
|
|
CUM P.W.
|
|
Period
|
|
Oil/cond
|
|
|
Oil/cond
|
|
|
Gas
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Taxes
|
|
|
Cost
|
|
|
Expense
|
|
|
Revenue
|
|
|
10.000%
|
|
Ending
|
|
MBBL
|
|
|
MBBL
|
|
|
MMCF
|
|
|
MMCF
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
|
|
12-31- 7
|
|
|
337.526
|
|
|
|
115.436
|
|
|
|
1254.805
|
|
|
|
346.018
|
|
|
|
6595.6
|
|
|
|
1702.1
|
|
|
|
8297.7
|
|
|
|
769.6
|
|
|
|
20116.3
|
|
|
|
272.9
|
|
|
|
−12861.1
|
|
|
|
−12698.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31- 8
|
|
|
763.975
|
|
|
|
238.728
|
|
|
|
4208.383
|
|
|
|
1048.204
|
|
|
|
13611.1
|
|
|
|
4992.5
|
|
|
|
18603.6
|
|
|
|
1724.0
|
|
|
|
34288.9
|
|
|
|
686.5
|
|
|
|
−18095.8
|
|
|
|
−28588.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31- 9
|
|
|
1100.696
|
|
|
|
377.005
|
|
|
|
6226.574
|
|
|
|
1399.110
|
|
|
|
21324.4
|
|
|
|
6691.9
|
|
|
|
28016.3
|
|
|
|
2574.2
|
|
|
|
11393.5
|
|
|
|
1189.7
|
|
|
|
12858.9
|
|
|
|
−18530.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-10
|
|
|
1010.404
|
|
|
|
347.386
|
|
|
|
5896.424
|
|
|
|
1193.718
|
|
|
|
19506.7
|
|
|
|
5654.5
|
|
|
|
25161.2
|
|
|
|
2272.8
|
|
|
|
2018.8
|
|
|
|
1362.0
|
|
|
|
19507.6
|
|
|
|
−4536.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-11
|
|
|
919.538
|
|
|
|
285.439
|
|
|
|
4640.775
|
|
|
|
924.529
|
|
|
|
16016.4
|
|
|
|
4366.5
|
|
|
|
20382.9
|
|
|
|
1829.6
|
|
|
|
532.4
|
|
|
|
1373.6
|
|
|
|
16647.3
|
|
|
|
6322.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-12
|
|
|
852.583
|
|
|
|
244.624
|
|
|
|
3778.028
|
|
|
|
747.083
|
|
|
|
13757.9
|
|
|
|
3585.4
|
|
|
|
17343.3
|
|
|
|
1564.6
|
|
|
|
1613.7
|
|
|
|
1402.6
|
|
|
|
12762.4
|
|
|
|
13873.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-13
|
|
|
808.690
|
|
|
|
218.540
|
|
|
|
3132.625
|
|
|
|
615.935
|
|
|
|
12315.4
|
|
|
|
2998.0
|
|
|
|
15313.4
|
|
|
|
1388.2
|
|
|
|
310.3
|
|
|
|
1412.7
|
|
|
|
12202.2
|
|
|
|
20453.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-14
|
|
|
738.219
|
|
|
|
189.539
|
|
|
|
2592.675
|
|
|
|
507.324
|
|
|
|
10665.6
|
|
|
|
2455.3
|
|
|
|
13120.9
|
|
|
|
1180.1
|
|
|
|
310.3
|
|
|
|
1400.0
|
|
|
|
10230.5
|
|
|
|
25466.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-15
|
|
|
683.468
|
|
|
|
167.712
|
|
|
|
2243.493
|
|
|
|
443.281
|
|
|
|
9424.0
|
|
|
|
2140.5
|
|
|
|
11564.5
|
|
|
|
1036.4
|
|
|
|
299.7
|
|
|
|
1406.4
|
|
|
|
8822.0
|
|
|
|
29395.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-16
|
|
|
645.796
|
|
|
|
150.685
|
|
|
|
1926.228
|
|
|
|
390.835
|
|
|
|
8455.3
|
|
|
|
1885.8
|
|
|
|
10341.1
|
|
|
|
925.9
|
|
|
|
314.1
|
|
|
|
1411.6
|
|
|
|
7689.5
|
|
|
|
32508.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-17
|
|
|
640.069
|
|
|
|
137.466
|
|
|
|
1700.667
|
|
|
|
348.741
|
|
|
|
7701.4
|
|
|
|
1681.5
|
|
|
|
9382.9
|
|
|
|
836.9
|
|
|
|
314.1
|
|
|
|
1410.2
|
|
|
|
6821.7
|
|
|
|
35018.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-18
|
|
|
637.842
|
|
|
|
125.831
|
|
|
|
1554.440
|
|
|
|
314.550
|
|
|
|
7036.7
|
|
|
|
1511.1
|
|
|
|
8547.8
|
|
|
|
758.6
|
|
|
|
299.7
|
|
|
|
1389.6
|
|
|
|
6099.9
|
|
|
|
37059.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-19
|
|
|
615.018
|
|
|
|
112.107
|
|
|
|
1417.194
|
|
|
|
283.630
|
|
|
|
6250.0
|
|
|
|
1355.6
|
|
|
|
7605.6
|
|
|
|
671.7
|
|
|
|
299.7
|
|
|
|
1344.5
|
|
|
|
5289.7
|
|
|
|
38667.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-20
|
|
|
589.716
|
|
|
|
102.616
|
|
|
|
1289.133
|
|
|
|
256.802
|
|
|
|
5710.9
|
|
|
|
1224.1
|
|
|
|
6935.0
|
|
|
|
610.2
|
|
|
|
188.3
|
|
|
|
1316.8
|
|
|
|
4819.7
|
|
|
|
39999.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-31-21
|
|
|
538.340
|
|
|
|
93.560
|
|
|
|
1142.771
|
|
|
|
228.715
|
|
|
|
5201.1
|
|
|
|
1086.0
|
|
|
|
6287.1
|
|
|
|
552.9
|
|
|
|
52.7
|
|
|
|
1300.1
|
|
|
|
4381.4
|
|
|
|
41102.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUBTOTAL
|
|
|
10881.880
|
|
|
|
2906.674
|
|
|
|
43004.215
|
|
|
|
9048.475
|
|
|
|
163572.5
|
|
|
|
43330.8
|
|
|
|
206903.3
|
|
|
|
18695.7
|
|
|
|
72352.5
|
|
|
|
18679.2
|
|
|
|
97175.9
|
|
|
|
41102.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REMAING
|
|
|
3485.669
|
|
|
|
703.593
|
|
|
|
9552.586
|
|
|
|
2279.900
|
|
|
|
39040.9
|
|
|
|
10198.0
|
|
|
|
49238.9
|
|
|
|
4370.1
|
|
|
|
0.0
|
|
|
|
16956.5
|
|
|
|
27912.3
|
|
|
|
45328.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL OF 53.7 YRS
|
|
|
14367.549
|
|
|
|
3610.267
|
|
|
|
52556.801
|
|
|
|
11328.375
|
|
|
|
202613.4
|
|
|
|
53528.8
|
|
|
|
256142.2
|
|
|
|
23065.8
|
|
|
|
72352.5
|
|
|
|
35635.7
|
|
|
|
125088.2
|
|
|
|
45328.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CUM PROD
|
|
|
0.000
|
|
|
|
|
|
|
|
