e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark One)
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2007
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission File Number: 1-33784
SANDRIDGE ENERGY,
INC.
(Exact name of registrant as
specified in its charter)
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Delaware
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20-8084793
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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1601 N.W. Expressway, Suite 1600, Oklahoma
City, Oklahoma
(Address of principal
executive offices)
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73118
(Zip Code)
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(405) 753-5500
(Registrants telephone
number, including area code)
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock, $0.001 par value
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act (Check one):
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Large accelerated filer
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Accelerated filer
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Non-accelerated
filer þ
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Smaller reporting
company o
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(Do not check if a smaller reporting
company)
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Indicate by check mark whether the registrant is a shell company
(as defined in Exchange Act
Rule 12b-2). Yes o No þ
The initial public offering of SandRidge Energy, Inc.s
common stock, par value of $0.001, commenced trading on
November 6, 2007. Prior to that date, there was no public
market for the registrants common stock. At
February 28, 2008 there were 142,718,362 shares of our
common stock outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Portions of the proxy statement for the 2008 Annual Meeting of
Shareholders are incorporated by reference in Part III.
SANDRIDGE
ENERGY, INC.
2007
ANNUAL REPORT ON
FORM 10-K
TABLE OF
CONTENTS
2
PART I
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Items 1
and 2.
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Business
and Properties
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General
SandRidge Energy, Inc. is an independent natural gas and oil
company headquartered in Oklahoma City, Oklahoma with our
principal focus on exploration, development and production
activities. We also own and operate drilling rigs and a related
oil field services company operating under the name Lariat
Services, Inc.; gas gathering, marketing and processing
facilities; and, through our wholly-owned subsidiary PetroSource
Energy Company,
CO2
treating and transportation facilities and tertiary oil recovery
operations. We were originally organized in the State of Texas
in 1984 under a predecessor company name and in 2006, we
reorganized as a Delaware corporation and adopted the SandRidge
Energy, Inc. name.
We are focused on expanding the continuing exploration and
exploitation of our significant holdings in an area of West
Texas that we refer to as the West Texas Overthrust, or
WTO, a natural gas prone geological region where we
have operated since 1986. The WTO includes the Piñon Field,
the South Sabino prospect, the Big Canyon prospect and other
prospects that we are currently evaluating. We intend to add to
our existing reserve and production base in this area by
increasing our development drilling activities in the Piñon
Field and our exploration program in other prospects that we
have identified. We believe that we are the largest operator and
producer in the WTO and have assembled the largest acreage
position in the area. We also operate significant interests in
the Cotton Valley Trend in East Texas, the Gulf Coast area, the
Gulf of Mexico, Oklahoma and the Piceance Basin of Colorado.
We have assembled an extensive natural gas and oil property base
in which we have identified approximately 4,600 potential
drilling locations, including approximately 2,600 in the WTO. As
of December 31, 2007, our proved reserves were
1,516.2 Bcfe, of which 86% were natural gas. We had
1,654 gross (1,234 net) producing wells, substantially all
of which we operate. As of December 31, 2007, we had
interests in approximately 1,303,107 gross (822,287 net)
natural gas and oil leased acres. We had 30 rigs drilling in the
WTO, six rigs drilling in East Texas, two rigs drilling in
Oklahoma, and two rigs drilling in other areas as of
December 31, 2007.
We also operate businesses that are complementary to our primary
exploration, development and production activities, which
provides us with operational flexibility and an advantageous
cost structure. We own a fleet of 32 drilling rigs, three of
which are currently being retrofitted. In addition, we are a 50%
partner in a limited partnership that owns an additional twelve
rigs, eleven of which are currently operational. We own related
oil field services businesses, gas gathering and treating
facilities and a marketing business. We also capture and supply
CO2
to support our tertiary oil recovery projects undertaken by us
or third parties. These assets are primarily located in our
primary operating area in West Texas.
In November 2007, we completed the initial public offering of
our common stock and received net proceeds of
$794.7 million. We used the proceeds to repay indebtedness
outstanding under our senior credit facility, repay a note
related to a recent acquisition and fund a portion of our 2007
and 2008 capital expenditure programs.
Our capital expenditures and acquisitions for 2007 of
approximately $1,397.4 million included
$1,150.6 million for exploration and development (including
land and seismic acquisitions and our tertiary recovery
operations), $123.2 million for drilling and oil field
services, $73.8 million for our midstream operations and
$49.8 million for other capital expenditures. Approximately
$871.2 million of our 2007 capital expenditures was spent
on our Piñon Field development and our exploratory projects
in the WTO (including land and seismic acquisitions). We drilled
approximately 316 gross (274.7 net) wells in 2007,
including approximately 190 gross (177.8 net) wells in the
WTO.
On November 21, 2006, we acquired all of the outstanding
membership interests in NEG Oil & Gas LLC
(NEG) for total consideration of approximately
$1.5 billion, excluding cash acquired. With core assets in
the Val Verde and Permian Basins of West Texas, including
overlapping or contiguous interests in the WTO, the NEG
acquisition dramatically increased our exploration and
production segment operations. The NEG acquisition, coupled with
numerous acquisitions of additional working interests completed
during 2007, 2006 and late 2005, have significantly increased
our holdings in the WTO.
Our principal executive offices are located at 1601 N.W.
Expressway, Suite 1600, Oklahoma City, Oklahoma 73118 and
our telephone number is
(405) 753-5500.
We make available free of charge on our website at
www.sandridgeenergy.com our annual reports on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K,
and amendments to those reports as soon as reasonably
practicable after we electronically file such material with, or
furnish it to, the Securities and Exchange Commission. Any
materials that we have filed with the SEC may be read and copied
at the SECs Public Reference Room at
100 F Street, N.E., Room 1580,
Washington, D.C. 20549. You may obtain information on the
operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330.
The SEC maintains an internet site that contains reports, proxy
and information statements, and other information regarding us.
The SECs website address is www.sec.gov.
3
References to SandRidge, us,
we, Company and our in this
report refer to SandRidge Energy, Inc. together with its
subsidiaries. PetroSource refers to our wholly-owned
subsidiary, PetroSource Energy Company and Lariat
refers to our wholly-owned subsidiary, Lariat Services, Inc.
Our
Strategy
Our primary objective is to achieve long-term growth and
maximize stockholder value over multiple business cycles by
pursuing the following strategies:
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Grow Through Exploration and Drilling and Development of
Existing Acreage. We expect to generate long-term
reserve and production growth by exploring and drilling and
developing our large acreage position. Our primary exploration
and development focus will be in the WTO, where we have
identified approximately 2,600 potential drilling locations and
had 30 rigs operating as of December 31, 2007.
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Apply Technological Improvements to Our Exploration and
Development Program. We intend to enhance our
drilling success rate and completion efficiency with improved
3-D seismic
acquisition and interpretation technologies, together with
advanced drilling, completion and production methods that
historically have not been widely used in the under-explored WTO.
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Seek Opportunistic Acquisitions in Our Core Geographic
Area. Since January 2006, through acquisitions
and leasing activities, we have tripled our net acreage position
in the WTO. We intend to continue to seek other opportunities to
optimize and enhance our exploratory acreage position in the WTO
and other strategic areas.
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Reduce Costs, Enhance Returns and Maintain Operating
Flexibility by Controlling Drilling Rigs and Midstream
Assets. Our rig fleet enables us to effectively
develop our own acreage while maintaining the flexibility of a
third-party contract drilling business. By controlling our fleet
of drilling rigs and gathering and treating assets, we believe
we will be able to better control overall costs and maintain a
high degree of operational flexibility.
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Capture and Utilize
CO2
for Tertiary Oil Recovery. We intend to
capitalize on our access to
CO2
reserves and
CO2
flooding expertise to pursue enhanced oil recovery in mature oil
fields in West Texas. By utilizing this
CO2
in our own tertiary recovery projects, we expect to recover
additional oil that would have otherwise been abandoned
following traditional waterfloods.
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Competitive
Strengths
We have a number of strengths that we believe will help us
successfully execute our strategies:
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Large Asset Base with Substantial Drilling
Inventory. Our producing properties are
characterized by long-lived predominantly natural gas reserves
with established production profiles. Our estimated proved
reserves of 1,516.2 Bcfe as of December 31, 2007 had a
proved reserves to production ratio of approximately
17.7 years. Our core area of operations in the WTO has
expanded to 600,546 gross (508,745 net) acres as of
December 31, 2007. We have identified approximately 2,600
potential drilling locations in the WTO and believe that we will
be able to expand the number of drilling locations in the
remainder of the WTO through exploratory drilling and our use of
3-D seismic
technology.
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Geographically Concentrated Exploration and Development
Operations. We intend to focus our drilling and
development operations in the near term on the WTO to fully
exploit this unique geological area. The WTO was created by the
collision of the ancestral North and South American continents,
which fractured and thrust the reservoir rock to come to rest in
repeating layers. We believe the geological environment of the
WTO and the height of the prospective pay zones create
opportunities for significant conventional accumulations of
natural gas and oil. To a lesser extent, we will also focus on
the highly prolific Cotton Valley Trend in East Texas. This
geographic concentration allows us to establish economies of
scale in both drilling and production operations to achieve
lower production costs and generate increased cash flows from
our producing properties. We believe our concentrated acreage
position will enable us to organically grow our reserves and
production for the next several years.
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Experienced Management Team Focused on Delivering Long-term
Stockholder Value. During 2006, we significantly
expanded our management team when Tom L. Ward, co-founder and
former president of Chesapeake Energy Corporation, purchased a
significant interest in us and became our Chairman and Chief
Executive Officer. Mr. Ward leads an experienced management
team of 11 executive officers and 38 senior executives. Our
management team averages over 24 years of experience
working in or servicing the natural gas and oil industry. Our
management team, board of directors and employees owned 37.2% of
our capital stock as of December 31, 2007, which we believe
aligns their objectives with those of our stockholders.
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High Degree of Operational Control. We operate
over 99.2% of our production in the WTO, East Texas and the Gulf
Coast area, which permits us to manage our operating costs and
better control capital expenditures and the timing of
development and exploitation activities.
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Large Modern Fleet of Drilling Rigs. We own a
fleet of 32 drilling rigs, three of which are currently being
retrofitted. In addition, we are a 50% partner in a limited
partnership that owns an additional twelve rigs, eleven of which
are operational. By controlling a large, modern and efficient
drilling fleet, we can develop our existing reserves and explore
for new reserves on a more economical basis.
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Our
Businesses and Primary Operations
Exploration
and Production
We explore for, develop and produce natural gas and oil
reserves, with a focus on increasing our reserves and production
in the WTO. We operate substantially all of our wells in the
WTO. We also have significant operated leasehold positions in
the Cotton Valley Trend in East Texas and the Gulf Coast area,
as well as other non-core operating areas.
The following table identifies certain information concerning
our exploration and production business as of December 31,
2007 unless otherwise noted:
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Estimated Net
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Proved
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Number of
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Proved
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Daily
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Reserves/
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Identified
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Reserves
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PV-10 (in
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Production
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Production
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Gross
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Net
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Potential Drilling
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(Bcfe)
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millions)(1)
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(Mmcfe/d)(2)
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(Years)
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Acreage
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Acreage
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Locations
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Area
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WTO
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922.2
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1,785.5
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115.7
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21.8
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600,546
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508,745
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2,594
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East Texas
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202.5
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331.1
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32.7
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17.0
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53,388
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32,739
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540
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Gulf Coast
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97.8
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388.3
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42.5
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6.3
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50,768
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33,317
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42
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Other:
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Gulf of Mexico
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60.1
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240.3
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18.3
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9.0
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73,614
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36,770
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66
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Other West Texas
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38.0
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192.6
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12.1
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8.6
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31,847
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22,941
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77
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Tertiary recovery- West Texas (PetroSource)
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119.7
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468.3
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0.8
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410.0
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9,064
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8,195
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67
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Piceance Basin
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9.0
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8.9
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0.6
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41.0
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40,334
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15,686
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828
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Other, including Oklahoma
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66.9
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135.5
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11.8
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15.5
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443,546
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163,894
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380
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Total
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1,516.2
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3,550.5
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234.5
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17.7
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1,303,107
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822,287
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4,594
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(1) |
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PV-10
generally differs from Standardized Measure of Discounted Net
Cash Flows, or Standardized Measure, which is measured only at
fiscal year end, because it does not include the effects of
income taxes on future net revenues. For a reconciliation of
PV-10 to
Standardized Measure as of December 31, 2007,
see Proved Reserves. Our Standardized
Measure was $2,718.5 million at December 31, 2007. |
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(2) |
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Average daily net production for the month of December 2007 was
235 Mmcfe/d. |
West
Texas Overthrust (WTO)
We have drilled and developed natural gas in the WTO since 1986.
This area is located in Pecos and Terrell Counties in West Texas
and is associated with the Marathon-Ouachita fold and thrust
belt that extends east-northeast across the United States into
the Appalachian Mountain Region. The WTO was created by the
collision of the ancestral North American and South American
continents resulting in source rock and reservoir rock,
including potential hydrocarbon traps, becoming thrusted upon
one another in multiple layers (imbricate stacking) along the
leading edge of the WTO. The collision and thrusting resulted in
the reservoir rock becoming highly fractured, increasing the
likelihood of conventional natural gas and oil accumulations in
the reservoir rock and creating a unique geological setting in
North America.
The primary reservoir rocks in the WTO range in depth from 2,000
to 11,000 feet and range in geologic age from the Permian
to the Devonian. The imbricate stacking of these conventional
gas-prone reservoirs provides for multi-pay exploration and
development opportunities. Despite this, the WTO has
historically been largely under-explored due primarily to the
remoteness and lack of infrastructure in the region, as well as
historical limitations of conventional subsurface geological and
geophysical methods. However, several fields including our
prolific Piñon Field have been discovered. We believe our
access to and control of the necessary
5
infrastructure combined with application of modern seismic
techniques will allow us to identify further exploration and
development opportunities in the WTO.
In May 2007, we began a three-year, multi-phase seismic program
to acquire 1,400 square miles of modern
3-D seismic
data in the WTO. We believe this enhanced
3-D seismic
program may identify structural details of potential reservoirs,
thus lowering exploratory drilling risk and improving completion
efficiency. The first two phases of the seismic program covered
389 square miles and were completed during 2007.
We have acquired leasehold acreage in the WTO, tripling our
position since January 2006. As of December 31, 2007 we
owned 600,546 gross (508,745 net) acres in the WTO,
substantially all of which are along the leading edge of the WTO.
Piñon Field. The Piñon Field,
located in Pecos County, is our most significant producing
field, and accounts for 61% of our proved reserve base as of
December 31, 2007 and approximately 76% of our 2007
exploration and development expenditures (including land and
seismic acquisitions). The Piñon Field lies along the
leading edge of the WTO. The primary reservoirs are the Wolfcamp
sands (average depth of 2,500 to 3,500 feet), the Tesnus
sands (average depth of 3,700 to 4,750 feet), the Upper
Caballos chert (average depth of 5,500 feet), and the Lower
Caballos chert (average depth of 7,300 to 10,000 feet).
As of December 31, 2007, our estimated proved natural gas
and oil reserves in the Piñon Field were 922.2 Bcfe,
55% of which were proved undeveloped reserves. This field has
produced more than 266.2 Bcfe through December 31,
2007 and currently produces in excess of 115 net Mmcfe per
day.
Our interests in the Piñon Field include 471 producing
wells as of December 31, 2007. We had a 93% average working
interest in the producing area of Piñon Field and were
running 30 drilling rigs in the Piñon Field as of
December 31, 2007. We drilled 190 wells in the field
during 2007. As of December 31, 2007, we have identified
approximately 2,600 potential well locations in the Piñon
Field, including approximately 400 proved undeveloped drilling
locations.
West Texas Overthrust Prospects. Through our
regional exploratory efforts, to date we have identified several
exploratory prospect areas in the WTO:
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South Sabino Prospect Area. The South Sabino
prospect area is located approximately twelve miles east of the
Piñon Field. We have drilled two wells which have
encountered the Caballos chert and hydrocarbons in zones less
than 7,000 feet deep. Those wells were selected using
2-D seismic
and limited subsurface well control. The wells appear to be on
trend with the Piñon Field and are structurally higher
against one of several thrust faults that make up the WTO.
Results from our first phase of
3-D seismic
in this area in 2007 are encouraging and we plan to drill up to
seven wells in the South Sabino Prospect in 2008.
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Big Canyon Prospect Area. Located
approximately 25 miles east of the Piñon Field along
the WTO, this prospect area represents potential opportunities
for future development. The key well, Big Canyon Ranch
106-1, was
drilled by a third-party to a depth of 24,075 feet and was
abandoned in December 1993 after testing gas from the Tesnus
sands and Caballos chert. Our
3-D seismic
survey over the Big Canyon prospect area was acquired in late
2007. Exploratory wells are planned in 2008 to further evaluate
both the Tesnus and the Caballos in a location structurally
updip to the Big Canyon Ranch
106-1 well.
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Other Prospect Areas. We have identified
several other potential prospect areas in the WTO that we are
currently evaluating.
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West Texas Overthrust Development. The
following table provides information concerning development
opportunities in the WTO:
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Estimated
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Estimated
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2008 Capital
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Net PUD
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Gross PUD
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Gross PUD
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Total Gross
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Gross 2008
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Expenditures
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2007 Year
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Reserves
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Reserves
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Drilling
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Drilling
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Drilling
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Budget
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End Rigs
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(Bcfe)(1)
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(Bcfe)(1)
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Locations(1)
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Locations(1)
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Locations
|
|
|
(In millions)(2)
|
|
|
Working
|
|
|
|
509.9
|
|
|
|
731.6
|
|
|
|
397
|
|
|
|
2,594
|
|
|
|
267
|
|
|
|
622
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
As of December 31, 2007. |
|
(2) |
|
Excludes capital expenditures related to land and seismic
acquisitions. |
East
Texas Cotton Valley Trend
We own significant natural gas and oil interests in the natural
gas bearing Cotton Valley Trend in East Texas, which covers
parts of East Texas and northern Louisiana. We held interests in
53,388 gross (32,739 net) acres in East Texas as of
December 31, 2007. At December 31, 2007, our estimated
net proved reserves in East Texas were 202.5 Bcfe, with net
production of approximately 32.7 Mmcfe per day. We intend
to target the tight sand reservoirs of the Cotton Valley, Pettit
and Travis Peak formations at depths of 6,500 to
10,500 feet. These sands are typically distributed over a
large area, which has led to a near 100% success rate in this
area. Due
6
to the tight nature of the reservoirs, significant hydraulic
fracture stimulation is required to obtain commercial production
rates and efficiently drain the reservoir. Production in this
area is generally characterized as long-lived, with wells having
high initial production and decline rates that stabilize at
lower levels after several years. Moreover, area operators
continue to focus on infill development drilling as many areas
have been down spaced to 40 acres per well, with some areas
down spaced to as little as 20 acres per well. Recently,
operators have begun drilling horizontal wells and we are
monitoring their success. We drilled 48 wells
(42.0 net wells) in the Cotton Valley Trend in 2007. We
currently have 6 rigs running in this region and expect to drill
an additional 71 wells during 2008.
Gulf
Coast
We own natural gas and oil interests in 50,768 gross
(33,317 net) acres in the Gulf Coast area as of
December 31, 2007, which encompasses the large coastal
plain from the southernmost tip of Texas through the southern
portion of Louisiana. As of December 31, 2007, our
estimated net proved reserves in the Gulf Coast area were
97.8 Bcfe, with net production of approximately
42.5 Mmcfe per day. This is a predominantly gas prone,
multi-pay, geologically complex area with significant faulting
and compartmentalized reservoirs where
3-D seismic
and other advanced exploration technologies are critical to our
efforts. This area is comprised of sediments ranging from
Cretaceous through Tertiary age and is productive from very
shallow depths of several thousand feet to depths in excess of
18,000 feet. We target shallower geological formations such
as the Frio and the Miocene, as well as deeper horizons such as
Wilcox and Vicksburg. Operations in this area are generally
characterized as being higher risk and higher potential than in
our other core areas, with successful wells typically having
higher initial production rates with steeper declines and
shorter production lives. Drilling cost per well also tends to
be significantly higher than in our other areas due to the
increased depth and complexity of wellbore conditions. We
drilled three wells in the Gulf Coast in 2007.
Other
Areas
Gulf of Mexico. We own natural gas and oil
interests in 73,614 gross (36,770 net) acres in state and
federal waters off the coast of Texas and Louisiana. At
December 31, 2007, our estimated net proved reserves were
60.1 Bcfe, with net production of approximately
18.3 Mmcfe per day for the month of December 2007. The
water depth ranges from 30 feet to 1,100 feet and
activity extends from the coast to more than 100 miles
offshore. The Gulf of Mexico is one of the premier
producing basins in the United States and is an area where we
have achieved value-added growth through exploitation and
exploration. Our production will range in depth from several
thousand feet to in excess of 17,000 feet. The reservoir
rocks range in age from the Plio-Pleistocene through the
Oligocene. Typical Gulf of Mexico reservoirs have high porosity
and permeability and wells historically flow at prolific rates.
Overall, the Gulf of Mexico is known as an area of high quality
3-D seismic
acquisition. Our major areas of activity will include the blocks
in East Breaks and High Island areas that are located off the
Texas coast, and the East Cameron area located off the
Louisiana coast. In this area we generally own non-operating
interests in blocks operated by larger companies such as Chevron
Corporation, BP plc and Apache Corporation. We are currently
evaluating our future drilling plans and intend to manage our
investment in this area to maximize returns without
significantly increasing future capital expenditures.
Other West Texas. Our other non-tertiary West
Texas assets include our Brooklaw Field and the Goldsmith Adobe
Unit in the Permian Basin. As of December 31, 2007, we own
31,847 gross (22,941 net) acres in these prospects. As of
December 31, 2007, our estimated net proved reserves were
38.0 Bcfe. We have identified 77 potential drilling
locations in these fields, including 63 proved undeveloped
locations, and intend to drill approximately 21 development
wells in 2008.
Piceance Basin. The Piceance Basin in
northwestern Colorado is a sedimentary basin consisting of
multiple productive sandstone formations in one of the
countrys most prolific natural gas regions. We entered the
Piceance Basin in 1993 with the purchase of leasehold interests
predominantly located on federal lands. We acquired this
position in order to utilize the experience we had gained in
underbalanced drilling and foam fracture simulations in West
Texas. Initially, development of these natural gas reserves was
limited due to high drilling costs and complex completion
requirements. However, new drilling and completion technologies
now enable successful development in this area.
We are currently evaluating wells we have drilled, but not
completed, on the western portion of our acreage block. At
December 31, 2007, we had identified 828 potential drilling
locations on the eastern portion of our 40,334 gross
(15,686 net) acres. We will continue to evaluate our position in
2008 and intend to manage our investment in this area to
maximize returns without significantly increasing future capital
expenditures.
Other. We own interests in properties in the
Arkoma and Anadarko Basins and other areas. As of
December 31, 2007, we held interests in 443,546 gross
(163,894 net) leasehold and option acres in these areas. During
2007, our acreage in Oklahoma grew to 371,006 gross
(121,387 net) acres. As we continue to drill and expand our
acreage positions, our Oklahoma prospects may become
increasingly important to our Company.
7
Tertiary
Oil Recovery
Wellman Unit. The Wellman Unit is part of our
tertiary oil recovery operations. The Wellman Field, located in
Terry County, Texas was discovered in 1950 and produces from the
Canyon Reef limestone formation of Permian age from an average
depth of 9,500 feet. The Wellman Unit is on the western
edge of the Horseshoe Atoll, a geologic feature in the northern
part of the Midland Basin. There are approximately 110 separate
fields that are contained within this feature, including seven
existing
CO2
floods. The Wellman Unit covers approximately 2,120 acres,
1,200 of which are well-suited for both water and
CO2
floods. The Wellman Field has been partially
CO2
flooded and water flooded to produce 83.7 Mmboe to date. We
recently re-initiated injection of
CO2,
and our injection rate averaged 10.9 Mmcf per day in 2007
and we expect to reach an average 30.9 Mmcf per day over
the next 10 years. As of December 31, 2007, net proved
reserves attributable to the Wellman Unit were 9.3 Mmboe.
We also own a
CO2
recycling plant at this unit with a capacity of 28 Mmcf per
day. The plant includes 6,000 horsepower of
CO2
compression and 4,850 horsepower of processing compression,
which is sufficient to handle the recycling of the
CO2
that will be produced in association with the production of
these reserves.
George Allen Unit. The George Allen Unit,
located in Gaines County, Texas covers 800 gross acres in
the George Allen Field and produces from the San Andres
formation from an average depth of 4,950 feet. We have also
leased an additional 320 acres adjacent to the unit to the
south. The field is located within the greater Wasson area which
contains seven active
CO2
floods including the largest in the world, the Denver Unit. The
George Allen Unit has produced 1.6 Mmboe to date, but it
also contains a significant transition zone which has been
proven to be a tertiary oil target at the nearby Denver Unit. We
are currently implementing a nine pattern pilot program.
CO2
injection began in December 2007 at 2.0 Mmcf per day.
Injection is expected to increase to 15 Mmcf per day by
mid-year 2008. As of December 31, 2007, net proved reserves
attributable to the George Allen Field were 8.0 Mmboe. As
of December 31, 2007, the
CO2
injection rate was 2.0 Mmcf per day.
South Mallet Unit. The South Mallet Unit,
located in Hockley County, Texas covers 3,540 gross acres
in the Slaughter/Levelland Field complex and produces from the
San Andres formation from an average depth of
5,000 feet. These fields are some of the largest in West
Texas and currently have ten active
CO2
floods and four more at various stages of readiness. The South
Mallet Unit has produced 27.8 Mmboe to date. We are
currently evaluating the project for
CO2
development with plans to begin injection of
CO2
in 2009. We expect to reach an injection rate of approximately
18 Mmcf per day by the beginning of 2010. As of
December 31, 2007, net proved reserves attributable to the
South Mallet Unit were 2.5 Mmboe.
Jones Ranch Area. Several miles west of the
George Allen Unit, in Gaines County, PetroSource has acquired
various leases in the Jones Ranch Area. These leases produce
from various depths and formations from approximately
2,400 gross acres. We are evaluating these leases for both
conventional development and tertiary potential.
Proved
Reserves
The following tables present our historical estimated net proved
natural gas and oil reserves and the present value of our
estimated proved reserves as of December 31, 2007, 2006 and
2005. The
PV-10 and
Standardized Measure shown in the table are not intended to
represent the current market value of our estimated natural gas
and oil reserves. At December 31, 2007, approximately 56%
of our proved reserves were proved undeveloped reserves. Based
on our current drilling schedule, we estimate that 88% of our
current proved undeveloped reserves will be developed by 2011
and all of our current proved undeveloped reserves will be
developed by 2012.
Netherland, Sewell & Associates, Inc., independent oil
and gas consultants, have prepared the reports of proved
reserves of natural gas and crude oil for our net interest in
oil and gas properties, which constitute approximately 89% of
our total proved reserves as of December 31, 2007,
approximately 92% of our total proved reserves as of
December 31, 2006 and 1.5% of our total proved reserves as
of December 31, 2005. DeGolyer and MacNaughton prepared the
reports of proved reserves for PetroSource (our tertiary oil
reserves located in West Texas), which constitute approximately
8% of our total proved reserves as of December 31, 2007,
approximately 7% of our total proved reserves as of
December 31, 2006 and approximately 98% of our total proved
reserves as of December 31, 2005. The remaining 3%, 1% and
0.5% of our proved reserves as of December 31, 2007, 2006
and 2005 were based on internally prepared estimates.
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Estimated Proved Reserves(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Bcf)(2)
|
|
|
1,297.0
|
|
|
|
850.7
|
|
|
|
237.4
|
|
Oil (MmBbls)
|
|
|
36.5
|
|
|
|
25.2
|
|
|
|
10.4
|
|
Total (Bcfe)
|
|
|
1,516.2
|
|
|
|
1001.8
|
|
|
|
300.0
|
|
PV-10 (in
millions)(3)
|
|
$
|
3,550.5
|
|
|
$
|
1,734.3
|
|
|
$
|
733.3
|
|
Standardized Measure of Discounted Net Cash Flows (in
millions)(4)
|
|
$
|
2,718.5
|
|
|
$
|
1,440.2
|
|
|
$
|
499.2
|
|
|
|
|
(1) |
|
Our estimated proved reserves and the future net revenues,
PV-10, and
Standardized Measure of Discounted Net Cash Flows were
determined using year end prices for natural gas and oil as of
December 31, 2007, 2006 and 2005. The calculated weighted
average prices were $6.46 per Mcf of natural gas and $87.47 per
barrel of oil at December 31, 2007, $5.32 per Mcf of
natural gas and $54.62 per barrel of oil at December 31,
2006 and $8.40 per Mcf of natural gas and $54.02 per barrel of
oil at December 31, 2005. |
|
(2) |
|
Given the nature of our natural gas reserves, a significant
amount of our production, primarily in the WTO, contains natural
gas high in
CO2
content. These figures are net of volumes of
CO2
in excess of pipeline quality specifications. |
|
(3) |
|
PV-10 is a
non-GAAP financial measure and represents the present value of
estimated future cash inflows from proved natural gas and oil
reserves, less future development and production costs,
discounted at 10% per annum to reflect timing of future cash
flows and using pricing assumptions in effect at the end of the
period.
PV-10
differs from Standardized Measure of Discounted Net Cash Flows
because it does not include the effects of income taxes on
future net revenues. Neither
PV-10 nor
Standardized Measure represents an estimate of fair market value
of our natural gas and oil properties.
PV-10 is
used by the industry and by our management as an arbitrary
reserve asset value measure to compare against past reserve
bases and the reserve bases of other business entities that are
not dependent on the taxpaying status of the entity. The
following tables provide a reconciliation of our Standardized
Measure to
PV-10: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Standardized Measure of Discounted Net Cash Flows
|
|
$
|
2,718.5
|
|
|
$
|
1440.2
|
|
|
$
|
499.2
|
|
Present value of future income tax discounted at 10%
|
|
|
832.0
|
|
|
|
294.1
|
|
|
|
234.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10
|
|
$
|
3,550.5
|
|
|
$
|
1,734.3
|
|
|
$
|
733.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4) |
|
The Standardized Measure of Discounted Net Cash Flows represents
the present value of estimated future cash inflows from proved
natural gas and oil reserves, less future development and
production costs, and income tax expenses, discounted at 10% per
annum to reflect timing of future cash flows and using the same
pricing assumptions as are used to calculate
PV-10.
Standardized Measure differs from
PV-10
because Standardized Measure includes the effect of future
income taxes. |
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.
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
(i) that portion delineated by drilling and defined by
gas-oil
and/or
oil-water contacts, if any, and (ii) 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.
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.
Estimates of proved reserves do not include the following:
|
|
|
|
|
oil that may become available from known reservoirs but is
classified separately as indicated additional reserves;
|
|
|
|
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;
|
9
|
|
|
|
|
crude oil, natural gas, and natural gas liquids that may occur
in undrilled prospects; and
|
|
|
|
crude oil, natural gas, and natural gas liquids that may be
recovered from oil shales, coal, gilsonite and other such
sources.
|
Production
and Price History
The following tables set forth information regarding our net
production of oil, natural gas and natural gas liquids and
certain price and cost information for each of the periods
indicated. Because of the relatively high volumes of
CO2
produced with natural gas in certain areas of the WTO, our
reported sales and reserves volumes and the related unit prices
received for natural gas in these areas are reported net of
CO2
volumes stripped at the gas plants. The gas plant fees for
removing
CO2
for our high
CO2
natural gas have been taken into account in our lease operating
expenses as processing and gathering fees. In all other areas,
natural gas sales are delivered to sales points with
CO2
levels within pipeline specifications and thus are included in
sales and reserves volumes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mmcf)
|
|
|
51,958
|
|
|
|
13,410
|
|
|
|
6,873
|
|
Oil (MBbls)
|
|
|
2,042
|
|
|
|
322
|
|
|
|
72
|
|
Combined equivalent volumes (Mmcfe)
|
|
|
64,211
|
|
|
|
15,342
|
|
|
|
7,305
|
|
Average daily combined equivalent volumes (Mmcfe/d)
|
|
|
175.9
|
|
|
|
42.0
|
|
|
|
20.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Average Prices(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
6.51
|
|
|
$
|
6.19
|
|
|
$
|
6.54
|
|
Oil (per Bbl)
|
|
$
|
68.12
|
|
|
$
|
56.61
|
|
|
$
|
48.19
|
|
Combined equivalent (per Mcfe)
|
|
$
|
7.45
|
|
|
$
|
6.60
|
|
|
$
|
6.63
|
|
|
|
|
(1) |
|
Reported prices represent actual prices for the periods
presented and do not give effect to hedging transactions. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Expenses per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
|
|
$
|
0.12
|
|
|
$
|
0.22
|
|
|
$
|
0.16
|
|
Processing and gathering(1)
|
|
|
0.28
|
|
|
|
0.37
|
|
|
|
0.42
|
|
Other lease operating expenses
|
|
|
1.25
|
|
|
|
1.70
|
|
|
|
1.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total lease operating expenses
|
|
$
|
1.65
|
|
|
$
|
2.29
|
|
|
$
|
2.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
$
|
0.30
|
|
|
$
|
0.30
|
|
|
$
|
0.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes costs attributable to gas treatment to remove
CO2
and other impurities from our high
CO2
natural gas. |
Productive
Wells
The following table sets forth the number of productive wells in
which we owned a working interest at December 31, 2007.
Productive wells consist of producing wells and wells capable of
producing, including natural gas wells awaiting pipeline
connections
10
to commence deliveries and oil wells awaiting connection to
production facilities. Gross wells are the total number of
producing wells in which we have an interest, and net wells are
the sum of our fractional working interests owned in gross wells.
|
|
|
|
|
|
|
|
|
Area
|
|
Gross
|
|
|
Net
|
|
|
WTO
|
|
|
471
|
|
|
|
435
|
|
East Texas
|
|
|
177
|
|
|
|
163
|
|
Gulf Coast
|
|
|
214
|
|
|
|
133
|
|
Other:
|
|
|
|
|
|
|
|
|
Gulf of Mexico
|
|
|
67
|
|
|
|
43
|
|
Other West Texas
|
|
|
264
|
|
|
|
251
|
|
Tertiary recovery West Texas (PetroSource)
|
|
|
46
|
|
|
|
43
|
|
Piceance Basin
|
|
|
52
|
|
|
|
20
|
|
Other, including Oklahoma
|
|
|
363
|
|
|
|
146
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,654
|
|
|
|
1,234
|
|
|
|
|
|
|
|
|
|
|
Developed
and Undeveloped Acreage
The following table sets forth information at December 31,
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
|
|
|
|
Acreage(1)
|
|
|
Undeveloped Acreage(2)
|
|
Area
|
|
Gross(3)
|
|
|
Net(4)
|
|
|
Gross(3)
|
|
|
Net(4)
|
|
|
WTO
|
|
|
13,157
|
|
|
|
10,824
|
|
|
|
587,389
|
|
|
|
497,921
|
|
East Texas
|
|
|
28,084
|
|
|
|
25,891
|
|
|
|
25,304
|
|
|
|
6,848
|
|
Gulf Coast
|
|
|
39,438
|
|
|
|
24,678
|
|
|
|
11,330
|
|
|
|
8,639
|
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico
|
|
|
73,614
|
|
|
|
36,770
|
|
|
|
|
|
|
|
|
|
Other West Texas
|
|
|
24,272
|
|
|
|
16,030
|
|
|
|
7,575
|
|
|
|
6,911
|
|
Tertiary recovery West Texas (PetroSource)
|
|
|
9,064
|
|
|
|
8,195
|
|
|
|
|
|
|
|
|
|
Piceance Basin
|
|
|
1,800
|
|
|
|
451
|
|
|
|
38,534
|
|
|
|
15,235
|
|
Other, including Oklahoma
|
|
|
86,498
|
|
|
|
43,255
|
|
|
|
357,048
|
|
|
|
120,639
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
275,927
|
|
|
|
166,094
|
|
|
|
1,027,180
|
|
|
|
656,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Developed acres are acres spaced or assigned to productive wells. |
|
(2) |
|
Undeveloped acres are acres on which wells have not been drilled
or completed to a point that would permit the production of
commercial quantities of oil or natural gas, regardless of
whether such acreage contains proved reserves. |
|
(3) |
|
A gross acre is an acre in which a working interest is owned.
The number of gross acres is the total number of acres in which
a working interest is owned. |
|
(4) |
|
A net acre is deemed to exist when the sum of the fractional
ownership working interests in gross acres equals one. The
number of net acres is the sum of the fractional working
interests owned in gross acres expressed as whole numbers and
fractions thereof. |
Many of the leases comprising the acreage set forth in the table
above will expire at the end of their respective primary terms
unless production from the leasehold acreage has been
established prior to such date, in which event the lease will
remain in effect until the cessation of production. We generally
have been able to obtain extensions of the primary terms of our
federal leases when we have been unable to obtain drilling
permits due to a pending Environmental Assessment, Environmental
Impact Statement or related
11
legal challenge. The following table sets forth as of
December 31, 2007 the expiration periods of the gross and
net acres that are subject to leases in the acreage summarized
in the above table.
|
|
|
|
|
|
|
|
|
|
|
Acres Expiring
|
|
Twelve Months Ending
|
|
Gross
|
|
|
Net
|
|
|
December 31, 2008
|
|
|
46,635
|
|
|
|
36,198
|
|
December 31, 2009
|
|
|
135,669
|
|
|
|
121,134
|
|
December 31, 2010
|
|
|
356,993
|
|
|
|
162,761
|
|
December 31, 2011 and later
|
|
|
390,181
|
|
|
|
279,038
|
|
Other(1)
|
|
|
373,629
|
|
|
|
223,156
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,303,107
|
|
|
|
822,287
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Leases remaining in effect until the cessation of development
efforts or cessation of production on the developed portion of
the particular lease. |
Drilling
Activity
The following table sets forth information with respect to wells
we completed during the periods indicated. The information
should not be considered indicative of future performance, nor
should it be assumed that there is necessarily any correlation
between the number of productive wells drilled, quantities of
reserves found or economic value. Productive wells are those
that produce commercial quantities of hydrocarbons, regardless
of whether they produce a reasonable rate of return.
Gross refers to the total wells in which we had a
working interest and net refers to gross wells
multiplied by our working interest.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Gross
|
|
|
Percent
|
|
|
Net
|
|
|
Percent
|
|
|
Gross
|
|
|
Percent
|
|
|
Net
|
|
|
Percent
|
|
|
Gross
|
|
|
Percent
|
|
|
Net
|
|
|
Percent
|
|
|
Development:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
281
|
|
|
|
99.3
|
%
|
|
|
244.4
|
|
|
|
99.5
|
%
|
|
|
82
|
|
|
|
94
|
%
|
|
|
50.8
|
|
|
|
95
|
%
|
|
|
31
|
|
|
|
100
|
%
|
|
|
13.0
|
|
|
|
100
|
%
|
Dry
|
|
|
2
|
|
|
|
0.7
|
%
|
|
|
1.3
|
|
|
|
0.5
|
%
|
|
|
5
|
|
|
|
6
|
%
|
|
|
2.5
|
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
283
|
|
|
|
100
|
%
|
|
|
245.7
|
|
|
|
100
|
%
|
|
|
87
|
|
|
|
100
|
%
|
|
|
53.3
|
|
|
|
100
|
%
|
|
|
31
|
|
|
|
100
|
%
|
|
|
13.0
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
27
|
|
|
|
82
|
%
|
|
|
24.3
|
|
|
|
84
|
%
|
|
|
19
|
|
|
|
76
|
%
|
|
|
13.0
|
|
|
|
72
|
%
|
|
|
2
|
|
|
|
22
|
%
|
|
|
0.8
|
|
|
|
22
|
%
|
Dry
|
|
|
6
|
|
|
|
18
|
%
|
|
|
4.7
|
|
|
|
16
|
%
|
|
|
6
|
|
|
|
24
|
%
|
|
|
5.0
|
|
|
|
28
|
%
|
|
|
7
|
|
|
|
78
|
%
|
|
|
2.9
|
|
|
|
78
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
33
|
|
|
|
100
|
%
|
|
|
29.0
|
|
|
|
100
|
%
|
|
|
25
|
|
|
|
100
|
%
|
|
|
18.0
|
|
|
|
100
|
%
|
|
|
9
|
|
|
|
100
|
%
|
|
|
3.7
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
308
|
|
|
|
98
|
%
|
|
|
268.7
|
|
|
|
98
|
%
|
|
|
101
|
|
|
|
90
|
%
|
|
|
63.8
|
|
|
|
89
|
%
|
|
|
33
|
|
|
|
83
|
%
|
|
|
13.8
|
|
|
|
83
|
%
|
Dry
|
|
|
8
|
|
|
|
2
|
%
|
|
|
6.0
|
|
|
|
2
|
%
|
|
|
11
|
|
|
|
10
|
%
|
|
|
7.5
|
|
|
|
11
|
%
|
|
|
7
|
|
|
|
17
|
%
|
|
|
2.9
|
|
|
|
17
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
316
|
|
|
|
100
|
%
|
|
|
274.7
|
|
|
|
100
|
%
|
|
|
112
|
|
|
|
100
|
%
|
|
|
71.3
|
|
|
|
100
|
%
|
|
|
40
|
|
|
|
100
|
%
|
|
|
16.7
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2007, we had 40 wells in process.
Drilling
Rigs
The following table sets forth information with respect to the
drilling on our acreage as of December 31, 2007.
|
|
|
|
|
|
|
|
|
Area
|
|
Owned(1)
|
|
|
Third-Party
|
|
|
WTO
|
|
|
28
|
|
|
|
2
|
|
East Texas
|
|
|
|
|
|
|
6
|
|
Gulf Coast
|
|
|
|
|
|
|
1
|
|
Other, including Oklahoma
|
|
|
1
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
29
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
(1) |
|
Includes rigs owned by Lariat, our wholly owned subsidiary, and
by Larclay, a limited partnership in which we have a 50%
interest. |
Marketing
and Customers
Through Integra Energy, our subsidiary, we market our natural
gas production in accordance with standard industry practices.
Each month we develop a portfolio of natural gas sales by
arranging for a percentage of Integra Energys natural gas
to be sold on a first of the month index price basis with the
remaining volume sold on a daily swing basis at current market
rates. Most of the natural gas is sold on a
month-to-month
basis, and any longer term or evergreen agreements that we are
subject to provide pricing provisions that allow us to receive
monthly market area based prices. During the year ended
December 31, 2007, we sold natural gas to 24 different
purchasers.