0.000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ULTIMATE
|
|
|
14367.549
|
|
|
|
|
|
|
|
52556.801
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASED ON C0NSTANT PRICES AND COSTS
PRESENT WORTH PROFILE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
8.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
54770.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
12.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
37583.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
15.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
28333.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
20.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
17227.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOR
|
|
|
25.00
|
|
|
|
PCT,
|
|
|
|
PRESENT WORTH
|
|
|
M$
|
|
|
|
|
9580.0
|
|
Table IV
All estimates and exhibits
herein are part of this NSAI report and are subject to its
parameters and conditions.
A-13
January 25, 2007
Mr. E. Joseph
Wright
Vice President
Operations & Engineering
COG Operating, LLC
550 West Texas Avenue, Suite 1300
Midland, Texas 79701
|
|
|
|
Re:
|
Evaluation Summary SEC Pricing
COG Operating, LLC Interests
Eddy and Lea Counties, New Mexico
Proved Reserves
As of December 31, 2006
|
Dear Mr. Wright:
As requested, we are submitting our estimates of proved reserves
and our forecasts of the resulting economics attributable to the
above captioned interests.
Composite reserve estimates and economic forecasts are presented
in the attached tables and are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
Proved
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
Developed
|
|
|
Proved
|
|
|
|
|
|
|
Proved
|
|
|
Producing
|
|
|
Non-Producing
|
|
|
Undeveloped
|
|
|
Net Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil/Condensate
|
|
|
- Mbbl
|
|
|
|
33,109
|
|
|
|
14,006
|
|
|
|
1,834
|
|
|
|
17,269
|
|
Gas
|
|
|
- MMcf
|
|
|
|
155,770
|
|
|
|
73,135
|
|
|
|
5,568
|
|
|
|
77,067
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil/Condensate
|
|
|
- M$
|
|
|
|
1,844,603
|
|
|
|
782,051
|
|
|
|
102,820
|
|
|
|
959,732
|
|
Gas
|
|
|
- M$
|
|
|
|
865,667
|
|
|
|
414,331
|
|
|
|
30,355
|
|
|
|
420,981
|
|
Severance and Ad Valorem Taxes
|
|
|
- M$
|
|
|
|
274,752
|
|
|
|
121,818
|
|
|
|
13,322
|
|
|
|
139,612
|
|
Operating Expenses
|
|
|
- M$
|
|
|
|
417,513
|
|
|
|
261,077
|
|
|
|
13,530
|
|
|
|
142,906
|
|
Investments
|
|
|
- M$
|
|
|
|
431,690
|
|
|
|
0.0
|
|
|
|
19,407
|
|
|
|
412,283
|
|
Operating Income (BFIT)
|
|
|
- M$
|
|
|
|
1,586,316
|
|
|
|
813,487
|
|
|
|
86,916
|
|
|
|
685,913
|
|
Discounted @ 10%
|
|
|
- M$
|
|
|
|
720,299
|
|
|
|
445,258
|
|
|
|
37,406
|
|
|
|
237,634
|
|
In accordance with the Securities and Exchange Commission
guidelines, the operating income (BFIT) has been discounted at
an annual rate of 10% to determine its present
worth. The discounted value, present worth,
shown above should not be construed to represent an estimate of
the fair market value by Cawley, Gillespie &
Associates, Inc.
The detailed forecasts of reserves and economics are presented
in the attached tables. The report is divided into sections by
reserves category. The Tables I-Proved, I-PDP, I-PDNP and I-PUD
are composite summaries of the reserves and associated economics
by reserve category. These summary tables are followed by
corresponding Table IIs which present the ultimate
recovery, gross and net reserves, ownership, revenue, expenses,
investments, net income and discounted
B-1
Mr. E. Joseph Wright
COG Operating, LLC
January 25, 2007
Page 2
cash flows for the individual properties in each Table I. These
tables are sorted by reservoir, field and property name.
Page 1 of the Appendix explains the type of data in these
tables.
The year-end Henry Hub spot market gas price of $5.635 per MMBtu
and the year-end Plains WTI posted oil price of $57.75 per
barrel were used. In accordance with the Securities and Exchange
Commission guidelines, the oil and gas prices were held
constant. Prices were adjusted for gravity, heating value,
quality, transportation and marketing.
Operating costs were based on operating expense records of
Concho Resources. For non-operated properties, these costs
include the overhead expenses allowed under existing joint
operating agreements. For operated properties, these costs
include Conchos portion of its headquarters general and
administrative expenses necessary to operate the properties.
Drilling and completion costs were based on estimates provided
by Concho Resources and reviewed by Cawley,
Gillespie & Associates. As per the Securities and
Exchange Commission guidelines, neither expenses nor investments
were escalated. The cost of plugging and the salvage value of
equipment have not been considered.
The proved reserve classifications conform to criteria of the
Securities and Exchange Commission. The reserves and economics
are predicated on the regulatory agency classifications, rules,
policies, laws, taxes and royalties in effect on the effective
date except as noted herein. The possible effects of changes in
legislation or other Federal or State restrictive actions have
not been considered. All reserve estimates represent our best
judgment based on data available at the time of preparation and
assumptions as to future economic and regulatory conditions. It
should be realized that the reserves actually recovered, the
revenue derived therefrom and the actual cost incurred could be
more or less than the estimated amounts.
The reserve estimates were based on interpretations of factual
data furnished by Concho Resources. Ownership interests were
supplied by Concho Resources and were accepted as furnished. To
some extent, information from public records has been used to
check and/or supplement these data. The basic engineering and
geological data were utilized subject to third party
reservations and qualifications. Nothing has come to our
attention, however, that would cause us to believe that we are
not justified in relying on such data. An
on-site
inspection of these properties has not been made nor have the
wells been tested by Cawley, Gillespie & Associates,
Inc.
This report was prepared for the exclusive use of Concho
Resources. Third parties should not rely on it without the
written consent of the above and Cawley, Gillespie &
Associates, Inc. Our work-papers and related data are available
for inspection and review by authorized parties.
Respectfully submitted,
/s/ CAWLEY, GILLESPIE & ASSOCIATES, INC.
CAWLEY, GILLESPIE & ASSOCIATES, INC.
B-2
8,700,000 shares
Common stock
Joint book-running managers
|
|
JPMorgan |
Banc
of America Securities LLC |
Joint lead manager
Lehman Brothers
Co-managers
BNP PARIBAS
Merrill Lynch & Co.
UBS Investment Bank
,
2007
Part II
Information not required in prospectus
|
|
Item 13.
|
Other expenses
of issuance and distribution
|
The following table sets forth the costs and expenses to be paid
by us in connection with the sale of the shares of common stock
being registered hereby. All amounts are estimates except for
the SEC registration fee and the FINRA filing fee.
|
|
|
|
|
Securities and Exchange Commission registration fee
|
|
$
|
6,291
|
FINRA filing fee
|
|
|
20,980
|
Accounting fees and expenses
|
|
|
250,000
|
Legal fees and expenses
|
|
|
250,000
|
Printing and engraving expenses
|
|
|
350,000
|
Transfer agent and registrar fees and expenses
|
|
|
5,000
|
Other expenses
|
|
|
17,729
|
|
|
|
|
Total
|
|
$
|
900,000
|
|
|
|
|
Item 14.
|
Indemnification
of directors and officers
|
Section 145 of the Delaware General Corporation Law
(DGCL) provides that a corporation may indemnify any
person who was or is a party or is threatened to be made a party
to any threatened, pending or completed action, suit or
proceeding whether civil, criminal, administrative or
investigative (other than an action by or in the right of the
corporation) by reason of the fact that he is or was a director,
officer, employee or agent of the corporation, or is or was
serving at the request of the corporation as a director,
officer, employee or agent of another corporation, partnership,
joint venture, trust or other enterprise, against expenses
(including attorneys fees), judgments, fines and amounts
paid in settlement actually and reasonably incurred by him in
connection with such action, suit or proceeding if he acted in
good faith and in a manner he reasonably believed to be in or
not opposed to the best interests of the corporation, and, with
respect to any criminal action or proceeding, had no reasonable
cause to believe his conduct was unlawful. Section 145
further provides that a corporation similarly may indemnify any
such person serving in any such capacity who was or is a party
or is threatened to be made a party to any threatened, pending
or completed action or suit by or in the right of the
corporation to procure a judgment in its favor by reason of the
fact that he is or was a director, officer, employee or agent of
the corporation or is or was serving at the request of the
corporation as a director, officer, employee or agent of another
corporation, partnership, joint venture, trust or other
enterprise, against expenses (including attorneys fees)
actually and reasonably incurred in connection with the defense
or settlement of such action or suit if he acted in good faith
and in a manner he reasonably believed to be in or not opposed
to the best interests of the corporation and except that no
indemnification shall be made in respect of any claim, issue or
matter as to which such person shall have been adjudged to be
liable to the corporation unless and only to the extent that the
Delaware Court of Chancery or such other court in which such
action or suit was brought shall determine upon application
that, despite
II-1
the adjudication of liability but in view of all of the
circumstances of the case, such person is fairly and reasonably
entitled to indemnity for such expenses which the Delaware Court
of Chancery or such other court shall deem proper. Our
certificate of incorporation and bylaws provide that
indemnification shall be to the fullest extent permitted by the
DGCL for all our current or former directors or officers. As
permitted by the DGCL, our certificate of incorporation provides
that we will indemnify our directors against liability to us or
our stockholders for monetary damages for breach of fiduciary
duty as a director, except (1) for any breach of the
directors duty of loyalty to us or our stockholders,
(2) for acts or omissions not in good faith or which
involve intentional misconduct or knowing violation of law,
(3) under Section 174 of the DGCL or (4) for any
transaction from which a director derived an improper personal
benefit.
We have also entered into indemnification agreements with all of
our directors and all of our named executive officers and
employment agreements with all of our named executive officers.
These indemnification agreements and employment agreements are
intended to permit indemnification to the fullest extent now or
hereafter permitted by the DGCL. It is possible that the
applicable law could change the degree to which indemnification
is expressly permitted.
The indemnification agreements and the employment agreements
cover expenses (including attorneys fees), judgments,
fines and amounts paid in settlement incurred as a result of the
fact that such person, in his or her capacity as a director or
officer, is made or threatened to be made a party to any suit or
proceeding. The indemnification agreements and the employment
agreements generally cover claims relating to the fact that the
indemnified party is or was an officer, director, employee or
agent of us or any of our affiliates, or is or was serving at
our request in such a position for another entity. The
indemnification agreements and the employment agreements also
obligate us to promptly advance all reasonable expenses incurred
in connection with any claim. The indemnitee is, in turn,
obligated to reimburse us for all amounts so advanced if it is
later determined that the indemnitee is not entitled to
indemnification. The indemnification provided under the
indemnification agreements and the employment agreements is not
exclusive of any other indemnity rights; however, double payment
to the indemnitee is prohibited.