The top five natural gas purchasers of our WTO production for
the year ended December 31, 2007 and each companys
approximate percentage of total sales during that period are
listed below:
|
|
|
|
|
Gas Purchasers
|
|
%
|
|
|
Magnus Energy Marketing, Ltd.
|
|
|
25.0
|
%
|
ANP Funding I, LLC
|
|
|
21.4
|
%
|
Atmos Energy Corporation
|
|
|
12.9
|
%
|
City of Austin, Texas
|
|
|
10.9
|
%
|
El Paso Industrial Energy, LP
|
|
|
10.5
|
%
|
In light of access to numerous other purchasers through existing
pipeline interconnections, we do not believe the loss of any of
our major gas purchasers would have a material effect on our
business.
See Note 21 in the consolidated financial statements
included in this report regarding major customers.
Title
to Properties
As is customary in the natural gas and oil 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 title defects on those
properties, we are typically responsible for curing any title
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. In addition, prior to completing an
acquisition of producing natural gas and oil 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. To date, we have
obtained title opinions on 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 natural gas and oil industry. Our natural gas
and oil properties are subject to customary royalty and other
interests, liens for current taxes and other burdens which we
believe do not materially interfere with the use of or affect
our carrying value of the properties.
Drilling
and Oil Field Services
We provide drilling and related oil field services to our
exploration and production business and to third parties in West
Texas.
Drilling
Operations
We drill for our own account in the WTO through our drilling and
oil field services subsidiary, Lariat Services, Inc. In
addition, we also drill wells for other natural gas and oil
companies, primarily located in the West Texas region. We
believe that drilling with our own rigs allows us to control
costs and maintain operating flexibility. We have a 50% interest
in a limited partnership, Larclay, that owns and operates
drilling rigs. We believe that our ownership of drilling rigs
and our related oil field services will continue to be a
catalyst of our growth. As of December 31, 2007, 22 of our
rigs and seven Larclay rigs were working on properties operated
by us, and we operated 43 rigs, including eleven of the twelve
rigs owned by Larclay. Our rig fleet is designed to drill in our
specific areas of operation and have an average horsepower of
over 800 and an average depth capacity of greater than
10,500 feet.
In 2005, we ordered 22 rigs from Chinese manufacturers for an
aggregate purchase price of $126.4 million, which included
the cost of assembling and equipping the rigs in the
U.S. Due in part to the shortage of experienced drilling
employees and various operational challenges, we have deemed it
prudent to retrofit five Chinese rigs to a conventional
operation. We anticipate the retrofit will be completed in the
second quarter of 2008.
13
The table below identifies certain information concerning our
contract drilling operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Number of operational rigs owned at end of period
|
|
|
25
|
|
|
|
25
|
|
|
|
19
|
|
Average number of operational rigs owned during the period
|
|
|
26.0
|
|
|
|
21.9
|
|
|
|
14.3
|
|
Average number of rigs utilized
|
|
|
23.8
|
|
|
|
21.9
|
|
|
|
14.3
|
|
Average drilling revenue per rig per day(1)(2)
|
|
$
|
17,177
|
|
|
$
|
17,034
|
|
|
$
|
11,503
|
|
|
|
|
(1) |
|
Represents the total revenues from our contract drilling
operations divided by the total number of days our drilling rigs
were used during the period. |
|
(2) |
|
Does not include revenues for related rental equipment. |
The table below identifies certain information concerning our
drilling rigs as of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating for
|
|
|
Operating for
|
|
|
|
Owned
|
|
|
Operational
|
|
|
Idle
|
|
|
SandRidge
|
|
|
Third Parties
|
|
|
Lariat
|
|
|
32
|
(1)
|
|
|
25
|
|
|
|
0
|
|
|
|
22
|
|
|
|
3
|
|
Larclay
|
|
|
12
|
(2)
|
|
|
11
|
|
|
|
1
|
|
|
|
7
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
44
|
|
|
|
36
|
|
|
|
1
|
|
|
|
29
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes three rigs that were being retrofitted and four rigs
that are non-operational. |
|
(2) |
|
Includes one rig that has not been assembled. |
Oil
Field Services
Our oil field services business began in 1986 and conducts
operations that complement our exploration and production
operation. These services include providing pulling units,
coiled-tubing units, trucking, location and road construction
roustabout services and rental tools to ourselves and to third
parties. Less than 28% of our oil field services in 2007 were
performed for third parties. We also provide underbalanced
drilling systems for our own wells. Our capital expenditures for
2007 related to our oil field services were $123.2 million
and we have budgeted approximately $50 million in capital
expenditures in 2008 for oil field services.
Types
of Drilling Contracts
We obtain our contracts for drilling natural gas and oil wells
either through competitive bidding or through direct
negotiations with customers. Our drilling contracts generally
provide for compensation on a daywork, footage or turnkey basis.
The contract terms we offer generally depend on the complexity
and risk of operations, the
on-site
drilling conditions, the type of equipment used, the anticipated
duration of the work to be performed and prevailing market
rates. For a discussion of these contracts, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Segment
Overview Drilling and Oil Field Services.
Our
Customers
We perform approximately two-thirds of our drilling services in
support of our exploration and production business and
approximately one-third with the other operators in West Texas.
For the year ended December 31, 2007, we generated revenues
of $38.1 million for drilling services performed for third
parties, with Mariner Energy, Inc. accounting for
$19.0 million of those revenues.
14
Midstream
Gas Services
We provide gathering, compression, processing and treating
services of natural gas in the TransPecos region of West Texas
and the Piceance Basin in Colorado. Our midstream operations and
assets not only serve our exploration and production business,
but also service other natural gas and oil companies. The
following tables set forth our primary midstream assets as of
December 31, 2007:
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Plant Capacity
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Average
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Third-Party
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Gas Plants
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(Mmcf/d)
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Utilization(1)
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Usage
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Pikes Peak(2) West Texas
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70
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90
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%
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1
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%
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Grey Ranch(3) West Texas
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92
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89
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%
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31
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%
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Sagebrush(4) Piceance Basin
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50
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24
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%
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21
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%
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(1) |
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Average utilization for the year ended December 31, 2007. |
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(2) |
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A project to expand Pikes Peak capacity to 70 Mmcf
per day was completed in the fourth quarter of 2007. |
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(3) |
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A project to expand the plant to 92 Mmcf/per day was
completed during the fourth quarter of 2007. The plant capacity
is expected to be further increased to 170 Mmcf/per day by
the third quarter of 2008. |
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(4) |
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Sagebrush commenced processing operations on May 1, 2007.
Current throughput is 22 Mmcf per day, increasing
utilization to 44%. |
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CO2
Compression
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Average
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PetroSource Facilities (West Texas)
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Capacity (Mmcf/d)
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Utilization(1)
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Pikes Peak
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38
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63
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%
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Mitchell
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26
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41
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%
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Grey Ranch
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40
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59
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%
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Terrell
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38
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66
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%
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(1) |
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Average utilization for year ended December 31, 2007. |
West
Texas
In Pecos County, we operate and own the Pikes Peak gas
treating plant, which has the capacity to treat 70 Mmcf per
day of gas for the removal of
CO2
from natural gas produced in the Piñon Field and nearby
areas. We also own the Grey Ranch
CO2
treatment plant located in Pecos County and have a 50% interest
in the partnership that leases the plant from us under a lease
expiring in 2010. Our 50% partner, Southern Union, operates the
plant. The treating capacities for both the Pikes Peak and
Grey Ranch plants are dependent upon the quality of natural gas
being treated. The above numbers for the Pikes Peak and
Grey Ranch plants are based on a natural gas stream that
averages 65%
CO2.
Our two West Texas plants remove
CO2
from natural gas production and deliver residue gas into the
Atmos Lone Star and Enterprise Energy Services pipelines. These
assets are operated on fixed fees based upon throughput of
natural gas. We have access for up to 60 Mmcf per day of
treating capacity at Anadarko Petroleum Corporations
Mitchell Plant under a long term fixed fee arrangement.
We also operate or own approximately 367 miles of natural
gas gathering pipelines and numerous dehydration units. Within
the Piñon Field, we operate separate gathering systems for
sweet natural gas and produced natural gas containing high
percentages of
CO2.
In addition to servicing our exploration and production
business, these assets also service other natural gas and oil
companies.
The majority of the produced natural gas gathered by our
midstream assets in West Texas requires compression from the
wellhead to the final sales meter. As of December 31, 2007,
we currently own and operate approximately 45,000 horsepower of
gas compression and anticipate installing an additional 40,000
horsepower in 2008.
Other
Areas
Our Piceance Basin system consists of a 50 Mmcf per day
processing plant (Sagebrush) and approximately 53 miles of
pipeline gathering systems and approximately 4,400 horsepower of
natural gas compression capacity. We gather and transport our
natural gas and third-party natural gas to market delivery
points on Colorado Interstate Gas Company, Questar Corporation
and Rocky Mountain Natural Gas Pipelines.
We also own approximately 70 miles of pipeline gathering
systems and operate more than 10,000 horsepower of natural gas
compression in East Texas and approximately 44 miles of
pipeline gathering systems in the Gulf Coast area.
15
Capital
Expenditures
The growth of our midstream assets is driven by our exploration
and development operations. Historically, pipeline and facility
expansions are made when warranted by the increase in production
or the development of additional acreage. During 2007, we spent
approximately $73.8 million in capital expenditures to
install pipeline and compression infrastructure to accommodate
our growth in production and for increased treating capacity for
high
CO2
gas, adding approximately 75 Mmcf per day in additional
treating capacity. We anticipate adding approximately
80 Mmcf per day in additional treating capacity in 2008. We
have budgeted approximately $107 million in 2008 capital
expenditures for our midstream and other segments.
Marketing
Through Integra Energy, our subsidiary, we buy and sell the
natural gas and oil production from SandRidge-operated wells and
third-party operated wells within our West Texas operations.
Through Integra Energy, we purchase and sell residue gas from
the Sagebrush plant into Questar Corporation and Colorado
Interstate Gas pipelines. We generally buy and sell natural gas
on back-to-back contracts using a portfolio of
baseload and spot sales agreements. Identical volumes are bought
and sold on monthly and daily contracts using a combination of
Inside FERC and Gas Daily pricing indices to
eliminate price exposure. We market our oil and condensate
production in both Texas and Colorado to Shell Trading
U.S. Company at current market rates.
We do not actively seek to buy and sell third-party natural gas
due to onerous credit requirements and minimal margin
expectations. We conduct thorough credit checks with all
potential purchasers and minimize our exposure by contracting
with multiple parties each month. We do not engage in any
hedging activities with respect to these contracts. We manage
several interruptible natural gas transportation agreements in
order to take advantage of price differentials or to secure
available markets when necessary. We currently have
75,000 MmBtu per day of firm transportation service
subscribed on the Oasis Pipeline for a portion of our Piñon
Field production for 2008.
Other
Operations
Our
CO2
gathering, merchant sales and tertiary oil recovery operations
are conducted through PetroSource. PetroSource owns
231 miles of
CO2
pipelines in West Texas with approximately 88,000 horsepower of
owned and leased
CO2
compression available with approximately 54,000 horsepower
currently operational. In addition, PetroSource has exclusive
long-term supply contracts to gather
CO2
from natural gas treatment plants in West Texas and is the sole
gatherer of
CO2
from the four natural gas treatment plants located in the
Delaware and Val Verde Basins of West Texas. Our
CO2
supply is primarily used in our and third parties tertiary
oil recovery operations. We have assembled an experienced
CO2
management team, including engineers and geologists with
extensive experience in
CO2
flooding with industry leaders.
Production from most oil reservoirs includes three distinct
phases: primary, secondary and tertiary or enhanced recovery.
During primary recovery, the natural pressure of the reservoir
or gravity drives oil into the wellbore and artificial lift
techniques (such as pumps) produce the oil to the surface.
However, only about 10% to 15% of a reservoirs original
oil in place is typically produced during primary recovery.
Secondary recovery techniques, most commonly water flooding,
often increase ultimate recovery to more than 20% to 45% of the
original oil in place. This technique involves injecting water
to displace oil and drive it to the wellbore. Even after a water
flood, the majority of the original oil in place is still
un-recovered. Tertiary or enhanced recovery techniques, such as
CO2 flooding,
can recover additional oil. In
CO2
flooding, the
CO2
is injected into the reservoir. At high pressures (approximately
2,000 psi), the
CO2
is in a liquid phase and can become miscible with the oil, which
means the
CO2
and oil mix together and form one fluid. This mixing changes the
fluid properties of the oil and enables this trapped oil to
begin to move in the reservoir again. The result is a
potentially significant increase in production.
CO2
injection can recover, on average, an additional 10% to 16% of
the original oil in place in a field over a period of 20 to
30 years. Mature fields that have been abandoned may still
be viable candidates for
CO2
floods.
CO2
flooding typically extends the life of oil fields by
20 years.
In 2004 and 2005, we acquired West Texas waterfloods, the
Wellman and South Mallet Units and the George Allen Unit, for
the purpose of evaluating for potential implementation of
tertiary oil recovery operations utilizing our equity
CO2
supply. For a discussion of our tertiary reserves and production
at the units, please read Exploration and
Production Operations Tertiary Oil Recovery.
We have also identified numerous other properties that are
attractive candidates for implementing
CO2
projects. We believe we have a competitive advantage in
identifying, acquiring and developing these properties because
of our expertise and large available
CO2
supply.
PetroSource currently has approximately 95 Mmcf per day of
CO2
in available supply. We currently deliver the majority of this
supply to Occidental Permian Ltd. and Pure Resources L.P. In
December 2007, we captured and sold 92 Mmcf per day. Our
long term contracts in place with Occidental provide for the
exchange of up to 60% of the delivered volumes. We believe our
current tertiary oil recovery properties will require an average
of 65 to 75 Mmcf of
CO2
per day over the next five years. We intend to increase our
supply
16
of
CO2
in order to provide sufficient capacity for our tertiary oil
recovery operations. We expect the supply of
CO2
to increase as additional natural gas reserves with a high
CO2
content are developed in the Piñon and surrounding fields.
In addition, we intend to increase the capacity of our
CO2
treating, gathering and transportation assets which will
continue to provide for our
CO2
needs, as well as the expansion of our merchant sales business.
Currently, two additional compressors are being refurbished at
the Grey Ranch and Mitchell Plant. These units will add over
11,000 horsepower and over 30 Mmcf per day of capacity.
Future regulation of greenhouse gas emissions may provide the
Company an opportunity to create economic benefits in the form
of Emissions Reduction Credits (ERCs), but such
regulation may also impose burdens on the conduct and cost of
our operations. Recently, a number of states and regions of the
U.S. have passed laws, adopted regulations or undertaken
regulatory initiatives to reduce the emission of
greenhouse gases, such as
CO2
and methane. In addition, the U.S. Congress is actively
considering legislation to reduce emissions of greenhouse gases,
and in light of the U.S. Supreme Courts recent
decision in Massachusetts, et al. v. EPA, the
U.S. Environmental Protection Agency 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 (not including the United States) 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. These legislative and regulatory
efforts may result in legal requirements that create a more
active and more valuable market in which to trade ERCs, although
the timing and scope of future legal requirements governing
greenhouse gases remain uncertain. We currently capture
approximately 1.5 million metric tons of
CO2
per year. We may benefit from such capture to the extent it
results in ERCs that can be traded or can be used by us to meet
future compliance obligations that may otherwise be costly to
satisfy. ERCs of just over 170,000 tonnes were sold on the
voluntary market during 2007.
Competition
We believe that our leasehold acreage position, oil field
service businesses, midstream assets,
CO2
supply and technical and operational capabilities generally
enable us to compete effectively. However, the natural gas and
oil industry is intensely competitive, and we face competition
in each of our business segments.
We believe our geographic concentration of operations and
vertical integration enable us to compete effectively with our
exploration and production operations. However, we compete with
companies that have greater financial and personnel resources
than we do. These companies may be able to pay more for
producing properties and undeveloped acreage. In addition, these
companies may have a greater ability to continue exploration
activities during periods of low natural gas and oil market
prices. Our larger or integrated competitors may be able to
absorb the burden of any existing and future federal, state, and
local laws and regulations more easily than we can, which would
adversely affect our competitive position. Our ability to
acquire additional properties and to discover reserves in the
future will be dependent upon our ability to evaluate and select
suitable properties and to consummate transactions in a highly
competitive environment. In addition, because we have fewer
financial and human resources than many companies in our
industry, we may be at a disadvantage in bidding for exploratory
prospects and producing natural gas and oil properties.
We believe the type, age and condition of our drilling rigs, the
quality of our crew and the responsiveness of our management
generally enable us to compete effectively. However, to the
extent we drill for third parties, we encounter substantial
competition from other drilling contractors. Our primary market
area is highly competitive. The drilling contracts we compete
for are sometimes awarded on the basis of competitive bids.
We believe pricing and rig availability are the primary factors
our potential customers consider in determining which drilling
contractor to select. While we must be competitive in our
pricing, our competitive strategy generally emphasizes the
quality of our equipment, the experience of our rig crews and
our willingness to drill on a turnkey basis, to differentiate us
from our competitors. This strategy is less effective when
demand for drilling services is weak or there is an oversupply
of rigs, as these conditions usually result in increased price
competition, which makes it more difficult for us to compete on
the basis of factors other than price. Many of our competitors
have greater financial, technical and other resources than we
do. Their greater capabilities in these areas may enable them to
better withstand industry downturns and better retain skilled
rig personnel.
We believe our geographic concentration of operations enables us
to compete effectively in our midstream business segment. Most
of our midstream assets are integrated with our production.
However, with respect to third-party gas and acquisitions, we
compete with companies that have greater financial and personnel
resources than we do. These companies may be able to pay more
for acquisitions. In addition, these companies may have a
greater ability to price their services below our prices for
similar services. Our larger or integrated competitors may be
able to absorb the burden of any existing and future federal,
state, and local laws and regulations more easily than we can,
which would adversely affect our competitive position.
17
We believe our supply of
CO2,
focus on small to mid-sized acquisitions and technical expertise
enable us to compete effectively in our tertiary oil recovery
business. However, we face the same competitive pressures in
this business that we do in our traditional exploration and
production segment.
Seasonal
Nature of Business
Generally, the demand for natural gas decreases during the
summer months and increases during the winter months. Seasonal
anomalies such as mild winters or cool summers sometimes lessen
this fluctuation. In addition, certain natural gas users utilize
natural gas storage facilities and purchase some of their
anticipated winter requirements during the summer. This can also
lessen seasonal demand fluctuations. Seasonal weather conditions
and lease stipulations can limit our drilling and producing
activities and other natural gas and oil operations in a portion
of our operating areas. These seasonal anomalies can pose
challenges for meeting our well drilling objectives and can
increase competition for equipment, supplies and personnel
during the spring and summer months, which could lead to
shortages and increase costs or delay our operations.
Environmental
Matters and Regulation
General
We are subject to extensive and complex federal, state and local
laws and regulations governing the protection of the environment
and of the health and safety of our employees. 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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require the installation of expensive pollution control
equipment;
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require safety-related procedures and personal protective
equipment to be used during operations;
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restrict the types, quantities and concentrations of various
substances that can be released into the environment in
connection with natural gas and oil drilling production,
transportation and processing activities;
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suspend, limit, prohibit or require approval before
construction, drilling and other activities; and
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require remedial measures to mitigate pollution from historical
and ongoing operations, such as the closure of pits and plugging
of abandoned wells.
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These laws, rules and regulations may also restrict the rate of
natural gas and oil production below the rate that would
otherwise be possible. The regulatory burden on the natural gas
and oil industry increases the cost of doing business in the
industry and consequently affects profitability.
Governmental authorities have the power to enforce compliance
with environmental laws, regulations and permits, and violations
are subject to injunction, as well as administrative, civil and
potentially criminal penalties. The effects of these laws and
regulations, as well as other laws or regulations that may be
adopted in the future, could have a material adverse impact on
our business, financial condition and results of operations.
Below is a discussion of the environmental laws and regulations
that could have a material impact on the oil and gas industry.
Comprehensive
Environmental Response, Compensation and Liability
Act
The Comprehensive Environmental Response, Compensation and
Liability Act, or CERCLA, also known as the Superfund law, and
analogous state laws impose joint and several liability, without
regard to fault or legality of conduct, on specific classes of
persons 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 strict
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 related environmental and 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. In the course of our operations, we generate wastes
that may fall within CERCLAs definition of hazardous
substances. Further, natural gas and oil exploration,
production, processing and other activities have been conducted
at some of our properties by previous owners and operators, and
materials from these operations remain at and could migrate from
some of our properties and may warrant or require investigation
or remediation or other response action. Therefore, governmental
agencies or third parties could seek to hold us responsible
under CERCLA or similar state laws for all or part of the costs
to clean up a site at or to which hazardous substances may have
been released or deposited.
18
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
U.S. 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 excluded
from regulation as RCRA hazardous wastes but instead are
regulated under RCRAs non-hazardous waste provisions.
However, it is possible that certain natural gas and oil
exploration and production wastes now classified as
non-hazardous could be classified as hazardous wastes in the
future. Any such change would likely increase our operating
expenses, which could have a material adverse effect on our
business, financial condition or results of operations as well
as on the industry in general.
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. These regulatory programs may
require us to obtain permits before commencing construction on a
new source of air emissions, and they may require us to reduce
emissions or to install expensive emission control technologies
at existing facilities and new facilities. As a result, we may
be required to incur increased capital and operating costs at
existing and new facilities. For instance, the Grey Ranch
natural gas treatment plant operates under a permit granted by
the Texas Commission on Environmental Quality, or TCEQ that
currently allows us to vent
CO2
emissions. Effective March 2009, we will be required to
install control devices that limit the quantity of organic
compounds vented by the plant. We are in the process of
refurbishing existing compressors at an estimated cost of
$4.0 million, which will enable us to capture the
CO2
for ultimate delivery to the marketplace. Additional expenses
and capital costs may be required for us to maintain or achieve
compliance with current and future laws governing air emissions.
We are subject to air quality compliance reviews by federal and
state agencies, and the failure to meet applicable requirements
may result in enforcement action, including fines and penalties.
In February 2008, we received a notice of alleged violations
from TCEQ for certain monitoring and recordkeeping deficiencies
and emissions in excess of allowable limits at our Pikes
Peak processing plant in 2007. We are preparing a response
regarding corrective action taken with regard to the alleged
violations.
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, including wetlands, as well as state waters.
These laws prohibit the discharge of produced waters and sand,
drilling fluids, drill cuttings and other substances related to
the oil and natural gas industry into onshore, coastal and
offshore waters without appropriate permits. Some of the
pollutant limitations have become more restrictive over the
years, and additional restrictions and limitations including
technology requirements and receiving water limits, may be
imposed in the future. The Clean Water Act also regulates storm
water discharges from industrial and construction activities.
Regulations promulgated by the EPA and state regulatory agencies
require industries engaged in certain industrial or construction
activities to acquire permits and implement storm water
management plans and best management practices, to conduct
periodic monitoring and reporting of discharges, and to train
employees. Further, federal and state regulations require
certain oil and natural gas exploration and production
facilities to obtain permits for storm water discharges. There
are costs associated with each of these regulatory requirements.
In addition, federal and state regulatory agencies can impose
administrative, civil and potentially criminal penalties for
non-compliance with discharge permits or other requirements of
the Clean Water Act and analogous state laws and regulations.
The Oil Pollution Act of 1990, or OPA, which amends and augments
the Clean Water Act, establishes strict liability for owners and
operators of facilities that are the site of a release of oil
into waters of the United States. In addition, OPA and
regulations that implement OPA impose a variety of regulations
on responsible parties related to the prevention of oil spills
and liability for clean up and natural resource damages
resulting from such spills. For example, some of our facilities
in the Gulf Coast region must develop, implement and maintain
facility response plans, conduct annual spill training for
certain employees and provide varying degrees of financial
assurance.
National
Environmental Policy Act
Natural gas and oil exploration and production activities on
federal lands or otherwise requiring federal approval 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 may
19
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 is 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. The NEPA process has the
potential to delay or even prohibit our development of natural
gas and oil projects in covered areas.
Future
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 restrict or regulate emissions of
greenhouse gases. At least 17 states, as well as other
regions, have already taken legal measures to reduce emissions
of greenhouse gases, primarily through the planned development
of greenhouse gas emissions inventories and 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. The
courts holding in Massachusetts, et al. v. EPA,
that greenhouse gases fall under the federal Clean Air
Acts definition of air pollutant, may lead to
future regulation of greenhouse gas emissions from stationary
sources under certain Clean Air Act programs. Other nations have
already agreed to regulate emissions of greenhouse gases
pursuant to 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-related
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, may have
an adverse effect on demand for our services or products and may
result in compliance obligations with respect to the release,
capture and use of carbon dioxide that could have an adverse
effect on our operations.
Anti-Terrorism
Measures
The federal Department of Homeland Security Appropriations Act
of 2007 requires the Department of Homeland Security, or DHS, to
issue regulations establishing risk-based performance standards
for the security of chemical and industrial facilities,
including oil and gas facilities that are deemed to present
high levels of security risk. The DHS issued an
interim final rule in April 2007 regarding risk-based
performance standards to be attained pursuant to the act and, on
November 20, 2007, further issued an Appendix A to the
interim rules that establish chemicals of interest and their
respective threshold quantities that will trigger compliance
with these interim rules. We have not yet determined the extent
to which our facilities are subject to the interim rules or the
associated costs to comply, but it is possible that such costs
could be substantial.
Other
Regulation of the Natural Gas and Oil Industry
The natural gas and oil industry is extensively regulated by
numerous federal, state and local authorities, including Native
American tribes. Legislation affecting the natural gas and oil
industry is under constant review for amendment or expansion,
frequently increasing the regulatory burden. Also, numerous
departments and agencies, both federal and state, and Native
American tribes are authorized by statute to issue rules and
regulations binding on the natural gas and oil industry and its
individual members, some of which carry substantial penalties
for failure to comply. Although the regulatory burden on the
natural gas and oil industry increases our cost of doing
business and, consequently, affects our profitability, these
burdens generally do not affect us any differently or to any
greater or lesser extent than they affect other companies in the
industry with similar types, quantities and locations of
production.
Drilling
and Production
Our operations are subject to various types of regulation at
federal, state, local and Native American tribal levels. These
types of regulation include requiring permits for the drilling
of wells, drilling bonds and reports concerning operations. Most
states, and some counties, municipalities and Native American
tribes, in which we operate also regulate one or more of the
following:
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the location of wells;
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the method of drilling and casing wells;
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the rates of production or allowables;
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the surface use and restoration of properties upon which wells
are drilled;
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the plugging and abandoning of wells; and
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notice to surface owners and other third parties.
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State laws regulate the size and shape of drilling and spacing
units or proration units governing the pooling of natural gas
and oil properties. Some states allow forced pooling or
integration of tracts to facilitate exploration while other
states rely on voluntary pooling of lands and leases. In some
instances, forced pooling or unitization may be implemented by
third parties and may reduce our interest in the unitized
properties. In addition, state conservation laws establish
maximum rates of production from natural gas and oil wells,
generally prohibit the venting or flaring of natural gas and
impose requirements regarding the ratability of production.
These laws and regulations may limit the amount of natural gas
and oil we can produce from our wells or limit the number of
wells or the locations at which we can drill. 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.
Federal, state and local regulations provide detailed
requirements for the abandonment of wells, closure or
decommissioning of production facilities and pipelines, and for
site restoration, in areas where we operate. Minerals Management
Service of the U.S. Department of the Interior, or MMS,
Regulations require that owners and operators plug and abandon
wells and decommission and remove offshore facilities located in
federal offshore lease areas in a prescribed manner. The MMS
requires federal leaseholders to post performance bonds or
otherwise provide necessary financial assurances to provide for
such abandonment, decommissioning and removal. The Railroad
Commission of Texas has financial responsibility requirements
for owners and operators of facilities in state waters to
provide for similar assurances. The U.S. Army Corps of
Engineers, or ACOE, and many other state and local
municipalities have regulations for plugging and abandonment,
decommissioning and site restoration. Although the ACOE does not
require bonds or other financial assurances, some other state
agencies and municipalities do have such requirements.
Natural
Gas Sales Transportation
Historically, federal legislation and regulatory controls have
affected the price of the natural gas we produce and the manner
in which we market our production. The Federal Energy Regulatory
Commission, or FERC, has jurisdiction over the transportation
and sale for resale of natural gas in interstate commerce by
natural gas companies under the Natural Gas Act of 1938 and the
Natural Gas Policy Act of 1978. Since 1978, various federal laws
have been enacted which have resulted in the complete removal of
all price and non-price controls for sales of domestic natural
gas sold in first sales, which include all of our
sales of our own production.
FERC also 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. Commencing in 1985, FERC promulgated a
series of orders, regulations and rule makings that
significantly fostered competition in the business of
transporting and marketing gas. Today, interstate pipeline
companies are required to provide nondiscriminatory
transportation services to producers, marketers and other
shippers, regardless of whether such shippers are affiliated
with an interstate pipeline company. FERCs initiatives
have led to the development of a competitive, unregulated, open
access market for gas purchases and sales that permits all
purchasers of gas to buy gas directly from third-party sellers
other than pipelines. However, the natural gas industry
historically has been very heavily regulated; therefore, we
cannot guarantee that the less stringent regulatory approach
currently pursued by FERC and Congress will continue
indefinitely into the future nor can we determine what effect,
if any, future regulatory changes might have on our natural gas
related activities.
Under FERCs current regulatory regime, transmission
services must be provided on an open-access, nondiscriminatory
basis at cost-based rates or at market-based rates if the
transportation market at issue is sufficiently competitive.
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, FERC
recently 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.
Employees
As of December 31, 2007, we had 2,219 full-time
employees and 8 part-time employees, including more than
150 geologists, geophysicists, petroleum engineers, technicians,
land and regulatory professionals. Of our 2,227 employees,
335 are located at our headquarters in Oklahoma City, Oklahoma,
eight in Amarillo, Texas and the remaining 1,884 employees
are working in our various field offices and at our drilling
sites.
Offices
As of December 31, 2007 we lease 80,861 square feet of
office space in Oklahoma City, Oklahoma at 1601 N.W. Expressway,
where our principal offices are located. The term of the lease
expires on August 31, 2009. In July 2007, we purchased
property to serve
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as our future corporate headquarters. The 3.51-acre site
contains four buildings and is located in downtown Oklahoma
City, Oklahoma.
We also lease or sublease 28,887 square feet of office
space in Amarillo, Texas at 701 S. Taylor Street,
where our principal offices were previously located. The leases
expire in April 2009. We lease 6,725 square feet of office
space at 16801 Greenspoint Park Drive in Houston, Texas under a
lease expiring in January 2014. PetroSource currently leases
approximately 7,848 square feet in Midland, Texas under a
lease expiring in December 2008. We own two buildings in
Fort Stockton, Texas that combined total 9,292 square
feet. Adjacent to these buildings, we own approximately
31,620 square feet of office and shop space. We also own an
approximate 10,000 square foot office building in Midland,
Texas and own 4,358 square feet of office space and
6,240 square feet of shop space in Odessa, Texas. In
addition, we lease a field office located in Longview and
Odessa, Texas, Yukon, Oklahoma, Shreveport, Louisiana and Rifle,
Colorado.
Glossary
of Natural Gas and Oil Terms
The following is a description of the meanings of some of the
natural gas and oil industry terms used in this Annual Report on
Form 10-K.
2-D
seismic or
3-D
seismic. Geophysical data that depict the
subsurface strata in two dimensions or three dimensions,
respectively.
3-D seismic
typically provides a more detailed and accurate interpretation
of the subsurface strata than
2-D seismic.
Bbl. One stock tank barrel, or 42
U.S. gallons liquid volume, used in this report in
reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent,
determined using the ratio of six Mcf of natural gas to one Bbl
of crude oil, condensate or natural gas liquids.
Boe. Barrels of oil equivalent, with six
thousand cubic feet of natural gas being equivalent to one
barrel of oil.
Btu or British thermal unit. The quantity of
heat required to raise the temperature of one pound of water by
one degree Fahrenheit.
Completion. The process of treating a drilled
well followed by the installation of permanent equipment for the
production of natural gas or oil, or in the case of a dry hole,
the reporting of abandonment to the appropriate agency.
Condensate. Liquid hydrocarbons associated
with the production of a primarily natural gas reserve.
CO2. Carbon
Dioxide.
Developed acreage. The number of acres that
are allocated or assignable to productive wells or wells capable
of production.
Development well. A well drilled into a proved
natural gas or oil reservoir to the depth of a stratigraphic
horizon known to be productive.
Dry hole. A well found to be incapable of
producing hydrocarbons in sufficient quantities such that
proceeds from the sale of such production exceed production
expenses and taxes.
Environmental Assessment (EA). A study to
determine whether a federal action significantly affects the
environment, which federal agencies may be required by the
National Environmental Policy Act or similar state statutes to
undertake prior to the commencement of activities that would
constitute federal actions, such as natural gas and oil
exploration and production activities on federal lands.
Environmental Impact Statement. A more
detailed study of the environmental effects of a federal
undertaking and its alternatives than an EA, which may be
required by the National Environmental Policy Act or similar
state statutes, either after the EA has been prepared and
determined that the environmental consequences of a proposed
federal undertaking, such as natural gas and oil exploration and
production activities on federal lands, may be significant, or
without the initial preparation of an EA if a federal agency
anticipates that a proposed federal undertaking may
significantly impact the environment.
Exploratory well. A well drilled to find and
produce natural gas or oil reserves not classified as proved, to
find a new reservoir in a field previously found to be
productive of natural gas or oil in another reservoir or to
extend a known reservoir.
Field. An area consisting of either a single
reservoir or multiple reservoirs all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition.
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Gross acres or gross wells. The total acres or
wells, as the case may be, in which a working interest is owned.
High
CO2
gas. Natural gas that contains more than 10%
CO2
by volume.
Imbricate stacking. A geological formation
characterized by multiple layers lying lapped over each other.
MBbls. Thousand barrels of crude oil or other
liquid hydrocarbons.
Mcf. Thousand cubic feet of natural gas.
Mcf/d. Mcf per day.
Mcfe. Thousand cubic feet equivalent,
determined using the ratio of six Mcf of natural gas to one Bbl
of crude oil, condensate or natural gas liquids.
MmBbls. Million barrels of crude oil or other
liquid hydrocarbons.
Mmboe. Million barrels of oil equivalent.
MBtu. Thousand British Thermal Units.
MmBtu. Million British Thermal Units.
Mmcf. Million cubic feet of natural gas.
Mmcf/d. Mmcf per day.
Mmcfe. Million cubic feet equivalent,
determined using the ratio of six Mcf of natural gas to one Bbl
of crude oil, condensate or natural gas liquids.
Mmcfe/d. Mmcfe per day.
Net acres or net wells. The sum of the
fractional working interest owned in gross acres or gross wells,
as the case may be.
Plugging and abandonment. Refers to the
sealing off of fluids in the strata penetrated by a well so that
the fluids from one stratum will not escape into another or to
the surface. Regulations of all states require plugging of
abandoned wells.
Present value of future net revenues
(PV-10). The
present value of estimated future revenues to be generated from
the production of proved reserves, before income taxes,
calculated in accordance with SEC guidelines, net of estimated
production and future development costs, using prices and costs
as of the date of estimation without future escalation and
without giving effect to hedging activities, non-property
related expenses such as general and administrative expenses,
debt service and depreciation, depletion and amortization.
PV-10 is
calculated using an annual discount rate of 10%.
Productive well. A well that is found to be
capable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of the production exceed production
expenses and taxes.
Prospect. A specific geographic area which,
based on supporting geological, geophysical or other data and
also preliminary economic analysis using reasonably anticipated
prices and costs, is deemed to have potential for the discovery
of commercial hydrocarbons.
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
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contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as
economically productive on the basis of available geological and
engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir.
(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.
Pulling Units. Pulling units are used in
connection with completions and workover operations.
PV-10. See
Present value of future net revenues.
Rental Tools. A variety of rental tools and
equipment, ranging from trash trailers to blow out preventors to
sand separators, for use in the oil field.
Reservoir. A porous and permeable underground
formation containing a natural accumulation of producible
natural gas
and/or oil
that is confined by impermeable rock or water barriers and is
separate from other reservoirs.
Roustabout Services. The provision of manpower
to assist in conducting oil field operations.
Standardized Measure or Standardized Measure of Discounted
Future Net Cash Flows. The present value of
estimated future cash inflows from proved natural gas and oil
reserves, less future development and production costs and
future income tax expenses, discounted at 10% per annum to
reflect timing of future cash flows and using the same pricing
assumptions as were used to calculate
PV-10.
Standardized Measure differs from
PV-10
because Standardized Measure includes the effect of future
income taxes and asset retirement obligations on future net
revenues.
Stratigraphic play. An oil or natural gas
formation contained within an area created by permeability and
porosity changes characteristic of the alternating rock layer
that result from the sedimentation process.
Trucking. The provision of trucks to move our
drilling rigs from one well location to another and to deliver
water and equipment to the field.
Underbalanced drilling. The procedure used to
drill oil and gas wells where the pressure in the wellbore is
kept lower than the fluid pressure in the formation being
drilled.
Undeveloped acreage. Lease acreage on which
wells have not been drilled or completed to a point that would
permit the production of commercial quantities of natural gas
and oil regardless of whether such acreage contains proved
reserves.
Working interest. The operating interest that
gives the owner the right to drill, produce and conduct
operating activities on the property and receive a share of
production and requires the owner to pay a share of the costs of
drilling and production operations.
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Natural
gas and oil prices are volatile, and a decline in natural gas
and oil prices can significantly affect our financial results
and impede our growth.
Our revenue, profitability and cash flow depend upon the prices
and demand for natural gas and oil. The markets for these
commodities are very volatile. Even relatively modest drops in
prices can significantly affect our financial results and impede
our growth. Changes in natural gas and oil prices have a
significant impact on the value of our reserves and on our cash
flow. Prices for natural gas and oil may fluctuate widely in
response to relatively minor changes in the supply of and demand
for natural gas and oil and a variety of additional factors that
are beyond our control, such as:
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the domestic and foreign supply of natural gas and oil;
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the price of foreign imports;
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worldwide economic conditions;
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political and economic conditions in oil producing countries,
including the Middle East and South America;
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the ability of members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls;
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the level of consumer product demand;
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weather conditions;
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technological advances affecting energy consumption;
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availability of pipeline infrastructure, treating,
transportation and refining capacity;
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domestic and foreign governmental regulations and taxes; and
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the price and availability of alternative fuels.
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Lower natural gas and oil prices may not only decrease our
revenues on a per share basis, but also may reduce the amount of
natural gas and oil that we can produce economically. This may
result in our having to make substantial downward adjustments to
our estimated proved reserves.
Our
estimated reserves are based on many assumptions that may turn
out to be inaccurate. Any significant inaccuracies in these
reserve estimates or underlying assumptions will materially
affect the quantities and present value of our
reserves.
The process of estimating natural gas and oil reserves is
complex and inherently imprecise. It requires interpretations of
available technical data and many assumptions, including
assumptions relating to production rates and economic factors
such as natural gas and oil prices, drilling and operating
expenses, capital expenditures and availability of funds. Any
significant inaccuracies in these interpretations or assumptions
could materially affect the estimated quantities and present
value of reserves shown in this report. See Business and
Properties Our Business and Primary Operations
for information about our natural gas and oil reserves.
Actual future production, natural gas and oil prices, revenues,
taxes, development expenditures, operating expenses and
quantities of recoverable natural gas and oil 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 report. In addition, we may
adjust estimates of proved reserves to reflect production
history, results of exploration and development, prevailing
natural gas and oil prices and other factors, many of which are
beyond our control.
The
present value of future net cash flows from our proved reserves
will not necessarily be the same as the current market value of
our estimated natural gas and oil reserves.
We base the estimated discounted future net cash flows from our
proved reserves on prices and costs in effect on the day of
estimate. Actual future net cash flows from our natural gas and
oil properties also will be affected by factors such as:
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actual prices we receive for natural gas and oil;
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actual cost of development and production expenditures;
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the amount and timing of actual production;
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supply of and demand for natural gas and oil; and
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changes in governmental regulations or taxation.
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The timing of both our production and our incurrence of expenses
in connection with the development and production of natural gas
and oil properties will affect the timing of actual future net
cash flows from proved reserves, and thus their actual present
value. In addition, the 10% discount factor we use when
calculating discounted future net cash flows may not be the most
appropriate discount factor based on interest rates in effect
from time to time and risks associated with us or the natural
gas and oil industry in general.
Unless
we replace our natural gas and oil reserves, our reserves and
production will decline, which would adversely affect our
business, financial condition and results of
operations.
Our future natural gas and oil reserves and production, and
therefore our cash flow and income, are highly dependent on our
success in efficiently developing and exploiting our current
reserves and economically finding or acquiring additional
recoverable reserves. We may not be able to develop, find or
acquire additional reserves to replace our current and future
production at acceptable costs.
Our
potential drilling location inventories are scheduled over
several years, making them susceptible to uncertainties that
could materially alter the occurrence or timing of their
drilling.
As of December 31, 2007, only 771 of our 4,594 identified
potential future well locations were attributed proved
undeveloped reserves. These potential drilling locations,
including those without proved undeveloped reserves, represent a
significant part of our growth strategy. Our ability to drill
and develop these locations is subject to a number of
uncertainties, including the availability of capital, seasonal
conditions, regulatory approvals, natural gas and oil prices,
costs and drilling results. Because of these uncertainties, we
do not know if the numerous potential drilling locations we have
will ever be drilled or if we will be able to produce natural
gas or oil from these or any other potential drilling locations.
As such, our actual drilling activities may materially differ
from our current expectations, which could adversely affect our
business.
We
will not know conclusively prior to drilling whether natural gas
or oil will be present in sufficient quantities to be
economically viable.
We describe some of our current prospects and drilling locations
and our plans to explore those prospects and drilling locations
in this
Form 10-K.
A prospect is a property on which we have identified what our
geoscientists believe, based on available seismic and geological
information, to be indications of natural gas or oil. Our
prospects and drilling locations are in various stages of
evaluation, ranging from a prospect that is ready to drill to a
prospect that will require substantial additional seismic data
processing and interpretation.