We are not obligated to indemnify the indemnitee with respect to
claims brought by the indemnitee against:
|
|
|
|
|
claims regarding the indemnitees rights under the
indemnification agreement;
|
|
|
|
claims to enforce a right to indemnification under any statute
or law; and
|
|
|
|
counter-claims against us in a proceeding brought by us against
the indemnitee; or
|
|
|
|
any other person, except for claims approved by our board of
directors.
|
We have obtained director and officer liability insurance for
the benefit of each of the above indemnitees. These policies
include coverage for losses for wrongful acts and omissions and
to ensure our performance under the indemnification agreements.
Each of the indemnitees are named as an insured under such
policies and provided with the same rights and benefits as are
accorded to the most favorably insured of our directors and
officers.
II-2
|
|
Item 15.
|
Recent sales
of unregistered securities
|
Since the formation of our company on February 22, 2006, we
have issued unregistered securities to a limited number of
persons, as described below. None of these transactions involved
any underwriters or public offerings, and we believe that each
of these transactions was exempt from registration requirements
pursuant to Section 4(2) of the Securities Act of 1933,
Regulation D promulgated thereunder or Rule 701 of the
Securities Act. The recipients of these securities represented
their intention to acquire the securities for investment only
and not with a view to or for sale in connection with any
distribution thereof, and appropriate legends were affixed to
the share certificates and instruments issued in these
transactions. No remuneration or commission was paid or given
directly or indirectly.
On February 24, 2006, we issued one share to our President
and Chief Operating Officer, in connection with the formation of
our company. This share of common stock was offered and sold
pursuant to the exemption from registration afforded by
Section 4(2) of the Securities Act of 1933.
On February 27, 2006, we issued 58,451,006 shares of
our common stock in connection with the combination transaction.
All of the shares of our common stock issued in connection with
the combination transaction were offered and sold pursuant to
the exemption from registration afforded by Section 4(2) of
the Securities Act of 1933 and Regulation D promulgated
thereunder. Pursuant to the combination transaction, certain
stockholders of Concho Equity Holdings Corp. exchanged their
equity interests in that company for shares of our common stock.
In addition, each of Chase Oil Corporation, Caza Energy LLC and
certain owners of oil and gas working interest affiliated with
Chase Oil Corporation contributed their interests in certain oil
and gas properties to our company in exchange for cash and our
common stock. All participants in the combination transaction
represented to us that they were accredited investors.
On May 18, 2006, we issued an additional
111,323 shares of our common stock in connection with the
combination transaction. Pursuant to the combination
transaction, certain owners of working interests affiliated with
Chase Oil Corporation in certain oil and gas properties
contributed their interests in certain oil and gas properties to
our company in exchange for cash
and/or
shares of our common stock. Pursuant to the terms of the
combination transaction, we were obligated to offer to purchase
the working interests of such persons as soon as possible after
the combination transaction. All of the persons offered and sold
these shares of common stock represented to us that they were
accredited investors.
On June 1, 2006, we issued 40,000 shares of our common
stock to members of our board of directors under a written
compensatory benefit plan. These shares of common stock were
offered and sold pursuant to the exemption from registration
afforded by Rule 701 under the Securities Act of 1933.
On June 28, 2006 through November 15, 2006, we issued,
in the aggregate, 173,584 shares of our common stock that
are subject to certain forfeiture restrictions to certain of our
employees under a written compensatory benefit plan. These
shares of common stock were offered and sold pursuant to the
exemption from registration afforded by Rule 701 under the
Securities Act of 1933.
On April 16, 2007, we merged our subsidiary, Concho
Acquisition, Inc., with and into its subsidiary, Concho Equity
Holdings Corp., to cause the conversion of the remaining shares
of common stock and preferred stock of Concho Equity Holdings
Corp. not held by Concho
II-3
Acquisition into shares of our common stock. The conversion
pursuant to the merger was on the same terms as the exchange of
the shares of common stock and preferred stock of Concho Equity
Holdings Corp. for shares of common stock of Concho Resources in
the combination transaction. As a result of the merger, we
issued 318,285 shares of our common stock to certain of our
employees who were stockholders of Concho Equity Holdings Corp.
prior to the merger.
On April 19, 2007, we issued, in the aggregate,
54,230 shares of our common stock to five persons in
connection with our acquisition of their working interests in
certain oil and gas properties. The working interests
represented interests in certain of the oil and gas properties
we acquired from Chase Oil Corporation and Caza Energy LLC in
connection with the combination transaction.
On April 23, 2007, we issued 20,000 shares of our
common stock to members of our board of directors under a
written compensatory benefit plan. These shares of common stock
were offered and sold pursuant to the exemption from
registration afforded by Rule 701 under the Securities Act
of 1933.
II-4
|
|
Item 16.
|
Exhibits and
financial statement schedules
|
(a) The following exhibits are filed herewith:
|
|
|
|
|
Number
|
|
Exhibit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
.1*
|
|
Form of Underwriting Agreement
|
|
2
|
.1
|
|
Combination Agreement dated February 24, 2006, among Concho
Resources Inc., Concho Equity Holdings Corp., Chase Oil
Corporation, Caza Energy LLC and the other signatories thereto
(incorporated herein by reference to Exhibit 2.1 filed with
the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
3
|
.1
|
|
Second Amended and Restated Certificate of Incorporation of
Concho Resources Inc. (incorporated herein by reference to
Exhibit 3.1 filed with the Current Report on
Form 8-K
filed by Concho Resources Inc. on August 8, 2007)
|
|
3
|
.2
|
|
Amended and Restated Bylaws of Concho Resources Inc.