The use of seismic data and other technologies and the study of
producing fields in the same area will not enable us to know
conclusively prior to drilling whether oil or natural gas will
be present or, if present, whether oil or natural gas will be
present in sufficient quantities to be economically viable. Even
if sufficient amounts of oil or natural gas exist, we may damage
the potentially productive hydrocarbon bearing formation or
experience mechanical difficulties while drilling or completing
the well, resulting in a reduction in production from the well
or abandonment of the well. During 2007, we participated in
drilling a total of 316 gross wells, of which eight have
been identified as dry holes. If we drill additional wells that
we identify as dry holes in our current and future prospects,
our drilling success rate may decline and materially harm our
business. In sum, the cost of drilling, completing and operating
any well is often uncertain, and new wells may not be productive.
Properties
that we buy may not produce as projected, and we may be unable
to determine reserve potential, identify liabilities associated
with the properties or obtain protection from sellers against
them.
Our reviews of properties we acquire are inherently incomplete
because it generally is not feasible to review in depth every
individual property involved in each acquisition. Even a
detailed review of records and properties may not necessarily
reveal existing or potential problems, nor will it permit a
buyer to become sufficiently familiar with the properties to
assess fully their deficiencies and potential. Inspections may
not always be performed on every well, and environmental
problems, such as soil or ground water contamination, are not
necessarily observable even when an inspection is undertaken.
Even when problems are identified, we often assume certain
environmental and other risks and liabilities in connection with
acquired properties, which risks and liabilities could have a
material adverse effect on our results of operations and
financial condition.
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The
development of the proved undeveloped reserves in the WTO and
other areas of operation may take longer and may require higher
levels of capital expenditures than we currently
anticipate.
Approximately 55.3% of the estimated proved reserves that we own
or have under lease in the WTO as of December 31, 2007 are
proved undeveloped reserves and 56.1% of our total reserves are
proved undeveloped reserves. Development of these reserves may
take longer and require higher levels of capital expenditures
than we currently anticipate. Therefore, ultimate recoveries
from these fields may not match current expectations. Delays in
the development of our reserves or increases in costs to drill
and develop such reserves will reduce the
PV-10 value
of our estimated proved undeveloped reserves and future net
revenues estimated for such reserves.
A
significant portion of our operations are located in WTO, making
us vulnerable to risks associated with operating in one major
geographic area.
As of December 31, 2007, approximately 60.8% of our proved
reserves and approximately 42.1% of our production were located
in the WTO. In addition, a substantial portion of our WTO
natural gas contains a high concentration of
CO2
and requires treating. As a result, we may be disproportionately
exposed to the impact of delays or interruptions of production
from these wells caused by transportation and treatment capacity
constraints, curtailment of production or treatment plant
closures for scheduled maintenance or unanticipated occurrences.
Many
of our prospects in the WTO may contain natural gas that is high
in CO2 content, which can negatively affect our
economics.
The reservoirs of many of our prospects in the WTO may contain
natural gas that is high in
CO2
content. The natural gas produced from these reservoirs must be
treated for the removal of
CO2
prior to marketing. If we cannot obtain sufficient capacity at
treatment facilities for our natural gas with a high
CO2
concentration, or if the cost to obtain such capacity
significantly increases, we could be forced to delay production
and development or experience increased production costs.
Furthermore, when we treat the gas for the removal of
CO2,
some of the methane is used to run the treatment plant as fuel
gas and other methane and heavier hydrocarbons, such as ethane,
propane and butane, cannot be separated from the
CO2
and is lost. This is known as plant shrink. Historically our
plant shrink has been approximately 14% in the WTO. We do not
know the amount of
CO2
we will encounter in any well until it is drilled. As a result,
sometimes we encounter
CO2
levels in our wells that are higher than expected. The amount of
CO2
in the gas produced affects the heating content of the gas. For
example, if a well is 65%
CO2,
the gas produced often has a heating content of between 300 and
350 MBtu per Mcf. Giving consideration for plant shrink, as
many as four Mcf of high
CO2
gas must be produced to sell one MmBtu of natural gas. We report
our volumes of natural gas reserves and production net of
CO2
volumes that are removed prior to sales.
Since the treatment expenses are incurred on an Mcf basis, we
will incur a higher effective treating cost per MmBtu of natural
gas sold for natural gas with a higher
CO2
content. As a result, high
CO2
gas wells must produce at much higher rates than low
CO2
gas wells to be economic, especially in a low natural gas price
environment.
A
significant decrease in natural gas production in our areas of
midstream gas services operation, due to the decline in
production from existing wells, depressed commodity prices or
otherwise, would adversely affect our revenues and cash flow for
our midstream gas services segment.
The profitability of our midstream business is materially
impacted by the volume of natural gas we gather, transmit and
process at our facilities. Most of the reserves backing up our
midstream assets are operated by our exploration and production
segment. A material decrease in natural gas production in our
areas of operation would result in a decline in the volume of
natural gas delivered to our pipelines and facilities for
gathering, transmitting and processing. We have no control over
many factors affecting production activity, including prevailing
and projected energy prices, demand for hydrocarbons, the level
of reserves, geological considerations, governmental regulation
and the availability and cost of capital. Failure to connect new
wells to our gathering systems would result in the amount of
natural gas we gather, transmit and process being reduced
substantially over time and could, upon exhaustion of the
current wells, cause us to abandon our gathering systems and,
possibly cease gathering, transmission and processing
operations. Our ability to connect to new wells will be
dependent on the level of drilling activity in our areas of
operations and competitive market factors. The effect of any
material decrease in the volume of natural gas handled by our
midstream assets would be to reduce our revenues, operating
income and cash flows.
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Our
use of 2-D
and 3-D
seismic data is subject to interpretation and may not accurately
identify the presence of natural gas and oil, which could
adversely affect the results of our drilling
operations.
A significant aspect of our exploration and development plan
involves seismic data. Even when properly used and interpreted,
2-D and
3-D seismic
data and visualization techniques are only tools used to assist
geoscientists in identifying subsurface structures and
hydrocarbon indicators and do not enable the interpreter to know
whether hydrocarbons are present in those structures. Other
geologists and petroleum professionals, when studying the same
seismic data, may have significantly different interpretations
than our professionals.
In addition, the use of
2-D and
3-D seismic
and other advanced technologies requires greater predrilling
expenditures than traditional drilling strategies, and we could
incur losses due to such expenditures. As a result, our drilling
activities may not be geologically successful or economical, and
our overall drilling success rate or our drilling success rate
for activities in a particular area may not improve.
We often gather
2-D and
3-D seismic
data over large areas. Our interpretation of seismic data
delineates for us those portions of an area that we believe are
desirable for drilling. Therefore, we may choose not to acquire
option or lease rights prior to acquiring seismic data, and in
many cases, we may identify hydrocarbon indicators before
seeking option or lease rights in the location. If we are not
able to lease those locations on acceptable terms, it would
result in our having made substantial expenditures to acquire
and analyze
2-D and
3-D data
without having an opportunity to attempt to benefit from those
expenditures.
Drilling
for and producing natural gas and oil are high risk activities
with many uncertainties that could adversely affect our
business, financial condition or results of
operations.
Our drilling and operating activities are subject to many risks,
including the risk that we will not discover commercially
productive reservoirs. Drilling for natural gas and oil can be
unprofitable, not only from dry holes, but from productive wells
that do not produce sufficient revenues to return a profit. In
addition, our drilling and producing operations may be
curtailed, delayed or canceled as a result of other factors,
including:
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unusual or unexpected geological formations and miscalculations;
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pressures;
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fires;
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blowouts;
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loss of drilling fluid circulation;
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title problems;
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facility or equipment malfunctions;
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unexpected operational events;
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shortages of skilled personnel;
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shortages or delivery delays of equipment and services;
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compliance with environmental and other regulatory
requirements; and
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adverse weather conditions.
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Any of these risks can cause substantial losses, including
personal injury or loss of life; damage to or destruction of
property, natural resources and equipment; pollution;
environmental contamination or loss of wells; and regulatory
fines or penalties.
Insurance against all operational risks is not available to us.
Additionally, we may elect not to obtain insurance if we believe
that the cost of available insurance is excessive relative to
the perceived risks presented. We do not carry environmental
insurance, for example. We could incur losses for uninsurable or
uninsured risks or in amounts in excess of existing insurance
coverage. The occurrence of an event that is not covered in full
or in part by insurance could have a material adverse impact on
our business activities, financial condition and results of
operations.
28
Market
conditions or operational impediments may hinder our access to
natural gas and oil markets or delay our
production.
Market conditions or a lack of satisfactory natural gas and oil
transportation arrangements may hinder our access to natural gas
and oil markets or delay our production. The availability of a
ready market for our natural gas and oil production depends on a
number of factors, including the demand for and supply of
natural gas and oil and the proximity of reserves to pipelines
and terminal facilities. Our ability to market our production
depends in substantial part on the availability and capacity of
gathering systems, pipelines and processing facilities. For
example, we are currently experiencing capacity limitations on
sour gas treating in the Piñon Field. Our failure to obtain
such services on acceptable terms or expand our midstream assets
could materially harm our business. We may be required to shut
in wells for a lack of a market or because access to natural gas
pipelines, gathering system capacity or processing facilities
may be limited or unavailable. If that were to occur, then we
would be unable to realize revenue from those wells until
production arrangements were made to deliver the production to
market.
Our
development and exploration operations require substantial
capital and we may be unable to obtain needed capital or
financing on satisfactory terms, which could lead to a loss of
properties and a decline in our natural gas and oil
reserves.
The natural gas and oil industry is capital intensive. We make
and expect to continue to make substantial capital expenditures
in our business and operations for the exploration, development,
production and acquisition of natural gas and oil reserves. To
date, we have financed capital expenditures primarily with
proceeds from the sale of equity, debt and cash generated by
operations. We intend to finance our future capital expenditures
with the sale of equity, asset sales, cash flow from operations
and current and new financing arrangements. Our cash flow from
operations and access to capital are subject to a number of
variables, including:
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|
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|
|
our proved reserves;
|
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|
|
the level of natural gas and oil we are able to produce from
existing wells;
|
|
|
|
the prices at which natural gas and oil are sold; and
|
|
|
|
our ability to acquire, locate and produce new reserves.
|
If our revenues decrease as a result of lower natural gas and
oil prices, operating difficulties, declines in reserves or for
any other reason, we may have limited ability to obtain the
capital necessary to sustain our operations at current levels.
In order to fund our capital expenditures, we must seek
additional financing. Our senior credit facility and term loan
contain covenants restricting our ability to incur additional
indebtedness without the consent of the lenders. Our lenders may
withhold this consent in their sole discretion.
In addition, we may not be able to obtain debt or equity
financing on terms favorable to us, or at all. The failure to
obtain additional financing could result in a curtailment of our
operations relating to exploration and development of our
prospects, which in turn could lead to a possible loss of
properties and a decline in our natural gas and oil reserves.
We
have a substantial amount of indebtedness, which may adversely
affect our cash flow and our ability to operate our
business.
As of December 31, 2007, our total indebtedness was
$1.1 billion, which represented approximately 38% of our
total capitalization. Our substantial level of indebtedness
increases the possibility that we may be unable to generate cash
sufficient to pay, when due, the principal of, interest on or
other amounts due in respect of our indebtedness. Our
substantial indebtedness, combined with our lease and other
financial obligations and contractual commitments, could have
other important consequences to us. For example, it could:
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|
|
make us more vulnerable to adverse changes in general economic,
industry and competitive conditions and adverse changes in
government regulation;
|
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|
|
require us to dedicate a substantial portion of our cash flow
from operations to payments on our indebtedness, thereby
reducing the availability of our cash flows to fund working
capital, capital expenditures, acquisitions and other general
corporate purposes;
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|
|
limit our flexibility in planning for, or reacting to, changes
in our business and the industry in which we operate;
|
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|
|
place us at a competitive disadvantage compared to our
competitors that are less leveraged and, therefore, may be able
to take advantage of opportunities that our leverage prevents us
from pursuing; and
|
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|
|
limit our ability to borrow additional amounts for working
capital, capital expenditures, acquisitions, debt service
requirements, execution of our business strategy or other
purposes.
|
29
Any of the above listed factors could materially adversely
affect our business, financial condition and results of
operations.
Our
senior credit facility and term loan have restrictions and
financial covenants which could adversely affect our
operations.
We will depend on our senior credit facility for a portion of
future capital needs. The senior credit facility and term loan
restrict our ability to obtain additional financing, make
investments, lease equipment, sell assets and engage in business
combinations. We also are required to comply with certain
financial covenants and ratios. Our ability to comply with these
restrictions and covenants in the future is uncertain and will
be affected by the levels of cash flow from our operations and
events or circumstances beyond our control. Our failure to
comply with any of the restrictions and covenants under the
senior credit facility, term loan or other debt financing could
result in a default under those facilities, which could cause
all of our existing indebtedness to be immediately due and
payable.
The senior credit facility limits the amounts we can borrow to a
borrowing base amount, determined by the lender in its sole
discretion on a semi-annual basis, based upon projected revenues
from the natural gas and oil properties securing our loan. The
lender can unilaterally adjust the borrowing base and the
borrowings permitted to be outstanding under the senior credit
facility, and any increase in the borrowing base requires its
consent. Outstanding borrowings in excess of the borrowing base
must be repaid immediately, or we must pledge other natural gas
and oil properties as additional collateral. We do not currently
have any substantial unpledged properties, and we may not have
the financial resources in the future to make any mandatory
principal prepayments required under the senior credit facility.
Our
derivative activities could result in financial losses or could
reduce our earnings.
To achieve a more predictable cash flow and to reduce our
exposure to adverse fluctuations in the prices of natural gas
and oil, we currently, and may in the future, enter into
derivative instruments for a portion of our natural gas and oil
production, including collars and fixed-price swaps. We have not
designated any of our derivative instruments as hedges for
accounting purposes and record all derivative instruments on our
balance sheet at fair value. Changes in the fair value of our
derivative instruments are recognized in current earnings.
Accordingly, our earnings may fluctuate significantly as a
result of changes in fair value of our derivative instruments.
Derivative instruments also expose us to the risk of financial
loss in some circumstances, including when:
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|
|
|
production is less than expected;
|
|
|
|
the counter-party to the derivative instrument defaults on its
contract obligations; or
|
|
|
|
there is a change in the expected differential between the
underlying price in the derivative instrument and actual prices
received.
|
In addition, these types of derivative arrangements limit the
benefit we would receive from increases in the prices for
natural gas and oil and may expose us to cash margin
requirements.
Competition
in the natural gas and oil industry is intense, which may
adversely affect our ability to succeed.
The natural gas and oil industry is intensely competitive, and
we compete with companies that have greater resources. Many of
these companies not only explore for and produce natural gas and
oil, but also carry on refining operations and market petroleum
and other products on a regional, national or worldwide basis.
These companies may be able to pay more for productive natural
gas and oil properties and exploratory prospects or identify,
evaluate, bid for and purchase a greater number of properties
and prospects than our financial or human resources permit. In
addition, these companies may have a greater ability to continue
exploration activities during periods of low natural gas and oil
market prices. Our larger competitors may be able to absorb the
burden of present and future federal, state, local and other
laws and regulations more easily than we can, which would
adversely affect our competitive position. Our ability to
acquire additional properties and to discover reserves in the
future will be dependent upon our ability to evaluate and select
suitable properties and to consummate transactions in a highly
competitive environment. In addition, because we have fewer
financial and human resources than many companies in our
industry, we may be at a disadvantage in bidding for exploratory
prospects and producing natural gas and oil properties.
Downturns in natural gas and oil prices can result in decreased
oil field activity which, in turn, can result in an oversupply
of service providers and drilling rigs. This oversupply can
result in severe reductions in prices received for oil field
services or a complete lack of work for crews and equipment.
30
We are
subject to complex federal, state, local and other laws and
regulations that could adversely affect the cost, manner or
feasibility of conducting our operations.
Our natural gas and oil exploration, production, transportation
and treatment 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 and local governmental authorities. We
may incur substantial costs in order to maintain compliance with
these existing laws and regulations. In addition, our costs of
compliance may increase if existing laws and regulations are
revised or reinterpreted, or if new laws and regulations become
applicable to our operations. For instance, we may be unable to
obtain all necessary permits, approvals and certificates for
proposed projects. Alternatively, we may have to incur
substantial expenditures to obtain, maintain or renew
authorizations to conduct existing projects. If a project is
unable to function as planned due to changing requirements or
public opposition, we may suffer expensive delays, extended
periods of non-operation or significant loss of value in a
project. All such costs may have a negative effect on our
business and results of operations.
Our business is subject to federal, state and local laws and
regulations as interpreted and enforced by governmental agencies
and other bodies vested with much authority relating to the
exploration for, and the development, production and
transportation of, natural gas and oil. Failure to comply with
such laws and regulations, as interpreted and enforced, could
have a material adverse effect on us. For instance, the
U.S. Department of the Interiors Minerals Management
Service (MMS) may suspend or terminate our
operations on federal leases for failure to pay royalties or
comply with safety and environmental regulations.
Our
operations expose us to potentially substantial costs and
liabilities with respect to environmental, health and safety
matters.
We may incur substantial costs and liabilities as a result of
environmental, health and safety requirements applicable to our
natural gas and oil exploration, development, production,
transportation, treatment, and other activities. These costs and
liabilities could arise under a wide range of environmental,
health and safety laws that cover, among other things, emissions
into the air and water, habitat and endangered species
protection, the containment and disposal of hazardous
substances, oil field waste and other waste materials, the use
of underground injection wells, and wetlands protection. These
laws and regulations are complex, change frequently and have
tended to become increasingly strict over time. Failure to
comply with environmental, health and safety laws or regulations
may result in assessment of administrative, civil, and criminal
penalties, imposition of cleanup and site restoration costs and
liens, and the issuance of orders enjoining or limiting our
current or future operations. Compliance with these laws and
regulations also increases the cost of our operations and may
prevent or delay the commencement or continuance of a given
operation. Specifically, we may incur increased expenditures in
the future in order to maintain compliance with laws and
regulations governing emissions of air pollutants from our
natural gas treatment plants. See Business and
Properties Environmental Matters and
Regulation.
Under certain environmental laws that impose strict, joint and
several liability, we may be required to remediate our
contaminated properties regardless of whether such contamination
resulted from the conduct of others or from consequences of our
own actions that were or were not in compliance with all
applicable laws at the time those actions were taken. In
addition, claims for damages to persons or property may result
from environmental and other impacts of our operations.
Moreover, new or modified environmental, health or safety laws,
regulations or enforcement policies could be more stringent and
impose unforeseen liabilities or significantly increase
compliance costs. Therefore, the costs to comply with
environmental, health or safety laws or regulations or the
liabilities incurred in connection with them could significantly
and adversely affect our business, financial condition or
results of operations. In addition, many countries as well as
several states and regions of the U.S. have agreed to
regulate emissions of greenhouse gases. Methane, a
primary component of natural gas, and carbon dioxide, a
byproduct of burning of natural gas and oil, are greenhouse
gases. Regulation of greenhouse gases could adversely impact
some of our operations and demand for some of our services or
products in the future. See Business
Environmental Matters and Regulation.
If we
fail to maintain an adequate system of internal control over
financial reporting this could adversely affect our ability to
accurately report our results.
We are not currently required to comply with Section 404 of
the Sarbanes Oxley Act of 2002, and are therefore not required
to make an assessment of the effectiveness of our internal
controls over financial reporting for that purpose. Management
is responsible for establishing and maintaining adequate
internal control over financial reporting. Our internal control
over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements in
accordance with generally accepted accounting principles. A
material weakness is a deficiency, or a combination of
deficiencies, in our internal control over financial reporting
that results in a reasonable possibility that a material
misstatement of the annual or interim financial statements will
not be prevented or detected on a timely basis. Effective
internal controls are necessary for us to provide reliable
financial reports and effectively prevent fraud. If we cannot
provide reliable financial reports or prevent fraud,
31
our reputation and operating results would be harmed. Our
efforts to develop and maintain our internal controls may not be
successful, and we may be unable to maintain adequate controls
over our financial processes and reporting in the future,
including future compliance with the obligations under
Section 404 of the Sarbanes-Oxley Act of 2002. We will be
required to comply with Section 404 of the Sarbanes-Oxley
Act of 2002 effective as of December 31, 2008. Any failure
to develop or maintain effective controls, or difficulties
encountered in their implementation or other effective
improvement of our internal controls could harm our operating
results. Ineffective internal controls could also cause
investors to lose confidence in our reported financial
information.
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Item 1B.
|
Unresolved
Staff Comments
|
None.
Information regarding our properties is included in Item 1
and in Note 6 of the notes to our consolidated financial
statements included in Item 8 of this report.
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Item 3.
|
Legal
Proceedings
|
The Company is a defendant in lawsuits from time to time in the
normal course of business. In managements opinion, the
Company is not currently involved in any legal proceedings
which, individually or in the aggregate, could have a material
effect on the financial condition, operations
and/or cash
flows of the Company.
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Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
Not applicable.
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
|
Price
Range of Common Stock
Following our initial public offering, our common stock
commenced trading on the New York Stock Exchange under the
symbol SD on November 6, 2007. Prior to
November 6, 2007, there was no active market for our common
stock. For the period November 6, 2007 to December 31,
2007, the high and low sales prices per share of our common
stock as reported by the New York Stock Exchange were $36.11 per
share and $29.53 per share, respectively.
At February 29, 2007, there were 503 holders of record
of our common stock and approximately 10,532 beneficial
owners.
We do not anticipate declaring or paying any cash dividends to
holders of our common stock in the foreseeable future. We
currently intend to retain all available funds and any future
earnings for use in the operation and expansion of our business,
including exploration, development and acquisition activities.
The terms of our revolving credit facility and senior term loans
restrict our ability to pay dividends to holders of common
stock. The certificate of designation for our convertible
preferred stock also prohibits the payment of dividends to
holders of our common stock without the consent of holders of a
majority of our outstanding convertible preferred stock.
Accordingly, if our dividend policy were to change in the
future, our ability to pay dividends would be subject to these
restrictions and our then existing conditions, including our
results of operations, financial condition, contractual
obligations, capital requirements, business prospects and other
factors deemed relevant by our board of directors. This
transaction did not involve any underwriter or a public
offering, and we believe this transaction was exempt from
registration requirements pursuant to Section 4(2) of the
Securities Act and Regulation D promulgated thereunder.
Recent
Sales of Unregistered Securities
On March 20, 2007, we sold approximately 17.8 million
shares of our common stock for net proceeds of
$318.7 million, after deducting offering expenses of
approximately $1.4 million. The stock was sold in private
sales as follows: 11.1 million shares to affiliates of Ares
Management LLC (Ares), a private institutional
investment firm, for $200 million, and 2.8 million
shares to an affiliate of Tom L. Ward, the Companys
Chairman, Chief Executive Officer and largest stockholder for
$50 million. In addition to the 13.9 million shares
sold to Ares and the affiliate of Mr. Ward, holders of the
Companys outstanding Series A Convertible Preferred
Shares and Common Units exercised preemptive rights resulting in
the sale of an additional 3.9 million shares for
$70 million. An affiliate of Mr. Ward exercised the
right to acquire 0.6 million of the preemptive shares for
$11.4 million, bringing the total shares purchased by
Mr. Wards affiliates to 3.4 million shares at a
purchase price of $61.4 million. All shares were sold at
$18 per share.
32
Use of
Proceeds from Sales of Registered Securities
On November 9, 2007, we completed the initial public
offering of our common stock. We sold 32,379,500 shares at
a price of $26 per share. We received net proceeds of
approximately $794.7 million after deducting underwriting
discounts and offering expenses of approximately
$47.1 million. We used the net proceeds to repay the
outstanding indebtedness under our senior credit facility
($515.9 million), to repay a note related to a recent
acquisition ($49.1 million), and to fund the remainder of
our 2007 capital expenditure program and a portion of our 2008
capital expenditure program ($229.7 million).
Issuer
Purchases of Equity Securities
As part of our restricted stock plan, we make required tax
payments on behalf of employees as their stock awards vest and
then withhold a number of vested shares having a value on the
date of vesting equal to the tax obligation. The shares withheld
were recorded as treasury shares. During the period
November 5, 2007 to December 31, 2007, we purchased
the following shares:
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|
|
|
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|
Total Number of
|
|
|
Maximum Number
|
|
|
|
|
|
|
|
|
|
Shares Purchased
|
|
|
of Shares that May
|
|
|
|
|
|
|
|
|
|
as Part of Publicly
|
|
|
Yet Be Purchased
|
|
|
|
Total Number of
|
|
|
Average Price
|
|
|
Announced Plans
|
|
|
Under the Plans or
|
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Period
|
|
Shares Purchased
|
|
|
Paid per Share
|
|
|
or Programs
|
|
|
Programs
|
|
|
November 5-30
|
|
|
1,098
|
|
|
$
|
31.88
|
|
|
|
N/A
|
|
|
|
N/A
|
|
December 1-31
|
|
|
|
|
|
|
|
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|
N/A
|
|
|
|
N/A
|
|
|
|
Item 6.
|
Selected
Financial Data
|
The following table sets forth, as of the dates and for the
periods indicated, our selected financial information. Our
financial information is derived from our audited consolidated
financial statements for such periods. The financial data
includes the results of the acquisition of NEG effective
November 21, 2006. The information should be read in
conjunction with Managements Discussion and Analysis
of Financial Condition and Results of Operations and our
consolidated financial statements and notes thereto contained in
this document. The following information is not necessarily
indicative of our future results.
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|
|
|
|
|
|
|
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|
|
|
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|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands, except per share data)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
677,452
|
|
|
$
|
388,242
|
|
|
$
|
287,693
|
|
|
$
|
175,995
|
|
|
$
|
155,337
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
106,192
|
|
|
|
35,149
|
|
|
|
16,195
|
|
|
|
10,230
|
|
|
|
7,980
|
|
Production taxes
|
|
|
19,557
|
|
|
|
4,654
|
|
|
|
3,158
|
|
|
|
2,497
|
|
|
|
2,099
|
|
Drilling and services
|
|
|
44,211
|
|
|
|
98,436
|
|
|
|
52,122
|
|
|
|
26,442
|
|
|
|
13,847
|
|
Midstream marketing
|
|
|
94,253
|
|
|
|
115,076
|
|
|
|
141,372
|
|
|
|
96,180
|
|
|
|
94,620
|
|
Depreciation, depletion and amortization natural gas
and crude oil
|
|
|
173,568
|
|
|
|
26,321
|
|
|
|
9,313
|
|
|
|
4,909
|
|
|
|
3,298
|
|
Depreciation, depletion and amortization other
|
|
|
53,541
|
|
|
|
29,305
|
|
|
|
14,893
|
|
|
|
7,765
|
|
|
|
5,284
|
|
General and administrative
|
|
|
61,780
|
|
|
|
55,634
|
|
|
|
11,908
|
|
|
|
6,554
|
|
|
|
3,705
|
|
Loss (gain) on derivative contracts
|
|
|
(60,732
|
)
|
|
|
(12,291
|
)
|
|
|
4,132
|
|
|
|
878
|
|
|
|
3,450
|
|
Loss (gain) on sale of assets
|
|
|
(1,777
|
)
|
|
|
(1,023
|
)
|
|
|
547
|
|
|
|
(210
|
)
|
|
|
(1,284
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
490,593
|
|
|
|
351,261
|
|
|
|
253,640
|
|
|
|
155,245
|
|
|
|
132,999
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
186,859
|
|
|
|
36,981
|
|
|
|
34,053
|
|
|
|
20,750
|
|
|
|
22,338
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands, except per share data)
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
5,423
|
|
|
|
1,109
|
|
|
|
206
|
|
|
|
56
|
|
|
|
103
|
|
Interest expense
|
|
|
(117,185
|
)
|
|
|
(16,904
|
)
|
|
|
(5,277
|
)
|
|
|
(1,678
|
)
|
|
|
(1,208
|
)
|
Minority interest
|
|
|
276
|
|
|
|
(296
|
)
|
|
|
(737
|
)
|
|
|
(262
|
)
|
|
|
(96
|
)
|
Income (loss) from equity investments
|
|
|
4,372
|
|
|
|
967
|
|
|
|
(384
|
)
|
|
|
(36
|
)
|
|
|
1,056
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(107,114
|
)
|
|
|
(15,124
|
)
|
|
|
(6,192
|
)
|
|
|
(1,920
|
)
|
|
|
(145
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
79,745
|
|
|
|
21,857
|
|
|
|
27,861
|
|
|
|
18,830
|
|
|
|
22,193
|
|
Income tax expense
|
|
|
29,524
|
|
|
|
6,236
|
|
|
|
9,968
|
|
|
|
6,433
|
|
|
|
7,585
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
50,221
|
|
|
|
15,621
|
|
|
|
17,893
|
|
|
|
12,397
|
|
|
|
14,608
|
|
Income (loss) from discontinued operations, net of tax
|
|
|
|
|
|
|
|
|
|
|
229
|
|
|
|
451
|
|
|
|
(85
|
)
|
Cumulative effect of accounting change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,636
|
)
|
Extraordinary gain
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
50,221
|
|
|
|
15,621
|
|
|
|
18,122
|
|
|
|
25,392
|
|
|
|
12,887
|
|
Preferred stock dividends and accretion
|
|
|
39,888
|
|
|
|
3,967
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available (applicable) to common stockholders
|
|
$
|
10,333
|
|
|
$
|
11,654
|
|
|
$
|
18,122
|
|
|
$
|
25,392
|
|
|
$
|
12,887
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Historical
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004(2)
|
|
|
2003(1)
|
|
|
|
(In thousands, except per share data)
|
|
|
Earnings Per Share Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
0.46
|
|
|
$
|
0.21
|
|
|
$
|
0.31
|
|
|
$
|
0.22
|
|
|
$
|
0.26
|
|
Income (loss) from discontinued operations, net of income tax
|
|
|
|
|
|
|
|
|
|
|
0.01
|
|
|
|
0.01
|
|
|
|
|
|
Extraordinary gain on acquisition
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.22
|
|
|
|
|
|
Cumulative effect of change in accounting principle, net of
income tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.03
|
)
|
Preferred stock dividends
|
|
|
(0.37
|
)
|
|
|
(0.05
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per share available to common stockholders
|
|
$
|
0.09
|
|
|
$
|
0.16
|
|
|
$
|
0.32
|
|
|
$
|
0.45
|
|
|
$
|
0.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding(3):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
108,828
|
|
|
|
73,727
|
|
|
|
56,559
|
|
|
|
56,312
|
|
|
|
56,312
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
110,041
|
|
|
|
74,664
|
|
|
|
56,737
|
|
|
|
56,312
|
|
|
|
56,312
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We adopted the provisions of SFAS 143 Accounting for
Retirement Obligations, resulting in a cumulative effect
of change in accounting principal of $1.6 million. |
|
(2) |
|
We recognized an extraordinary gain from the recognition of the
excess of fair value over acquisition cost of $12.5 million
related to an acquisition we made in 2004. |
|
(3) |
|
The number of shares has been adjusted to reflect a 281.562-to-1
stock split in December 2005. |
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands)
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
63,135
|
|
|
$
|
38,948
|
|
|
$
|
45,731
|
|
|
$
|
12,973
|
|
|
$
|
176
|
|
Property, plant and equipment, net
|
|
$
|
3,337,410
|
|
|
$
|
2,134,718
|
|
|
$
|
337,881
|
|
|
$
|
114,818
|
|
|
$
|
70,289
|
|
Total assets
|
|
$
|
3,630,566
|
|
|
$
|
2,388,384
|
|
|
$
|
458,683
|
|
|
$
|
197,017
|
|
|
$
|
127,744
|
|
Long-term debt
|
|
$
|
1,067,649
|
|
|
$
|
1,066,831
|
|
|
$
|
43,133
|
|
|
$
|
59,340
|
|
|
$
|
24,740
|
|
Redeemable convertible preferred stock
|
|
$
|
450,715
|
|
|
$
|
439,643
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Total stockholders equity
|
|
$
|
1,766,891
|
|
|
$
|
649,818
|
|
|
$
|
289,002
|
|
|
$
|
59,330
|
|
|
$
|
33,940
|
|
Total liabilities and stockholders equity
|
|
$
|
3,630,566
|
|
|
$
|
2,388,384
|
|
|
$
|
458,683
|
|
|
$
|
197,017
|
|
|
$
|
127,744
|
|
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
Introduction
The following discussion and analysis is intended to help the
reader understand our business, financial condition, results of
operations, liquidity and capital resources. This discussion and
analysis is provided as a supplement to, and should be read in
conjunction with, the other sections of this Annual Report on
Form 10-K,
including: Items 1 and 2. Business and
Properties, Item 6. Selected Financial
Data, and Item 8. Financial Statements and
Supplementary Data. The following discussion contains
forward-looking statements that reflect our future plans,
estimates, beliefs and expected performance. The forward-looking
statements are dependent upon events, risks and uncertainties
that may be outside our control. Our actual results could differ
materially from those discussed in these forward-looking
statements. Factors that could cause or contribute to such
differences include, but are not limited to, market prices for
natural gas and oil, economic and competitive conditions,
regulatory changes, estimates of proved reserves, potential
failure to achieve production from development projects, capital
expenditures and other uncertainties, as well as those factors
discussed below and elsewhere in this Annual Report on
Form 10-K,
particularly in Item 1A - Risk Factors and
Cautionary Statement Concerning Forward-Looking
Statements below, all of which are difficult to predict.
In light of these risks, uncertainties and assumptions, the
forward-looking events discussed may not occur.
Overview
of Our Company
We are a rapidly expanding independent natural gas and oil
company concentrating on exploration, development and production
activities. We are focused on continuing the exploration and
exploitation of our significant holdings in the West Texas
Overthrust, which we refer to as the WTO, a natural gas prone
geological region where we have operated since 1986 that
includes the Piñon Field the South Sabino the Big Canyon
Prospect and other prospects that we are currently evaluating.
We also own and operate drilling rigs and conduct related oil
field services, and we own and operate interests in gas
gathering, marketing and processing facilities and
CO2
gathering and transportation facilities.
On November 21, 2006, we acquired all of the outstanding
membership interests in NEG Oil & Gas, LLC, or NEG,
for total consideration of approximately $1.5 billion,
excluding cash acquired. With core assets in the Val Verde and
Permian Basins of West Texas, including overlapping or
contiguous interests in the WTO, the NEG acquisition has
dramatically increased our exploration and production segment
operations. The NEG acquisition, coupled with numerous
acquisitions of additional working interests completed during
2007, 2006 and late 2005, have significantly increased our
holdings in the WTO. We also operate significant interests in
the Cotton Valley Trend in East Texas, the Gulf Coast area, the
Gulf of Mexico, Oklahoma and the Piceance Basin of Colorado.
During November 2007, we completed the initial public offering
of our common stock. We used the proceeds from this offering to
repay indebtedness outstanding under our senior credit facility
as well as a note payable related to a recent acquisition, to
fund the remainder of our 2007 capital expenditure program and a
portion of our 2008 capital expenditure program. See further
discussion of these transactions in Note 18 to the
consolidated financial statements contained in this
Form 10-K.
35
Segment
Overview
We operate in four related business segments: exploration and
production, drilling and oil field services, midstream gas
services and other. Management evaluates the performance of our
business segments based on operating income, which is computed
as segment operating revenue less direct operating costs. These
measurements provide important information to us about the
activity and profitability of our lines of business. Set forth
in the table below is financial information regarding each of
our current segments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Segment revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
478,747
|
|
|
$
|
106,413
|
|
|
$
|
54,051
|
|
Drilling and oil field services
|
|
|
73,202
|
|
|
|
138,657
|
|
|
|
80,151
|
|
Midstream gas services
|
|
|
107,578
|
|
|
|
122,892
|
|
|
|
147,499
|
|
Other
|
|
|
17,925
|
|
|
|
20,280
|
|
|
|
5,992
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
677,452
|
|
|
|
388,242
|
|
|
|
287,693
|
|
Segment operating income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
|
198,913
|
|
|
|
17,069
|
|
|
|
14,886
|
|
Drilling and oil field services
|
|
|
10,473
|
|
|
|
32,946
|
|
|
|
18,295
|
|
Midstream gas services
|
|
|
6,783
|
|
|
|
3,528
|
|
|
|
4,096
|
|
Other
|
|
|
(29,310
|
)
|
|
|
(16,562
|
)
|
|
|
(3,224
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating income
|
|
|
186,859
|
|
|
|
36,981
|
|
|
|
34,053
|
|
Interest income
|
|
|
5,423
|
|
|
|
1,109
|
|
|
|
206
|
|
Interest expense
|
|
|
(117,185
|
)
|
|
|
(16,904
|
)
|
|
|
(5,277
|
)
|
Other income (expense)
|
|
|
4,648
|
|
|
|
671
|
|
|
|
(1,121
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
$
|
79,745
|
|
|
$
|
21,857
|
|
|
$
|
27,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mmcf)
|
|
|
51,958
|
|
|
|
13,410
|
|
|
|
6,873
|
|
Oil (MBbls)
|
|
|
2,042
|
|
|
|
322
|
|
|
|
72
|
|
Combined equivalent volumes (Mmcfe)
|
|
|
64,211
|
|
|
|
15,342
|
|
|
|
7,305
|
|
Average daily combined equivalent volumes (Mmcfe/d)
|
|
|
175.9
|
|
|
|
42.0
|
|
|
|
20.0
|
|
Average prices- as reported(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
6.51
|
|
|
$
|
6.19
|
|
|
$
|
6.54
|
|
Oil (per Bbl)
|
|
$
|
68.12
|
|
|
$
|
56.61
|
|
|
$
|
48.19
|
|
Combined equivalent (per Mcfe)
|
|
$
|
7.45
|
|
|
$
|
6.60
|
|
|
$
|
6.63
|
|
Average prices- including impact of derivative contract
settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
7.18
|
|
|
$
|
7.25
|
|
|
$
|
6.54
|
|
Oil (per Bbl)
|
|
$
|
68.10
|
|
|
$
|
56.61
|
|
|
$
|
48.19
|
|
Combined equivalent (per Mcfe)
|
|
$
|
7.98
|
|
|
$
|
7.52
|
|
|
$
|
6.63
|
|
Drilling and oil field services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of operational drilling rigs owned at end of period
|
|
|
25
|
|
|
|
25
|
|
|
|
19
|
|
Average number of operational drilling rigs owned during the
period
|
|
|
26.0
|
|
|
|
21.9
|
|
|
|
14.3
|
|
Average drilling revenue per rig per day(2)
|
|
$
|
17,177
|
|
|
$
|
17,034
|
|
|
$
|
11,503
|
|
|
|
|
(1) |
|
Prices represent actual average prices for the periods presented
and do not give effect to derivative transactions. |
|
(2) |
|
Does not include revenues for related rental equipment. |
Exploration
and Production Segment
We explore for, develop and produce natural gas and oil
reserves, with a focus on our proved reserves and extensive
undeveloped acreage positions in the WTO. We operate
substantially all of our wells in our core areas and employ our
drilling rigs and other drilling services in the exploration and
development of our operated wells and, to a lesser extent, on
our non-operated wells.
36
The primary factors affecting the financial results of our
exploration and production segment are the prices we receive for
our natural gas and oil production, the quantity of our natural
gas and oil production and changes in the fair value of
derivative instruments we use to reduce the volatility of the
prices we receive for our natural gas and oil production.
Because we are vertically integrated, our exploration and
production activities affect the results of our oil field
service and midstream segments. The NEG acquisition in November
2006 substantially increased our revenues and operating income
in our exploration and production segment. However, because our
working interest in the Piñon Field increased to
approximately 93%, there are greater intercompany eliminations
that affect the consolidated financial results of our drilling
and oil field service and midstream gas services segments.
Exploration and production segment revenues increased to
$478.7 million in the year ended December 31, 2007
from $106.4 million in 2006, an increase of 350%, as a
result of a 320% increase in production volumes and a 13%
increase in the average price we received for the natural gas
and oil we produced. During 2007, we increased natural gas
production by 38.5 Bcf to 52.0 Bcf and increased crude
oil production by 1,720 MBbls to 2,042 MBbls. The
total combined 48.9 Bcfe increase in production was due
primarily to acquisitions and successful drilling in the WTO.
The average price we received for our natural gas production for
the year ended December 31, 2007 increased 5%, or $0.32 per
Mcf, to $6.51 per Mcf from $6.19 per Mcf in 2006. The average
price received for our crude oil production increased to $68.12
from $56.61 per Bbl in 2006. Including the impact of derivative
contract settlements, the effective price received for natural
gas for the year ended December 31, 2007 was $7.18 per Mcf
as compared to $7.25 per Mcf during the comparable period in
2006. Our oil derivative contract settlements decreased our
effective price received for oil by $0.02 per Bbl to $68.10 per
Bbl for the year ended December 31, 2007. Our derivative
contracts had no impact on effective oil prices during the year
ended December 31, 2006.
For the year ended December 31, 2007, we had
$198.9 million in operating income in our exploration and
production segment, compared to $17.1 million in operating
income in 2006. The $372.4 million increase in exploration
and production segment revenues was partially offset by a
$71.0 million increase in production expenses and a
$147.2 million increase in depreciation, depletion and
amortization, or DD&A. The increase in production expenses
was attributable to the additional properties acquired in the
NEG acquisition and operating expenses on our new wells. During
the year ended December 31, 2007, the exploration and
production segment reported a $60.7 million net gain on our
derivative positions ($34.5 million realized gains and
$26.2 million unrealized gains) compared to a
$12.3 million net gain ($14.2 million realized gains
and $1.9 million unrealized losses) in the comparable
period in 2006. During 2007, we selectively entered into natural
gas swaps and basis swaps by capitalizing on what we perceived
as spikes in the price of natural gas or favorable basis
differences between the NYMEX price and natural gas prices at
our principal West Texas pricing point of Waha Hub. Unrealized
gains or losses on derivative contracts represent the change in
fair value of open derivative positions during the period. The
change in fair value is principally measured based on period end
prices as compared to the contract price. Future volatility in
natural gas and oil prices could have an adverse effect on the
operating results of our exploration and production segment.
For the year ended December 31, 2006, exploration and
production segment revenues increased to $106.4 million
from $54.1 million in 2005. The increase in 2006 compared
to 2005 was attributable to increased production due to
successful drilling activity and approximately 40 days of
production from the NEG acquisition effective November 21,
2006. NEG contributed approximately $36.9 million of
revenues in the 2006 period. Production volumes increased to
15,342 Mmcfe in 2006 from 7,305 Mmcfe in 2005,
representing an 8,037 Mmcfe, or 110% increase.
Approximately 4,902 Mmcfe, or 61%, of the increase was
attributable to NEG production for the period from
November 21, 2006 to December 31, 2006. Average
combined prices were essentially unchanged at $6.60 per Mcfe as
compared to $6.63 per Mcfe in 2005.
Exploration and production segment operating income increased
$2.2 million in 2006 to $17.1 million from
$14.9 million in 2005. The increase was primarily
attributable to the increased production revenues described
above, approximately $12.3 million in derivative gains
(including a $1.9 million unrealized loss) in 2006 as
compared to a $4.1 million derivative loss (including a
$1.3 million unrealized loss) in 2005, and the addition of
NEG for the period from November 21, 2006 to
December 31, 2006. The increase in exploration and
production segment income was substantially offset by a
$20.5 million, or 106%, increase in production costs, a
$26.7 million, or 380%, increase in general and
administrative expenses and a $19.3 million increase in
DD&A. Approximately $7.0 million of the increase in
production costs was attributable to the NEG acquisition with
the remainder of the increase attributable to the increase in
the number of wells operated in 2006 as compared to 2005. The
increase in DD&A for our exploration and production segment
was attributable to higher production and the increase in the
full-cost pool due to the NEG acquisition.
As of December 31, 2007, we had 1,516.2 Bcfe of
estimated net proved reserves with a
PV-10 of
$3,550.5 million, while at December 31, 2006 we had
1,001.8 Bcfe of estimated net proved reserves with a
PV-10 of
$1,734.3 million. Our Standardized Measure of Discounted
Future Net Cash Flows was $2,718.5 million at
December 31, 2007 as compared to $1,440.2 million at
December 31, 2006 and $499.2 million at
December 31, 2005. For a discussion of
PV-10 and a
reconciliation to Standardized Measure of Discounted Net Cash
Flows, see Items 1 and 2. Business and
Properties. The increase in 2007 was primarily
attributable to
37
revisions of our previous estimates due to performance and
results of our drilling activity. The increase in 2006 was
primarily related to the addition of the NEG reserves which was
partially offset by a decrease in the price of natural gas to
$5.32 per Mcf at December 31, 2006 from $8.40 per Mcf at
December 31, 2005.
Estimates of net proved reserves are inherently imprecise. In
order to prepare our estimates, we must analyze available
geological, geophysical, production and engineering data and
project production rates and the timing of development
expenditures. The process also requires economic assumptions
about matters such as natural gas and oil prices, drilling and
operating expenses, capital expenditures, taxes and the
availability of funds. We may adjust estimates of proved
reserves to reflect production history, results of exploration
and development, prevailing natural gas and oil prices and other
factors, many of which are beyond our control. Approximately 97%
of our year-end reserve estimates are prepared by independent
petroleum reserve engineers.
Over the past several years, higher natural gas and oil prices
have led to higher demand for drilling rigs, operating personnel
and field supplies and services. Higher prices have also caused
increases in the costs of those goods and services. To date, the
higher sales prices have more than offset the higher field
costs. Our ownership of drilling rigs has also assisted us in
stabilizing our overall cost structure. Given the inherent
volatility of natural gas and oil prices that are influenced by
many factors beyond our control, we plan our activities and
budget based on conservative sales price assumptions, which
generally are lower than the average sales prices received in
2007. We focus our efforts on increasing natural gas reserves
and production while controlling costs at a level that is
appropriate for long-term operations. Our future earnings and
cash flows are dependent on our ability to manage our overall
cost structure to a level that allows for profitable production.
Like all exploration and production companies, we face the
challenge of natural production declines. As initial reservoir
pressures are depleted, natural gas and oil production from a
given well naturally decreases. Thus, a natural gas and oil
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 and
acquiring more reserves than we produce. Our future growth will
depend on our ability to continue to add reserves in excess of
production. We will maintain our focus on managing the costs
associated with adding reserves through drilling and
acquisitions as well as the costs associated with producing such
reserves. Our ability to add reserves through drilling is
dependent on our capital resources and can be limited by many
factors, including our ability to timely obtain drilling permits
and regulatory approvals. In the WTO, this has not posed a
problem. However, in other areas, the permitting and approval
process has been more difficult in recent years due to increased
activism from environmental and other groups. This has increased
the time it takes to receive permits in some locations.
Drilling
and Oil Field Services Segment
We drill for our own account primarily in the WTO through our
drilling and oil field services subsidiary, Lariat Services. We
also drill wells for other natural gas and oil companies,
primarily located in the West Texas region. Our oil field
services business conducts operations that complement our
drilling services operation. These services include providing
pulling units, trucking, rental tools, location and road
construction and roustabout services to ourselves and to third
parties. Additionally, we provide under-balanced drilling
systems only for our own account.
In October 2005, we and Clayton Williams Energy, Inc.
(CWEI) formed a limited partnership, Larclay, which
acquired twelve sets of rig components and other related
equipment to assemble into completed land drilling rigs. The
drilling rigs were to be used for drilling on CWEIs
prospects, our prospects or for contracting to third parties on
daywork drilling contracts. All of these rigs have been
delivered, although one rig has not been assembled. CWEI was
responsible for securing financing and the purchase of the rigs.
The partnership financed 100% of the acquisition cost of the
rigs utilizing a guarantee by CWEI. We operate the rigs owned by
the partnership. The partnership and CWEI are responsible for
all costs related to the initial construction and equipping of
the drilling rigs. In the event of an operating shortfall within
the partnership, we, along with CWEI are responsible to fund the
shortfall through loans to the partnership. We and CWEI each
have a 50% interest in Larclay. We account for Larclay as an
equity investment.
The financial results of our drilling and oil field services
segment depend on many factors, particularly the demand for and
the price we can charge for our services. We provide drilling
services for our own account and for others, generally on a
daywork or turnkey contract basis. Substantially all of our
drilling contract revenues are derived from daywork drilling
contracts. However, we generally assess the complexity and risk
of operations, the
on-site
drilling conditions, the type of equipment to be used, the
anticipated duration of the work to be performed and the
prevailing market rates in determining the contract terms we
offer.
Daywork Contracts. Under a daywork drilling
contract, we provide a drilling rig with required personnel to
our customer who supervises the drilling of the well. We are
paid based on a negotiated fixed rate per day while the rig is
used. Daywork drilling contracts specify the equipment to be
used, the size of the hole and the depth of the well. Under a
daywork drilling contract, the customer bears a large portion of
the out-of-pocket drilling costs, and we generally bear no part
of the usual risks associated with drilling, such as time delays
and unanticipated costs. As of December 31, 2007, 24 of our
rigs were operating under daywork contracts and 22 of these were
38
working for our account. As of December 31, 2007, the 10
operating rigs owned by Larclay were operating under daywork
contracts and seven of these were working for our account. The
remaining three operating Larclay rigs were working for CWEI as
of December 31, 2007.
Turnkey Contracts. Under a typical turnkey
contract, a customer will pay us to drill a well to a specified
depth and under specified conditions for a fixed price,
regardless of the time required or the problems encountered in
drilling the well. We provide most of the equipment and drilling
supplies required to drill the well. We subcontract for related
services such as the provision of casing crews, cementing and
well logging. Generally we do not receive progress payments and
are paid only after the well is drilled. We routinely enter into
turnkey contracts in areas where our experience and expertise
permit us to drill wells more profitably than under a daywork
contract. As of December 31, 2007, one of our rigs was
operating under a turnkey contract.
Drilling and oil field services segment revenue decreased to
$73.2 million for the year ended December 31, 2007
from $138.7 million for the year ended December 31,
2006. Operating income decreased to $10.5 million during
2007 from $32.9 million in the same period in 2006. The
decline in revenues and operating income is primarily
attributable to an increase in the number of rigs operating on
our properties and an increase in our ownership interest in our
natural gas and oil properties. Our drilling and oil field
services segment records revenues and operating income only on
wells drilled for or on behalf of third parties. The portion of
drilling costs incurred by our drilling and oil field services
segment relating to our ownership interest is capitalized as
part of our full-cost pool. With the NEG acquisition and other
WTO property acquisitions, our average working interest has
increased to approximately 93% in the wells we operate in the
WTO, and the third-party interest has declined to less than 20%.
During the year ended December 31, 2007, approximately 72%
of drilling and oil field service segment revenue was generated
by work performed on our own account and eliminated in
consolidation as compared to approximately 34% for the
comparable period in 2006. The number of drilling rigs we owned
increased 19% to an average of 26 rigs during 2007 from an
average of 21.9 rigs in 2006. The average daily rate we received
per rig of $17,177, excluding revenues for related rental
equipment and before intercompany eliminations was essentially
unchanged from 2006. Our rig utilization rate was 90%,
representing 1,095 stacked rig days in 2007. The decline in
operating income was principally attributable to the increase in
the number and working interest ownership in wells drilled for
our own account.
During 2006, our drilling and oil field services segment
reported $138.7 million in revenues, an increase of
$58.5 million, or 73%, from 2005. Operating income
increased to $32.9 million in 2006 from $18.3 million
in 2005. The increase in revenue and operating income was
primarily attributable to an increase in the number of rigs we
owned and an increase in the average revenue per rig per day we
earned from the rigs. The number of rigs we owned increased 32%
to 25 rigs as of December 31, 2006 and the average revenue
we received per rig, excluding revenues for related rental
equipment, increased 48% (before intercompany eliminations) to
$17,034 per day from $11,503 per day. Our margins increased
primarily due to our rig rates increasing faster than our
operating costs.
We believe our ownership of drilling rigs and related oil field
services will continue to be a major catalyst of our growth. As
of December 31, 2007, our drilling fleet consisted of 44
rigs, including the twelve rigs owned by Larclay. As of
December 31, 2007, 29 of our rigs are working on properties
that we operate; six of our rigs are drilling on a contract
basis for third parties; three are being retrofitted and six are
idle or being repaired.
In 2005 we placed an order for 22 drilling rigs to be
constructed by Chinese manufacturers for an approximate
aggregate purchase price of $126.4 million, of which
$75.6 million was attributable to Larclay. We believe this
is a lower cost when compared to newly built
U.S. manufactured rigs with similar capabilities.
Midstream
Gas Services Segment
We provide gathering, compression, processing and treating
services of natural gas in West Texas and the Piceance Basin in
northwestern Colorado, primarily through our wholly-owned
subsidiary, ROC Gas. Through our gas marketing subsidiary,
Integra Energy LLC (Integra Energy), we buy and sell
natural gas produced from our operated wells as well as
third-party operated wells. Gas marketing revenue is one of our
largest revenue components; however, it is a very low margin
business. Substantially all of our marketing fees are billed on
a per unit basis. On a consolidated basis, gas purchases and
other costs of sales include the total value we receive from
third parties for the gas we sell and the amount we pay for gas,
which are reported as midstream and marketing expense. The
primary factors affecting our midstream gas services are the
quantity of gas we gather, treat and market and the prices we
pay and receive for natural gas.
Midstream gas services revenue for the year ended
December 31, 2007 was $107.6 million compared to
$122.9 million in 2006. The decrease in midstream gas
services revenues is attributable to the increase in our working
interest in the WTO as a result of the NEG and other
acquisitions.
Midstream gas services segment revenue decreased
$24.6 million for the year ended December 31, 2006
from $147.5 million in 2005 to $122.9 million in 2006.
The NEG acquisition significantly decreased our midstream gas
services revenue as more gas was transported for our own
account. We do not record midstream gas revenue for
transportation, treating and processing of our own gas.
39
Prior to the NEG acquisition, transportation, treating and
processing of gas for NEG was recorded as midstream gas services
revenue. Operating income increased $3.3 million in 2007 to
$6.8 million due to lower gas prices paid and an increase
in marketing and transportation for our own account. Operating
income decreased to $3.5 million in 2006 from
$4.1 million in the 2005 period, primarily due to the NEG
acquisition and
start-up
operating expenses for our Sagebrush processing plant in 2006.
The Sagebrush plant was placed into full operation during May
2007. We have the contractual right to periodically increase
fees we receive for transportation and processing based on
certain indexes.
Other
Segment
Our other segment consists primarily of our
CO2
gathering and tertiary oil recovery operations and other
investments. We conduct our
CO2
gathering and tertiary oil recovery operations through our
wholly-owned subsidiary, PetroSource. In the fourth quarter of
2005 we acquired a majority interest in PetroSource, and in the
first and second quarters of 2006 we acquired the remaining
interests in PetroSource. Prior to the majority acquisition of
PetroSource we accounted for PetroSources results of
operation as an equity investment in an unconsolidated
subsidiary. PetroSource gathers
CO2
from natural gas treatment plants located in West Texas and
transports this
CO2
for use in our and third parties tertiary oil recovery
operations.
We believe our tertiary oil recovery operations will provide
significant long-term production growth potential at reasonable
rates of return. Generally, there is a significant delay between
the initial capital expenditures for infrastructure and
CO2
injections and the resulting production increases, if any, as
tertiary oil recovery operations require the construction of
facilities before
CO2
flooding can commence. After the infrastructure is in place and
injections begin, it usually takes an additional 18 months
before the field responds (i.e. oil production increases) to the
injection of
CO2.
As a result, we do not anticipate that PetroSource will be
profitable for the next several years.
Results
of Operations
Year
Ended December 31, 2007 Compared to the Year Ended
December 31, 2006
Impact of the NEG Acquisition. The results of
operations for the year ended December 31, 2006 include the
results of NEG from November 21, 2006. The results of
operations for the year ended December 31, 2007 include the
NEG acquisition for the full year. While NEG was principally an
exploration and production company, the acquisition affected
several of our revenue and expense categories. Revenues and
expenses related to our natural gas and crude oil operations
increased due to increased production from the acquired NEG
properties. Revenues and expenses relating to our drilling and
services and midstream and marketing operations decreased due to
increased intercompany eliminations as more services were
provided on company-owned properties. General and administrative
expenses increase due to the addition of new staff. Interest
expense increased due to the additional borrowings incurred in
conjunction with the NEG acquisition.
Revenue. Total revenue increased 75% to
$677.5 million for the year ended December 31, 2007
from $388.2 million in 2006. This increase was due to a
$376.4 million increase in natural gas and oil sales and
was partially offset by lower revenues in our other segments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and crude oil
|
|
$
|
477,612
|
|
|
$
|
101,252
|
|
|
$
|
376,360
|
|
|
|
371.7
|
%
|
Drilling and services
|
|
|
73,197
|
|
|
|
139,049
|
|
|
|
(65,852
|
)
|
|
|
(47.4
|
)%
|
Midstream and marketing
|
|
|
107,765
|
|
|
|
122,896
|
|
|
|
(15,131
|
)
|
|
|
(12.3
|
)%
|
Other
|
|
|
18,878
|
|
|
|
25,045
|
|
|
|
(6,167
|
)
|
|
|
(24.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
677,452
|
|
|
$
|
388,242
|
|
|
$
|
289,210
|
|
|
|
74.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas and crude oil revenues increased
$376.4 million to $477.6 million for the year ended
December 31, 2007, compared to $101.3 million in 2006,
primarily as a result of an increase in natural gas and crude
oil production volumes. Total natural gas production increased
287% to 51,958 Mmcf in 2007 compared to 13,410 Mmcf in
2006, while crude oil production increased 534% to
2,042 MBbls in 2007 from 322 MBbls in 2006. The
increase was due to the NEG acquisition and our successful
drilling in the WTO. The average price received for our natural
gas and crude oil production increased 13% in 2007 to $7.45 per
Mcfe compared to $6.60 per Mcfe in 2006, excluding the impact of
derivative contracts.
Drilling and services revenue decreased 47% to
$73.2 million in 2007 compared to $139.0 million in
2006. The decline in revenues is primarily attributable to an
increase in the number of rigs operating on our properties and
an increase in our ownership
40
interest in our natural gas and oil properties. The number of
rigs we owned increased to 26.0 (average for the year ended
December 31, 2007) in 2007 compared to 21.9 in 2006,
an increase of 19%, and the average daily revenue per rig, after
considering the effect of the elimination of intercompany usage,
was essentially unchanged at $17,177 per day.
Midstream and marketing revenue decreased $15.1 million, or
12%, with revenues of $107.8 million for the year ended
December 31, 2007, as compared to $122.9 million in
2006. The NEG acquisition significantly decreased our midstream
gas services revenues as more gas was transported for our own
account. Prior to the acquisition, transportation, treating and
processing of gas for NEG was recorded as midstream gas services
revenue. We have the contractual right to periodically increase
fees we receive for transportation and processing based on
certain indexes.
Other revenue decreased to $18.9 million during 2007 from
$25.0 million in 2006. The decrease was primarily due to
the sale of various non-energy related assets to our former
President and Chief Operating Officer. Revenues related to these
assets are included in the 2006 period prior to their sale in
August 2006. This decrease was slightly offset by an increase in
revenues generated by our
CO2
operations.
Operating Costs and Expenses. Total operating
costs and expenses increased to $490.6 million during 2007,
compared to $351.3 million in 2006, primarily due to
increases in our production-related costs as well as an increase
in corporate staff. These increases were partially offset by
decreases in costs attributable to our drilling and services and
midstream and marketing operations as well as increased gains on
derivative instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
$
|
106,192
|
|
|
$
|
35,149
|
|
|
$
|
71,043
|
|
|
|
202.1
|
%
|
Production taxes
|
|
|
19,557
|
|
|
|
4,654
|
|
|
|
14,903
|
|
|
|
320.2
|
%
|
Drilling and services
|
|
|
44,211
|
|
|
|
98,436
|
|
|
|
(54,225
|
)
|
|
|
(55.1
|
)%
|
Midstream and marketing
|
|
|
94,253
|
|
|
|
115,076
|
|
|
|
(20,823
|
)
|
|
|
(18.1
|
)%
|
Depreciation, depletion, and amortization natural
gas and crude oil
|
|
|
173,568
|
|
|
|
26,321
|
|
|
|
147,247
|
|
|
|
559.4
|
%
|
Depreciation, depletion and amortization other
|
|
|
53,541
|
|
|
|
29,305
|
|
|
|
24,236
|
|
|
|
82.7
|
%
|
General and administrative
|
|
|
61,780
|
|
|
|
55,634
|
|
|
|
6,146
|
|
|
|
11.0
|
%
|
Gain on derivative instruments
|
|
|
(60,732
|
)
|
|
|
(12,291
|
)
|
|
|
(48,441
|
)
|
|
|
(394.1
|
)%
|
Gain on sale of assets
|
|
|
(1,777
|
)
|
|
|
(1,023
|
)
|
|
|
(754
|
)
|
|
|
(73.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
$
|
490,593
|
|
|
$
|
351,261
|
|
|
$
|
139,332
|
|
|
|
39.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expense includes the costs associated with our
exploration and production activities, including, but not
limited to, lease operating expense and processing costs.
Production expenses increased $71.0 million due to
increased production from our 2007 drilling activity and the
addition of the NEG properties. The remainder of the increase
was due to an increase in lease operating expenses due to an
increase in the number of wells we operate. Production taxes
increased $14.9 million, or 320%, to $19.6 million
primarily due to increased gas production as a result of our
2007 drilling activity and the addition of the NEG properties in
2006.
Drilling and services and midstream and marketing expenses
decreased 55% and 18% respectively, during 2007 as compared to
2006 primarily because of the increase in the number and working
interest ownership of the wells we drilled for our own account.
DD&A for our natural gas and crude oil properties increased
to $173.6 million during 2007 from $26.3 million in
2006. Our DD&A per Mcfe increased $0.98 to $2.70 from $1.72
in 2006. The increase is primarily attributable to our 2007
capital expenditures and the NEG acquisition, which increased
our depreciable properties by the purchase price plus future
development costs and increased production. Our production
increased 320% to 64.2 Bcfe from 15.3 Bcfe in 2006.
DD&A for our other assets consists primarily of
depreciation of our drilling rigs, natural gas plants and other
equipment. The $24.2 million increase in
DD&A other was due primarily to our increased
investments in rigs, other oilfield services equipment and
midstream assets. During 2006 and 2007, capital expenditures for
drilling rigs, other oilfield services equipment and midstream
assets were $293 million on a combined basis. We calculate
depreciation of property and equipment using the straight-line
method over the estimated useful lives of the assets, which
range from three to 25 years. Our drilling rigs and related
oil field services equipment are depreciated over an average
seven-year useful life.
General and administrative expenses increased 11% to
$61.8 million during 2007 from $55.6 million in 2006.
The increase was principally attributable to a
$17.3 million increase in corporate salaries and wages
which was due to a significant increase in corporate
41
and support staff. As of December 31, 2007 we had
2,227 employees as compared to 1,443 at December 31,
2006. The increase in corporate salaries and wages was partially
offset by $4.6 million in capitalized general and
administrative expenses, a $5.5 million decrease due to a
legal settlement recorded in 2006 and a $1.6 million
decrease in stock compensation expense. In accordance with the
full-cost method of accounting, we capitalize internal costs
that can be directly identified with our acquisition,
exploration and development activities and do not include any
costs related to production, general corporate overhead or
similar activities. During 2006 we settled a legal dispute
resulting in an additional loss on the settlement of
$5.5 million. As part of a severance package for certain
executive officers, the Board of Directors approved the
acceleration of vesting of certain stock awards resulting in
increased compensation expense recognized during 2006.
For the year ended December 31, 2007, we recorded a gain of
$60.7 million ($26.2 million unrealized gain and
$34.5 million realized gain) on our derivatives instruments
compared to a $12.3 million gain ($1.9 million
unrealized loss and $14.2 million realized gain) in 2006.
During 2007, we selectively entered into natural gas swaps and
basis swaps by capitalizing on what we perceived as spikes in
the price of natural gas or favorable basis differences between
the NYMEX price and natural gas prices at our principal West
Texas pricing point of Waha Hub. Unrealized gains or losses on
derivatives contracts represent the change in fair value of open
derivatives positions during the period. The change in fair
value is principally measured based on period end prices as
compared to the contract price. The unrealized gain recorded
during 2007 was attributable to a decrease in average natural
gas prices at December 31, 2007 as compared to the average
natural gas prices at the various contract dates.
Other Income (Expense). Total other expense
increased to $107.1 million for the year ended
December 31, 2007 from $15.1 million in 2006. The
increase is reflected in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
$
|
5,423
|
|
|
$
|
1,109
|
|
|
$
|
4,314
|
|
|
|
389.0
|
%
|
Interest expense
|
|
|
(117,185
|
)
|
|
|
(16,904
|
)
|
|
|
(100,281
|
)
|
|
|
593.2
|
%
|
Minority interest
|
|
|
276
|
|
|
|
(296
|
)
|
|
|
572
|
|
|
|
193.2
|
%
|
Income from equity investments
|
|
|
4,372
|
|
|
|
967
|
|
|
|
3,405
|
|
|
|
352.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(107,114
|
)
|
|
|
(15,124
|
)
|
|
|
(91,990
|
)
|
|
|
(608.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
79,745
|
|
|
|
21,857
|
|
|
|
57,888
|
|
|
|
264.8
|
%
|
Income tax expense
|
|
|
29,524
|
|
|
|
6,236
|
|
|
|
23,288
|
|
|
|
373.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
50,221
|
|
|
$
|
15,621
|
|
|
$
|
34,600
|
|
|
|
221.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income increased to $5.4 million in 2007 from
$1.1 million in 2006. This increase was due to interest
income from investment of excess cash after the repayment of
debt.
Interest expense increased to $117.2 million during 2007,
from $16.9 million in 2006. This increase was attributable
to increased average debt balances. To finance the NEG
acquisition, we entered into a $750 million senior credit
facility, which had an initial borrowing base of
$300 million, and an $850 million senior bridge
facility. In March 2007, we entered into a $1.0 billion
senior term loan and sold 17.8 million shares of common
stock in a private placement. A portion of the proceeds from the
senior unsecured term loan was used to repay the bridge loan.
Please read Liquidity and Capital
Resources.
The minority interest is derived from Cholla Pipeline, LP,
Sagebrush Pipeline, LLC and Integra. We acquired the remaining
minority interest in Integra in the fourth quarter of 2007.
During the year ended December 31, 2007 we reported income
from equity investments of $4.4 million as compared to
$1.0 million in 2006. Approximately $1.9 million of
the increase was attributable to income from our interest in the
Grey Ranch processing plant which has experienced increased
profitability due to higher levels of utilization in 2007 as
compared to 2006. Approximately $1.5 million of the
increase was attributable to income from Larclay as all of
Larclays rigs have now been delivered and all but one rig
are operational.
We reported an income tax expense of $29.5 million for the
year ended December 31, 2007 as compared to an expense of
$6.2 million in 2006. The current period income tax expense
represents an effective income tax rate of 37.0% as compared to
28.5% in 2006. The lower effective income tax rate in 2006 was
attributable to favorable percentage depletion deductions during
that period.
42
Year
Ended December 31, 2006 Compared to Year Ended
December 31, 2005
Revenue. Total revenue increased to
$388.2 million in 2006 from $287.7 million in 2005,
which is further explained by the categories below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and crude oil
|
|
$
|
101,252
|
|
|
$
|
49,987
|
|
|
$
|
51,265
|
|
|
|
102.6
|
%
|
Drilling and services
|
|
|
139,049
|
|
|
|
80,343
|
|
|
|
58,706
|
|
|
|
73.1
|
%
|
Midstream and marketing
|
|
|
122,896
|
|
|
|
147,133
|
|
|
|
(24,237
|
)
|
|
|
(16.5
|
)%
|
Other
|
|
|
25,045
|
|
|
|
10,230
|
|
|
|
14,815
|
|
|
|
144.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
388,242
|
|
|
$
|
287,693
|
|
|
$
|
100,549
|
|
|
|
35.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and crude oil revenue increased $51.3 million
to $101.3 million in 2006 from $50.0 million in 2005.
This was primarily a result of an increase in natural gas
production volumes. Total natural gas production almost doubled
to 13,410 Mmcf in 2006 compared to 6,873 Mmcf in 2005.
Natural gas prices decreased $0.35, or 5%, in the 2006 period to
$6.19 per Mcf compared to $6.54 per Mcf in 2005.
Drilling and services revenue increased 73% to
$139.0 million for the year ended December 31, 2006
compared to $80.3 million in the same period in 2005,
primarily due to an increase in the number of drilling rigs we
owned and to an increase in the average daily revenue per rig.
The number of rigs we owned increased to 25 (21.9 average for
the year) as of December 31, 2006 compared to 19 (14.3
average for the year) in 2005, an increase of 32%, and the
average daily revenue per rig, after considering the effect of
the elimination of intercompany usage, increased 48% to $17,034
in 2006 compared to $11,503 in 2005. Additionally, the revenue
from our heavy hauling trucking subsidiary increased
$7.8 million during the comparison period due to an
expansion of our trucking services. The revenue from our pulling
unit operations increased $7.7 million because of an
increase in the demand for these oil field services and an
increase in the rate we charge.
Midstream and marketing revenue decreased $24.2 million
from 2005 with revenues of $122.9 million during the year
ended December 31, 2006 as compared to $147.1 million
in 2005. We do not record midstream and marketing revenues for
marketing, transportation, treating and processing of our own
gas. The NEG acquisition significantly decreased our midstream
gas services revenues as more gas was transported and marketed
for our own account. Prior to the NEG acquisition,
transportation, treating and processing of gas for NEG was
recorded as midstream and marketing revenue. We have the
contractual right to periodically increase fees we receive for
transportation and processing based on certain indexes.
Other revenues increased $14.8 million to
$25.0 million in 2006 from $10.2 million in 2005. The
increase was primarily attributable to an increase of
$12.0 million in
CO2
and tertiary oil recovery revenues. In December 2005, we
acquired an additional equity interest in PetroSource which
increased our ownership interest to 86.5%, resulting in the
consolidation of PetroSource commencing in the fourth quarter of
2005. We recorded PetroSource revenues for the full year in
2006. The remainder of the increase was attributable to
additional administration fees collected from operating natural
gas and oil wells and lease acreage income received as a result
of an increase in the number of wells, an increase in overhead
rates and an increase in leasing activities. Approximately
$0.9 million of the increase was related to an increase of
revenue from a shopping center that was sold in 2006.
Operating Costs and Expenses. Total operating
costs and expenses increased $97.6 million to
$351.3 million in 2006 from $253.6 million in 2005,
which is further explained by the categories below.
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
$
|
35,149
|
|
|
$
|
16,195
|
|
|
$
|
18,954
|
|
|
|
117.0
|
%
|
Production taxes
|
|
|
4,654
|
|
|
|
3,158
|
|
|
|
1,496
|
|
|
|
47.4
|
%
|
Drilling and services
|
|
|
98,436
|
|
|
|
52,122
|
|
|
|
46,314
|
|
|
|
88.9
|
%
|
Midstream and marketing
|
|
|
115,076
|
|
|
|
141,372
|
|
|
|
(26,296
|
)
|
|
|
(18.6
|
)%
|
Depreciation, depletion and amortization-natural gas and oil
|
|
|
26,321
|
|
|
|
9,313
|
|
|
|
17,008
|
|
|
|
182.6
|
%
|
Depreciation, depletion and amortization-other
|
|
|
29,305
|
|
|
|
14,893
|
|
|
|
14,412
|
|
|
|
96.8
|
%
|
General and administrative
|
|
|
55,634
|
|
|
|
11,908
|
|
|
|
43,726
|
|
|
|
367.2
|
%
|
Loss (gain) on derivative instruments
|
|
|
(12,291
|
)
|
|
|
4,132
|
|
|
|
(16,423
|
)
|
|
|
(397.5
|
)%
|
Loss (gain) on sale of assets
|
|
|
(1,023
|
)
|
|
|
547
|
|
|
|
(1,570
|
)
|
|
|
(287.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
$
|
351,261
|
|
|
$
|
253,640
|
|
|
$
|
97,621
|
|
|
|
38.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expense increased to $35.1 million in 2006 from
$16.2 million in 2005 primarily due to the increase in the
number of wells operated in 2006 as compared to 2005, the
addition of NEG for the period from November 21, 2006 to
December 31, 2006 and the addition of PetroSource for the
full year in 2006 as compared to one quarter in 2005.
Approximately $7.5 million of the increase was attributable
to the NEG acquisition and approximately $3.2 million of
the increase was attributable to PetroSource with the remainder
of the increase due to an increase in the number of wells we
operate.
Production taxes increased $1.5 million, or 47%, to
$4.7 million due to the increase in natural gas production,
which was partially offset by a decline in realized natural gas
prices. Production taxes are generally assessed at the wellhead
and are based on the volumes produced times the price received.
Drilling and services expenses increased 89% to
$98.4 million in 2006 from $52.1 million in 2005,
primarily due to an increase in oil field services operating
expense. Oil field services operating expenses, including fuel,
repairs and maintenance, increased $14.2 million due to an
increase in the number of drilling rigs we owned as well as work
we performed on a turnkey and footage basis rather than a day
rate basis.
Midstream and marketing expenses decreased $26.3 million,
or 19%, to $115.1 million in 2006 as compared to
$141.4 million in 2005 due to a decrease in the average
price paid for natural gas that we market and a decrease in
natural gas purchased from third parties as we focused our
marketing efforts more on our own production.
DD&A relating to our natural gas and oil properties
increased 183% to $26.3 million in 2006 from
$9.3 million in 2005. The increase was primarily
attributable to a 110% increase in year-over-year production and
a 37% increase in DD&A per unit of production. The average
DD&A per Mcfe was $1.68 for the year ended
December 31, 2006 as compared to $1.23 in 2005. The
increase in the DD&A rate was attributable to the NEG
acquisition which added significantly higher reserves at a
higher cost per Mcfe.
DD&A related to other property, plant and equipment
increased $14.4 million, or 97%, primarily due to our
investment in additional drilling rigs and oil field service
equipment.
General and administrative expense increased $43.7 million
to $55.6 million in 2006 from $11.9 million in 2005,
due in part to an increase in expense related to salaries and
wages as we added a significant amount of staff to accommodate
our acquisitions and our increased drilling activities, a
$5 million dispute settlement, a $3.6 million increase
in property and franchise taxes, higher administrative costs
associated with our increase in staff including rent, utilities,
insurance and office equipment and supplies, a $2.5 million
increase in bad debt expense and an increase in legal and
professional expenses. Legal and professional fees increased
$4.7 million due primarily to an increase in legal fees
relating to two legal issues and increased audit fees.
For the year ended December 31, 2006, we recorded a gain on
derivative instruments of $12.3 million compared to a loss
of $4.1 million in 2005. We enter into collars and
fixed-price swaps to mitigate the effect of price fluctuations
of natural gas and oil. We use natural gas basis swaps to
mitigate the risk of fluctuations in pricing differentials
between our natural gas well head prices and benchmark spot
prices. We have not designated any of these derivative contracts
as hedges for accounting purposes. We record derivatives
contracts at fair value on the balance sheet, and gains or
losses resulting from changes in the fair value of our
derivative contracts (unrealized) are recognized as a component
of operating costs and expenses. Unrealized gains or losses are
realized upon settlement. During the first eleven months of
2006, we settled or terminated all of our natural gas derivative
contracts and realized a net gain of approximately
$14.2 million. Offsetting the 2006 net realized gain
on the settlement or early termination of our derivative
44
instruments was a net unrealized loss of $1.9 million which
represented the change in fair value of our derivatives
instruments from the purchase date in early December 2006 to
December 31, 2006. Generally, we record unrealized gains on
our swaps and fixed-price swaps when natural gas and oil
commodity prices decrease and record unrealized losses as
natural gas and oil prices increase. We record unrealized gains
on our basis swaps if the pricing differential increases and
unrealized losses as the pricing differential decreases. Gains
or losses on derivatives contracts are realized upon settlement.
During 2005 we did not terminate any derivatives positions and
realized a loss of $2.8 million due to normal settlements.
Future volatility in natural gas and oil prices could have an
adverse effect on the operating results of our exploration and
production segment.
Other Income (Expense). Total other expense
increased to $15.1 million in 2006 from $6.2 million
in 2005. The increase is detailed in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
$
|
1,109
|
|
|
$
|
206
|
|
|
$
|
903
|
|
|
|
438.3
|
%
|
Interest expense
|
|
|
(16,904
|
)
|
|
|
(5,277
|
)
|
|
|
(11,627
|
)
|
|
|
(220.3
|
)%
|
Minority interest
|
|
|
(296
|
)
|
|
|
(737
|
)
|
|
|
441
|
|
|
|
59.8
|
%
|
Income (loss) from equity investments
|
|
|
967
|
|
|
|
(384
|
)
|
|
|
1,351
|
|
|
|
351.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(15,124
|
)
|
|
|
(6,192
|
)
|
|
|
(8,932
|
)
|
|
|
(144.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
21,857
|
|
|
|
27,861
|
|
|
|
(6,004
|
)
|
|
|
(21.5
|
)%
|
Income tax expense
|
|
|
6,236
|
|
|
|
9,968
|
|
|
|
(3,732
|
)
|
|
|
(37.4
|
)%
|
Income from discontinued operations, net of tax
|
|
|
|
|
|
|
229
|
|
|
|
(229
|
)
|
|
|
(100.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
15,621
|
|
|
$
|
18,122
|
|
|
$
|
(2,501
|
)
|
|
|
(13.8
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income increased to $1.1 million in 2006 from
$0.2 million in 2005. This increase was due to interest
income recognized in 2006 related to excess cash balances with
various financial institutions.
Interest expense increased to $16.9 million in 2006 from
$5.3 million in 2005. This increase was due to the
additional debt that we incurred to finance our purchase of NEG.
We recorded income from equity investments of $1.0 million
in 2006 as compared to a $0.4 million loss in 2005. The
2005 loss was primarily due to PetroSource. We accounted for
PetroSource under the equity method during the first nine months
of 2005.
Income tax expense decreased to $6.2 million in 2006 from
$10.0 million in 2005 primarily due to a decrease in our
effective income tax rate. During 2006, we realized a
$3.5 million reduction in tax expense from our percentage
depletion deduction, which was partially offset by
$1.3 million in additional state income taxes.
Liquidity
and Capital Resources
Summary
Our operating cash flow is influenced mainly by the prices we
receive for our natural gas and oil production; the quantity of
natural gas we produce and, to a lesser extent, the quantity of
oil we produce; the success of our development and exploration
activities; the demand for our drilling rigs and oil field
services and the rates we receive for these services; and the
margins we obtain from our natural gas and
CO2
gathering and processing contracts.
On November 9, 2007, we completed the initial public
offering of our common stock. The Company sold
32,379,500 shares of SandRidge common stock, including
4,170,000 shares sold directly to an entity controlled by
Tom L. Ward. The shares were sold at a price of $26 per share.
After deducting underwriting discounts of approximately
$44.0 million and offering expenses of $3.1 million,
the Company received net proceeds of approximately
$794.7 million. The net proceeds were utilized as follows
(in millions):
|
|
|
|
|
Repayment of outstanding balance and accrued interest on senior
credit facility
|
|
$
|
515.9
|
|
Repayment of note payable and accrued interest incurred in
connection with recent acquisition
|
|
|
49.1
|
|
Excess cash to fund capital expenditures
|
|
|
229.7
|
|
|
|
|
|
|
Total
|
|
$
|
794.7
|
|
|
|
|
|
|
45
During 2006 and the first quarter of 2007, we entered into
various debt and equity transactions to fund the acquisition of
NEG and our 2007 capital expenditure program. As of
December 31, 2007, our cash and cash equivalents were
$63.1 million, and we had approximately $677.3 million
available under our senior credit facility. The cash balance at
December 31, 2007 was the result of the remaining proceeds
from our initial public offering described above. As of
December 31, 2007, we had no amounts outstanding under our
senior credit facility, and $1.1 billion in total debt
outstanding.
Capital
Expenditures
We make and expect to continue to make substantial capital
expenditures in the exploration, development, production and
acquisition of natural gas and oil reserves. We believe that our
cash flows from operations, current cash and investments on hand
and availability under our senior credit facility will be
sufficient to meet our capital expenditure budget for the next
twelve months.
Our capital expenditures by segment were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Capital Expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
1,046,552
|
|
|
$
|
170,872
|
|
|
$
|
61,227
|
|
Drilling and oil field services
|
|
|
123,232
|
|
|
|
89,810
|
|
|
|
43,730
|
|
Midstream gas services
|
|
|
63,828
|
|
|
|
16,975
|
|
|
|
25,904
|
|
Other
|
|
|
47,236
|
|
|
|
28,884
|
|
|
|
3,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, excluding acquisitions
|
|
|
1,280,848
|
|
|
|
306,541
|
|
|
|
134,596
|
|
Acquisitions
|
|
|
116,650
|
|
|
|
1,054,075
|
|
|
|
21,247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,397,498
|
|
|
$
|
1,360,616
|
|
|
$
|
155,843
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We estimate that our total capital expenditures for 2008,
excluding acquisitions, will be approximately
$1.25 billion. Our planned 2008 capital expenditures are
consistent with 2007 levels. As in 2007, our 2008 capital
expenditures for our exploration and production segment will be
focused on growing and developing our reserves and production on
our existing acreage and acquiring additional acreage, primarily
in the WTO. Of our total $1.25 billion capital expenditure
budget, approximately $1.1 billion is budgeted for
exploration and production activities. Included in our 2008
exploration and production capital expenditure budget is
$622 million for drilling in the WTO, including the
Piñon field, $285 million for drilling in areas other
than the WTO, $33 million for PetroSource and
$194 million for land and seismic. Based on encouraging
initial results from our
3-D seismic
acquisition program that we commenced in 2007, we have budgeted
$151 million of our 2008 WTO capital expenditures to
explore for new fields within the WTO. We plan to drill
approximately 440 gross wells in 2008.
During 2008 we expect to complete our rig fleet expansion
program that we started in 2005. We have accepted the delivery
of all of the rigs ordered from Chinese manufacturers. We are in
the process of retro-fitting and rigging up three of these rigs,
which we expect to join our fleet during the first half of 2008.
We are also continuing to upgrade and modernize our rig fleet.
Approximately $52 million of our 2008 capital expenditure
budget will be spent on our drilling and oil field services
segment.
We anticipate spending approximately $107 million in
capital expenditures in our midstream gas services and other
segments as we aggressively expand our network of gas gathering
lines and plant and compression capacity.
The majority of our capital expenditures will be discretionary
and could be curtailed if our cash flows decline from expected
levels or we are unable to obtain capital on attractive terms;
however, we have various sources of capital in the form of our
revolving credit facility, potential asset sales or the
incurrence of additional long-term debt.
46
Cash
Flows from Continuing Operations
Our cash flows from continuing operations are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Cash Flows from Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows provided by operating activities
|
|
$
|
357,452
|
|
|
$
|
67,349
|
|
|
$
|
63,297
|
|
Cash flows used in investing activities
|
|
|
(1,385,581
|
)
|
|
|
(1,340,567
|
)
|
|
|
(155,826
|
)
|
Cash flows provided by financing activities
|
|
|
1,052,316
|
|
|
|
1,266,435
|
|
|
|
126,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
$
|
24,187
|
|
|
$
|
(6,783
|
)
|
|
$
|
33,884
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities. Net cash provided by
operating activities for the years ended December 31, 2007
and 2006 were $357.5 million and $67.3 million,
respectively. The increase in cash provided by operating
activities from 2006 to 2007 was primarily due to our
$34.6 million increase in net income as a result of our
320% increase in production volumes as a result of the NEG and
various other acquisitions as well as our drilling success.
Also, contributing to this increase was $34.5 million in
realized gains on our derivative contracts. These increases were
partially offset by increases in general and administrative
costs such as salaries and wages.
Cash flows provided by operating activities increased
$4.0 million to $67.3 million in 2006 from
$63.3 million in 2005 primarily due to an increase in
non-cash DD&A of $31.4 million and an increase in
non-cash stock-based compensation expense of $8.3 million
as net income decreased approximately $2.5 million in 2006
over 2005. The increases were substantially offset by changes in
operating assets and liabilities.
Investing Activities. Cash flows used in
investing activities increased to $1,385.6 million during
2007 from $1,340.6 million in 2006. During 2006, we
acquired NEG for $990.4 million, net of cash received and
$231.2 million in common stock. Capital expenditures for
property plant and equipment during 2007 were
$1,280.8 million as compared to $306.5 million in 2006
as we continued to ramp up our capital expenditure program.