(incorporated herein by reference to Exhibit 3.2 filed with
the Current Report on
Form 8-K
filed by Concho Resources Inc. on August 8, 2007)
|
|
4
|
.1
|
|
Specimen Common Stock Certificate (incorporated herein by
reference to Exhibit 4.1 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
5
|
.1*
|
|
Opinion of Vinson & Elkins L.L.P.
|
|
10
|
.1
|
|
Credit Agreement dated February 24, 2006, among Concho
Resources Inc., JPMorgan Chase Bank, N.A., as administrative
agent, Bank of America, N.A., as syndication agent, Wachovia
Bank, National Association, and BNP Paribas, as documentation
agents, and the other lenders party thereto (incorporated herein
by reference to Exhibit 10.1 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.2
|
|
Second Lien Credit Agreement dated March 27, 2007, among
Concho Resources Inc., Bank of America, N.A., as administrative
agent, and Banc of America LLC, as sole lead arranger and sole
booking manager (incorporated herein by reference to
Exhibit 10.2 filed with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.3
|
|
Transition Services Agreement dated April 23, 2007, between
COG Operating LLC and Mack Energy Corporation (incorporated
herein by reference to Exhibit 10.3 filed with the
Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.4
|
|
Form of Drilling Agreement with Silver Oak Drilling, LLC
(incorporated herein by reference to Exhibit 10.4 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.5
|
|
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
(incorporated herein by reference to Exhibit 10.5 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.6
|
|
Software License Agreement dated March 2, 2006, between
Enertia Software Systems and Concho Resources Inc. (incorporated
herein by reference to Exhibit 10.6 filed with the
Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
II-5
|
|
|
|
|
Number
|
|
Exhibit
|
|
|
|
10
|
.7
|
|
Leasehold Acquisition Agreement dated April 1, 2005, by and
between Trey Resources, Inc. and COG Oil and Gas LP
(incorporated herein by reference to Exhibit 10.7 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.8
|
|
Transfer of Operating Rights (Sublease) in a Lease for Oil and
Gas for Valhalla properties (incorporated herein by reference to
Exhibit 10.8 filed with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.9
|
|
Assignment of Oil and Gas Leases from Caza Energy LLC
(incorporated herein by reference to Exhibit 10.9 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.10
|
|
Escrow Agreement dated February 27, 2006, among Concho
Resources Inc., Timothy A. Leach, Steven L. Beal, David W.
Copeland, Curt F. Kamradt and E. Joseph Wright and the other
signatories thereto (incorporated herein by reference to
Exhibit 10.10 filed with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.11
|
|
Business Opportunities Agreement dated February 27, 2006,
among Concho Resources Inc. and the other signatories thereto
(incorporated herein by reference to Exhibit 10.11 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.12
|
|
Registration Rights Agreement dated February 27, 2006,
among Concho Resources Inc. and the other signatories thereto
(incorporated herein by reference to Exhibit 10.12 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.13
|
|
Concho Resources Inc. 2006 Stock Incentive Plan (incorporated
herein by reference to Exhibit 10.13 filed with the
Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.14
|
|
[Reserved]
|
|
10
|
.15
|
|
Form of Nonstatutory Stock Option Agreement (incorporated herein
by reference to Exhibit 10.15 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.16
|
|
Form of Restricted Stock Agreement (for employees) (incorporated
herein by reference to Exhibit 10.16 filed with the
Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.17
|
|
Form of Restricted Stock Agreement (for non-employee directors)
(incorporated herein by reference to Exhibit 10.17 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.18
|
|
Employment Agreement dated July 14, 2006, between Concho
Resources Inc. and Timothy A. Leach (incorporated herein by
reference to Exhibit 10.18 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.19
|
|
Employment Agreement dated July 14, 2006, between Concho
Resources Inc. and Steven L. Beal (incorporated herein by
reference to Exhibit 10.19 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.20
|
|
Employment Agreement dated July 14, 2006, between Concho
Resources Inc. and David W. Copeland (incorporated herein
by reference to Exhibit 10.20 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
II-6
|
|
|
|
|
Number
|
|
Exhibit
|
|
|
|
10
|
.21
|
|
Employment Agreement dated July 14, 2006, between Concho
Resources Inc. and Curt F. Kamradt (incorporated herein by
reference to Exhibit 10.21 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.22
|
|
Employment Agreement dated July 14, 2006, between Concho
Resources Inc. and David M. Thomas III (incorporated
herein by reference to Exhibit 10.22 filed with the
Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.23
|
|
Employment Agreement dated July 14, 2006, between Concho
Resources Inc. and E. Joseph Wright (incorporated herein by
reference to Exhibit 10.23 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.24
|
|
Form of Indemnification Agreement between Concho Resources Inc.
and each of the officers and directors thereof (incorporated
herein by reference to Exhibit 10.24 filed with the
Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.25#
|
|
Gas Purchase Contract between COG Oil & Gas LP and Duke
Energy Field Services, LP dated November 1, 2006
(incorporated herein by reference to Exhibit 10.25 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.26
|
|
Letter agreement between COG Operating LLC and Navajo Refining
Company, L.P. dated January 15, 2007 (incorporated herein
by reference to Exhibit 10.26 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.27
|
|
First Amendment to Credit Agreement, dated as of July 6,
2006, among Concho Resources Inc., certain of its subsidiaries,
JPMorgan Chase Bank, N.A. and the other leaders party thereto.
(incorporated herein by reference to Exhibit 10.27 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.28
|
|
Second Amendment to Credit agreement, dated as of March 7,
2007, among Concho Resources Inc., certain of its subsidiaries,
JPMorgan Chase Bank, N.A. and the other leaders party thereto.