During 2007 our capital expenditures were $1,046.6 million
in our exploration and production segment, $123.2 million
for drilling and oil field services, $63.8 million for
midstream gas services and $47.2 million for other capital
expenditures.
Cash flows used in investing activities increased to
$1,340.6 million for the year ended December 31, 2006
from $155.8 million in 2005. During 2006, our cash flows
used in investing activities included acquisitions of
$1,054 million, including the NEG acquisition described
above. During the comparison period, exploration and production
capital expenditures increased to $170.9 million in 2006
from $61.2 million in 2005, primarily because of the
additional wells that were drilled in the Piñon Field in
2006 and 2005. Capital expenditures for drilling and oil field
services increased to $89.8 million in 2006 from
$43.7 million in 2005, due to an increase in the number of
drilling rigs. Proceeds from the sale of assets increased to
$19.7 million in 2006 from $3.3 million in 2005.
Financing Activities. Since December 2005, we
have used equity issuances, borrowings and, to a lesser extent,
our cash flows from operations to fund our rapid growth. During
2007 we raised $1.1 billion in equity issuances and had net
cash repayments of $0.7 million of debt. Our equity
issuances included the November 2007 initial public offering of
our common stock yielding net proceeds of $794.7 million
and a March 2007 private placement of our common stock which
provided net proceeds of approximately $318.7 million.
Proceeds from borrowings were $1,331.5 million during 2007
and we repaid approximately $1,332.2 million leaving net
cash repayments during 2007 of approximately $0.7 million.
We used the net proceeds from our term loan and the common stock
issuances to repay our senior bridge facility and all of the
outstanding borrowings under our senior credit facility. Our
financing activities provided $1,052.3 million in cash
during 2007 compared to $1,266.4 million in 2006.
During the year ended December 31, 2006, we incurred net
borrowings of $743.0 million, raised $100.8 million
from issuances of common stock and raised $439.5 million
from an issuance of redeemable convertible preferred stock. Our
net borrowings, common stock issuances and issuance of
redeemable preferred stock in 2006 were primarily used to
finance the NEG acquisition as well as our 2006 capital
expenditure program. Most of our borrowings in 2005 funded the
acquisition of drilling rigs, our exploration and production
activities and the expansion of our gathering and treating
assets. In December 2005, we received $173.1 million in net
proceeds from a private placement of common stock, which was
primarily used to reduce outstanding borrowings and to increase
our interest in PetroSource.
47
Credit
Facilities and Other Indebtedness
Senior Credit Facility. On November 21,
2006, we entered into a new $750 million senior secured
revolving credit facility (the senior credit
facility) with Bank of America, N.A., as Administrative
Agent. The senior credit facility matures on November 21,
2011.
The proceeds of the senior credit facility were used to
(i) partially finance the NEG acquisition,
(ii) refinance our existing senior secured revolving credit
facility and NEGs existing credit facility, and
(iii) pay fees and expenses related to the NEG acquisition
and our existing credit facility. Future borrowings under the
senior credit facility will be available for capital
expenditures, working capital and general corporate purposes and
to finance permitted acquisitions of natural gas and oil
properties and other assets related to the exploration,
production and development of natural gas and oil properties.
The senior credit facility will be available to be drawn on and
repaid without restriction so long as we are in compliance with
its terms, including certain financial covenants.
The senior credit facility contains various covenants that limit
our and certain of our subsidiaries ability to grant
certain liens; make certain loans and investments; make
distributions; redeem stock; redeem or prepay debt; merge or
consolidate with or into a third-party; or engage in certain
asset dispositions, including a sale of all or substantially all
of our assets. Additionally, the senior credit facility limits
our and certain of our subsidiaries ability to incur
additional indebtedness.
The senior credit facility also contains financial covenants,
including maintenance of agreed upon levels for (i) the
ratio of total funded debt to EBITDAX (as defined in the senior
credit facility), which may not exceed 4.5:1.0 calculated using
the last fiscal quarter on an annualized basis as of the end of
fiscal quarters ending on or before September 30, 2008 and
calculated using the last four completed fiscal quarters
thereafter, (ii) the ratio of EBITDAX to interest expense
plus current maturities of long-term debt, which must be at
least 2.5:1.0 calculated using the last four completed fiscal
quarters and (iii) the current ratio, which must be at
least 1.0:1.0. As of December 31, 2007, we were in
compliance with these financial covenants.
The obligations under the senior credit facility are secured by
first priority liens on all shares of capital stock of each of
our present and future subsidiaries; all intercompany debt of us
and our subsidiaries; and substantially all of our assets and
the assets of our guarantor subsidiaries, including proved
natural gas and oil reserves representing at least 80% of the
present discounted value (as defined in the senior credit
facility) of our proved natural gas and oil reserves reviewed in
determining the borrowing base for the senior credit facility
(as determined by the administrative agent). Additionally, the
obligations under the senior credit facility are guaranteed by
certain of our subsidiaries.
The borrowing base for the senior credit facility is determined
by the administrative agent in its sole discretion in accordance
with its normal and customary natural gas and oil lending
practices and approved by lenders. The reaffirmation of an
existing borrowing base amount or an increase in the borrowing
base requires approval by the facility lenders. The borrowing
base is subject to review semi-annually; however, the lenders
reserve the right to have one additional redetermination of the
borrowing base per calendar year. Unscheduled redeterminations
may be made at our request, but are limited to one request per
year.
The borrowing base is determined based on proved developed
producing reserves, proved developed non-producing reserves and
proved undeveloped reserves and was $700 million as of
December 31, 2007. We repaid all outstanding borrowings
under this facility on November 9, 2007, and as of
December 31, 2007, there were $22.7 million in letters
of credit and no principal amounts outstanding under the senior
credit facility. Subsequent to December 31, 2007, we began
drawing on our senior credit facility to partially fund our 2008
capital expenditure program. As of February 22, 2008 the
outstanding balance under our senior credit facility was
$155 million, and including outstanding letters of credit
of $22.7 million, the available balance under our senior
credit facility was $522.3 million.
At our election, interest under the senior credit facility is
determined by reference to (i) LIBOR, plus an applicable
margin between 1.25% and 2.00% per annum or (ii) the higher
of the federal funds rate plus 0.5% or the prime rate plus, in
either case, an applicable margin between 0.25% and 1.00% per
annum. Interest is payable quarterly for prime rate loans and at
the applicable maturity date for LIBOR loans, except that if the
interest period for a LIBOR loan is six months, interest is paid
at the end of each three-month period. The average interest rate
paid on amounts outstanding under our senior credit facility for
the year ended December 31, 2007 was 7.34%.
If an event of default exists under the senior credit facility,
the lenders may accelerate the maturity of the obligations
outstanding under the senior credit facility and exercise other
rights and remedies. Each of the following will be an event of
default:
|
|
|
|
|
failure to pay any principal when due or any interest, fees or
other amount within certain grace periods;
|
|
|
|
failure to perform or otherwise comply with the covenants in the
credit agreement or other loan documents, subject, in certain
instances, to certain grace periods;
|
|
|
|
bankruptcy or insolvency events involving us or our subsidiaries;
|
48
|
|
|
|
|
a change of control (as defined in the senior credit facility).
|
March 2007 Senior Term Loans. On
March 22, 2007, we entered into a $1 billion principal
amount of senior unsecured term loans. The proceeds of the
senior term loans were used to partially repay the senior bridge
facility described below. The senior term loans include both a
floating rate tranche and fixed rate tranche.
We issued $350 million at a variable rate with interest
payable quarterly and principal due on April 1, 2014 (the
Variable Rate Term Loans). The Variable Rate Term
Loans bear interest, at our option, at LIBOR plus 3.625% or the
higher of (i) the federal funds rate, as defined, plus
3.125% or (ii) a banks prime rate plus 2.625%. After
April 1, 2009 the Variable Rate Term Loans may be prepaid
in whole or in part with a prepayment penalty. The average
interest rates paid on amounts outstanding under our variable
rate term loans during 2007 was 8.94%. In January 2008, we
entered into a $350 million notional amount interest rate
swap agreement with a financial institution that effectively
fixed our interest rate on the Variable Rate Term Loans at
6.2625% for the period from April 1, 2008 through
April 1, 2011.
We issued $650 million at a fixed rate of 8.625% with
principal due on April 1, 2015 (the Fixed Rate Term
Loans). Under the terms of the Fixed Rate Term Loans,
interest is payable quarterly and during the first four years
interest may be paid, at our option, either entirely in cash or
entirely with additional Fixed Rate Term Loans. If we elect to
pay the interest due during any period in additional Fixed Rate
Term Loans, the interest rate increases to 9.375% during such
period. After April 1, 2011 the Fixed Rate Term Loans may
be prepaid in whole or in part with prepayment penalties.
After March 22, 2008, but not later than April 30,
2008, we are required to offer to exchange the senior term loans
for senior unsecured notes with registration rights. The senior
unsecured notes will have substantially similar terms and
conditions as the senior term loans. If the exchange does not
occur by May 31, 2008, the interest rate on the senior term
loans will increase by 0.25% every 90 days up to a maximum
of 0.50%. Debt covenants under the senior term loans include
financial covenants similar to those of the senior credit
facility and include limitations on the incurrence of
indebtedness, payment of dividends, asset sales, certain asset
purchases, transactions with related parties, and consolidation
or merger agreements. We incurred $26.1 million of debt
issuance costs in connection with the senior term loans. These
costs are included in other assets and amortized over the term
of the senior term loans.
Other Indebtedness. We have financed a portion
of our drilling rig fleet and related oil field services
equipment through notes with Merrill Lynch Capital Corporation.
At December 31, 2007, the aggregate outstanding balance of
these notes was $47.8 million, with annual fixed interest
rates ranging from 7.64% to 8.87%. The notes have a final
maturity date of December 1, 2011, require aggregate
monthly installments for principal and interest in the amount of
$1.2 million and are secured by the equipment. The notes
have a prepayment penalty (currently 1-3%) in the event we repay
the notes prior to maturity.
On November 15, 2007, we entered into a $20 million
note payable which is fully secured by one of the buildings and
a parking garage located on our property in downtown Oklahoma
City, Oklahoma which we purchased in July 2007. The mortgage
bears interest at 6.08% per annum, and matures November 15,
2022. Payments of principal and interest in the amount of
approximately $0.5 million are due on a quarterly basis
through the maturity date.
We have financed the purchase of other equipment used in our
business. At December 31, 2006, the aggregate outstanding
balance of these financings was $4.5 million. We repaid
such borrowings during 2007 with borrowings under our senior
credit facility.
In 2007 we also repaid $4.0 million in secured borrowings
incurred in 2005 for the purpose of completing our gas
processing plant and pipeline in Colorado.
Senior Bridge Facility. On November 21,
2006, we entered into an $850 million senior unsecured
bridge facility (the senior bridge facility). This
facility was repaid in full in March 2007 with proceeds from our
senior unsecured term loans.
Prior Senior Credit Facility. On
November 21, 2006, we replaced a $130 million
revolving credit facility with our current senior credit
facility. The prior senior credit facility bore interest at our
option at either LIBOR plus 2.15% or the Bank of America, N.A.
prime rate. We paid a commitment fee on the unused portion of
the borrowing base amount equal to 1/8% per annum. The prior
senior credit facility was collateralized by natural gas and oil
properties representing at least 80% of the present discounted
value of our proved reserves and by a negative pledge on any of
our non-mortgaged properties.
Convertible
Preferred Stock
We have 2,184,286 shares of convertible preferred stock
issued and outstanding. Each holder of our convertible preferred
stock is entitled to quarterly cash dividends at the annual rate
of 7.75% of the accreted value of its convertible preferred
stock. During 2007 we paid cash dividends of $33.3 million.
At our option, we may choose to increase the accreted value of
the convertible preferred stock in lieu of paying any quarterly
cash dividend. The accreted value was $210 per share as of
December 31, 2007. Each share of convertible preferred
stock is currently convertible into approximately
10.2 shares of common stock at the option of the holder,
subject to certain
49
anti-dilution adjustments. Beginning in the second quarter of
2008, we may convert all outstanding shares of convertible
preferred stock at the then current conversion rate subject to
the satisfaction of certain conditions.
Contractual
Obligations
A summary of our contractual obligations as of December 31,
2007 is provided in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Year
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
After 2012
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Long-term debt
|
|
$
|
15,350
|
|
|
$
|
16,580
|
|
|
$
|
12,476
|
|
|
$
|
7,222
|
|
|
$
|
1,052
|
|
|
$
|
1,014,969
|
|
|
$
|
1,067,649
|
|
Interest on term loans(1)
|
|
|
92,868
|
|
|
|
91,580
|
|
|
|
90,322
|
|
|
|
89,510
|
|
|
|
89,219
|
|
|
|
172,020
|
|
|
|
625,519
|
|
Firm transportation(2)
|
|
|
1,597
|
|
|
|
1,597
|
|
|
|
1,597
|
|
|
|
1,597
|
|
|
|
1,597
|
|
|
|
6,775
|
|
|
|
14,760
|
|
Operating leases
|
|
|
2,139
|
|
|
|
1,102
|
|
|
|
110
|
|
|
|
110
|
|
|
|
46
|
|
|
|
|
|
|
|
3,507
|
|
Third-party drilling rig commitments(3)
|
|
|
12,803
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,803
|
|
Dispute settlement payments(4)
|
|
|
5,000
|
|
|
|
5,000
|
|
|
|
5,000
|
|
|
|
5,000
|
|
|
|
|
|
|
|
|
|
|
|
20,000
|
|
Asset retirement obligations
|
|
|
864
|
|
|
|
365
|
|
|
|
|
|
|
|
7,822
|
|
|
|
444
|
|
|
|
49,085
|
|
|
|
58,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
130,621
|
|
|
$
|
116,224
|
|
|
$
|
109,505
|
|
|
$
|
111,261
|
|
|
$
|
92,358
|
|
|
$
|
1,242,849
|
|
|
$
|
1,802,818
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Based on interest rates as of December 31, 2007. |
|
(2) |
|
We entered into a firm transportation agreement with Questar
Pipeline Company giving us guaranteed capacity on its pipeline
for 10 MmBtu per day at an estimated charge of
$0.9 million per year, with a total commitment of
$9.1 million. In December 2006, we assigned our rights and
obligations to a third-party. |
|
(3) |
|
Drilling contracts with third-party drilling rig operators at
specified day rates. All of our drilling rig contracts contain
operator performance conditions that allow for pricing
adjustments or early termination for operator nonperformance. |
|
(4) |
|
In January 2007, we settled a royalty interest dispute and
agreed to pay five installments of $5 million each, plus
interest commencing April 1, 2007. The remaining
installments are due on July 1 of each year commencing
July 1, 2008. |
In connection with the NEG acquisition, we acquired restricted
deposits representing bank trust and escrow accounts required by
surety bond underwriters and certain former owners of NEGs
offshore properties. In accordance with requirements of the U.S
Department of Interiors Mineral Management Service, NEG
was required to put in place surety bonds or escrow agreements
to provide satisfaction of its eventual responsibility to plug
and abandon wells and remove structures when certain offshore
fields are no longer in use. As part of the agreement with the
surety bond underwriter or the former owners of the particular
fields, bank trust and escrow accounts were set up and funded
based on the terms of the escrow agreements. Certain amounts are
required to be paid upon receipt of proceeds from production.
During 2007, funds totaling $10.3 million were released
from escrow accounts and returned to us.
In connection with one of the escrow accounts, we are required
to make quarterly deposits to the escrow accounts of
$0.8 million up to a maximum of $14.0 million.
Payments to the escrow account are estimated as follows (in
thousands):
|
|
|
|
|
2008
|
|
$
|
3,200
|
|
2009
|
|
|
3,200
|
|
2010
|
|
|
2,586
|
|
|
|
|
|
|
|
|
$
|
8,986
|
|
|
|
|
|
|
Additionally, two of the escrow accounts require us to deposit
additional funds in an escrow account equal to 10% of the net
proceeds, as defined, from certain of our offshore properties.
During 2007 we deposited approximately $5.8 million in the
escrow accounts.
Critical
Accounting Policies and Estimates
The discussion and analysis of our financial condition and
results of operations are based upon our consolidated financial
statements, which have been prepared in accordance with
accounting principles generally accepted in the United States.
The preparation of our financial statements requires us to make
assumptions and prepare estimates that affect the reported
amounts of assets and liabilities, the disclosure of contingent
assets and liabilities and revenues and expenses. We base our
estimates on historical experience and various other assumptions
that we believe are reasonable; however, actual results may
differ. See Item 8.
50
Consolidated Financial Statements and Supplementary Data,
Note 1 Summary of Organization and Significant
Accounting Policies included in Exhibit I for a
discussion of our significant accounting policies.
Proved Reserves. Over 97% of our reserves are
estimated on an annual basis by independent petroleum engineers.
Estimates of proved reserves are based on the quantities of
natural gas and oil which geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in
future years from known reservoirs under existing economic and
operating conditions. However, there are numerous uncertainties
inherent in estimating quantities of proved reserves and in
projecting future revenues, rates of production and timing of
development expenditures, including many factors beyond our
control. The estimation process is very complex and relies on
assumptions and subjective interpretations of available
geologic, geophysical, engineering and production data, and the
accuracy of reserve estimates is a function of the quality and
quantity of available data, engineering and geological
interpretation and judgment. In addition, as a result of
volatility and changing market conditions, commodity prices and
future development costs will change from period to period,
causing estimates of proved reserves to change, as well as
causing estimates of future net revenues to change. For the
years ended December 31, 2007, 2006 and 2005, we revised
our proved reserves upward from prior years reports by
approximately 351.6 Bcfe, 26.6 Bcfe and
12.3 Bcfe, respectively due to market prices at the end of
the applicable period or from production performance indicating
more (or less) reserves in place or larger (or smaller)
reservoir size than initially estimated. Estimates of proved
reserves are key components of our most significant financial
estimates involving our rate for recording depreciation,
depletion and amortization and our full-cost ceiling limitation.
These revisions may be material and could materially affect our
future depletion, depreciation and amortization expenses.
Method of accounting for natural gas and oil
properties. Our natural gas and oil properties
are accounted for using the full-cost method of accounting. All
direct costs and certain indirect costs associated with the
acquisition, exploration and development of natural gas and oil
properties are capitalized. Exploration and development costs
include dry hole costs, geological and geophysical costs, direct
overhead related to exploration and development activities and
other costs incurred for the purpose of finding natural gas and
oil reserves. Amortization of natural gas and oil properties is
provided using the unit-of-production method based on estimated
proved natural gas and oil reserves. No gains or losses are
recognized upon the sale or disposition of natural gas and oil
properties unless the sale or disposition represents a
significant quantity of natural gas and oil reserves, which
would have a significant impact on the depreciation, depletion
and amortization rate.
In accordance with full-cost accounting rules, capitalized costs
are subject to a limitation. The capitalized cost of natural gas
and oil properties, net of accumulated depreciation, depletion,
and amortization, may not exceed the estimated future net cash
flows from proved natural gas and oil reserves discounted at
10%, plus the lower of cost or fair market value of unproved
properties as adjusted for related tax effects. The full-cost
ceiling limitation is calculated using natural gas and oil
prices in effect as of the balance sheet date and adjusted for
basis or location differential, held constant over
the life of the reserves. If capitalized costs exceed this limit
(the ceiling limitation), the excess must be charged
to expense. Once incurred, a write-down is not reversible at a
later date. We did not have any adjustment to earnings due to
the ceiling limitation for the periods presented herein.
Unevaluated Properties. The balance of
unevaluated properties is comprised of capital costs incurred
for undeveloped acreage, wells and production facilities in
progress and wells pending determination, together with
capitalized interest costs for these projects. These costs are
initially excluded from our amortization base until the outcome
of the project has been determined or, generally, until it is
known whether proved reserves will or will not be assigned to
the property. We assess all items classified as unevaluated
property on a quarterly basis for possible impairment or
reduction in value. We assess our properties on an individual
basis or as a group if properties are individually
insignificant. Our assessment includes consideration of the
following factors, among others: intent to drill; remaining
lease term; geological and geophysical evaluations; drilling
results and activity; the assignment of proved reserves; and the
economic viability of development if proved reserves are
assigned. During any period in which these factors indicate an
impairment, the cumulative drilling costs incurred to date for
such property and all or a portion of the associated leasehold
costs are transferred to the full-cost pool and are then subject
to amortization. We estimate that substantially all of our costs
classified as unproved as of the balance sheet date will be
evaluated and transferred within a four-year period.
Asset Retirement Obligations. Asset retirement
obligations represent the estimated future abandonment costs of
tangible long-lived assets such as platforms, wells, service
assets, pipelines and other facilities. We estimate the fair
value of an assets retirement obligation in the period in
which the liability is incurred, if a reasonable estimate can be
made. We employ a present value technique to estimate the fair
value of an asset retirement obligation, which reflects certain
assumptions, including an inflation rate, our credit-adjusted,
risk-free interest rate, the estimated settlement date of the
liability and the estimated current cost to settle the liability
based on third-party quotes and current actual costs. Changes in
timing or to the original estimate of cash flows will result in
changes to the carrying amount of the liability.
Revenue Recognition and Gas Balancing. Oil and
natural gas revenues are recorded when title passes to the
customer, net of royalties, discounts and allowances, as
applicable. We account for oil and natural gas production
imbalances using the sales method, whereby we recognize revenue
on all oil and natural gas sold to our customers notwithstanding
the fact that its ownership may be less
51
than 100% of the oil and natural gas sold. Liabilities are
recorded for imbalances greater than our proportionate share of
remaining estimated oil and natural gas reserves.
We recognize revenues and expenses generated from
daywork drilling contracts as the services are
performed, since we do not bear the risk of completion of the
well. Under footage and turnkey
contracts, we bear the risk of completion of the well;
therefore, revenues and expenses are recognized when the well is
substantially completed. Under this method, substantial
completion is determined when the well bore reaches the
negotiated depth as stated in the contract. The duration of all
three types of contracts ranges typically from 20 to
90 days. The entire amount of a loss, if any, is recorded
when the loss is determinable. The costs of uncompleted drilling
contracts include expenses incurred to date on
footage or turnkey contracts, which are
still in process at the end of the period.
We may receive lump-sum fees for the mobilization of equipment
and personnel. Mobilization fees received and costs incurred to
mobilize a rig from one market to another are recognized over
the term of the related drilling contract. The contract terms
are typically from 20 to 90 days.
Revenues of our midstream gas services segment are derived from
providing supply, transportation, balancing and sales services
for producers and wholesale customers on our natural gas
pipelines, as well as other interconnected pipeline systems.
Midstream gas services are primarily undertaken to realize
incremental margins on gas purchased at the wellhead, and
provide value-added services to customers. In general, natural
gas purchased and sold by our midstream gas business is priced
at a published daily or monthly index price. Sales to wholesale
customers typically incorporate a premium for managing their
transmission and balancing requirements. Revenues are recognized
upon delivery of natural gas to customers
and/or when
services are rendered, pricing is determinable and
collectibility is reasonably assured.
Revenue from sales of
CO2
is recognized when the product is delivered to the customer. We
recognize service fees related to the transportation of
CO2
as revenue when the related service is provided.
Property, Plant and Equipment, Net. Other
capitalized costs, including drilling equipment, natural gas
gathering and processing equipment, transportation equipment and
other property and equipment are carried at cost. Renewals and
improvements are capitalized while repairs and maintenance are
expensed. Depreciation of drilling equipment is recorded using
the straight-line method based on estimated useful lives.
Depreciation of other property and equipment is computed using
the straight-line method over the estimated useful lives of the
assets ranging from 3 to 39 years.
Realization of the carrying value of property and equipment is
reviewed for possible impairment whenever events or changes in
circumstances indicate that the carrying amount may not be
recoverable. Assets are determined to be impaired if a forecast
of undiscounted estimated future net operating cash flows
directly related to the asset including disposal value if any,
is less than the carrying amount of the asset. If any asset is
determined to be impaired, the loss is measured as the amount by
which the carrying amount of the asset exceeds its fair value.
An estimate of fair value is based on the best information
available, including prices for similar assets. Changes in such
estimates could cause us to reduce the carrying value of
property and equipment.
When property and equipment components are disposed of, the cost
and the related accumulated depreciation are removed from the
accounts and any resulting gain or loss is generally reflected
in operations.
Income Taxes. Deferred income taxes are
provided on temporary differences between financial statement
and income tax reporting. Temporary differences are differences
between the amounts of assets and liabilities reported for
financial statement purposes and their tax bases. Deferred tax
assets are recognized for temporary differences that will be
deductible in future years tax returns and for operating
loss and tax credit carryforwards. Deferred tax assets are
reduced by a valuation allowance if it is deemed more likely
than not that some or all of the deferred tax assets will not be
realized. Deferred tax liabilities are recognized for temporary
differences that will be taxable in future years tax
returns.
Derivative Financial Instruments. To manage
risks related to increases in interest rates and changes in
natural gas and oil prices, we enter into interest rate swaps
and natural gas and oil futures contracts.
We recognize all of our derivative instruments as either assets
or liabilities at fair value. The accounting for changes in the
fair value (i.e., gains or losses) of a derivative instrument
depends on whether it has been designated and qualifies as part
of a hedging relationship, and further, on the type of hedging
relationship. For those derivative instruments that are
designated and qualify as hedging instruments, we designate the
hedging instrument, based on the exposure being hedged, as
either a fair value hedge or a cash flow hedge. For derivative
instruments not designated as hedging instruments, the gain or
loss is recognized in current earnings during the period of
change. None of our derivatives were designated as hedging
instruments during 2007, 2006 and 2005.
52
New
Accounting Pronouncements
For a discussion of recently adopted accounting standards, see
Note 1 to our consolidated financial statements included in
Exhibit I.
Effects
of Inflation
The effect of inflation in the natural gas and oil industry is
primarily driven by the prices for natural gas and oil.
Increased commodity prices increase demand for contract drilling
rigs and services, which supports higher drilling rig activity.
This in turn affects the overall demand for our drilling rigs
and the dayrates we can obtain for our contract drilling
services.
Over the last three years, natural gas and oil prices have been
volatile, and during periods of higher utilization we have
experienced increases in labor cost and the cost of services to
support our drilling rigs.
During this same period, when commodity prices declined, labor
rates did not return to the levels that existed before the
increases. If natural gas prices increase substantially for a
long period, shortages in support equipment (such as drill pipe,
third-party services and qualified labor) may result in
additional increases in our material and labor costs. These
conditions may limit our ability to realize improvements in
operating profits. How inflation will affect us in the future
will depend on additional increases, if any, realized in our
drilling rig rates and the prices we receive for our natural gas
and oil.
CAUTIONARY
STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
Various statements contained in this report, including those
that express a belief, expectation, or intention, as well as
those that are not statements of historical fact, are
forward-looking statements. The forward-looking statements may
include projections and estimates concerning the timing and
success of specific projects and our future production,
revenues, income and capital spending. Our forward-looking
statements are generally accompanied by words such as
estimate, project, predict,
believe, expect, anticipate,
potential, could, may,
foresee, plan, goal or other
words that convey the uncertainty of future events or outcomes.
The forward-looking statements in this Annual Report on
Form 10-K
speak only as of the date of this annual Report on
Form 10-K;
we disclaim any obligation to update these statements unless
required by securities law, and we caution you not to rely on
them unduly. We have based these forward-looking statements on
our current expectations and assumptions about future events.
While our management considers these expectations and
assumptions to be reasonable, they are inherently subject to
significant business, economic, competitive, regulatory and
other risks, contingencies and uncertainties relating to, among
other matters, the risks discussed in
Item 1A-
Risk Factors including the following:
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the volatility of natural gas and oil prices;
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uncertainties in estimating natural gas and oil reserves;
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the need to replace the natural gas and oil reserves we produce;
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our ability to execute our growth strategy by drilling wells as
planned;
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the need to drill productive, economically viable natural gas
and oil wells;
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risks and liabilities associated with acquired properties;
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amount, nature and timing of capital expenditures, including
future development costs, required to develop the WTO;
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concentration of operations in the WTO;
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economic viability of WTO production with high
CO2
content;
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availability of natural gas production for our midstream
services operations;
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limitations of seismic data;
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risks associated with drilling natural gas and oil wells;
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availability of satisfactory natural gas and oil marketing and
transportation;
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availability and terms of capital;
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substantial existing indebtedness;
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limitations on operations resulting from debt restrictions and
financial covenants;
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potential financial losses or earnings reductions from commodity
derivatives;
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53
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competition in the natural gas and oil industry;
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costs to comply with current and future governmental regulation
of the natural gas and oil industry, including environmental,
health and safety laws and regulations; and
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the need to maintain adequate internal control over financial
reporting.
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Item 7A.
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Quantitative
and Qualitative Disclosures about Market Risk
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The discussion in this section provides information about the
financial instruments we use to manage commodity price and
interest rate volatility. All contracts are financial contracts,
which are settled in cash and do not require the delivery of a
physical quantity to satisfy settlement.
Commodity Price Risk. Our most significant
market risk is the prices we receive for our natural gas and oil
production, which can be highly volatile. In light of this
historical volatility, we periodically have entered into, and
expect in the future to enter into, derivative arrangements
aimed at reducing the variability of natural gas and oil prices
we receive for our production. We will from time to time enter
into commodities pricing derivative instruments for a portion of
our anticipated production volumes depending upon our
managements view of opportunities under the then current
market conditions. We do not intend to enter into derivative
instruments that would exceed our expected production volumes
for the period covered by the derivative arrangement. Our
current credit agreement limits our ability to enter into
derivatives transactions to 85% of expected production volumes
from estimated proved reserves. Future credit agreements could
require a minimum level of commodity price hedging.
We use, or may use, a variety of commodity-based derivative
instruments, including collars, fixed-price swaps and basis
protection swaps. These transactions generally require no cash
payment upfront and are settled in cash at maturity. While our
derivative strategy may result in lower operating profits than
if we were not party to these derivative instruments in times of
high natural gas prices, we believe that the stabilization of
prices and protection afforded us by providing a revenue floor
for our production is very beneficial.
For natural gas derivatives, transactions are settled based upon
the New York Mercantile Exchange price of natural gas at the
Waha hub, a West Texas gas marketing and delivery center, on the
final trading day of the month. Settlement for natural gas
derivative contracts occurs in the month following the
production month. Generally, our trade counterparties are
affiliates of the financial institution that is a party to our
credit agreement, although we do have transactions with
counterparties that are not affiliated with this institution.
While we believe that the gas and oil price derivative
arrangements we enter into are important to our program to
manage price variability for our production, we have not
designated any of our derivative contracts as hedges for
accounting purposes. We record all derivative contracts on the
balance sheet at fair value, which will be significantly
affected by changes in gas and oil prices. We establish fair
value of our derivative contracts by market price quotations of
the derivative contract or, if not available, market price
quotations of derivative contracts with similar terms and
characteristics. When market quotations are not available, we
will estimate the fair value of derivative contracts using
option pricing models that management believes represent its
best estimate. Changes in fair values of our derivative
contracts that are not designated as hedges for accounting
purposes are recognized as unrealized gains and losses in
current period earnings. As a result, our current period
earnings may be significantly affected by changes in fair value
of our commodities derivative arrangements. The gain recognized
in earnings, included in operating costs and expenses, for the
years ended December 31, 2007 and 2006 was
$60.7 million and $12.3 million, respectively. For the
year ended December 31, 2005, we recognized a loss of
$4.1 million.
At December 31, 2007, our open commodity derivative
contracts consisted of the following:
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Weighted Avg.
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Period
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Commodity
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Notional Volume
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Fixed Price
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Fixed price swaps:
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November 2007 March 2008
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Natural gas
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1,520,000 MmBtu
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|
$
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8.51
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November 2007 June 2008
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Natural gas
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4,860,000 MmBtu
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$
|
8.05
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November 2007 June 2008
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Natural gas
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9,720,000 MmBtu
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$
|
8.20
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January 2008
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Natural gas
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310,000 MmBtu
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$
|
8.24
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January 2008 June 2008
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Natural gas
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3,640,000 MmBtu
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$
|
7.99
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January 2008 June 2008
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Natural gas
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3,640,000 MmBtu
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$
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7.99
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January 2008 December 2008
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Natural gas
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3,660,000 MmBtu
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$
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8.23
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January 2008 December 2008
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Natural gas
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3,660,000 MmBtu
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$
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8.48
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54
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Weighted Avg.
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Period
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Commodity
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Notional Volume
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Fixed Price
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January 2008 December 2008
|
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Natural gas
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3,660,000 MmBtu
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|
$
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9.00
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April 2008 June 2008
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Natural gas
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910,000 MmBtu
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$
|
7.17
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May 2008 August 2008
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Natural gas
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2,460,000 MmBtu
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$
|
8.38
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July 2008
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Natural gas
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310,000 MmBtu
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$
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8.00
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July 2008
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Natural gas
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310,000 MmBtu
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$
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8.02
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July 2008 September 2008
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Natural gas
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920,000 MmBtu
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$
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7.43
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July 2008 September 2008
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Natural gas
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920,000 MmBtu
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$
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7.49
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July 2008 September 2008
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Natural gas
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920,000 MmBtu
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$
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8.06
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July 2008 September 2008
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Natural gas
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920,000 MmBtu
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$
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8.07
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July 2008 September 2008
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Natural gas
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920,000 MmBtu
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$
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8.23
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July 2008 September 2008
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Natural gas
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920,000 MmBtu
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$
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8.36
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July 2008 December 2008
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Natural gas
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1,840,000 MmBtu
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$
|
8.31
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July 2008 December 2008
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Natural gas
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1,840,000 MmBtu
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$
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8.59
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August 2008
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Natural gas
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310,000 MmBtu
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$
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8.00
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August 2008
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Natural gas
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310,000 MmBtu
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$
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8.07
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September 2008
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Natural gas
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300,000 MmBtu
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$
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8.05
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September 2008
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Natural gas
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300,000 MmBtu
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$
|
8.10
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October 2008 December 2008
|
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Natural gas
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920,000 MmBtu
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$
|
7.96
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October 2008 December 2008
|
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Natural gas
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1,840,000 MmBtu
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$
|
8.00
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October 2008 December 2008
|
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Natural gas
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920,000 MmBtu
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$
|
8.07
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October 2008 December 2008
|
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|
Natural gas
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920,000 MmBtu
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$
|
8.11
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October 2008 December 2008
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Natural gas
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920,000 MmBtu
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$
|
8.16
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October 2008 December 2008
|
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Natural gas
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920,000 MmBtu
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$
|
8.32
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October 2008 December 2008
|
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|
Natural gas
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|
920,000 MmBtu
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$
|
8.83
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January 2009 March 2009
|
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Natural gas
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|
|
900,000 MmBtu
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|
|
$
|
8.56
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January 2009 March 2009
|
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Natural gas
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|
|
900,000 MmBtu
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|
|
$
|
8.60
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January 2009 March 2009
|
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|
Natural gas
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|
|
900,000 MmBtu
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|
|
$
|
8.65
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January 2009 March 2009
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Natural gas
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900,000 MmBtu
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$
|
8.91
|
|
Collars:
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January 2008 June 2008
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Crude oil
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42,000 Bbls
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|
$
|
50.00 - $83.35
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July 2008 December 2008
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Crude oil
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54,000 Bbls
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|
$
|
50.00 - $82.60
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Waha basis swaps:
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January 2008 December 2008
|
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Natural gas
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10,980,000 MmBtu
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|
$
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(0.57
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)
|
January 2008 December 2008
|
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|
Natural gas
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7,320,000 MmBtu
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|
$
|
(0.585
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)
|
January 2008 December 2008
|
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|
Natural gas
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|
7,320,000 MmBtu
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|
$
|
(0.59
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)
|
January 2008 December 2008
|
|
|
Natural gas
|
|
|
|
3,660,000 MmBtu
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|
|
$
|
(0.595
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)
|
January 2008 December 2008
|
|
|
Natural gas
|
|
|
|
3,660,000 MmBtu
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|
$
|
(0.625
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)
|
January 2008 December 2008
|
|
|
Natural gas
|
|
|
|
7,320,000 MmBtu
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|
|
$
|
(0.635
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)
|
January 2008 December 2008
|
|
|
Natural gas
|
|
|
|
7,320,000 MmBtu
|
|
|
$
|
(0.6525
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)
|
May 2008 August 2008
|
|
|
Natural gas
|
|
|
|
2,460,000 MmBtu
|
|
|
$
|
(0.45
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)
|
June 2008 August 2008
|
|
|
Natural gas
|
|
|
|
920,000 MmBtu
|
|
|
$
|
(0.4808
|
)
|
September 2008 December 2008
|
|
|
Natural gas
|
|
|
|
2,440,000 MmBtu
|
|
|
$
|
(0.7930
|
)
|
January 2009 December 2009
|
|
|
Natural gas
|
|
|
|
3,650,000 MmBtu
|
|
|
$
|
(0.47
|
)
|
January 2009 December 2009
|
|
|
Natural gas
|
|
|
|
3,650,000 MmBtu
|
|
|
$
|
(0.49
|
)
|
January 2009 December 2009
|
|
|
Natural gas
|
|
|
|
3,650,000 MmBtu
|
|
|
$
|
(0.4975
|
)
|
55
These derivatives have not been designated as hedges and the
Company records all derivatives on the balance sheet at fair
value. Changes in derivative fair values are recognized in
earnings. Cash settlements and valuation gains and losses are
included in (gain) loss on derivative contracts in the
consolidated statements of operations. The following summarizes
the cash settlements and valuation gains and losses for the
years ended December 31, 2007, 2006 and 2005 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Realized (gain) loss
|
|
$
|
(34,494
|
)
|
|
$
|
(14,169
|
)
|
|
$
|
2,836
|
|
Unrealized (gain) loss
|
|
|
(26,238
|
)
|
|
|
1,878
|
|
|
|
1,296
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) loss on derivative contracts
|
|
$
|
(60,732
|
)
|
|
$
|
(12,291
|
)
|
|
$
|
4,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Risk. We are subject to interest
rate risk on our long-term fixed and variable interest rate
borrowings. Fixed rate debt, where the interest rate is fixed
over the life of the instrument, exposes us (i) to changes
in market interest rates reflected in the fair value of the debt
and (ii) to the risk that we may need to refinance maturing
debt with new debt at a higher rate. Variable rate debt, where
the interest rate fluctuates, exposes us to short-term changes
in market interest rates as our interest obligations on these
instruments are periodically redetermined based on prevailing
market interest rates, primarily LIBOR and the federal funds
rate.
The indebtedness evidenced by notes payable related to our
drilling rig fleet and related oil field services equipment,
Sagebrush Pipeline, insurance financing, and other equipment and
vehicles and a portion of our senior term loans is a fixed-rate
debt, which exposes us to cash-flow risk from market interest
rate changes on these notes. The fair value of that debt varies
as interest rates change.
Borrowings under our senior credit facility and a portion of our
senior term loans expose us to certain market risks. We use
sensitivity analysis to determine the impact that market risk
exposures may have on our variable interest rate borrowings.
Based on the approximately $350.0 million outstanding
balance of the variable rate portion of our senior term loans at
December 31, 2007, a one percent change in the applicable
rate, with all other variables held constant, would result in a
change in our interest expense of approximately
$3.5 million for the year ended December 31, 2007.
In addition to commodity price derivative arrangements, we may
enter into derivative transactions to fix the interest we pay on
a portion of the money we borrow under our credit agreements. At
December 31, 2007, we were not party to any interest rate
swap instruments. In January 2008, we entered into a
$350 million notional amount interest rate swap agreement
with a financial institution that effectively fixed our interest
rate on the Variable Rate Term Loans at 6.2625% for the period
from April 1, 2008 through April 1, 2011.
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
Our consolidated financial statements required by this item are
included in this report beginning on
page F-1.
|
|
Item 9.
|
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure
|
Not applicable.
|
|
Item 9A.
|
Controls
and Procedures
|
Evaluation
of Disclosure Controls and Procedures
We performed an evaluation, under the supervision and with the
participation of our management, including our Chief Executive
Officer and Chief Financial Officer, of the effectiveness of the
design and operation of our disclosure controls and procedures
pursuant to Exchange Act
Rules 13a-15
and 15d-15
as of the end of the period covered by this report. Based upon
that evaluation, our Chief Executive Officer and our Chief
Financial Officer concluded that our disclosure controls and
procedures were effective to provide reasonable assurance that
the information required to be disclosed by us in our reports
filed or submitted under the Exchange Act is recorded,
processed, summarized and reported within the time periods
specified in the rules and forms of the Securities and Exchange
Commission and such information is accumulated and communicated
to management as appropriate to allow timely decisions regarding
required disclosure.
Changes
in Internal Control over Financial Reporting
There were no changes in our internal control over financial
reporting during the quarter ended December 31, 2007 that
have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
56
This annual report on
Form 10-K
does not include a report of managements assessment
regarding internal control over financial reporting or an
attestation report of the Companys registered public
accounting firm due to a transition period established by rules
of the Securities and Exchange Commission for newly public
companies.
|
|
Item 9B.
|
Other
Information
|
Not applicable.
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance
|
The information required by this item is incorporated herein by
reference to our definitive proxy statement, which will be filed
no later than April 29, 2008.
|
|
Item 11.
|
Executive
Compensation
|
The information required by this item is incorporated herein by
reference to our definitive proxy statement, which will be filed
no later than April 29, 2008.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
The information required by this item is incorporated herein by
reference to our definitive proxy statement, which will be filed
no later than April 29, 2008.
|
|
Item 13.
|
Certain
Relationships and Related Transactions and Director
Independence
|
The information required by this item is incorporated herein by
reference to our definitive proxy statement, which will be filed
no later than April 29, 2008.
|
|
Item 14.
|
Principal
Accountant Fees and Services
|
The information required by this item is incorporated herein by
reference to our definitive proxy statement, which will be filed
no later than April 29, 2008.
PART IV
|
|
Item 15.
|
Exhibits
and Financial Statement Schedules
|
The following documents are filed as a part of this report:
(1) Consolidated Financial Statements
Reference is made to the Index to Consolidated Financial
Statements appearing on
page F-1.
(2) Financial Statement Schedules
All financial statement schedules have been omitted because they
are not applicable or the required information is presented in
the consolidated financial statements or notes thereto.
(3) Exhibits
See Exhibit Index for a description of the exhibits filed
as a part of this report.
57
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
Page(s)
|
|
|
|
F-2
|
|
|
|
|
F-3
|
|
|
|
|
F-4
|
|
|
|
|
F-5
|
|
|
|
|
F-6
|
|
|
|
|
F-7
|
|
F-1
Report of
Independent Registered Public Accounting Firm
To the Board of Directors
and Stockholders of SandRidge Energy, Inc.
In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of operations, changes in
stockholders equity and of cash flows present fairly, in
all material respects, the financial position of SandRidge
Energy, Inc. and its subsidiaries at December 31, 2007 and
2006, and the results of their operations and their cash flows
for each of the three years in the period ended
December 31, 2007 in conformity with accounting principles
generally accepted in the United States of America. 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 of these statements in accordance with
standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit 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, and evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Houston, Texas
March 7, 2008
F-2
SandRidge
Energy, Inc. and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
63,135
|
|
|
$
|
38,948
|
|
Accounts receivable, net:
|
|
|
|
|
|
|
|
|
Trade
|
|
|
94,741
|
|
|
|
89,774
|
|
Related parties
|
|
|
20,018
|
|
|
|
5,731
|
|
Derivative contracts
|
|
|
21,958
|
|
|
|
|
|
Inventories
|
|
|
3,993
|
|
|
|
2,544
|
|
Deferred income taxes
|
|
|
1,820
|
|
|
|
6,315
|
|
Other current assets
|
|
|
20,787
|
|
|
|
31,494
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
226,452
|
|
|
|
174,806
|
|
Oil and natural gas properties, using full cost method of
accounting
|
|
|
|
|
|
|
|
|
Proved
|
|
|
2,848,531
|
|
|
|
1,636,832
|
|
Unproved
|
|
|
259,610
|
|
|
|
282,374
|
|
Less: accumulated depreciation and depletion
|
|
|
(230,974
|
)
|
|
|
(60,752
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
2,877,167
|
|
|
|
1,858,454
|
|
|
|
|
|
|
|
|
|
|
Other property, plant and equipment, net
|
|
|
460,243
|
|
|
|
276,264
|
|
Derivative contracts
|
|
|
270
|
|
|
|
|
|
Investments
|
|
|
7,956
|
|
|
|
3,584
|
|
Restricted deposits
|
|
|
31,660
|
|
|
|
33,189
|
|
Other assets
|
|
|
26,818
|
|
|
|
42,087
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,630,566
|
|
|
$
|
2,388,384
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
15,350
|
|
|
$
|
26,201
|
|
Accounts payable and accrued expenses:
|
|
|
|
|
|
|
|
|
Trade
|
|
|
215,497
|
|
|
|
129,799
|
|
Related parties
|
|
|
395
|
|
|
|
1,834
|
|
Asset retirement obligation
|
|
|
864
|
|
|
|
|
|
Derivative contracts
|
|
|
|
|
|
|
958
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
232,106
|
|
|
|
158,792
|
|
Long-term debt
|
|
|
1,052,299
|
|
|
|
1,040,630
|
|
Derivative contracts
|
|
|
|
|
|
|
3,052
|
|
Other long-term obligations
|
|
|
16,817
|
|
|
|
21,219
|
|
Asset retirement obligation
|
|
|
57,716
|
|
|
|
45,216
|
|
Deferred income taxes
|
|
|
49,350
|
|
|
|
24,922
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
1,408,288
|
|
|
|
1,293,831
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 16)
|
|
|
|
|
|
|
|
|
Minority interest
|
|
|
4,672
|
|
|
|
5,092
|
|
Redeemable convertible preferred stock, $0.001 par value,
2,625 shares authorized, 2,184 and 2,137 shares issued
and outstanding at December 31, 2007 and 2006, respectively
|
|
|
450,715
|
|
|
|
439,643
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value; 47,375 shares
authorized; no shares issued and outstanding in 2007 and 2006
|
|
|
|
|
|
|
|
|
Common stock, $0.001 par value, 400,000 shares
authorized; 141,847 issued and 140,391 outstanding at
December 31, 2007 and 93,048 issued and 91,604 outstanding
at December 31, 2006
|
|
|
140
|
|
|
|
92
|
|
Additional paid-in capital
|
|
|
1,686,113
|
|
|
|
574,868
|
|
Treasury stock, at cost
|
|
|
(18,578
|
)
|
|
|
(17,835
|
)
|
Retained earnings
|
|
|
99,216
|
|
|
|
92,693
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
1,766,891
|
|
|
|
649,818
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
3,630,566
|
|
|
$
|
2,388,384
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-3
SandRidge
Energy, Inc. and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and crude oil
|
|
$
|
477,612
|
|
|
$
|
101,252
|
|
|
$
|
49,987
|
|
Drilling and services
|
|
|
73,197
|
|
|
|
139,049
|
|
|
|
80,343
|
|
Midstream and marketing
|
|
|
107,765
|
|
|
|
122,896
|
|
|
|
147,133
|
|
Other
|
|
|
18,878
|
|
|
|
25,045
|
|
|
|
10,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
677,452
|
|
|
|
388,242
|
|
|
|
287,693
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
106,192
|
|
|
|
35,149
|
|
|
|
16,195
|
|
Production taxes
|
|
|
19,557
|
|
|
|
4,654
|
|
|
|
3,158
|
|
Drilling and services
|
|
|
44,211
|
|
|
|
98,436
|
|
|
|
52,122
|
|
Midstream and marketing
|
|
|
94,253
|
|
|
|
115,076
|
|
|
|
141,372
|
|
Depreciation, depletion and amortization natural gas
and crude oil
|
|
|
173,568
|
|
|
|
26,321
|
|
|
|
9,313
|
|
Depreciation, depletion and amortization other
|
|
|
53,541
|
|
|
|
29,305
|
|
|
|
14,893
|
|
General and administrative
|
|
|
61,780
|
|
|
|
55,634
|
|
|
|
11,908
|
|
(Gain) loss on derivative contracts
|
|
|
(60,732
|
)
|
|
|
(12,291
|
)
|
|
|
4,132
|
|
(Gain) loss on sale of assets
|
|
|
(1,777
|
)
|
|
|
(1,023
|
)
|
|
|
547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
490,593
|
|
|
|
351,261
|
|
|
|
253,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
186,859
|
|
|
|
36,981
|
|
|
|
34,053
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
5,423
|
|
|
|
1,109
|
|
|
|
206
|
|
Interest expense
|
|
|
(117,185
|
)
|
|
|
(16,904
|
)
|
|
|
(5,277
|
)
|
Minority interest
|
|
|
276
|
|
|
|
(296
|
)
|
|
|
(737
|
)
|
Income (loss) from equity investments
|
|
|
4,372
|
|
|
|
967
|
|
|
|
(384
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(107,114
|
)
|
|
|
(15,124
|
)
|
|
|
(6,192
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income tax expense
|
|
|
79,745
|
|
|
|
21,857
|
|
|
|
27,861
|
|
Income tax expense
|
|
|
29,524
|
|
|
|
6,236
|
|
|
|
9,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
50,221
|
|
|
|
15,621
|
|
|
|
17,893
|
|
Income from discontinued operations (net of tax expense of $118
in 2005)
|
|
|
|
|
|
|
|
|
|
|
229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
50,221
|
|
|
|
15,621
|
|
|
|
18,122
|
|
Preferred stock dividends and accretion
|
|
|
39,888
|
|
|
|
3,967
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income available to common stockholders
|
|
|
10,333
|
|
|
$
|
11,654
|
|
|
$
|
18,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
0.46
|
|
|
$
|
0.21
|
|
|
$
|
0.31
|
|
Income from discontinued operations, net of income tax
|
|
|
|
|
|
|
|
|
|
|
0.01
|
|
Preferred dividends
|
|
|
(0.37
|
)
|
|
|
(0.05
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted income per share available to common
stockholders
|
|
$
|
0.09
|
|
|
$
|
0.16
|
|
|
$
|
0.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
108,828
|
|
|
|
73,727
|
|
|
|
56,559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
110,041
|
|
|
|
74,664
|
|
|
|
56,737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
SandRidge
Energy, Inc. and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
Common
|
|
|
Paid-In
|
|
|
Deferred
|
|
|
Treasury
|
|
|
Retained
|
|
|
|
|
|
|
Stock
|
|
|
Stock
|
|
|
Capital
|
|
|
Compensation
|
|
|
Stock
|
|
|
Earnings
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Balance, December 31, 2004
|
|
$
|
23
|
|
|
$
|
200
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
59,108
|
|
|
$
|
59,331
|
|
Exchange of preferred stock for common stock
|
|
|
(23
|
)
|
|
|
1
|
|
|
|
22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of treasury shares
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
(17,335
|
)
|
|
|
|
|
|
|
(17,340
|
)
|
Stock split (change in par value)
|
|
|
|
|
|
|
(141
|
)
|
|
|
141
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of stock in acquisitions
|
|
|
|
|
|
|
4
|
|
|
|
55,281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55,285
|
|
Stock offering, net of $18.0 million in offering costs
|
|
|
|
|
|
|
12
|
|
|
|
173,110
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
173,122
|
|
Restricted shares
|
|
|
|
|
|
|
2
|
|
|
|
15,366
|
|
|
|
(15,366
|
)
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Amortization of deferred compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
481
|
|
|
|
|
|
|
|
|
|
|
|
481
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,122
|
|
|
|
18,122
|
|
Dividends on preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005
|
|
|
|
|
|
|
73
|
|
|
|
243,920
|
|
|
|
(14,885
|
)
|
|
|
(17,335
|
)
|
|
|
77,229
|
|
|
|
289,002
|
|
Stock offering
|
|
|
|
|
|
|
|
|
|
|
3,343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,343
|
|
Change in accounting principle for stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
(14,885
|
)
|
|
|
14,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of stock in acquisitions
|
|
|
|
|
|
|
13
|
|
|
|
236,271
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
236,284
|
|
Stock offering, net of $3.9 million in offering costs
|
|
|
|
|
|
|
6
|
|
|
|
97,427
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
97,433
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
8,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,792
|
|
Accretion on redeemable convertible preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(157
|
)
|
|
|
(157
|
)
|
Purchase of treasury shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(500
|
)
|
|
|
|
|
|
|
(500
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,621
|
|
|
|
15,621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
|
|
|
|
|
92
|
|
|
|
574,868
|
|
|
|
|
|
|
|
(17,835
|
)
|
|
|
92,693
|
|
|
|
649,818
|
|
Stock offerings, net of $4.5 million in offering costs
|
|
|
|
|
|
|
50
|
|
|
|
1,113,314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,113,364
|
|
Conversion of common stock to redeemable convertible preferred
stock
|
|
|
|
|
|
|
(1
|
)
|
|
|
(9,650
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,651
|
)
|
Accretion on redeemable convertible preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,421
|
)
|
|
|
(1,421
|
)
|
Purchase of treasury stock
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,660
|
)
|
|
|
|
|
|
|
(1,661
|
)
|
Common stock issued under retirement plan
|
|
|
|
|
|
|
|
|
|
|
379
|
|
|
|
|
|
|
|
917
|
|
|
|
|
|
|
|
1,296
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
7,202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,202
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,221
|
|
|
|
50,221
|
|
Redeemable convertible preferred stock dividend
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(42,277
|
)
|
|
|
(42,277
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
$
|
|
|
|
$
|
140
|
|
|
$
|
1,686,113
|
|
|
$
|
|
|
|
$
|
(18,578
|
)
|
|
$
|
99,216
|
|
|
$
|
1,766,891
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
SandRidge
Energy, Inc. and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
50,221
|
|
|
$
|
15,621
|
|
|
$
|
18,122
|
|
Income from discontinued operations, net of tax
|
|
|
|
|
|
|
|
|
|
|
229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
50,221
|
|
|
|
15,621
|
|
|
|
17,893
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for doubtful accounts
|
|
|
|
|
|
|
2,528
|
|
|
|
33
|
|
Depreciation, depletion and amortization
|
|
|
227,109
|
|
|
|
55,626
|
|
|
|
24,206
|
|
Debt issuance cost amortization
|
|
|
15,998
|
|
|
|
299
|
|
|
|
|
|
Deferred income taxes
|
|
|
28,923
|
|
|
|
348
|
|
|
|
9,460
|
|
Provision for inventory obsolescence
|
|
|
203
|
|
|
|
|
|
|
|
|
|
Unrealized (gain) loss on derivatives
|
|
|
(26,238
|
)
|
|
|
1,878
|
|
|
|
1,296
|
|
(Income) loss on sale of assets
|
|
|
(1,777
|
)
|
|
|
(1,023
|
)
|
|
|
547
|
|
Interest income restricted deposits
|
|
|
(1,354
|
)
|
|
|
(151
|
)
|
|
|
|
|
(Gain) loss from equity investments, net of distributions
|
|
|
(4,372
|
)
|
|
|
(956
|
)
|
|
|
846
|
|
Stock-based compensation
|
|
|
7,202
|
|
|
|
8,792
|
|
|
|
481
|
|
Minority interest
|
|
|
(276
|
)
|
|
|
296
|
|
|
|
737
|
|
Changes in operating assets and liabilities increasing
(decreasing) cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(19,061
|
)
|
|
|
(2,648
|
)
|
|
|
(25,494
|
)
|
Inventories
|
|
|
(1,730
|
)
|
|
|
(938
|
)
|
|
|
(46
|
)
|
Other current assets
|
|
|
12,374
|
|
|
|
(22,238
|
)
|
|
|
(1,146
|
)
|
Other assets and liabilities, net
|
|
|
(5,069
|
)
|
|
|
(2,131
|
)
|
|
|
775
|
|
Accounts payable and accrued expenses
|
|
|
75,299
|
|
|
|
12,046
|
|
|
|
33,709
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities by continuing
operations
|
|
|
357,452
|
|
|
|
67,349
|
|
|
|
63,297
|
|
Net cash provided by operating activities by discontinued
operations
|
|
|
|
|
|
|
|
|
|
|
347
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
357,452
|
|
|
|
67,349
|
|
|
|
63,644
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures for property, plant and equipment
|
|
|
(1,280,848
|
)
|
|
|
(306,541
|
)
|
|
|
(134,596
|
)
|
Acquisitions of assets, net of cash received of $0, $21,100 and
$66
|
|
|
(116,650
|
)
|
|
|
(1,054,075
|
)
|
|
|
(21,247
|
)
|
Proceeds from sale of assets
|
|
|
9,034
|
|
|
|
19,742
|
|
|
|
3,327
|
|
Proceeds from sale of investments
|
|
|
|
|
|
|
2,373
|
|
|
|
413
|
|
Contributions on equity investments
|
|
|
|
|
|
|
(3,388
|
)
|
|
|
(1,350
|
)
|
Refunds of restricted deposits
|
|
|
10,328
|
|
|
|
|
|
|
|
|
|
Fundings of restricted deposits
|
|
|
(7,445
|
)
|
|
|
(1,051
|
)
|
|
|
|
|
Restricted cash
|
|
|
|
|
|
|
2,373
|
|
|
|
(2,373
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities for continuing operations
|
|
|
(1,385,581
|
)
|
|
|
(1,340,567
|
)
|
|
|
(155,826
|
)
|
Net cash used in investing activities for discontinued operations
|
|
|
|
|
|
|
|
|
|
|
(1,473
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(1,385,581
|
)
|
|
|
(1,340,567
|
)
|
|
|
(157,299
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from borrowings
|
|
|
1,331,541
|
|
|
|
1,261,910
|
|
|
|
247,460
|
|
Repayments of borrowings
|
|
|
(1,332,219
|
)
|
|
|
(518,870
|
)
|
|
|
(301,285
|
)
|
Dividends paid-preferred
|
|
|
(33,321
|
)
|
|
|
|
|
|
|
(1
|
)
|
Minority interests contributions (distributions)
|
|
|
(144
|
)
|
|
|
(618
|
)
|
|
|
7,117
|
|
Proceeds from issuance of common stock
|
|
|
1,114,660
|
|
|
|
100,776
|
|
|
|
173,122
|
|
Proceeds from issuance of redeemable convertible preferred stock
|
|
|
|
|
|
|
439,486
|
|
|
|
|
|
Purchase of treasury shares
|
|
|
(1,661
|
)
|
|
|
(500
|
)
|
|
|
|
|
Debt issuance costs
|
|
|
(26,540
|
)
|
|
|
(15,749
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities for continuing
operations
|
|
|
1,052,316
|
|
|
|
1,266,435
|
|
|
|
126,413
|
|
Net cash provided by financing activities for discontinued
operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
1,052,316
|
|
|
|
1,266,435
|
|
|
|
126,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
|
|
24,187
|
|
|
|
(6,783
|
)
|
|
|
32,758
|
|
CASH AND CASH EQUIVALENTS, beginning of year
|
|
|
38,948
|
|
|
|
45,731
|
|
|
|
12,973
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, end of year
|
|
$
|
63,135
|
|
|
$
|
38,948
|
|
|
$
|
45,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosure of Cash Flow Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest, net of amounts capitalized
|
|
$
|
83,567
|
|
|
$
|
15,079
|
|
|
$
|
7,222
|
|
Cash paid for income taxes
|
|
|
2,371
|
|
|
|
1,599
|
|
|
|
|
|
Supplemental Disclosure of Noncash Investing and Financing
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Redeemable convertible preferred stock dividends, net of
dividends paid
|
|
$
|
8,956
|
|
|
$
|
|
|
|
$
|
|
|
Insurance premium financed
|
|
|
1,496
|
|
|
|
5,023
|
|
|
|
2,133
|
|
Accretion on redeemable convertible preferred stock
|
|
|
1,421
|
|
|
|
157
|
|
|
|
|
|
Common stock issued in connection with acquisitions
|
|
|
|
|
|
|
236,284
|
|
|
|
55,285
|
|
Assumption of restricted deposits and notes payable in
connection with acquisition
|
|
|
|
|
|
|
313,628
|
|
|
|
|
|
Assets disposed in exchange for common stock
|
|
|
|
|
|
|
|
|
|
|
17,335
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-6
SandRidge
Energy, Inc. and Subsidiaries
|
|
1.
|
Summary
of Significant Accounting Policies
|
Nature of Business. SandRidge Energy, Inc. and
its subsidiaries (formerly known as Riata Energy, Inc.)
(collectively, the Company or SandRidge)
is an oil and gas company with its principal focus on
exploration, development and production related to oil and gas
activities. SandRidge also owns and operates drilling rigs and
provides related oil field services, midstream gas services
operations, and
CO2
and tertiary oil recovery operations. SandRidges primary
exploration, development and production areas are concentrated
in West Texas. The Company also operates significant interests
in the Cotton Valley Trend in East Texas, Gulf Coast area, the
Gulf of Mexico, Oklahoma, and the Piceance Basin in Colorado.
On November 21, 2006, the Company acquired all of the
outstanding membership interests of NEG Oil & Gas LLC
(NEG) (See Note 2).
Principles of Consolidation. The consolidated
financial statements include the accounts of SandRidge Energy,
Inc. and its wholly owned or majority owned subsidiaries. All
significant intercompany accounts and transactions have been
eliminated in consolidation.
Reclassifications. Certain reclassifications
have been made in prior period financial statements to conform
with current period presentation.
Use of Estimates. The preparation of the
consolidated 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 and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could
differ from those estimates.
Estimates of oil and natural gas reserves and their values,
future production rates and future costs and expenses are
inherently uncertain for numerous reasons, including many
factors beyond the Companys control. Reservoir engineering
is a subjective process of estimating underground accumulations
of oil and natural gas that cannot be measured in an exact
manner. The accuracy of any reserve estimate is a function of
the quality of data available and of engineering and geological
interpretation and judgment. In addition, estimates of reserves
may be revised based on actual production, results of subsequent
exploitation and development activities, prevailing commodity
prices, operating costs and other factors. These revisions may
be material and could materially affect the Companys
future depletion, depreciation and amortization expenses.
The Companys revenue, profitability, and future growth are
substantially dependent upon the prevailing and future prices
for oil and natural gas, which are dependent upon numerous
factors beyond its control such as economic, regulatory
developments and competition from other energy sources. The
energy markets have historically been volatile and there can be
no assurance that oil and natural gas prices will not be subject
to wide fluctuations in the future. A substantial or extended
decline in oil and natural gas prices could have a material
adverse effect on the Companys financial position, results
of operations, cash flows and quantities of oil and natural gas
reserves that may be economically produced.
Cash and Cash Equivalents. The Company
considers all highly-liquid instruments with a maturity of three
months or less when purchased to be cash equivalents. Those
securities are readily convertible to known amounts of cash and
bear insignificant risk of changes in value due to their short
maturity period.
Restricted Cash. Restricted cash of
approximately $2.4 million at December 31, 2005 was
pledged as collateral on certain bank debt. The restriction was
released in April 2006.
Accounts Receivable, Net. The Company has
receivables for sales of oil, gas and natural gas liquids, as
well as receivables related to the exploration and extraction
services for oil, gas and natural gas liquids. Management has
established an allowance for doubtful accounts. The allowance is
evaluated by management and is based on managements
periodic review of the collectibility of the receivables in
light of historical experience, the nature and volume of the
receivables, and other subjective factors.
Inventories. Inventories consist of oil field
services supplies and are stated at the lower of cost or market
with cost determined on an average cost basis.
Debt Issue Costs. The Company amortizes debt
issue costs related to its senior credit facility, senior bridge
facility and term loans as interest expense over the scheduled
maturity period of the debt. Unamortized debt issuance costs
were approximately $26.0 million as of December 31,
2007 and approximately $15.5 million as of
December 31, 2006. The Company includes those unamortized
costs in other assets.
F-7
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Revenue Recognition and Gas Balancing. Oil and
natural gas revenues are recorded when title passes to the
customer, net of royalties, discounts and allowances, as
applicable. The Company accounts for oil and natural gas
production imbalances using the sales method, whereby the
Company recognizes revenue on all oil and natural gas sold to
its customers notwithstanding the fact that its ownership may be
less than 100% of the oil and natural gas sold. Liabilities are
recorded by the Company for imbalances greater than the
Companys proportionate share of remaining estimated oil
and natural gas reserves. The Company has recorded a liability
for gas imbalance positions related to gas properties with
insufficient proved reserves of $1.6 million and
$0.9 million at December 31, 2007 and 2006,
respectively. The Company includes the gas imbalance positions
in other long-term obligations.
The Company recognizes revenues and expenses generated from
daywork drilling contracts as the services are
performed, because the Company does not bear the risk of
completion of the well. Under footage and
turnkey contracts, the Company bears the risk of
completion of the well; therefore, revenues and expenses are
recognized when the well is substantially completed. Under this
method, substantial completion is determined when the well bore
reaches the negotiated depth as stated in the contract. The
duration of all three types of contracts ranges typically from
20 to 90 days. The entire amount of a loss, if any, is
recorded when the loss is determinable. The costs of uncompleted
drilling contracts include expenses incurred to date on
turnkey contracts that are still in process at the
end of the period.
The Company may receive lump-sum fees for the mobilization of
equipment and personnel. Mobilization fees received and costs
incurred to mobilize a rig from one market to another are
recognized over the term of the related drilling contract. The
contract terms are typically from 20 to 90 days.
Revenues from the midstream services segment are derived from
providing gathering, compression, treating, processing,
transportation, balancing and sales services for producers and
wholesale customers on natural gas pipelines, as well as other
interconnected pipeline systems. Midstream gas services are
primarily undertaken to realize incremental margins on gas
purchased at the wellhead, and provide value-added services to
customers. In general, natural gas purchased and sold by the
midstream gas business is priced at a published daily or monthly
index price. Sales to wholesale customers typically incorporate
a premium for managing their transmission and balancing
requirements. Revenues are recognized upon delivery of natural
gas to customers
and/or when
services are rendered, pricing is determinable and
collectibility is reasonably assured.
Revenue from sales of
CO2
is recognized when the product is delivered to the customer. The
Company recognizes service fees related to the transportation of
CO2
as revenue when the related service is provided.
Environmental Costs. Environmental
expenditures are expensed or capitalized, as appropriate,
depending on their future economic benefit. Expenditures that
relate to an existing condition caused by past operations, and
that do not have future economic benefit, are expensed.
Liabilities related to future costs are recorded on an
undiscounted basis when environmental assessments
and/or
remediation activities are probable and costs can be reasonably
estimated. Environmental costs accrued at December 31, 2007
and 2006 were not material.
Oil and Natural Gas Operations. The Company
uses the full cost method to account for its natural gas and oil
properties. Under full cost accounting, all costs directly
associated with the acquisition, exploration and development of
natural gas and oil reserves are capitalized into a full
cost pool. These capitalized costs include costs of all
unproved properties, internal costs directly related to the
Companys acquisition, exploration and development
activities and capitalized interest. During 2007, the Company
capitalized internal costs and interest expenses of
$4.6 million and $0.3 million, respectively, to the
full cost pool. No internal costs or interest expense was
capitalized to the full cost pool in 2006 or 2005.
Capitalized costs are amortized using a unit-of-production
method. Under this method, the provision for depreciation,
depletion and amortization is computed at the end of each
quarter by multiplying total production for such quarter by a
depletion rate. The depletion rate is determined by dividing the
total unamortized cost base plus future development costs by net
equivalent proved reserves at the beginning of the quarter.
Costs associated with unproved properties are excluded from the
total unamortized cost base until a determination has been made
as to the existence of proved reserves. Unproved properties are
reviewed at the end of each quarter to determine whether the
costs incurred should be reclassified to the full cost pool and,
thereby, subject to amortization. Sales and abandonments of
natural gas and oil properties being amortized are accounted for
as adjustments to the full cost pool, with no gain or loss
recognized, unless the adjustments would significantly alter the
relationship between capitalized costs and proved natural gas
and oil reserves. A significant alteration would not ordinarily
be expected to occur upon the sale of reserves involving less
than 25% of the reserve quantities of a cost center.
F-8
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Under full cost accounting, total capitalized costs of natural
gas and oil properties (net of accumulated depreciation,
depletion and amortization) less related deferred income taxes
may not exceed an amount equal to the present value of future
net revenues from proved reserves, discounted at 10% per annum,
plus the lower of cost or fair value of unevaluated properties,
plus estimated salvage value, less income tax effects (the
ceiling limitation). A ceiling limitation
calculation is performed at the end of each quarter. If total
capitalized costs (net of accumulated depreciation, depletion
and amortization) less related deferred taxes are greater than
the ceiling limitation, a write-down or impairment of the full
cost pool is required. A write-down of the carrying value of the
full cost pool is a non-cash charge that reduces earnings and
impacts stockholders equity in the period of occurrence
and typically results in lower depreciation, depletion and
amortization expense in future periods. Once incurred, a
write-down is not reversible at a later date.
The ceiling test is calculated using natural gas and oil prices
in effect as of the balance sheet date, as adjusted for
basis or location differentials as of the balance
sheet date and held constant over the life of the reserves
(net wellhead prices). If applicable, these net
wellhead prices would be further adjusted to include the effects
of any fixed price arrangements for the sale of natural gas and
oil. The Company may, from time-to-time, use derivative
financial instruments to hedge against the volatility of natural
gas prices. Derivative contracts that qualify and are designated
as cash flow hedges are included in estimated future cash flows.
Historically, the Company has not designated any of its
derivative contracts as cash flow hedges. In addition, the
future cash outflows associated with future development or
abandonment of wells are included in the computation of the
discounted present value of future net revenues for purposes of
the ceiling test calculation.
The costs associated with unproved properties are not initially
included in the amortization base and relate to unproved
leasehold acreage, wells and production facilities in progress
and wells pending determination of the existence of proved
reserves, together with capitalized interest costs for these
projects. Unproved leasehold costs are transferred to the
amortization base with the costs of drilling the related well
once a determination of the existence of proved reserves has
been made or upon impairment of a lease. Costs of seismic data
are allocated to various unproved leaseholds and transferred to
the amortization base with the associated leasehold costs on a
specific project basis. Costs associated with wells in progress
and completed wells that have yet to be evaluated are
transferred to the amortization base once a determination is
made whether or not proved reserves can be assigned to the
property. Costs of dry holes are transferred to the amortization
base immediately upon determination that the well is
unsuccessful.
All items classified as unproved property are assessed on a
quarterly basis for possible impairment or reduction in value.
Properties are assessed on an individual basis or as a group if
properties are individually insignificant. The assessment
includes consideration of the following factors, among others:
intent to drill; remaining lease term; geological and
geophysical evaluations; drilling results and activity; the
assignment of proved reserves; and the economic viability of
development if proved reserves are assigned. During any period
in which these factors indicate an impairment, the cumulative
drilling costs incurred to date for such property and all or a
portion of the associated leasehold costs are transferred to the
full cost pool and are then subject to amortization.
Property, Plant and Equipment, Net. Other
capitalized costs, including drilling equipment, natural gas
gathering and processing equipment, transportation equipment and
other property and equipment are carried at cost. Renewals and
improvements are capitalized while repairs and maintenance are
expensed. Depreciation of drilling equipment is recorded using
the straight-line method based on estimated useful lives.
Depreciation of other property and equipment is computed using
the straight-line method over the estimated useful lives of the
assets ranging from 3 to 39 years.
Realization of the carrying value of property and equipment is
reviewed for possible impairment whenever events or changes in
circumstances indicate that the carrying amount may not be
recoverable. Assets are determined to be impaired if a forecast
of undiscounted estimated future net operating cash flows
directly related to the asset including disposal value if any,
is less than the carrying amount of the asset. If any asset is
determined to be impaired, the loss is measured as the amount by
which the carrying amount of the asset exceeds its fair value.
An estimate of fair value is based on the best information
available, including prices for similar assets. Changes in such
estimates could cause the Company to reduce the carrying value
of property and equipment.
When property and equipment components are disposed of, the cost
and the related accumulated depreciation are removed from the
accounts and any resulting gain or loss is generally reflected
in operations.
Investments. Investments in affiliated
companies are accounted for under the cost or equity method,
based on the Companys ability to exercise significant
influence.
Asset Retirement Obligation. The Company owns
oil and natural gas properties which require expenditures to
plug and abandon the wells when the oil and natural gas reserves
in the wells are depleted. These expenditures are recorded in
the period in which the liability is incurred (at the time the
wells are drilled or acquired). Asset retirement obligations are
recorded as a liability at
F-9
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
their estimated present value at the assets inception,
with the offsetting increase to property cost. Periodic
accretion expense of the estimated liability is recorded in the
statements of operations.
Asset retirement obligations primarily represent the
Companys estimate of fair value to plug, abandon and
remediate the oil and natural gas properties at the end of their
productive lives, in accordance with applicable state laws. The
Company has determined its asset retirement obligations by
calculating the present value of estimated expenses related to
the liability. Estimating the future asset retirement
obligations requires management to make estimates and judgments
regarding timing, existence of a liability, and what constitutes
adequate restoration. Inherent in the present value calculation
rates, are the timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the
extent future revisions to these assumptions impact the present
value of the existing asset retirement obligations liability, a
corresponding adjustment is made to the related asset. The
following is a reconciliation of the asset retirement obligation
for the years ended December 31 (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
Asset retirement obligation, January 1
|
|
$
|
45,216
|
|
|
$
|
6,979
|
|
|
$
|
4,394
|
|
Liability incurred upon acquiring and drilling wells
|
|
|
3,265
|
|
|
|
2,996
|
|
|
|
2,779
|
|
NEG acquisition
|
|
|
|
|
|
|
40,343
|
|
|
|
|
|
Revisions in estimated cash flows
|
|
|
5,971
|
|
|
|
(5,700
|
)
|
|
|
|
|
Liability settled in current period
|
|
|
(9
|
)
|
|
|
|
|
|
|
(512
|
)
|
Accretion of discount expense
|
|
|
4,137
|
|
|
|
598
|
|
|
|
318
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation, December 31
|
|
|
58,580
|
|
|
|
45,216
|
|
|
|
6,979
|
|
Less: current portion
|
|
|
864
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation, net of current
|
|
$
|
57,716
|
|
|
$
|
45,216
|
|
|
$
|
6,979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Taxes. Deferred income taxes are
provided on temporary differences between financial statement
and income tax reporting. Temporary differences are differences
between the amounts of assets and liabilities reported for
financial statement purposes and their tax bases. Deferred tax
assets are recognized for temporary differences that will be
deductible in future years tax returns and for operating
loss and tax credit carryforwards. Deferred tax assets are
reduced by a valuation allowance if it is deemed more likely
than not that some or all of the deferred tax assets will not be
realized. Deferred tax liabilities are recognized for temporary
differences that will be taxable in future years tax
returns.
The Company accounts for uncertain tax positions in accordance
with FASB Interpretation No. 48 (FIN 48),
Accounting for Uncertainty in Income Taxes.
Accordingly, the Company reports a liability for unrecognized
tax benefits resulting from uncertain tax positions taken or
expected to be taken in a tax return. The Company recognizes
interest and penalties, if any, related to unrecognized tax
benefits in income tax expense.
Minority Interest. As of December 31,
2007, minority interest in the Companys consolidated
subsidiaries consisted of the following:
|
|
|
|
|
26.19% interest in Sagebrush Pipeline, LLC; and
|
|
|
|
1.29% interest in Cholla Pipeline, LP.
|
Concentration of Risk. The Company maintains
cash balances at several banks. Accounts at each institution are
insured by the Federal Deposit Insurance Corporation up to
$100,000. From time to time, the Company may have balances in
these accounts that exceed the federally insured limit. The
Company does not anticipate any loss associated with balances in
excess of the federally insured limit.
Fair Value of Financial Instruments. For
certain of the Companys financial instruments, including
cash, accounts receivable and accounts payable, the carrying
value approximates fair value because of their short maturity.
The carrying value of borrowings under the senior credit
facility and the notes payable approximates fair value because
their interest rates are based on market indexes. The fair value
of the fixed portion of the Companys senior credit
facility and convertible preferred stock approximate book value
as reflected in the accompanying balance sheets.
Derivative Financial Instruments. To manage
risks related to increases in interest rates and changes in oil
and gas prices, the Company occasionally enters into interest
rate swaps and oil and gas derivatives contracts.
F-10
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The Company recognizes all of its derivative instruments as
either assets or liabilities at fair value. The accounting for
changes in the fair value (i.e., gains or losses) of a
derivative instrument depends on whether it has been designated
and qualifies as part of a hedging relationship, and further, on
the type of hedging relationship. For those derivative
instruments that are designated and qualify as hedging
instruments, the Company designates the hedging instrument,
based on the exposure being hedged, as either a fair value hedge
or a cash flow hedge. For derivative instruments not designated
as hedging instruments, the gain or loss is recognized in
current earnings during the period of change. None of the
Companys derivatives were designated as hedging
instruments during 2007, 2006 and 2005.
Stock-Based Compensation. Effective
January 1, 2006, the Company adopted
SFAS No. 123-R,
Share-Based Payment (SFAS 123R).
SFAS 123R establishes the accounting for equity instruments
exchanged for employee services. Under SFAS 123R,
share-based compensation cost is measured at the grant date
based on the calculated fair value of the award. The expense is
recognized over the employees requisite service period,
generally the vesting period of the award. SFAS 123R also
requires the related excess tax benefit received upon exercise
of stock options or vesting of restricted stock, if any, to be
reflected in the statement of cash flows as a financing activity
rather than an operating activity. The Company does not have any
excess tax benefits.
Recent Accounting Pronouncements. In September
2006, the FASB issued SFAS No. 157, Fair Value
Measurements, which establishes a formal framework for
measuring fair values of assets and liabilities in financial
statements that are already required by U.S generally accepted
accounting principles to be measured at fair value.
SFAS No. 157 clarifies guidance in FASB Concepts
Statement No. 7 which discusses present value techniques in
measuring fair value. Additional disclosures are also required
for transactions measured at fair value. No new fair value
measurements are prescribed, and SFAS No. 157 is
intended to codify the several definitions of fair value
included in various accounting standards. However, the
application of this Statement may change current practices for
certain companies. SFAS No. 157 is effective for
fiscal years beginning after November 15, 2007. The Company
will implement SFAS No. 157 on January 1, 2008.
The Company continues to evaluate the impact of
SFAS No. 157 on the consolidated financials statements.
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 permits an entity to choose to measure
certain financial assets and liabilities at fair value.
SFAS No. 159 also revises provisions of
SFAS No. 115 that apply to available-for-sale and
trading securities. This statement is effective for fiscal years
beginning after November 15, 2007. We do not believe the
adoption of SFAS No. 159 will have a material impact
on our consolidated financial position, results of operations,
or cash flows.
In December 2007, the FASB issued SFAS No. 141(R),
Business Combinations, which replaces
SFAS No. 141. SFAS No. 141(R) establishes
principles and requirements for how an acquirer recognizes and
measures in its financial statements the identifiable assets
acquired, the liabilities assumed, any noncontrolling interest
in the acquiree and the goodwill acquired. The Statement also
establishes disclosure requirements which will enable users to
evaluate the nature and financial effects of the business
combination. SFAS No. 141(R) is effective for fiscal
years beginning after December 15, 2008. The Company plans
to implement this standard on January 1, 2009. The Company
has not yet evaluated the potential impact of this standard.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statements an amendment of Accounting Research
Bulletin No. 51, which establishes accounting
and reporting standards for ownership interests in subsidiaries
held by parties other than the parent, the amount of
consolidated net income attributable to the parent and to the
noncontrolling interest, changes in a parents ownership
interest and the valuation of retained noncontrolling equity
investments when a subsidiary is deconsolidated. The Statement
also establishes reporting requirements that provide sufficient
disclosures that clearly identify and distinguish between the
interests of the parent and the interests of the noncontrolling
owners. SFAS No. 160 is effective for fiscal years
beginning after December 15, 2008. The Company plans to
implement this standard on January 1, 2009. The Company has
not evaluated the potential impact of this standard.
|
|
2.
|
Acquisitions
and Dispositions
|
2005
Acquisitions
The Company closed the following acquisitions in 2005:
|
|
|
|
|
Acquired additional equity interests in PetroSource Energy
Company, LLC (PetroSource), which increased the
Companys ownership from 22.4% to 86.5%, resulting in the
consolidation of PetroSource in the Companys financial
statements;
|
F-11
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
Acquired from an executive officer and director the remaining
50% equity interest in the Companys compression services
subsidiary, Lariat Compression Company (Larco),
resulting in it becoming a wholly-owned subsidiary;
|
|
|
|
Acquired from an executive officer and director approximately
7,400 net acres of additional leasehold interest in West
Texas in properties in which the Company previously held
interests;
|
|
|
|
Acquired approximately 2,503 net acres additional leasehold
interest in property in the Piceance Basin in which the Company
previously held interests;
|
|
|
|
Acquired from a director additional working interests in
Missouri and Nevada leases in which the Company previously held
interests;
|
|
|
|
Acquired an additional 19.5% before pay-out interest in the
Companys subsidiary, Sagebrush Pipeline LLC; and
|
|
|
|
Acquired certain interests in several oil and natural gas
properties in West Texas from Carl E. Gungoll Exploration, LLC
and certain other parties. The purchase price was approximately
$8.0 million, comprised of $5.4 million in cash, and
174,833 shares of common stock (valued at
$2.6 million).
|
The acquisitions were financed with approximately
$21.3 million in cash and the issuance of
3,685,690 shares of common stock with an aggregate value of
approximately $55.3 million. Details are set forth below
for each of the acquisition transactions (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Addition to
|
|
|
|
|
|
|
|
|
|
|
|
Consideration Paid
|
|
|
|
Property,
|
|
|
|
|
|
Elimination
|
|
|
Change in
|
|
|
Common
|
|
|
Common
|
|
|
Cash, Net
|
|
|
|
Plant &
|
|
|
Addition to Net
|
|
|
of
|
|
|
Minority
|
|
|
Stock No.
|
|
|
Stock at
|
|
|
of Cash
|
|
Acquisition Transaction
|
|
Equipment
|
|
|
Assets(1)
|
|
|
Investments
|
|
|
Interest
|
|
|
of Shares
|
|
|
$15/Share
|
|
|
Acquired
|
|
|
PetroSource additional interests
|
|
$
|
73,744
|
|
|
$
|
(37,381
|
)
|
|
$
|
(3,052
|
)
|
|
$
|
3,253
|
|
|
|
958
|
|
|
$
|
14,372
|
|
|
$
|
15,686
|
|
Larco remaining interest
|
|
|
5,054
|
|
|
|
|
|
|
|
|
|
|
|
(2,446
|
)
|
|
|
500
|
|
|
|
7,500
|
|
|
|
|
|
West Texas additional lease interests
|
|
|
10,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
667
|
|
|
|
10,000
|
|
|
|
|
|
Piceance Basin additional interests
|
|
|
17,565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,164
|
|
|
|
17,456
|
|
|
|
109
|
|
Various additional lease interests
|
|
|
268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
|
|
268
|
|
|
|
|
|
Sagebrush additional interests
|
|
|
689
|
|
|
|
|
|
|
|
|
|
|
|
(2,378
|
)
|
|
|
204
|
|
|
|
3,067
|
|
|
|
|
|
Gungoll lease interests
|
|
|
8,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
176
|
|
|
|
2,622
|
|
|
|
5,452
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
$
|
115,394
|
|
|
$
|
(37,381
|
)
|
|
$
|
(3,052
|
)
|
|
$
|
(1,571
|
)
|
|
|
3,686
|
|
|
$
|
55,285
|
|
|
$
|
21,247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The purchase price for additional interests in PetroSource was
approximately $30.1 million, comprised of
$15.7 million in cash (net of $0.1 million in cash
acquired), and approximately 958,000 shares of SandRidge
common stock (valued at $14.4 million). The purchase price
has been allocated to accounts receivable of $4.5 million,
other current assets of $0.1 million, other assets of
$0.4 million, accounts payable and accrued expenses of
$2.6 million, long-term debt of $37.4 million, and
asset retirement obligations of $2.4 million. |
The Company completed its purchase accounting allocations for
the 2005 acquisitions in 2006 and recorded an additional
$3.8 million deferred tax liability related to the Larco
equity acquisition.