(incorporated herein by reference to Exhibit 10.28 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.29
|
|
Form of option letter agreement among Concho Resources Inc.,
Concho Equity Holdings Corp. and each of Messrs. Leach and Beal
(incorporated herein by reference to Exhibit 10.29 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
II-7
|
|
|
|
|
Number
|
|
Exhibit
|
|
|
|
10
|
.30
|
|
Form of option letter agreement among Concho Resources Inc.,
Concho Equity Holdings Corp. and each of Messrs. Copeland,
Kamradt, Thomas and Wright (incorporated herein by reference to
Exhibit 10.30 filed with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.31
|
|
First Amendment to Employment Agreement, dated August 21, 2007,
by and between Concho Resources Inc. and Timothy A. Leach
(incorporated herein by reference to Exhibit 10.3 filed with the
Current Report on Form 8-K filed by Concho Resources Inc. on
August 24, 2007)
|
|
10
|
.32
|
|
First Amendment to Employment Agreement, dated August 21, 2007,
by and between Concho Resources Inc. and Steven L. Beal
(incorporated herein by reference to Exhibit 10.4 filed with the
Current Report on Form 8-K filed by Concho Resources Inc. on
August 24, 2007)
|
|
10
|
.33
|
|
First Amendment to Employment Agreement, dated August 21, 2007,
by and between Concho Resources Inc. and David W. Copeland
(incorporated herein by reference to Exhibit 10.5 filed with the
Current Report on Form 8-K filed by Concho Resources Inc. on
August 24, 2007)
|
|
10
|
.34
|
|
First Amendment to Employment Agreement, dated August 21, 2007,
by and between Concho Resources Inc. and Curt F. Kamradt
(incorporated herein by reference to Exhibit 10.6 filed with the
Current Report on Form 8-K filed by Concho Resources Inc. on
August 24, 2007)
|
|
10
|
.35
|
|
First Amendment to Employment Agreement, dated August 21, 2007,
by and between Concho Resources Inc. and E. Joseph Wright
(incorporated herein by reference to Exhibit 10.7 filed with the
Current Report on Form 8-K filed by Concho Resources Inc. on
August 24, 2007)
|
|
10
|
.36
|
|
First Amendment to Employment Agreement, dated August 31, 2007,
by and between Concho Resources Inc. and David M.
Thomas III (incorporated herein by reference to Exhibit
10.9 filed with the Quarterly Report on Form 10-Q filed by
Concho Resources Inc. on September 10, 2007)
|
|
10
|
.37
|
|
Form of Amendment to Stock Option Award Agreement with executive
officers related to the Pre-Combination Options (incorporated
herein by reference to Exhibit 10.1 filed with the Current
Report on Form
8-K filed by
Concho Resources Inc. on November 20, 2007)
|
|
10
|
.38
|
|
Form of Amendment to Nonstatutory Stock Option Agreement with
executive officers related to the June 2006 Options
(incorporated herein by reference to Exhibit 10.2 filed with the
Current Report on Form
8-K filed by
Concho Resources Inc. on November 20, 2007)
|
|
10
|
.39
|
|
Form of Restricted Stock Agreement (incorporated herein by
reference to Exhibit 10.3 filed with the Current Report on Form
8-K filed by Concho Resources Inc. on November 20, 2007)
|
|
21
|
.1
|
|
Subsidiaries of Concho Resources Inc. (incorporated herein by
reference to Exhibit 21.1 filed with the Registration
Statement on
Form S-1
(Registration No.
333-142315)
filed by Concho Resources Inc.)
|
|
23
|
.1**
|
|
Consent of Grant Thornton LLP Tulsa
|
|
23
|
.2**
|
|
Consent of Grant Thornton LLP Kansas City
|
|
23
|
.3**
|
|
Consent of Grant Thornton LLP Dallas
|
II-8
|
|
|
|
|
Number
|
|
Exhibit
|
|
|
|
23
|
.4**
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
23
|
.5**
|
|
Consent of Cawley, Gillespie & Associates, Inc.
|
|
23
|
.6*
|
|
Consent of Vinson & Elkins L.L.P. (included as part of
Exhibit 5.1)
|
|
24
|
.1*
|
|
Power of Attorney
|
|
|
|
|
|
The Combination Agreement filed as
Exhibit 2.1 omits certain of the schedules and exhibits to
the Combination Agreement in accordance with Item 601
(b)(2) of Regulation S-K. A list briefly identifying the
contents of all omitted schedules and exhibits is included with
the Combination Agreement filed as Exhibit 2.1. Concho
Resources agrees to furnish supplementally a copy of any omitted
schedule or exhibit to the Securities and Exchange Commission
upon request.
|
|
#
|
|
Confidential treatment of certain
provisions of this exhibit has previously been granted by the
Securities and Exchange Commission. Omitted material for which
confidential treatment has been granted has been filed
separately with the Securities and Exchange Commission.
|
The undersigned registrant hereby undertakes:
(a) Insofar as indemnification for liabilities arising
under the Securities Act of 1933 may be permitted to directors,
officers and controlling persons of the registrant pursuant to
the provisions described in Item 14, or otherwise, the
registrant has been advised that in the opinion of the SEC such
indemnification is against public policy as expressed in the
Securities Act of 1933 and is, therefore, unenforceable. In the
event that a claim for indemnification against such liabilities
(other than the payment by the registrant of expenses incurred
or paid by a director, officer or controlling person of the
registrant in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling
person in connection with the securities being registered, the
registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of
appropriate jurisdiction the question whether such
indemnification by it is against public policy as expressed in
the Securities Act of 1933 and will be governed by the final
adjudication of such issue.
(b) To provide to the underwriters at the closing specified
in the underwriting agreement, certificates in such
denominations and registered in such names as required by the
underwriters to permit prompt delivery to each purchaser.
(c) For purpose of determining any liability under the
Securities Act of 1933, the information omitted from the form of
prospectus filed as part of this registration statement in
reliance upon Rule 430A and contained in the form of
prospectus filed by the registrant pursuant to
Rule 424(b)(1) or (4) or 497(h) under the Securities
Act of 1933 shall be deemed to be part of this registration
statement as of the time it was declared effective.
(d) For the purpose of determining any liability under the
Securities Act of 1933, each post-effective amendment that
contains a form of prospectus shall be deemed to be a new
registration statement relating to the securities offered
therein, and the offering of such securities at that time shall
be deemed to be the initial bona fide offering thereof.
II-9
Signatures
Pursuant to the requirements of the Securities Act of 1933, the
Registrant has duly caused this Registration Statement on
Form S-1
to be signed on its behalf by the undersigned, thereunto duly
authorized, in Midland, Texas, on this 6th day of December,
2007
CONCHO RESOURCES INC.
Name: Timothy A. Leach
|
|
|
|
Title:
|
Chairman and Chief Executive Officer
|
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement on
Form S-1
has been signed by the following persons in the capacities and
on the dates indicated.
|
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
/s/ Timothy
A. Leach
Timothy
A. Leach
|
|
Chairman, Chief Executive Officer and Director
(principal executive officer)
|
|
December 6, 2007
|
|
|
|
|
|
/s/ Steven
L. Beal
Steven
L. Beal
|
|
President, Chief Operating Officer and Director
|
|
December 6, 2007
|
|
|
|
|
|
/s/ Curt
F. Kamradt
Curt
F. Kamradt
|
|
Vice President, Chief Financial Officer and Treasurer
(principal financial and accounting officer)
|
|
December 6, 2007
|
|
|
|
|
|
*
Tucker
S. Bridwell
|
|
Director
|
|
December 6, 2007
|
|
|
|
|
|
*
W.
Howard Keenan, Jr.
|
|
Director
|
|
December 6, 2007
|
|
|
|
|
|
*
Ray
M. Poage
|
|
Director
|
|
December 6, 2007
|
|
|
|
|
|
*
A.
Wellford Tabor
|
|
Director
|
|
December 6, 2007
|
|
|
|
|
|
|
|
*By:
|
|
/s/ Timothy
A. Leach
Attorney-in-fact
|
|
|
|
|
II-10
Exhibit index
|
|
|
|
|
Number
|
|
Exhibit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
.1*
|
|
Form of Underwriting Agreement
|
|
2
|
.1
|
|
Combination Agreement dated February 24, 2006, among Concho
Resources Inc., Concho Equity Holdings Corp., Chase Oil
Corporation, Caza Energy LLC and the other signatories thereto
(incorporated herein by reference to Exhibit 2.1 filed with
the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
3
|
.1
|
|
Second Amended and Restated Certificate of Incorporation of
Concho Resources Inc. (incorporated herein by reference to
Exhibit 3.1 filed with the Current Report on
Form 8-K
filed by Concho Resources Inc. on August 8, 2007)
|
|
3
|
.2
|
|
Amended and Restated Bylaws of Concho Resources Inc.
(incorporated herein by reference to Exhibit 3.2 filed with
the Current Report on
Form 8-K
filed by Concho Resources Inc. on August 8, 2007)
|
|
4
|
.1
|
|
Specimen Common Stock Certificate (incorporated herein by
reference to Exhibit 4.1 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
5
|
.1*
|
|
Opinion of Vinson & Elkins L.L.P.
|
|
10
|
.1
|
|
Credit Agreement dated February 24, 2006, among Concho
Resources Inc., JPMorgan Chase Bank, N.A., as administrative
agent, Bank of America, N.A., as syndication agent, Wachovia
Bank, National Association, and BNP Paribas, as documentation
agents, and the other lenders party thereto (incorporated herein
by reference to Exhibit 10.1 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.2
|
|
Second Lien Credit Agreement dated March 27, 2007, among
Concho Resources Inc., Bank of America, N.A., as administrative
agent, and Banc of America LLC, as sole lead arranger and sole
booking manager (incorporated herein by reference to
Exhibit 10.2 filed with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.3
|
|
Transition Services Agreement dated April 23, 2007, between
COG Operating LLC and Mack Energy Corporation (incorporated
herein by reference to Exhibit 10.3 filed with the
Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.4
|
|
Form of Drilling Agreement with Silver Oak Drilling, LLC
(incorporated herein by reference to Exhibit 10.4 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.5
|
|
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
(incorporated herein by reference to Exhibit 10.5 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.6
|
|
Software License Agreement dated March 2, 2006, between
Enertia Software Systems and Concho Resources Inc. (incorporated
herein by reference to Exhibit 10.6 filed with the
Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
|
|
|
|
Number
|
|
Exhibit
|
|
|
|
10
|
.7
|
|
Leasehold Acquisition Agreement dated April 1, 2005, by and
between Trey Resources, Inc. and COG Oil and Gas LP
(incorporated herein by reference to Exhibit 10.7 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.8
|
|
Transfer of Operating Rights (Sublease) in a Lease for Oil and
Gas for Valhalla properties (incorporated herein by reference to
Exhibit 10.8 filed with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.9
|
|
Assignment of Oil and Gas Leases from Caza Energy LLC
(incorporated herein by reference to Exhibit 10.9 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.10
|
|
Escrow Agreement dated February 27, 2006, among Concho
Resources Inc., Timothy A. Leach, Steven L. Beal, David W.
Copeland, Curt F. Kamradt and E. Joseph Wright and the other
signatories thereto (incorporated herein by reference to
Exhibit 10.10 filed with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.11
|
|
Business Opportunities Agreement dated February 27, 2006,
among Concho Resources Inc. and the other signatories thereto
(incorporated herein by reference to Exhibit 10.11 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.12
|
|
Registration Rights Agreement dated February 27, 2006,
among Concho Resources Inc. and the other signatories thereto
(incorporated herein by reference to Exhibit 10.12 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.13
|
|
Concho Resources Inc. 2006 Stock Incentive Plan (incorporated
herein by reference to Exhibit 10.13 filed with the
Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.14
|
|
[Reserved]
|
|
10
|
.15
|
|
Form of Nonstatutory Stock Option Agreement (incorporated herein
by reference to Exhibit 10.15 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.16
|
|
Form of Restricted Stock Agreement (for employees) (incorporated
herein by reference to Exhibit 10.16 filed with the
Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.17
|
|
Form of Restricted Stock Agreement (for non-employee directors)
(incorporated herein by reference to Exhibit 10.17 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
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|
10
|
.18
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|
Employment Agreement dated July 14, 2006, between Concho
Resources Inc. and Timothy A. Leach (incorporated herein by
reference to Exhibit 10.18 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.19
|
|
Employment Agreement dated July 14, 2006, between Concho
Resources Inc. and Steven L. Beal (incorporated herein by
reference to Exhibit 10.19 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.20
|
|
Employment Agreement dated July 14, 2006, between Concho
Resources Inc. and David W. Copeland (incorporated herein
by reference to Exhibit 10.20 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
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|
|
|
|
|
Number
|
|
Exhibit
|
|
|
|
10
|
.21
|
|
Employment Agreement dated July 14, 2006, between Concho
Resources Inc. and Curt F. Kamradt (incorporated herein by
reference to Exhibit 10.21 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.22
|
|
Employment Agreement dated July 14, 2006, between Concho
Resources Inc. and David M. Thomas III (incorporated
herein by reference to Exhibit 10.22 filed with the
Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.23
|
|
Employment Agreement dated July 14, 2006, between Concho
Resources Inc. and E. Joseph Wright (incorporated herein by
reference to Exhibit 10.23 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.24
|
|
Form of Indemnification Agreement between Concho Resources Inc.