2006
Acquisitions and Dispositions
The Company closed the following acquisitions in 2006:
|
|
|
|
|
On March 15, 2006, the Company acquired from an executive
officer and director, an additional 12.5% interest in
PetroSource. The acquisition consisted of the retirement of
subordinated debt of approximately $1.0 million and a
$4.5 million cash payment for the ownership interest
acquired for a total acquisition price of approximately
$5.5 million.
|
|
|
|
On May 1, 2006, the Company purchased certain leases in
developed and undeveloped properties from an oil and gas
company. The purchase price was approximately $40.9 million
in cash. The cash consideration was paid in July 2006.
|
|
|
|
On May 26, 2006, the Company purchased several oil and
natural gas properties from an oil and gas company. The purchase
price was approximately $12.9 million, comprised of
$8.2 million in cash, and 251,351 shares of Company
common stock (valued at $4.7 million). The cash and equity
consideration was paid in July 2006.
|
F-12
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
On June 1, 2006, the Company purchased certain producing
well interests from an executive officer and director. The
purchase price was approximately $9.0 million in cash.
|
|
|
|
On June 7, 2006, the Company acquired the remaining 1%
interest in PetroSource Energy Company, a consolidated
subsidiary, from an oil and gas company. The purchase price was
27,749 shares of Company common stock (valued at
$0.5 million). As a result of this acquisition, the Company
became the 100% owner of PetroSource.
|
The 2006 acquisitions described above were financed with
approximately $63.7 million in cash and the issuance of
279,100 shares of common stock with an aggregate value of
approximately $5.1 million. Details are set forth below for
each of the acquisition transactions (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consideration Paid
|
|
|
|
Addition to
|
|
|
Change in
|
|
|
Retirement
|
|
|
Common
|
|
|
|
|
|
|
|
Acquisition
|
|
Property, Plant
|
|
|
Minority
|
|
|
of Subordinated
|
|
|
Stock No.
|
|
|
Common
|
|
|
|
|
Transaction
|
|
&Equipment
|
|
|
Interest
|
|
|
Debt(1)
|
|
|
of Shares
|
|
|
Stock
|
|
|
Cash
|
|
|
PetroSource additional interests
|
|
$
|
2,116
|
|
|
$
|
(2,370
|
)
|
|
$
|
(1,003
|
)
|
|
|
|
|
|
$
|
|
|
|
$
|
5,489
|
|
Purchased leases
|
|
|
40,960
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,960
|
|
Oil and natural gas properties
|
|
|
12,850
|
|
|
|
|
|
|
|
|
|
|
|
251
|
|
|
|
4,650
|
|
|
|
8,200
|
|
Producing well interest from executive officer and director
|
|
|
9,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,000
|
|
PetroSource additional interest (remaining 1% interest)
|
|
|
85
|
|
|
|
(393
|
)
|
|
|
|
|
|
|
28
|
|
|
|
478
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
$
|
65,011
|
|
|
$
|
(2,763
|
)
|
|
$
|
(1,003
|
)
|
|
|
279
|
|
|
$
|
5,128
|
|
|
$
|
63,649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes retirement of subordinated debt of $972,000 and accrued
interest of $31,000. |
In July 2006, the Company sold leaseholds and lease and well
equipment for $16.0 million. The book basis of the assets
at the time of the sale transaction was $3.7 million
resulting in a gain of $12.3 million. The sale was
accounted for as an adjustment to the full cost pool, with no
gain recognized.
On November 21, 2006, the Company acquired all of the
outstanding membership interests in NEG Oil & Gas, or
NEG, for approximately $990.4 million in cash, the
assumption of $300.0 million in debt, the receipt of cash
of $21.1 million, and the issuance of
12,842,000 shares of the Companys common stock
(valued at approximately $231.2 million). With core assets
in the Val Verde and Permian Basins of West Texas, including
overlapping or contiguous interests in the WTO, the NEG
acquisition has dramatically increased our exploration and
production segment operations. To finance the NEG acquisition,
the Company entered into a new $750 million senior secured
credit facility and an $850 million senior unsecured bridge
loan facility. The Company also issued $550 million of
redeemable convertible preferred stock and common units
(consisting of shares of common stock and a warrant to purchase
convertible preferred stock upon the surrender of the common
stock) in a private placement to certain eligible purchasers.
In the fourth quarter of 2007, we completed our valuation of
assets acquired and liabilities assumed related to the NEG
acquisition and allocated the appropriate fair values. Upon
further refinement of the appraisal values, we have increased
our values assigned to the properties acquired and reduced the
value assigned to goodwill of $26.2 million. The
accompanying balance sheet at December 31, 2006 includes
the preliminary allocations of the purchase price for the NEG
acquisition. The allocation of the purchase price to specific
assets and liabilities were based, in part, upon an appraisal of
the fair value of NEG assets.
F-13
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The following table presents the final NEG acquisition purchase
price allocation, including professional fees and other related
acquisition costs, to the net assets acquired and liabilities
assumed, based on the fair values at the acquisition date and
including subsequent adjustments to the purchase price
allocation (in thousands):
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
21,100
|
|
Accounts receivable
|
|
|
30,840
|
|
Other current assets
|
|
|
6,025
|
|
Property, plant and equipment
|
|
|
1,524,072
|
|
Restricted deposits
|
|
|
31,987
|
|
Other assets
|
|
|
270
|
|
|
|
|
|
|
Total assets acquired
|
|
|
1,614,294
|
|
Accounts payable and other current liabilities
|
|
|
46,082
|
|
Deferred income taxes
|
|
|
2,189
|
|
Long-term debt
|
|
|
281,641
|
|
Other long-term obligations
|
|
|
1,357
|
|
Asset retirement obligation
|
|
|
40,343
|
|
|
|
|
|
|
Net assets acquired
|
|
|
1,242,682
|
|
Less: Cash and cash equivalents acquired
|
|
|
(21,100
|
)
|
|
|
|
|
|
Net amount paid for acquisition
|
|
$
|
1,221,582
|
|
|
|
|
|
|
Pro
Forma Information
The unaudited financial information in the table below
summarizes the combined results of operations of SandRidge and
NEG, on a pro forma basis, as though the companies had been
combined as of January 1, 2005. The pro forma financial
information is presented for informational purposes only and is
not indicative of the results of operations that would have been
achieved if the acquisition had taken place on January 1,
2005 or of results that may occur in the future. The pro forma
adjustments include estimates and assumptions based on currently
available information. The Company believes the estimates and
assumptions are reasonable, and the significant effects of the
transactions are properly reflected. However, actual results may
differ materially from this pro forma financial information. The
following table presents the actual results for the years ended
December 31, 2006 and 2005 and the respective unaudited pro
forma information to reflect the NEG acquisition (in thousands,
except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
Actual
|
|
|
Pro Forma
|
|
|
Actual
|
|
|
Pro Forma
|
|
|
|
(Unaudited)
|
|
|
Revenues
|
|
$
|
388,242
|
|
|
$
|
565,256
|
|
|
$
|
287,693
|
|
|
$
|
560,235
|
|
Income (loss) from continuing operations
|
|
|
15,621
|
|
|
|
36,337
|
|
|
|
17,893
|
|
|
|
(49,594
|
)
|
Net income (loss)
|
|
|
15,621
|
|
|
|
36,337
|
|
|
|
18,122
|
|
|
|
(49,594
|
)
|
Basic and diluted earnings per share available (applicable) to
common stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
$
|
0.21
|
|
|
$
|
0.40
|
|
|
$
|
0.31
|
|
|
$
|
(0.96
|
)
|
Net income (loss) available to common stockholders
|
|
$
|
0.16
|
|
|
$
|
0.04
|
|
|
$
|
0.32
|
|
|
$
|
(0.96
|
)
|
2007
Acquisitions
The Company closed the following acquisitions in 2007:
|
|
|
|
|
On October 9, 2007, the Company purchased developed and
undeveloped properties located in West Texas from an oil and gas
company. The purchase price was approximately
$73.8 million, comprised of $25.0 million in cash and
a $48.8 million note payable. The $25 million cash
consideration paid was funded through a draw on the
Companys senior credit facility. All principal and accrued
interest (interest at 7% annually) due on the note payable were
repaid on November 9, 2007 with proceeds from the
Companys initial public offering. For additional
discussion of the Companys initial public offering, refer
to Note 18 herein.
|
F-14
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
On November 28, 2007, the Company purchased a gas treatment
plant and related gathering system located in Pecos County,
Texas. The purchase price of approximately $10.0 million
was paid in cash.
|
|
|
|
On November 29, 2007, the Company purchased leasehold
acreage and producing well interests located predominantly in
the WTO from a group of entities controlled by a significant
shareholder. The purchase price of approximately
$32.0 million was paid in cash.
|
|
|
3.
|
Discontinued
Operations
|
On September 30, 2005, the Company exchanged substantially
all of its land and agriculture operations with its majority
shareholder. The majority shareholder exchanged
1,414,849 shares of the Companys common stock for
these operations. The shares were exchanged at their historical
basis and the exchange was reflected as a treasury share
transaction. The net book value of assets exchanged was
$23.6 million. There was no gain (loss) recognized in this
transaction. The land and agriculture operations are presented
as discontinued operations, net of income taxes in the
consolidated statements of operations.
The following table summarizes net revenue and net income from
discontinued operations for the years ended December 31 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Revenues
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,683
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
(1,336
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
347
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
(118
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from discontinued operations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No assets were classified as held for sale at December 31,
2007 or 2006.
A summary of accounts receivable is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Oil and natural gas services
|
|
$
|
6,622
|
|
|
$
|
8,489
|
|
Oil and natural gas sales
|
|
|
72,393
|
|
|
|
57,458
|
|
Joint interest billing
|
|
|
17,874
|
|
|
|
26,553
|
|
Other
|
|
|
90
|
|
|
|
299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
96,979
|
|
|
|
92,799
|
|
Less allowance for doubtful accounts
|
|
|
(2,238
|
)
|
|
|
(3,025
|
)
|
|
|
|
|
|
|
|
|
|
Total accounts receivable, net
|
|
$
|
94,741
|
|
|
$
|
89,774
|
|
|
|
|
|
|
|
|
|
|
The following tables show the balance in the allowance for
doubtful accounts and activity for the years ended December 31
(in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
|
Charged to
|
|
|
|
|
|
Balance at
|
|
|
|
Beginning
|
|
|
Costs and
|
|
|
|
|
|
End of
|
|
Allowance for Doubtful Accounts
|
|
of Period
|
|
|
Expenses
|
|
|
Deductions(1)
|
|
|
Period
|
|
|
Year ended December 31, 2005
|
|
$
|
1,074
|
|
|
$
|
33
|
|
|
$
|
(256
|
)
|
|
$
|
851
|
|
Year ended December 31, 2006
|
|
$
|
851
|
|
|
$
|
2,528
|
|
|
$
|
(354
|
)
|
|
$
|
3,025
|
|
Year ended December 31, 2007
|
|
$
|
3,025
|
|
|
$
|
|
|
|
$
|
(787
|
)
|
|
$
|
2,238
|
|
|
|
|
(1) |
|
Deductions represent the write-off/recovery of receivables. |
F-15
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Other current assets consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Prepaid insurance
|
|
$
|
9,379
|
|
|
$
|
7,604
|
|
Prepaid drilling
|
|
|
5,924
|
|
|
|
2,207
|
|
Materials and supplies
|
|
|
4,751
|
|
|
|
6,244
|
|
Post closing receivable NEG acquisition
|
|
|
|
|
|
|
15,232
|
|
Other
|
|
|
733
|
|
|
|
207
|
|
|
|
|
|
|
|
|
|
|
Total other current assets
|
|
$
|
20,787
|
|
|
$
|
31,494
|
|
|
|
|
|
|
|
|
|
|
|
|
6.
|
Property,
Plant and Equipment
|
Property, plant and equipment consists of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Oil and natural gas properties:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
2,848,531
|
|
|
$
|
1,636,832
|
|
Unproved
|
|
|
259,610
|
|
|
|
282,374
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas properties
|
|
|
3,108,141
|
|
|
|
1,919,206
|
|
Less accumulated depreciation and depletion
|
|
|
(230,974
|
)
|
|
|
(60,752
|
)
|
|
|
|
|
|
|
|
|
|
Net oil and natural gas properties capitalized costs
|
|
|
2,877,167
|
|
|
|
1,858,454
|
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
1,149
|
|
|
|
738
|
|
Non oil and gas equipment
|
|
|
539,893
|
|
|
|
337,294
|
|
Buildings and structures
|
|
|
38,288
|
|
|
|
6,564
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
579,330
|
|
|
|
344,596
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(119,087
|
)
|
|
|
(68,332
|
)
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
|
460,243
|
|
|
|
276,264
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
$
|
3,337,410
|
|
|
$
|
2,134,718
|
|
|
|
|
|
|
|
|
|
|
The amount of capitalized interest included in the above non oil
and gas equipment balance at December 31, 2007 and 2006 was
approximately $3.4 million and $1.4 million,
respectively. The Company did not capitalize any interest in
2005.
On July 11, 2007, the Company purchased property to serve
as its future corporate headquarters. The 3.51-acre site
contains four buildings and is located in downtown Oklahoma
City, Oklahoma. The purchase price was approximately
$29.5 million in cash. Payment of the purchase price was
funded through a draw on the Companys senior credit
facility.
F-16
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Costs
Excluded from Amortization
Costs associated with unproved properties related to continuing
operations of $259.6 million as of December 31, 2007
are excluded from amounts subject to amortization. A summary of
costs related to unproved properties which have been excluded
from oil and natural gas properties being amortized at
December 31, 2007 and the year in which they were incurred
is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluded
|
|
|
|
Year Cost Incurred
|
|
|
Costs at
|
|
|
|
Prior
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
Years
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2007
|
|
|
Property acquisition
|
|
$
|
|
|
|
$
|
|
|
|
$
|
259,610
|
|
|
$
|
|
|
|
$
|
259,610
|
|
Exploration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
|
|
|
$
|
|
|
|
$
|
259,610
|
|
|
$
|
|
|
|
$
|
259,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The majority of the evaluation activities are expected to be
completed within a four-year period. In addition, the
Companys internal engineers evaluate all properties on an
annual basis. The average composite rates used for depreciation,
depletion and amortization were $2.64 per Mcfe in 2007, $1.68
per Mcfe in 2006 and $1.23 per Mcfe in 2005.
|
|
7.
|
Investment
in Affiliated Companies
|
The Company has certain investments that it accounts for under
the equity method of accounting because it owns more than 20%
and has significant influence but does not control. The equity
method investments include the following:
Grey Ranch, L.P. Grey Ranch is primarily
engaged in process and transportation of gas and natural gas
liquids. The Company purchased its investment during 2003. At
December 31, 2007 and 2006, the Company owned 50% of Grey
Ranch, L.P. and had approximately $4,176,000 and $2,201,000,
respectively, recorded in the consolidated balance sheets
relating to this investment. The Company contributed a
disproportionate amount of capital into the partnership,
amounting to approximately $750,000, as of December 31,
2007 and 2006. The excess amount contributed is being amortized
over the average life of the partnerships long-lived
assets.
Larclay, L.P. The Company and Clayton Williams
Energy, Inc. (CWEI) each own a 50% interest in
Larclay, L.P., a limited partnership formed to acquire drilling
rigs and provide land drilling services. The Company purchased
its investment in 2006 and accounts for it under the equity
method of accounting. The Company serves as the operations
manager of the partnership. CWEI was responsible for securing
the financing and purchasing the rigs. The partnership financed
100% of the acquisition cost of the rigs through a guarantee by
CWEI. At December 31, 2007 and 2006, the Company had
approximately $3,780,000 and $1,383,000, respectively, recorded
in the consolidated balance sheets relating to this investment.
Restricted deposits represent bank trust and escrow accounts
required by the U.S. Department of Interiors Minerals
Management Service, surety bond underwriters, purchase
agreements or other settlement agreements to satisfy the
Companys eventual responsibility to plug and abandon wells
and remove structures when certain offshore fields are no longer
in use. These restricted deposits were acquired as part of the
NEG acquisition in November 2006 (See Note 2).
In connection with one of these agreements, the Company is
required to make scheduled quarterly deposits of
$0.8 million to an escrow account. Aggregate scheduled
fundings under this agreement are as follows (in thousands):
|
|
|
|
|
Years ending December 31:
|
|
|
|
|
2008
|
|
$
|
3,200
|
|
2009
|
|
|
3,200
|
|
2010 and none thereafter
|
|
|
2,586
|
|
Additionally, two of the agreements require us to deposit
additional funds in an escrow account equal to 10% of the net
proceeds, as defined, from certain of our offshore properties.
During 2007, we deposited approximately $5.8 million in
these escrow accounts.
F-17
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
During 2007, we were released from obligations under two of
these escrow agreements. As a result, funds totaling
$10.3 million were released from escrow accounts and
returned to the Company.
|
|
9.
|
Accounts
Payable and Accrued Expenses
|
Accounts payable and accrued expenses consist of the following
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Accounts payable-trade
|
|
$
|
154,423
|
|
|
$
|
103,683
|
|
Redeemable convertible preferred stock dividends
|
|
|
8,956
|
|
|
|
|
|
Payroll and benefits
|
|
|
15,690
|
|
|
|
10,718
|
|
Drilling advances
|
|
|
5,817
|
|
|
|
5,318
|
|
Legal (current)
|
|
|
5,000
|
|
|
|
5,000
|
|
Accrued interest
|
|
|
24,201
|
|
|
|
3,850
|
|
Other
|
|
|
1,410
|
|
|
|
1,230
|
|
|
|
|
|
|
|
|
|
|
Total accounts payable and accrued expenses
|
|
$
|
215,497
|
|
|
$
|
129,799
|
|
|
|
|
|
|
|
|
|
|
Long-term obligations consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Senior term loans
|
|
$
|
1,000,000
|
|
|
$
|
|
|
Senior credit facility
|
|
|
|
|
|
|
140,000
|
|
Senior bridge facility
|
|
|
|
|
|
|
850,000
|
|
Other notes payable:
|
|
|
|
|
|
|
|
|
Drilling rig fleet and related oil field services equipment
|
|
|
47,836
|
|
|
|
61,105
|
|
Mortgage
|
|
|
19,651
|
|
|
|
|
|
Sagebrush
|
|
|
|
|
|
|
4,000
|
|
Insurance financing
|
|
|
|
|
|
|
7,240
|
|
Other equipment and vehicles
|
|
|
162
|
|
|
|
4,486
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
1,067,649
|
|
|
|
1,066,831
|
|
Less: Current maturities of long-term debt
|
|
|
15,350
|
|
|
|
26,201
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
1,052,299
|
|
|
$
|
1,040,630
|
|
|
|
|
|
|
|
|
|
|
Senior Credit Facility. On November 21,
2006, the Company entered into a $750 million senior
secured revolving credit facility (the senior credit
facility). The senior credit facility matures on
November 21, 2011.
The proceeds of the senior credit facility were used to
(i) partially finance the NEG acquisition,
(ii) refinance the existing senior secured revolving credit
facility and NEGs existing credit facility, and
(iii) pay fees and expenses related to the NEG acquisition
and the existing credit facility. Future borrowings under the
senior credit facility will be available for capital
expenditures, working capital and general corporate purposes and
to finance permitted acquisitions of oil and gas properties and
other assets related to the exploration, production and
development of oil and gas properties. The senior credit
facility will be available to be drawn on and repaid without
restriction so long as the Company is in compliance with its
terms, including certain financial covenants.
The senior credit facility contains various covenants that limit
the Company and certain of its subsidiaries ability to
grant certain liens; make certain loans and investments; make
distributions; redeem stock; redeem or prepay debt; merge or
consolidate with or into a third party; or engage in certain
asset dispositions, including a sale of all or substantially all
of the Companys assets. Additionally, the senior credit
facility limits the Company and certain of its
subsidiaries ability to incur additional indebtedness with
certain exceptions, including under the senior term loans (as
discussed below).
F-18
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The senior credit facility also contains financial covenants,
including maintenance of agreed upon levels for the
(i) ratio of total funded debt to EBITDAX (as defined in
the senior credit facility), (ii) ratio of EBITDAX to
interest expense plus current maturities of long-term debt, and
(iii) current ratio. The Company was in compliance with
these financial covenants as of December 31, 2007.
The obligations under the senior credit facility are secured by
first priority liens on all shares of capital stock of each of
the Companys present and future subsidiaries; all
intercompany debt of the Company and its subsidiaries; and
substantially all of the Company assets and the assets of its
guarantor subsidiaries, including proved oil and natural gas
reserves representing at least 80% of the present discounted
value (as defined in the senior credit facility) of proved oil
and natural gas reserves reviewed in determining the borrowing
base for the senior credit facility. Additionally, the
obligations under the senior credit facility are guaranteed by
certain Company subsidiaries.
At the Companys election, interest under the senior credit
facility is determined by reference to (i) the LIBOR rate
plus an applicable margin between 1.25% and 2.00% per annum or
(ii) the higher of the federal funds rate plus 0.5% or the
prime rate plus, in either case, an applicable margin between
0.25% and 1.00% per annum. Interest is payable quarterly for
prime rate loans and at the applicable maturity date for LIBOR
loans, except that if the interest period for a LIBOR loan is
six months, interest is paid at the end of each three-month
period. The average interest rate paid on amounts outstanding
under our senior credit facility for the year ended
December 31, 2007 was 7.34%.
The borrowing base of proved reserves was initially set at
$300.0 million. As of December 31, 2006, the Company
had $140.0 million of outstanding indebtedness on the
senior credit facility. Proceeds from the Companys sale of
common stock on March 20, 2007, as described in
Note 18, were used to pay outstanding borrowings under the
Companys senior credit facility.
The borrowing base was increased to $400.0 million on
May 2, 2007, and to $700.0 million on
September 14, 2007 where it remained at December 31,
2007. At December 31, 2007, the Company had no amounts
outstanding under this facility. The Company repaid all amounts
outstanding under this facility in November 2007. See
Note 18 for further discussion.
If an event of default exists under the senior credit facility,
the lenders may accelerate the maturity of the obligations
outstanding under the senior credit facility and exercise other
rights and remedies. Each of the following will be an event of
default:
|
|
|
|
|
failure to pay any principal when due or any interest, fees or
other amount within certain grace periods;
|
|
|
|
failure to perform or otherwise comply with the covenants in the
credit agreement or other loan documents, subject, in certain
instances, to certain grace periods;
|
|
|
|
bankruptcy or insolvency events involving the Company or its
subsidiaries;
|
|
|
|
a change of control (as defined in the senior credit facility).
|
Senior Bridge Facility. On November 21,
2006, the Company also entered into a $850.0 million senior
unsecured bridge facility (the senior bridge
facility), which was repaid in March 2007. The Company
expensed the remaining unamortized debt issuance costs related
to the senior bridge facility of approximately
$12.5 million to interest expense in March 2007.
Together with borrowings under the senior credit facility, the
proceeds from the senior bridge facility were used to
(i) partially finance the NEG acquisition,
(ii) refinance existing senior secured revolving credit
facility and NEGs existing credit facility, and
(iii) pay fees and expenses related to the NEG acquisition
and the existing credit facility.
Senior Term Loans. On March 22, 2007, the
Company entered into $1.0 billion in senior unsecured term
loans (the senior term loans). The closing of the
senior term loans was generally contingent upon closing the
private placement of common equity as described in Note 18.
The senior term loans include both floating rate term loans and
fixed rate term loans.
The Company issued $350.0 million at a variable rate with
interest payable quarterly and principal due on April 1,
2014 (the variable rate term loans). The variable
rate term loans bear interest, at the Companys option, at
the British Bankers Association LIBOR rate plus 3.625% or the
higher of (i) the federal funds rate, as defined, plus
3.125% or (ii) a banks prime rate plus 2.625%. After
April 1, 2009 the variable rate term loans may be prepaid
in whole or in part with certain prepayment penalties. The
average interest rates paid on amounts outstanding under the
Companys variable term loans for the year ended
December 31, 2007 was 8.94%. Subsequent to year end, the
Company entered into an interest rate swap to effectively fix
the interest rate related to this portion of the term loan
through April 1, 2011 (See Note 20).
F-19
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The Company issued $650.0 million at a fixed rate of 8.625%
with the principal due on April 1, 2015 (the fixed
rate term loans). Under the terms of the fixed rate term
loans, interest is payable quarterly and during the first four
years interest may be paid, at the Companys option, either
entirely in cash or entirely with additional fixed rate term
loans. If the Company elects to pay the interest due during any
period in additional fixed rate term loans, the interest rate
increases to 9.375% during such period. After April 1,
2011, the fixed rate term loans may be prepaid in whole or in
part with certain prepayment penalties.
After March 22, 2008, but not later than April 30,
2008, the Company is required to offer to exchange the senior
term loans for senior unsecured notes with registration rights
and with identical terms and conditions as the term loans. If
the Company does not complete the exchange of the senior term
loans for senior unsecured notes with registration rights by
May 31, 2008, the annual interest rate on the senior term
loans will increase by 0.25% every 90 days up to a maximum
of 0.50%.
Debt covenants under the senior term loans include financial
covenants similar to those of the senior credit facility and
include limitations on the incurrence of indebtedness, payment
of dividends, asset sales, certain asset purchases, transactions
with related parties, and consolidation or merger agreements.
The Company incurred $26.1 million of debt issuance costs
in connection with the senior term loans. These costs are
included in other assets and amortized over the term of the
senior term loans. A portion of the proceeds from the senior
term loans was used to repay the Companys
$850.0 million senior bridge facility.
Other Indebtedness. The Company has financed a
portion of its drilling rig fleet and related oil field services
equipment through notes. At December 31, 2007, the
aggregate outstanding balance of these notes was
$47.8 million, with an annual fixed interest rate ranging
from 7.64% to 8.87%. The notes have a final maturity date of
December 1, 2011, require aggregate monthly installments
for principal and interest in the amount of $1.2 million
and are secured by the equipment. The notes have a prepayment
penalty (currently 1-3%) in the event the Company repays the
notes prior to maturity.
On November 15, 2007, the Company entered into a note
payable in the amount of $20 million with a lending
institution as a mortgage on the downtown Oklahoma City property
purchased by the Company in July 2007 (see additional discussion
in Note 6). This note is fully secured by one of the
buildings and a parking garage located on the downtown property,
bears interest at 6.08% annually, and matures on
November 15, 2022. Payments of principal and interest in
the amount of approximately $0.5 million are due on a
quarterly basis through the maturity date. During 2008, the
Company expects to make payments of principal and interest on
this note totaling $0.8 million and $1.2 million,
respectively.
Prior to 2007, the Company financed the purchase of various
vehicles, oil field services equipment and other equipment
through various notes payable. The aggregate outstanding balance
of these notes as of December 31, 2006 was
$4.5 million. Additionally, the Company financed its
insurance payment made in 2007. These notes were substantially
repaid during 2007 with borrowings under our senior credit
facility. Also, in 2007 we repaid a $4.0 million loan
incurred in 2005 for the purpose of completing a gas processing
plant and pipeline in Colorado.
Prior Senior Credit Facility. On
November 21, 2006, we replaced a $130 million
revolving credit facility with our existing senior credit
facility. The prior senior credit facility bore interest at the
Companys option at either LIBOR plus 2.15% or the Bank of
America, N.A. prime rate. The Company paid a commitment fee on
the unused portion of the borrowing base amount equal to
1/8%
per annum. The prior senior credit facility was collateralized
by natural gas and oil properties representing at least 80% of
the present discounted value of the Companys proved
reserves and by a negative pledge on any of the Companys
non-mortgaged properties.
Maturities of Long-Term Debt. Aggregate
maturities of long-term debt during the next five years are as
follows (in thousands):
|
|
|
|
|
Years ending December 31:
|
|
|
|
|
2008
|
|
$
|
15,350
|
|
2009
|
|
|
16,580
|
|
2010
|
|
|
12,476
|
|
2011
|
|
|
7,222
|
|
2012
|
|
|
1,052
|
|
Thereafter
|
|
|
1,014,969
|
|
|
|
|
|
|
Total debt
|
|
$
|
1,067,649
|
|
|
|
|
|
|
F-20
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
11.
|
Other
Long-Term Obligations
|
The Company has recorded a long-term obligation for amounts to
be paid under a litigation settlement agreement with Conoco,
Inc. entered into in January 2007. The Company agreed to pay
approximately $25.0 million plus interest, payable in
$5.0 million increments on April 1, 2007, July 1,
2008, July 1, 2009, July 1, 2010, and July 1,
2011. The $5.0 million payment made in 2007 has been
included in accounts payable-trade in the accompanying
consolidated balance sheet as of December 31, 2006, and the
$5.0 million payment to be made in 2008 has been included
in accounts payable-trade in the accompanying consolidated
balance sheet as of December 31, 2007. Unpaid settlement
amounts of approximately $15.0 million and
$20.0 million have been included in other long-term
obligations in the accompanying consolidated balance sheets as
of December 31, 2007 and 2006, respectively.
The Company has entered into various derivative contracts
including fixed price swaps, collars and basis swaps with
counterparties. The contracts expire on various dates through
December 31, 2009.
At December 31, 2007, the Companys open commodity
derivative contracts consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Avg.
|
|
Period
|
|
Commodity
|
|
Notional
|
|
|
Fixed Price
|
|
|
Fixed price swaps:
|
|
|
|
|
|
|
|
|
|
|
November 2007 March 2008
|
|
Natural gas
|
|
|
1,520,000 MmBtu
|
|
|
$
|
8.51
|
|
November 2007 June 2008
|
|
Natural gas
|
|
|
4,860,000 MmBtu
|
|
|
$
|
8.05
|
|
November 2007 June 2008
|
|
Natural gas
|
|
|
9,720,000 MmBtu
|
|
|
$
|
8.20
|
|
January 2008
|
|
Natural gas
|
|
|
310,000 MmBtu
|
|
|
$
|
8.24
|
|
January 2008 June 2008
|
|
Natural gas
|
|
|
3,640,000 MmBtu
|
|
|
$
|
7.99
|
|
January 2008 June 2008
|
|
Natural gas
|
|
|
3,640,000 MmBtu
|
|
|
$
|
7.99
|
|
January 2008 December 2008
|
|
Natural gas
|
|
|
3,660,000 MmBtu
|
|
|
$
|
8.23
|
|
January 2008 December 2008
|
|
Natural gas
|
|
|
3,660,000 MmBtu
|
|
|
$
|
8.48
|
|
January 2008 December 2008
|
|
Natural gas
|
|
|
3,660,000 MmBtu
|
|
|
$
|
9.00
|
|
April 2008 June 2008
|
|
Natural gas
|
|
|
910,000 MmBtu
|
|
|
$
|
7.17
|
|
May 2008 August 2008
|
|
Natural gas
|
|
|
2,460,000 MmBtu
|
|
|
$
|
8.38
|
|
July 2008
|
|
Natural gas
|
|
|
310,000 MmBtu
|
|
|
$
|
8.00
|
|
July 2008
|
|
Natural gas
|
|
|
310,000 MmBtu
|
|
|
$
|
8.02
|
|
July 2008 September 2008
|
|
Natural gas
|
|
|
920,000 MmBtu
|
|
|
$
|
7.43
|
|
July 2008 September 2008
|
|
Natural gas
|
|
|
920,000 MmBtu
|
|
|
$
|
7.49
|
|
July 2008 September 2008
|
|
Natural gas
|
|
|
920,000 MmBtu
|
|
|
$
|
8.06
|
|
July 2008 September 2008
|
|
Natural gas
|
|
|
920,000 MmBtu
|
|
|
$
|
8.07
|
|
July 2008 September 2008
|
|
Natural gas
|
|
|
920,000 MmBtu
|
|
|
$
|
8.23
|
|
July 2008 September 2008
|
|
Natural gas
|
|
|
920,000 MmBtu
|
|
|
$
|
8.36
|
|
July 2008 December 2008
|
|
Natural gas
|
|
|
1,840,000 MmBtu
|
|
|
$
|
8.31
|
|
July 2008 December 2008
|
|
Natural gas
|
|
|
1,840,000 MmBtu
|
|
|
$
|
8.59
|
|
August 2008
|
|
Natural gas
|
|
|
310,000 MmBtu
|
|
|
$
|
8.00
|
|
August 2008
|
|
Natural gas
|
|
|
310,000 MmBtu
|
|
|
$
|
8.07
|
|
September 2008
|
|
Natural gas
|
|
|
300,000 MmBtu
|
|
|
$
|
8.05
|
|
September 2008
|
|
Natural gas
|
|
|
300,000 MmBtu
|
|
|
$
|
8.10
|
|
October 2008 December 2008
|
|
Natural gas
|
|
|
920,000 MmBtu
|
|
|
$
|
7.96
|
|
F-21
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Avg.
|
|
Period
|
|
Commodity
|
|
Notional
|
|
|
Fixed Price
|
|
|
October 2008 December 2008
|
|
Natural gas
|
|
|
1,840,000 MmBtu
|
|
|
$
|
8.00
|
|
October 2008 December 2008
|
|
Natural gas
|
|
|
920,000 MmBtu
|
|
|
$
|
8.07
|
|
October 2008 December 2008
|
|
Natural gas
|
|
|
920,000 MmBtu
|
|
|
$
|
8.11
|
|
October 2008 December 2008
|
|
Natural gas
|
|
|
920,000 MmBtu
|
|
|
$
|
8.16
|
|
October 2008 December 2008
|
|
Natural gas
|
|
|
920,000 MmBtu
|
|
|
$
|
8.32
|
|
October 2008 December 2008
|
|
Natural gas
|
|
|
920,000 MmBtu
|
|
|
$
|
8.83
|
|
January 2009 March 2009
|
|
Natural gas
|
|
|
900,000 MmBtu
|
|
|
$
|
8.56
|
|
January 2009 March 2009
|
|
Natural gas
|
|
|
900,000 MmBtu
|
|
|
$
|
8.60
|
|
January 2009 March 2009
|
|
Natural gas
|
|
|
900,000 MmBtu
|
|
|
$
|
8.65
|
|
January 2009 March 2009
|
|
Natural gas
|
|
|
900,000 MmBtu
|
|
|
$
|
8.91
|
|
Collars:
|
|
|
|
|
|
|
|
|
|
|
January 2008 June 2008
|
|
Crude oil
|
|
|
42,000 Bbls
|
|
|
$
|
50.00 - $83.35
|
|
July 2008 December 2008
|
|
Crude oil
|
|
|
54,000 Bbls
|
|
|
$
|
50.00 - $82.60
|
|
Waha basis swaps:
|
|
|
|
|
|
|
|
|
|
|
January 2008 December 2008
|
|
Natural gas
|
|
|
10,980,000 MmBtu
|
|
|
$
|
(0.57
|
)
|
January 2008 December 2008
|
|
Natural gas
|
|
|
7,320,000 MmBtu
|
|
|
$
|
(0.585
|
)
|
January 2008 December 2008
|
|
Natural gas
|
|
|
7,320,000 MmBtu
|
|
|
$
|
(0.59
|
)
|
January 2008 December 2008
|
|
Natural gas
|
|
|
3,660,000 MmBtu
|
|
|
$
|
(0.595
|
)
|
January 2008 December 2008
|
|
Natural gas
|
|
|
3,660,000 MmBtu
|
|
|
$
|
(0.625
|
)
|
January 2008 December 2008
|
|
Natural gas
|
|
|
7,320,000 MmBtu
|
|
|
$
|
(0.635
|
)
|
January 2008 December 2008
|
|
Natural gas
|
|
|
7,320,000 MmBtu
|
|
|
$
|
(0.6525
|
)
|
May 2008 August 2008
|
|
Natural gas
|
|
|
2,460,000 MmBtu
|
|
|
$
|
(0.45
|
)
|
June 2008 August 2008
|
|
Natural gas
|
|
|
920,000 MmBtu
|
|
|
$
|
(0.4808
|
)
|
September 2008 December 2008
|
|
Natural gas
|
|
|
2,440,000 MmBtu
|
|
|
$
|
(0.7930
|
)
|
January 2009 December 2009
|
|
Natural gas
|
|
|
3,650,000 MmBtu
|
|
|
$
|
(0.47
|
)
|
January 2009 December 2009
|
|
Natural gas
|
|
|
3,650,000 MmBtu
|
|
|
$
|
(0.49
|
)
|
January 2009 December 2009
|
|
Natural gas
|
|
|
3,650,000 MmBtu
|
|
|
$
|
(0.4975
|
)
|
These derivatives have not been designated as hedges. The
Company records all derivatives on the balance sheet at fair
value. Changes in derivative fair values are recognized in
earnings. Cash settlements and valuation gains and losses are
included in (gain) loss on derivative contracts in the
consolidated statements of operations. The following summarizes
the cash settlements and valuation gains and losses for the
years ended December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Realized (gain) loss
|
|
$
|
(34,494
|
)
|
|
$
|
(14,169
|
)
|
|
$
|
2,836
|
|
Unrealized (gain) loss
|
|
|
(26,238
|
)
|
|
|
1,878
|
|
|
|
1,296
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) loss on derivative contracts
|
|
$
|
(60,732
|
)
|
|
$
|
(12,291
|
)
|
|
$
|
4,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13.
|
Retirement
and Deferred Compensation Plans
|
Retirement Plan. The Company maintains a
401(k) retirement plan for its employees. Under the plan,
eligible employees may elect to defer a portion of their
earnings up to the maximum allowed by regulations promulgated by
the Internal Revenue Service. Prior to August 2006, the Company
made matching contributions equal to 50% on the first 6% of
employee deferred wages (maximum 3% matching). The Company
modified the 401(k) retirement plan in August 2006 to change the
matching contributions to equal a match of 100% on the first 15%
of employee deferred wages (maximum 15% matching). The plan was
also modified to make the matching contributions payable in
Company common stock. Accrued payables in the amounts of
$5.2 million and $1.3 million are
F-22
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
reflected in the consolidated balance sheets as of
December 31, 2007 and 2006, respectively, related to the
matching contributions. During June 2007, the Company satisfied
its matching obligation related to employees contributions
made in 2006 through a transfer of treasury stock (See
Note 18). For 2007, 2006 and 2005, retirement plan expense
was approximately $4.9 million, $1.5 million and
$0.3 million, respectively.
Deferred Compensation Plan. Effective
February 1, 2007 the Company established a non-qualified
deferred compensation plan in order to provide our employees
with flexibility in meeting their future income needs and
assisting them in their retirement planning. Pursuant to the
terms of the deferred compensation plan, eligible highly
compensated employees are provided the opportunity to defer
income in excess of the IRA annual limitations on qualified
401(k) retirement plans. The 2007 annual 401(k) deferral limit
for employees under age 50 was $15,500. Employees turning
age 50 or over in 2007 could defer up to $20,500.
On January 1, 2007, the Company adopted the provisions of
FIN 48. The Company has determined that no uncertain tax
positions exist and therefore no reserves have been recorded for
purposes of FIN 48 as of December 31, 2007. As a
result, the Company has not recorded any additional liabilities
for any unrecognized tax benefits as of December 31, 2007.
The Company and its subsidiaries file income tax returns in the
U.S. federal and various state jurisdictions. Tax years
1994 to present remain open for the majority of taxing
authorities. The Companys accounting policy is to
recognize interest and penalties, if any, related to
unrecognized tax benefits as income tax expense. The Company
does not have an accrued liability for the payment of penalties
and interest at December 31, 2007.
Significant components of the Companys deferred tax assets
(liabilities) are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Deferred tax assets (liabilities):
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
Accrued liabilities
|
|
$
|
1,820
|
|
|
$
|
4,451
|
|
Other
|
|
|
|
|
|
|
1,864
|
|
|
|
|
|
|
|
|
|
|
Total current deferred tax assets
|
|
$
|
1,820
|
|
|
$
|
6,315
|
|
|
|
|
|
|
|
|
|
|
Noncurrent:
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
$
|
(45,537
|
)
|
|
$
|
(25,692
|
)
|
Net operating loss carryforwards
|
|
|
2,397
|
|
|
|
|
|
Other
|
|
|
(6,210
|
)
|
|
|
770
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent deferred tax liabilities
|
|
$
|
(49,350
|
)
|
|
$
|
(24,922
|
)
|
|
|
|
|
|
|
|
|
|
The provisions for income taxes for continuing operations
consisted of the following components for the years ended
December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
|
|
|
$
|
3,235
|
|
|
$
|
508
|
|
State
|
|
|
601
|
|
|
|
2,653
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
601
|
|
|
|
5,888
|
|
|
|
508
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
28,121
|
|
|
|
345
|
|
|
|
9,460
|
|
State
|
|
|
802
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28,923
|
|
|
|
348
|
|
|
|
9,460
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total provision for income taxes
|
|
$
|
29,524
|
|
|
$
|
6,236
|
|
|
$
|
9,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-23
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
A reconciliation of the provision for income taxes from
continuing operations at the statutory federal tax rates to the
Companys actual provision for income taxes is as follows
for the years ended December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Computed at federal statutory rates
|
|
$
|
27,911
|
|
|
$
|
7,650
|
|
|
$
|
9,543
|
|
State taxes, net of federal benefit
|
|
|
912
|
|
|
|
1,724
|
|
|
|
390
|
|
Nondeductible expenses
|
|
|
312
|
|
|
|
84
|
|
|
|
35
|
|
Percentage depletion deduction
|
|
|
|
|
|
|
(3,488
|
)
|
|
|
|
|
Change in rate
|
|
|
|
|
|
|
326
|
|
|
|
|
|
Other
|
|
|
389
|
|
|
|
(60
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total provision for income taxes
|
|
$
|
29,524
|
|
|
$
|
6,236
|
|
|
$
|
9,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007, the Company had $6.8 million
of net operating loss carryforwards that will begin to expire in
2023. The Company, as of December 31, 2007, had
approximately $0.5 million of alternative minimum tax
credits that do not expire.
Basic earnings per share are computed using the weighted average
number of common shares outstanding during the year. Diluted
earnings per share are computed using the weighted average
shares outstanding during the year, but also include the
dilutive effect of awards of restricted stock. The following
table summarizes the calculation of weighted average common
shares outstanding used in the computation of diluted earnings
per share for the years ended December 31 (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Weighted average basic common shares outstanding
|
|
|
108,828
|
|
|
|
73,727
|
|
|
|
56,559
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock
|
|
|
1,213
|
|
|
|
937
|
|
|
|
178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average diluted common and potential common shares
outstanding
|
|
|
110,041
|
|
|
|
74,664
|
|
|
|
56,737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In computing diluted earnings per share, the Company evaluated
the if-converted method with respect to its outstanding
redeemable convertible preferred stock. Under this method, the
Company assumes the conversion of the preferred stock to common
stock and determines if this is more dilutive than including the
preferred stock dividends (paid and unpaid) in the computation
of income available to common stockholders. The Company
determined the if-converted method is not more dilutive and has
included preferred stock dividends in the determination of
income available to common stockholders.
|
|
16.
|
Commitments
and Contingencies
|
Operating Leases. The Company has obligations
under noncancelable operating leases, primarily for the use of
office space and equipment. Total rental expense under operating
leases for the years ended December 31, 2007, 2006 and 2005
was approximately $2.3 million, $1.1 million and
$1.1 million, respectively.