and each of the officers and directors thereof (incorporated
herein by reference to Exhibit 10.24 filed with the
Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.25#
|
|
Gas Purchase Contract between COG Oil & Gas LP and
Duke Energy Field Services, LP dated November 1, 2006
(incorporated herein by reference to Exhibit 10.25 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.26
|
|
Letter agreement between COG Operating LLC and Navajo Refining
Company, L.P. dated January 15, 2007 (incorporated herein
by reference to Exhibit 10.26 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.27
|
|
First Amendment to Credit Agreement, dated as of July 6,
2006, among Concho Resources Inc., certain of its subsidiaries,
JPMorgan Chase Bank, N.A. and the other leaders party thereto.
(incorporated herein by reference to Exhibit 10.27 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.28
|
|
Second Amendment to Credit agreement, dated as of March 7,
2007, among Concho Resources Inc., certain of its subsidiaries,
JPMorgan Chase Bank, N.A. and the other leaders party thereto.
(incorporated herein by reference to Exhibit 10.28 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.29
|
|
Form of option letter agreement among Concho Resources Inc.,
Concho Equity Holdings Corp. and each of Messrs. Leach and Beal
(incorporated herein by reference to Exhibit 10.29 filed
with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
10
|
.30
|
|
Form of option letter agreement among Concho Resources Inc.,
Concho Equity Holdings Corp. and each of Messrs. Copeland,
Kamradt, Thomas and Wright (incorporated herein by reference to
Exhibit 10.30 filed with the Registration Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
|
|
|
|
Number
|
|
Exhibit
|
|
|
|
10
|
.31
|
|
First Amendment to Employment Agreement, dated August 21, 2007,
by and between Concho Resources Inc. and Timothy A. Leach
(incorporated herein by reference to Exhibit 10.3 filed with the
Current Report on Form 8-K filed by Concho Resources Inc. on
August 24, 2007)
|
|
10
|
.32
|
|
First Amendment to Employment Agreement, dated August 21, 2007,
by and between Concho Resources Inc. and Steven L. Beal
(incorporated herein by reference to Exhibit 10.4 filed with the
Current Report on Form 8-K filed by Concho Resources Inc. on
August 24, 2007)
|
|
10
|
.33
|
|
First Amendment to Employment Agreement, dated August 21, 2007,
by and between Concho Resources Inc. and David W. Copeland
(incorporated herein by reference to Exhibit 10.5 filed with the
Current Report on Form 8-K filed by Concho Resources Inc. on
August 24, 2007)
|
|
10
|
.34
|
|
First Amendment to Employment Agreement, dated August 21, 2007,
by and between Concho Resources Inc. and Curt F. Kamradt
(incorporated herein by reference to Exhibit 10.6 filed with the
Current Report on Form 8-K filed by Concho Resources Inc. on
August 24, 2007)
|
|
10
|
.35
|
|
First Amendment to Employment Agreement, dated August 21, 2007,
by and between Concho Resources Inc. and E. Joseph Wright
(incorporated herein by reference to Exhibit 10.7 filed with the
Current Report on Form 8-K filed by Concho Resources Inc. on
August 24, 2007)
|
|
10
|
.36
|
|
First Amendment to Employment Agreement, dated August 31, 2007,
by and between Concho Resources Inc. and David M.
Thomas III (incorporated herein by reference to Exhibit
10.9 filed with the Quarterly Report on Form 10-Q filed by
Concho Resources Inc. on September 10, 2007)
|
|
10
|
.37
|
|
Form of Amendment to Stock Option Award Agreement with executive
officers related to the Pre-Combination Options (incorporated
herein by reference to Exhibit 10.1 filed with the Current
Report on
Form 8-K
filed by Concho Resources Inc. on November 20, 2007)
|
|
10
|
.38
|
|
Form of Amendment to Nonstatutory Stock Option Agreement with
executive officers related to the June 2006 Options
(incorporated herein by reference to Exhibit 10.2 filed
with the Current Report on
Form 8-K
filed by Concho Resources Inc. on November 20, 2007)
|
|
10
|
.39
|
|
Form of Restricted Stock Agreement (incorporated herein by
reference to Exhibit 10.3 filed with the Current Report on
Form 8-K
filed by Concho Resources Inc. on November 20, 2007)
|
|
21
|
.1
|
|
Subsidiaries of Concho Resources Inc. (incorporated herein by
reference to Exhibit 21.1 filed with the Registration
Statement on
Form S-1
(Registration
No. 333-142315)
filed by Concho Resources Inc.)
|
|
23
|
.1**
|
|
Consent of Grant Thornton LLP Tulsa
|
|
23
|
.2**
|
|
Consent of Grant Thornton LLP Kansas City
|
|
23
|
.3**
|
|
Consent of Grant Thornton LLP Dallas
|
|
23
|
.4**
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
23
|
.5**
|
|
Consent of Cawley, Gillespie & Associates, Inc.
|
|
23
|
.6*
|
|
Consent of Vinson & Elkins L.L.P. (included as part of
Exhibit 5.1)
|
|
24
|
.1*
|
|
Power of Attorney
|
|
|
|
|
|
The Combination Agreement filed as
Exhibit 2.1 omits certain of the schedules and exhibits to
the Combination Agreement in accordance with Item 601(b)(2)
of
Regulation S-K.
A list briefly identifying the contents of all omitted schedules
and exhibits is included with the Combination Agreement filed as
Exhibit 2.1. Concho Resources agrees to furnish
supplementally a copy of any omitted schedule or exhibit to the
Securities and Exchange Commission upon request.
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|
#
|
|
Confidential treatment of certain
provisions of this exhibit has previously been granted by the
Securities and Exchange Commission. Omitted material for which
confidential treatment has been granted has been filed
separately with the Securities and Exchange Commission.
|