Future minimum lease payments under noncancelable operating
leases (with initial lease terms in excess of one year) as of
December 31, 2007 are as follows (in thousands):
|
|
|
|
|
Years ending December 31:
|
|
|
|
|
2008
|
|
$
|
2,139
|
|
2009
|
|
|
1,102
|
|
2010
|
|
|
110
|
|
2011
|
|
|
110
|
|
2012
|
|
|
45
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,506
|
|
|
|
|
|
|
F-24
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Litigation. The Company is a defendant in
lawsuits from time to time in the normal course of business. In
managements opinion, the Company is not currently involved
in any legal proceedings which, individually or in the
aggregate, could have a material effect on the financial
condition, operations
and/or cash
flows of the Company.
|
|
17.
|
Redeemable
Convertible Preferred Stock
|
In November 2006, the Company sold 2,136,667 shares of
redeemable convertible preferred stock in order to finance a
portion of the NEG acquisition and received net proceeds from
this sale of approximately $439.5 million after deducting
offering expenses of approximately $9.3 million (See
Note 2). Each holder of the redeemable convertible
preferred stock is entitled to quarterly cash dividends at the
annual rate of 7.75% of the accreted value of its redeemable
convertible preferred stock. The accreted value was $210 per
share as of December 31, 2007 and 2006. Each share of
convertible preferred stock was initially convertible into ten
(10.2 currently) shares of common stock at the option of the
holder, subject to certain anti-dilution adjustments. A summary
of dividends declared and paid on the redeemable convertible
preferred stock is as follows (in thousands, except per share
data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
|
|
|
|
Declared
|
|
Dividend Period
|
|
per Share
|
|
|
Total
|
|
|
Date Paid
|
|
January 31, 2007
|
|
November 21, 2006 February 1, 2007
|
|
$
|
3.21
|
|
|
$
|
6,859
|
|
|
February 15, 2007
|
May 8, 2007
|
|
February 2, 2008 May 1, 2007
|
|
|
3.97
|
|
|
|
8,550
|
|
|
May 15, 2007
|
June 8, 2007
|
|
May 2, 2007 August 1, 2007
|
|
|
4.10
|
|
|
|
8,956
|
|
|
August 15, 2007
|
September 24, 2007
|
|
August 2, 2007 November 1, 2007
|
|
|
4.10
|
|
|
|
8,956
|
|
|
November 15, 2007
|
December 16, 2007
|
|
November 2, 2007 February 1, 2008
|
|
|
4.10
|
|
|
|
8,956
|
|
|
February 15, 2008
|
On March 30, 2007, certain holders of the Companys
common units (consisting of shares of common stock and a warrant
to purchase redeemable convertible preferred stock upon the
surrender of common stock) exercised warrants to purchase
redeemable convertible preferred stock. The holders exchanged
526,316 shares of common stock for 47,619 shares of
redeemable convertible preferred stock.
Approximately $38.5 million and $3.8 million in paid
and unpaid dividends have been included in the Companys
earnings per share calculations for the years ended
December 31, 2007 and 2006, respectively, as presented in
the accompanying consolidated statements of operations.
The following table presents information regarding
SandRidges common stock (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Shares authorized
|
|
|
400,000
|
|
|
|
400,000
|
|
Shares outstanding at end of period
|
|
|
140,391
|
|
|
|
91,604
|
|
Shares held in treasury
|
|
|
1,456
|
|
|
|
1,444
|
|
The Company is authorized to issue 50,000,000 shares of
preferred stock, $0.001 par value, of which
2,625,000 shares are designated as redeemable convertible
preferred. As of December 31, 2007 and 2006 there were
2,184,286 and 2,136,667 shares, respectively, of redeemable
convertible preferred stock outstanding (See Note 17).
There were no undesignated preferred shares outstanding as of
December 31, 2007 and 2006.
Stock Split. On December 19, 2005, the
Company effected a 281.562 for 1 stock split. All references in
the accompanying financial statements have been restated to
reflect this stock split. The Company also authorized
400,000,000 shares of common stock with a par value of
$0.001 per share.
Common Stock Issuance. In December 2005, the
Company sold 12.5 million shares of common stock in a
private placement and received net proceeds from this sale of
approximately $173.1 million after deducting the initial
purchasers discount of $16.8 million and offering
expenses of approximately $1.2 million. Approximately
$105.5 million of the proceeds of the offering were used to
repay outstanding bank debt and finance the Companys
December 2005 acquisitions (See Note 2).
F-25
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
In January 2006, the Company issued an additional
239,630 shares of common stock upon exercise of an
over-allotment option. The Company issued these shares at a
price of $15.00 per share after deducting the purchasers
fee of $0.3 million. The Company received net proceeds from
the sale of approximately $3.3 million.
In November 2006, the Company sold 5.3 million common units
(consisting of shares of common stock ($18.00 per share) and a
warrant ($1.00 per share) to purchase convertible preferred
stock upon the surrender of the common stock) as part of the NEG
acquisition and received net proceeds from this sale of
approximately $97.4 million after deducting the offering
expenses of approximately $3.9 million (See Note 2).
In March 2007, the Company sold approximately 17.8 million
shares of common stock for net proceeds of $318.7 million
after deducting offering expenses of approximately
$1.4 million. The stock was sold in private sales to
various investors including Tom L. Ward, the Companys
Chairman of the Board of Directors and Chief Executive Officer,
who invested $61.4 million in exchange for approximately
3.4 million shares of common stock.
On November 9, 2007, the Company completed an initial
public offering (the IPO) of its common stock. The
Company sold 28,700,000 shares of SandRidge common stock,
including 4,710,000 shares sold directly to an entity
controlled by Tom L. Ward. The shares were sold at a price of
$26 per share. After deducting underwriting discounts of
approximately $38.3 million and estimated offering expenses
of approximately $3.1 million, the Company received net
proceeds of approximately $704.8 million. This transaction
priced after market close on November 5, 2007. In
conjunction with the IPO, the underwriters were granted an
option to purchase 3,679,500 additional shares of the
Companys common stock. The underwriters fully exercised
this option and purchased the additional shares on
November 6, 2007. After deducting underwriting discounts of
approximately $5.7 million, the Company received net
proceeds of approximately $89.9 million from these
additional shares. This offering generated total gross proceeds
to the Company of $841.8 million and total net proceeds of
approximately $794.7 million to the Company after deducting
total underwriting discounts of approximately $44.0 million
and other offering expenses of approximately $3.1 million.
The aggregate net proceeds of approximately $794.7 million
received by the Company at closing on November 9, 2007 were
utilized as follows (in millions):
|
|
|
|
|
Repayment of outstanding balance and accrued interest on senior
credit facility
|
|
$
|
515.9
|
|
Repayment of note payable and accrued interest incurred in
connection with recent acquisition
|
|
|
49.1
|
|
Excess cash to fund future capital expenditures
|
|
|
229.7
|
|
|
|
|
|
|
Total
|
|
$
|
794.7
|
|
|
|
|
|
|
Treasury Stock. The Company makes required tax
payments on behalf of employees as their stock awards vest and
then withholds a number of vested shares having a value on the
date of vesting equal to the tax obligation. As a result of such
transactions, the Company withheld 44,649 shares at a total
value of $0.8 million and 29,000 shares at a total
value of $0.5 million during the years ended
December 31, 2007 and 2006, respectively. These shares were
accounted for as treasury stock.
On June 28, 2007, the Company purchased 39,844 shares
of its common stock into treasury through an open market
repurchase transaction in order to fund a portion of its 401(k)
matching obligation as described below. Cash consideration for
these shares of approximately $0.8 million was paid in July
2007.
On June 29, 2007, the Company transferred
72,044 shares of its treasury stock to an account
established for the benefit of the Companys 401(k) Plan.
The transfer was made in order to satisfy the Companys
$1.3 million accrued payable to match employee
contributions made to the plan during 2006. Historical cost of
the shares transferred totaled approximately $0.9 million,
resulting in an increase to the Companys additional
paid-in capital of approximately $0.4 million.
Restricted Stock. The Company issues
restricted stock awards under incentive compensation plans which
vest over specified periods of time. Awards issued prior to 2006
had vesting periods of one, four or seven years. All awards
issued during and after 2006 have four year vesting periods.
Shares of restricted common stock are subject to restriction on
transfer and certain conditions to vesting.
The Company granted restricted stock awards of approximately
1.6 million shares in December 2005. The stock awards
included (i) 153,667 shares scheduled to vest on
December 31, 2006, (ii) 904,833 shares scheduled
to vest on June 30, 2010, and
(iii) 493,667 shares scheduled to vest on
June 30, 2013. In June 2006, the Company modified the
vesting periods of the one year period and four year period
restricted stock awards. One year restricted stock awards were
modified to vest on October 1, 2006, rather than
December 31, 2006, and four year restricted stock awards
were modified to vest 25% each January 1, for four years,
beginning
F-26
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
January 1, 2007, rather than all vesting on June 30,
2010. The Company recognized compensation cost related to these
modifications of $17,250 in June 2006.
Additionally, the Company modified the vesting period related to
restricted shares awarded to certain executive officers who
resigned in June 2006 and August 2006 as a component of their
separations from the Company. The Board of Directors agreed to
immediately vest all of the executive officers restricted
stock, a total of 222,000 shares, including
20,334 shares which would have vested in 2006,
150,000 shares which would have vested in 2010, and
51,666 shares which would have vested in 2013. The Company
recognized compensation cost related to these modifications of
$2.3 million in the year ended December 31, 2006.
In December 2006, the Company accelerated the vesting of 39,960
restricted shares on behalf of certain employees who resigned
from the Company in late December 2006. These shares had been
scheduled to vest on January 1, 2007. The Company
recognized additional compensation cost in December 2006 for
these shares of approximately $0.1 million due to the
modification. Other restricted shares held by these employees
were forfeited.
Restricted stock activity for the year ended December 31,
2007 was as follows (shares in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
Number of
|
|
|
Average Grant
|
|
|
|
Shares
|
|
|
Date Fair Value
|
|
|
Unvested restricted shares outstanding at December 31, 2006
|
|
|
937
|
|
|
$
|
15.88
|
|
Granted
|
|
|
1,600
|
|
|
|
19.79
|
|
Vested
|
|
|
(466
|
)
|
|
|
15.62
|
|
Canceled
|
|
|
(144
|
)
|
|
|
15.15
|
|
|
|
|
|
|
|
|
|
|
Unvested restricted shares outstanding at December 31, 2007
|
|
|
1,927
|
|
|
$
|
19.25
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, the Company recognized
stock-based compensation expense related to restricted stock of
approximately $7.2 million in 2007, $8.8 million in
2006, and $0.5 million in 2005. Stock-based compensation
expense is reflected in general and administrative expense in
the consolidated statements of operations.
As of December 31, 2007, there was approximately
$30.5 million of unrecognized compensation cost related to
unvested restricted stock awards which is expected to be
recognized over a weighted average period of 2.21 years.
|
|
19.
|
Related
Party Transactions
|
During the ordinary course of business, the Company has
transactions with certain shareholders and other related
parties. These transactions primarily consist of purchases of
drilling equipment and sales of oil field service supplies.
Following is a summary of significant transactions with such
related parties for the years ended December 31 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Sales to and reimbursements from related parties
|
|
$
|
118,631
|
|
|
$
|
14,102
|
|
|
$
|
12,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of services from related parties
|
|
$
|
77,555
|
|
|
$
|
4,811
|
|
|
$
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In August 2006, the Company sold various non-energy related
assets to the Companys former President and Chief
Operating Officer, N. Malone Mitchell, 3rd, for approximately
$6.1 million in cash. The sale transaction resulted in a
$0.8 million gain recognized in earnings by the Company in
August 2006. The gain is included in gain on sale of assets in
the consolidated statements of operations.
In September 2006, the Company entered into a facilities lease
with a member of its Board of Directors. The Company believes
that the payments to be made under this lease are at fair market
rates. Rent expense related to the lease totaled
$1.3 million and $0.3 million for the years ended
December 31, 2007 and 2006, respectively. The lease extends
to August 2009.
In May 2007, the Company purchased leasehold acreage from a
partnership controlled by a director. The purchase price was
approximately $8.3 million in cash.
In June 2007, the Company purchased certain producing well
interests from a director. The purchase price was approximately
$3.5 million in cash.
F-27
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Larclay, L.P. The Company and CWEI each own a
50% interest in Larclay, L.P., a limited partnership formed to
acquire drilling rigs and provide land drilling services.
Larclay currently owns 12 rigs, one of which has not yet been
assembled. The Company purchased its investment in 2006 and
accounts for it under the equity method of accounting. The
Company serves as the operations manager of the partnership.
CWEI is responsible for financing and purchasing the rigs. The
Company had sales to and cost reimbursements from Larclay for
the years ended December 31, 2007 and 2006 of
$53.3 million and $1.6 million, respectively. As of
December 31, 2007 and 2006, the Company had accounts
receivable related party due from Larclay of
$16.6 million and $3.0 million, respectively.
Additionally, the Company contracted with Larclay to utilize
rigs for drilling. For the year ended December 31, 2007 the
amount we were billed for these services was $33.3 million.
As of December 31, 2007, the Company had accounts
payable related party due to Larclay of
$0.3 million. The Company made no purchases from Larclay in
2006.
See Note 2 for a discussion of additional related party
transactions.
In January 2008, the Company entered into an interest rate swap
to fix the variable LIBOR interest rate on the
$350.0 million floating rate portion of its term loan at
6.26% for the period from April 1, 2008 to April 1,
2011. This swap has not been designated as a hedge.
|
|
21.
|
Industry
Segment Information
|
SandRidge has four business segments: Exploration and
Production, Drilling and Oil Field Services, Midstream Services,
and Other representing its four main business units offering
different products and services. The Exploration and Production
segment is engaged in the development, acquisition and
production of oil and natural gas properties. The Drilling and
Oil Field Services segment is engaged in the land contract
drilling of oil and natural gas wells. The Midstream Gas
Services segment is engaged in the purchasing, gathering,
processing and treating of natural gas. The Other segment
transports
CO2
to market for use by the Company and others in tertiary oil
recovery operations and other miscellaneous operations.
F-28
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The accounting policies of the segments are the same as those
described in the Summary of Significant Accounting Policies
(Note 1). Management evaluates the performance of
SandRidges operating segments based on operating income,
which is defined as operating revenues less operating expenses
and depreciation, depletion and amortization. Summarized
financial information concerning the Companys segments is
shown in the following table (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
479,321
|
|
|
$
|
106,990
|
|
|
$
|
54,425
|
|
Elimination of inter-segment revenue
|
|
|
574
|
|
|
|
577
|
|
|
|
374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production, net of inter-segment revenue
|
|
|
478,747
|
|
|
|
106,413
|
|
|
|
54,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and oil field services
|
|
|
261,818
|
|
|
|
211,055
|
|
|
|
109,766
|
|
Elimination of inter-segment revenue
|
|
|
188,616
|
|
|
|
72,398
|
|
|
|
29,615
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and oil field services, net of inter-segment revenue
|
|
|
73,202
|
|
|
|
138,657
|
|
|
|
80,151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream services
|
|
|
285,065
|
|
|
|
192,960
|
|
|
|
192,503
|
|
Elimination of inter-segment revenue
|
|
|
177,487
|
|
|
|
70,068
|
|
|
|
45,004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream services, net of inter-segment revenues
|
|
|
107,578
|
|
|
|
122,892
|
|
|
|
147,499
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
29,286
|
|
|
|
21,411
|
|
|
|
6,164
|
|
Elimination of inter-segment revenue
|
|
|
11,361
|
|
|
|
1,131
|
|
|
|
172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other, net of inter-segment revenue
|
|
|
17,925
|
|
|
|
20,280
|
|
|
|
5,992
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
677,452
|
|
|
$
|
388,242
|
|
|
$
|
287,693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
198,913
|
|
|
$
|
17,069
|
|
|
$
|
14,886
|
|
Drilling and oil field services
|
|
|
10,473
|
|
|
|
32,946
|
|
|
|
18,295
|
|
Midstream services
|
|
|
6,783
|
|
|
|
3,528
|
|
|
|
4,096
|
|
Other
|
|
|
(29,310
|
)
|
|
|
(16,562
|
)
|
|
|
(3,224
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating income
|
|
|
186,859
|
|
|
|
36,981
|
|
|
|
34,053
|
|
Interest expense, net
|
|
|
(111,762
|
)
|
|
|
(15,795
|
)
|
|
|
(5,071
|
)
|
Other income (expense), net
|
|
|
4,648
|
|
|
|
671
|
|
|
|
(1,121
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
$
|
79,745
|
|
|
$
|
21,857
|
|
|
$
|
27,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable Assets(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
3,143,137
|
|
|
$
|
2,091,459
|
|
|
$
|
243,612
|
|
Drilling and oil field services
|
|
|
271,563
|
|
|
|
175,169
|
|
|
|
100,995
|
|
Midstream services
|
|
|
127,822
|
|
|
|
75,606
|
|
|
|
33,845
|
|
Other
|
|
|
88,044
|
|
|
|
46,150
|
|
|
|
80,231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,630,566
|
|
|
$
|
2,388,384
|
|
|
$
|
458,683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
1,046,552
|
|
|
$
|
170,872
|
|
|
$
|
61,227
|
|
Drilling and oil field services
|
|
|
123,232
|
|
|
|
89,810
|
|
|
|
43,730
|
|
Midstream services
|
|
|
63,828
|
|
|
|
16,975
|
|
|
|
25,904
|
|
Other
|
|
|
47,236
|
|
|
|
28,884
|
|
|
|
3,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
1,280,848
|
|
|
$
|
306,541
|
|
|
$
|
134,596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
175,565
|
|
|
$
|
28,104
|
|
|
$
|
8,796
|
|
Drilling and oil field services
|
|
|
37,792
|
|
|
|
20,268
|
|
|
|
11,851
|
|
Midstream services
|
|
|
6,641
|
|
|
|
3,180
|
|
|
|
1,652
|
|
Other
|
|
|
7,110
|
|
|
|
4,074
|
|
|
|
1,907
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation, depletion and amortization
|
|
$
|
227,108
|
|
|
$
|
55,626
|
|
|
$
|
24,206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Identifiable assets are those used in SandRidges
operations in each industry segment. |
Major Customer. During 2007, the Company had
sales in excess of 10% of total revenues to an oil and gas
purchaser ($76.1 million or 11.2% of total revenues). There
were no customers that accounted for 10% or more of our total
revenues in 2006 or 2005.
F-29
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
22.
|
Supplemental
Information on Oil and Gas Producing Activities
(Unaudited)
|
The Supplementary Information on Oil and Gas Producing
Activities is presented as required by SFAS No. 69,
Disclosures about Oil and Gas Producing Activities.
The supplemental information includes capitalized costs related
to oil and gas producing activities; costs incurred for the
acquisition of oil and gas producing activities, exploration and
development activities; and the results of operations from oil
and gas producing activities. Supplemental information is also
provided for per unit production costs; oil and gas production
and average sales prices; the estimated quantities of proved oil
and gas reserves; the standardized measure of discounted future
net cash flows associated with proved oil and gas reserves; and
a summary of the changes in the standardized measure of
discounted future net cash flows associated with proved oil and
gas reserves.
The Companys capitalized costs consisted of the following
(in thousands):
Capitalized
Costs Related to Oil and Gas Producing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Oil and natural gas properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
2,848,531
|
|
|
$
|
1,636,832
|
|
|
$
|
160,789
|
|
Unproved
|
|
|
259,610
|
|
|
|
282,374
|
|
|
|
33,974
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas properties
|
|
|
3,108,141
|
|
|
|
1,919,206
|
|
|
|
194,763
|
|
Less accumulated depreciation and depletion
|
|
|
(230,974
|
)
|
|
|
(60,752
|
)
|
|
|
(35,029
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net oil and natural gas properties capitalized costs
|
|
$
|
2,877,167
|
|
|
$
|
1,858,454
|
|
|
$
|
159,734
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
Incurred in Property Acquisition, Exploration and Development
Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Acquisitions of properties
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
303,282
|
|
|
$
|
1,311,029
|
|
|
$
|
14,554
|
|
Unproved
|
|
|
|
|
|
|
268,839
|
|
|
|
21,085
|
|
Exploration(1)
|
|
|
361,973
|
|
|
|
18,612
|
|
|
|
2,527
|
|
Development
|
|
|
485,348
|
|
|
|
115,153
|
|
|
|
60,364
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost incurred
|
|
$
|
1,150,603
|
|
|
$
|
1,713,633
|
|
|
$
|
98,530
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
2007 amount includes seismic costs of $38.6 million. |
F-30
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The Companys results of operations from oil and gas
producing activities for each of the years 2007, 2006 and 2005
are shown in the following table (in thousands):
Results
of Operations for Oil and Gas Producing Activities
|
|
|
|
|
For the Year Ended December 31, 2005
|
|
|
|
|
Revenues
|
|
$
|
48,405
|
|
Expenses:
|
|
|
|
|
Production costs
|
|
|
19,353
|
|
Depreciation, depletion and amortization expenses
|
|
|
8,995
|
|
|
|
|
|
|
Total expenses
|
|
|
28,348
|
|
|
|
|
|
|
Income before income taxes
|
|
|
20,057
|
|
Provision for income taxes
|
|
|
7,020
|
|
|
|
|
|
|
Results of operations for oil and gas producing activities
|
|
$
|
13,037
|
|
|
|
|
|
|
For the Year Ended December 31, 2006
|
|
|
|
|
Revenues
|
|
$
|
101,252
|
|
Expenses:
|
|
|
|
|
Production costs
|
|
|
39,803
|
|
Depreciation, depletion and amortization expenses
|
|
|
25,723
|
|
|
|
|
|
|
Total expenses
|
|
|
65,526
|
|
|
|
|
|
|
Income before income taxes
|
|
|
35,726
|
|
Provision for income taxes
|
|
|
10,718
|
|
|
|
|
|
|
Results of operations for oil and gas producing activities
|
|
$
|
25,008
|
|
|
|
|
|
|
For the Year Ended December 31, 2007
|
|
|
|
|
Revenues
|
|
$
|
477,612
|
|
Expenses:
|
|
|
|
|
Production costs
|
|
|
125,749
|
|
Depreciation, depletion and amortization expenses
|
|
|
169,392
|
|
|
|
|
|
|
Total expenses
|
|
|
295,141
|
|
|
|
|
|
|
Income before income taxes
|
|
|
182,471
|
|
Provision for income taxes
|
|
|
65,690
|
|
|
|
|
|
|
Results of operations for oil and gas producing activities
|
|
$
|
116,781
|
|
|
|
|
|
|
The table below represents the Companys estimate of proved
crude oil and natural gas reserves attributable to the
Companys net interest in oil and gas properties based upon
the evaluation by the Company and its independent petroleum
engineers of pertinent geological and engineering data in
accordance with United States Securities and Exchange Commission
regulations. Estimates of substantially all of the
Companys proved reserves have been prepared by the team of
independent reservoir engineers and geoscience professionals and
are reviewed by members of the Companys senior management
with professional training in petroleum engineering to ensure
that the Company consistently applies rigorous professional
standards and the reserve definitions prescribed by the United
States Securities and Exchange Commission.
Netherland, Sewell & Associates, Inc. and DeGolyer and
MacNaughton, independent oil and gas consultants, have prepared
the estimates of proved reserves of natural gas and crude oil
attributable to several portions of the Companys net
interest in oil and gas properties as of the end of one or more
of 2007, 2006 and 2005. Netherland, Sewell &
Associates, Inc. and DeGolyer and MacNaughton are independent
petroleum engineers, geologists, geophysicists and
petrophysicists and do not own an interest in us or our
properties and are not employed on a contingent basis.
Netherland, Sewell & Associates, Inc. prepared the
estimates of proved
F-31
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
reserves for all of our properties other than those held by
PetroSource, which constitute approximately 89% of our total
proved reserves as of December 31, 2007. DeGolyer and
MacNaughton prepared the estimates of proved reserves for
PetroSource, which constitute approximately 8% of our total
proved reserves as of December 31, 2007. The small
remaining portion of estimates of proved reserves were based on
Company estimates.
The Company believes the geologic and engineering data examined
provides reasonable assurance that the proved reserves are
recoverable in future years from known reservoirs under existing
economic and operating conditions. Estimates of proved reserves
are subject to change, either positively or negatively, as
additional information is available and contractual and economic
conditions change.
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, that is, 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. Proved developed reserves are the quantities of
crude oil, natural gas liquids and natural gas expected to be
recovered through existing investments in wells and field
infrastructure under current operating conditions. Proved
undeveloped reserves require additional investments in wells and
related infrastructure in order to recover the production.
During 2007, the Company recognized additional reserves
attributable to extensions and discoveries as a result of
successful drilling in the Piñon Field. Drilling
expenditures of $97.1 resulted in the addition of 44.7 Bcfe
of net proved developed reserves by extending the field
boundaries as well as proving the producing capabilities of
formations not previously captured as proved reserves. The
remaining 55.1 Bcfe of net proved reserves for 2007 are
proved undeveloped reserves associated with direct offsets to
the 2007 drilling program extending the boundaries of the
Piñon Field and zone identification. Changes in reserves
associated with the development drilling have been accounted for
in revisions of previous reserve estimates.
During 2006, the Company recognized additional reserves
attributable to extensions and discoveries as a result of
successful drilling in the Piñon Field. Drilling
expenditures of $18.6 million resulted in the addition of
10.9 Bcfe of net proved developed reserves by extending the
field boundaries as well as proving the producing capabilities
of formations not previously captured as proved reserves. The
remaining 83.1 Bcfe of net proved reserves for 2006 are
proved undeveloped reserves associated with direct offsets to
the 2006 drilling program extending the boundaries of the
Piñon Field and zone identification. Changes in reserves
associated with the development drilling have been accounted for
in revisions of previous reserve estimates.
F-32
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Reserve
Quantity Information
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
|
|
|
Nat. Gas
|
|
|
|
(MBbls)
|
|
|
(MMcf)(a)
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
As of December 31, 2004
|
|
|
682
|
|
|
|
144,452
|
|
Revisions of previous estimates
|
|
|
108
|
|
|
|
11,679
|
|
Acquisitions of new reserves
|
|
|
9,518
|
|
|
|
32,022
|
|
Extensions and discoveries
|
|
|
200
|
|
|
|
56,133
|
|
Production
|
|
|
(72
|
)
|
|
|
(6,873
|
)
|
|
|
|
|
|
|
|
|
|
As of December 31, 2005
|
|
|
10,436
|
|
|
|
237,413
|
|
Revisions of previous estimates
|
|
|
1,250
|
|
|
|
19,139
|
|
Acquisitions of new reserves
|
|
|
13,753
|
|
|
|
514,170
|
|
Extensions and discoveries
|
|
|
58
|
|
|
|
93,396
|
|
Production
|
|
|
(322
|
)
|
|
|
(13,410
|
)
|
|
|
|
|
|
|
|
|
|
As of December 31, 2006
|
|
|
25,175
|
|
|
|
850,708
|
|
Revisions of previous estimates
|
|
|
5,492
|
|
|
|
318,639
|
|
Acquisitions of new reserves
|
|
|
53
|
|
|
|
75,139
|
|
Extensions and discoveries
|
|
|
7,849
|
|
|
|
104,501
|
|
Production
|
|
|
(2,042
|
)
|
|
|
(51,958
|
)
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007
|
|
|
36,527
|
|
|
|
1,297,029
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
As of December 31, 2004
|
|
|
231
|
|
|
|
50,981
|
|
As of December 31, 2005
|
|
|
899
|
|
|
|
69,377
|
|
As of December 31, 2006
|
|
|
10,994
|
|
|
|
308,296
|
|
As of December 31, 2007
|
|
|
12,532
|
|
|
|
590,358
|
|
|
|
|
(a) |
|
Natural gas reserves are computed at 14.65 pounds per square
inch absolute and 60 degrees Fahrenheit. |
The standardized measure of discounted cash flows and summary of
the changes in the standardized measure computation from year to
year are prepared in accordance with SFAS No. 69. The
assumptions that underlie the computation of the standardized
measure of discounted cash flows may be summarized as follows:
|
|
|
|
|
the standardized measure includes the Companys estimate of
proved crude oil, natural gas liquids and natural gas reserves
and projected future production volumes based upon year-end
economic conditions;
|
|
|
|
pricing is applied based upon year-end market prices adjusted
for fixed or determinable contracts that are in existence at
year-end. The calculated weighted average per unit prices for
the Companys proved reserves and future net revenues were
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Natural gas (per Mcf)
|
|
$
|
6.46
|
|
|
$
|
5.32
|
|
|
$
|
8.40
|
|
Crude oil (per barrel)
|
|
$
|
87.47
|
|
|
$
|
54.62
|
|
|
$
|
54.02
|
|
|
|
|
|
|
future development and production costs are determined based
upon actual cost at year-end;
|
|
|
|
the standardized measure includes projections of future
abandonment costs based upon actual costs at year-end; and
|
|
|
|
a discount factor of 10% per year is applied annually to the
future net cash flows.
|
F-33
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Standardized
Measure of Discounted Future Net Cash Flows Related to
Proved Oil and Gas Reserves
|
|
|
|
|
|
|
(In thousands)
|
|
|
As of December 31, 2005
|
|
|
|
|
Future cash inflows from production
|
|
$
|
2,558,668
|
|
Future production costs
|
|
|
(653,748
|
)
|
Future development costs(a)
|
|
|
(296,489
|
)
|
Future income tax expenses
|
|
|
(546,867
|
)
|
|
|
|
|
|
Undiscounted future net cash flows
|
|
|
1,061,564
|
|
10% annual discount
|
|
|
(562,410
|
)
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
499,154
|
|
|
|
|
|
|
As of December 31, 2006
|
|
|
|
|
Future cash inflows from production
|
|
$
|
5,901,660
|
|
Future production costs
|
|
|
(1,623,216
|
)
|
Future development costs(a)
|
|
|
(931,947
|
)
|
Future income tax expenses
|
|
|
(638,599
|
)
|
|
|
|
|
|
Undiscounted future net cash flows
|
|
|
2,707,898
|
|
10% annual discount
|
|
|
(1,267,752
|
)
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
1,440,146
|
|
|
|
|
|
|
As of December 31, 2007
|
|
|
|
|
Future cash inflows from production
|
|
$
|
11,578,381
|
|
Future production costs
|
|
|
(2,706,208
|
)
|
Future development costs(a)
|
|
|
(1,640,500
|
)
|
Future income tax expenses
|
|
|
(1,782,909
|
)
|
|
|
|
|
|
Undiscounted future net cash flows
|
|
|
5,448,764
|
|
10% annual discount
|
|
|
(2,730,227
|
)
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
2,718,537
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes abandonment costs. |
F-34
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The following table represents the Companys estimate of
changes in the standardized measure of discounted future net
cash flows from proved reserves (in thousands):
Changes
in the Standardized Measure of Discounted Future Net Cash
Flows
From Proved Oil and Gas Reserves
|
|
|
|
|
Present value as of December 31, 2004
|
|
$
|
198,962
|
|
Changes during the year:
|
|
|
|
|
Revenues less production and other costs
|
|
|
(29,052
|
)
|
Net changes in prices, production and other costs
|
|
|
225,227
|
|
Development costs incurred
|
|
|
56,368
|
|
Net changes in future development costs
|
|
|
(86,828
|
)
|
Extensions and discoveries
|
|
|
96,514
|
|
Revisions of previous quantity estimates
|
|
|
47,501
|
|
Accretion of discount
|
|
|
28,981
|
|
Net change in income taxes
|
|
|
(155,250
|
)
|
Purchases of reserves in-place
|
|
|
196,206
|
|
Timing differences and other(a)
|
|
|
(79,475
|
)
|
|
|
|
|
|
Net change for the year
|
|
|
300,192
|
|
|
|
|
|
|
Present value as of December 31, 2005
|
|
$
|
499,154
|
|
Revenues less production and other costs
|
|
|
(61,449
|
)
|
Net changes in prices, production and other costs
|
|
|
(294,437
|
)
|
Development costs incurred
|
|
|
75,323
|
|
Net changes in future development costs
|
|
|
(75,466
|
)
|
Extensions and discoveries
|
|
|
126,061
|
|
Revisions of previous quantity estimates
|
|
|
54,313
|
|
Accretion of discount
|
|
|
73,643
|
|
Net change in income taxes
|
|
|
(36,962
|
)
|
Purchases of reserves in-place
|
|
|
1,135,062
|
|
Timing differences and other(a)
|
|
|
(55,096
|
)
|
|
|
|
|
|
Net change for the year
|
|
|
940,992
|
|
|
|
|
|
|
Present value as of December 31, 2006
|
|
$
|
1,440,146
|
|
Changes during the year:
|
|
|
|
|
Revenues less production and other costs
|
|
|
(351,863
|
)
|
Net changes in prices, production and other costs
|
|
|
800,630
|
|
Development costs incurred
|
|
|
485,348
|
|
Net changes in future development costs
|
|
|
(723,943
|
)
|
Extensions and discoveries
|
|
|
328,094
|
|
Revisions of previous quantity estimates
|
|
|
998,729
|
|
Accretion of discount
|
|
|
88,596
|
|
Net change in income taxes
|
|
|
(537,835
|
)
|
Purchases of reserves in-place
|
|
|
155,051
|
|
Timing differences and other(a)
|
|
|
35,584
|
|
|
|
|
|
|
Net change for the year
|
|
|
1,278,391
|
|
|
|
|
|
|
Present value as of December 31, 2007
|
|
$
|
2,718,537
|
|
|
|
|
|
|
|
|
|
(a) |
|
The change in timing differences and other are related to
revisions in the Companys estimated time of production and
development. |
F-35
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
23.
|
Quarterly
Financial Results (Unaudited)
|
Our operating results for each quarter of 2007 and 2006 are
summarized below (in thousands, except per share data).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
149,064
|
|
|
$
|
159,063
|
|
|
$
|
153,648
|
|
|
$
|
215,677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
$
|
14,408
|
|
|
$
|
75,160
|
|
|
$
|
59,716
|
|
|
$
|
37,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(19,493
|
)
|
|
$
|
34,564
|
|
|
$
|
20,920
|
|
|
$
|
14,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available (applicable) to common stockholders
|
|
$
|
(28,459
|
)
|
|
$
|
22,270
|
|
|
$
|
11,607
|
|
|
$
|
4,915
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available (applicable) to common
stockholders(1)
|
|
$
|
(0.31
|
)
|
|
$
|
0.21
|
|
|
$
|
0.11
|
|
|
$
|
0.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
85,915
|
|
|
$
|
87,915
|
|
|
$
|
89,650
|
|
|
$
|
124,762
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
$
|
3,468
|
|
|
$
|
6,757
|
|
|
$
|
8,576
|
|
|
$
|
18,180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
8,383
|
|
|
$
|
5,649
|
|
|
$
|
4,895
|
|
|
$
|
(3,306
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available (applicable) to common stockholders
|
|
$
|
8,383
|
|
|
$
|
5,649
|
|
|
$
|
4,895
|
|
|
$
|
(7,273
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available (applicable) to common
stockholders(1)
|
|
$
|
0.12
|
|
|
$
|
0.08
|
|
|
$
|
0.07
|
|
|
$
|
(0.10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Income (loss) available (applicable) to common stockholders for
each quarter is computed using the weighted-average number of
shares outstanding during the quarter, while earnings per share
for the fiscal year is computed using the weighted-average
number of shares outstanding during the year. Thus, the sum of
income (loss) available (applicable) to common stockholders for
each of the four quarters may not equal the fiscal year amount. |
F-36
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized, on March 7, 2008.
SANDRIDGE ENERGY, INC.
Tom L. Ward, Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities indicated on
March 7, 2008.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
*
Tom
L. Ward
|
|
President, Chief Executive Officer and Chairman of the Board
(Principal Executive Officer)
|
|
March 7, 2008
|
|
|
|
|
|
*
Dirk
M. Van Doren
|
|
Chief Financial Officer and
Executive Vice President
(Principal Financial Officer)
|
|
March 7, 2008
|
|
|
|
|
|
*
Randall
D. Cooley
|
|
Senior Vice President Accounting (Principal
Accounting Officer)
|
|
March 7, 2008
|
|
|
|
|
|
*
Dan
Jordan
|
|
Director
|
|
March 7, 2008
|
|
|
|
|
|
*
Bill
Gilliland
|
|
Director
|
|
March 7, 2008
|
|
|
|
|
|
*
Roy
T. Oliver, Jr.
|
|
Director
|
|
March 7, 2008
|
|
|
|
|
|
*
Stuart
W. Ray
|
|
Director
|
|
March 7, 2008
|
|
|
|
|
|
*
D.
Dwight Scott
|
|
Director
|
|
March 7, 2008
|
|
|
|
|
|
*
Jeff
Serota
|
|
Director
|
|
March 7, 2008
|
|
|
|
|
|
|
|
*By:
|
|
/s/ V.
Bruce Thompson
|
|
|
|
|
EXHIBIT INDEX
|
|
|
|
|
|
|
|
|
|
|
|
|
Filed Herewith(*) or
|
|
|
Exhibit
|
|
|
|
Incorporated by
|
|
File
|
Number
|
|
Description
|
|
Reference to Exhibit No.
|
|
Number
|
|
|
3
|
.1
|
|
Certificate of Incorporation
|
|
3.1 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
3
|
.2
|
|
Certificate of Designation of convertible preferred stock
|
|
3.2 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
3
|
.3
|
|
Bylaws
|
|
3.3 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.1
|
|
Specimen Stock Certificate representing common stock
|
|
4.1 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.2
|
|
Resale Registration Rights Agreement, dated December 21,
2005, by and between SandRidge Energy, Inc. (as successor by
merger to Riata Energy, Inc.) and Banc of America Securities, LLC
|
|
4.2 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.2.1
|
|
Form of Consent to Amend December 21, 2005 Resale
Registration Rights Agreement, dated June 13, 2006
|
|
4.11 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.2.2
|
|
Form of Consent to Amend December 21, 2005 Resale
Registration Rights Agreement, dated April 23, 2007
|
|
4.12 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.2.3
|
|
Form of Consent to Amend December 21, 2005 Resale
Registration Rights Agreement, dated October 4, 2007
|
|
4.13 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.3
|
|
Registration Rights Agreement, dated November 21, 2006, by
and among SandRidge Energy, Inc. (as successor by merger to
Riata Energy, Inc.) and the Purchasers party thereto
|
|
4.3 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.3.1
|
|
Form of Consent to Amend November 21, 2006 Registration
Rights Agreement, dated October 4, 2007
|
|
4.14 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.4
|
|
Securities Purchase Agreement, dated November 21, 2006, by
and among SandRidge Energy, Inc. (as successor by merger to
Riata Energy, Inc.) and the Purchasers party thereto
|
|
4.4 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.5
|
|
Specimen Stock Certificate representing convertible preferred
stock
|
|
4.5 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.6
|
|
Form of Warrant to Purchase Convertible Preferred Stock
|
|
4.6 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.7
|
|
Amended and Restated Shareholders Agreement, dated April 4,
2007, among SandRidge Energy, Inc. (as successor by merger to
Riata Energy, Inc.) and certain shareholders
|
|
4.7 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.8
|
|
Registration Rights Agreement, dated March 20, 2007, by and
among SandRidge Energy, Inc. and the several purchasers party
thereto
|
|
4.8 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.8.1
|
|
Form of Consent to Amend March 20, 2007 Registration Rights
Agreement, dated October 4, 2007
|
|
4.15 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.9
|
|
Stock Purchase Agreement, dated February 12, 2007, by and
among SandRidge Energy, Inc. and each of the investors signatory
thereto
|
|
4.9 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
4
|
.10
|
|
Shareholders Agreement, dated March 20, 2007, by and among
SandRidge Energy, Inc. and certain common shareholders
|
|
4.10 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Filed Herewith(*) or
|
|
|
Exhibit
|
|
|
|
Incorporated by
|
|
File
|
Number
|
|
Description
|
|
Reference to Exhibit No.
|
|
Number
|
|
|
10
|
.1
|
|
Executive Nonqualified Excess Plan
|
|
*
|
|
|
|
10
|
.2
|
|
2005 Stock Plan of SandRidge Energy, Inc.
|
|
10.2 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.2.1
|
|
Form of Restricted Stock Award Agreement under 2005 Stock Plan
|
|
*
|
|
|
|
10
|
.3
|
|
Employment Participation Plan of SandRidge Energy, Inc.
|
|
10.3 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.4
|
|
Well Participation Plan of SandRidge Energy, Inc
|
|
10.4 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.5.1
|
|
Employment Agreement of Tom L. Ward, dated June 8, 2006
|
|
10.11 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.5.2
|
|
Employment Agreement of Larry K. Coshow, dated September 2,
2006
|
|
10.12 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.6
|
|
Form of Indemnification Agreement for directors and officers
|
|
10.5 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.7
|
|
Senior Credit Facility, dated November 21, 2006, by and
among SandRidge Energy, Inc. (as successor by merger to Riata
Energy, Inc.) and Bank of America, N.A., as Administrative Agent
and Banc of America Securities LLC as Lead Arranger and Book
Running Manager
|
|
10.6 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.7.1
|
|
Amendment No. 1 to Senior Credit Facility, dated
November 21, 2006 by and among SandRidge Energy, Inc.
|
|
10.9 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.7.2
|
|
Amendment No. 2 to Senior Credit Facility, dated
November 21, 2006
|
|
10.10 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.8
|
|
Senior Bridge Facility, dated November 21, 2006, by and
among SandRidge Energy, Inc. (as successor by merger to Riata
Energy, Inc.) and Banc of America Bridge LLC, as the Initial
Bridge Lender and Banc of America Securities LLC, Credit Suisse
Security, Goldman, Sachs Credit Partners L.P., and Lehman
Brothers, Inc. as joint lead arrangers and book runners
|
|
10.7 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.9
|
|
Credit Agreement, dated March 22, 2007 by and among
SandRidge Energy, Inc. and Bank of America, N.A., as
Administrative Agent and Banc of America Securities LLC as Lead
Arranger
|
|
10.8 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.10
|
|
Partnership Interest Purchase Agreement, dated November 21,
2005 by and among Riata Energy, Inc. and Matthew McCann
|
|
10.13 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.11
|
|
Purchase and Sale Agreement, dated December 4, 2005 by and
between Gillco Energy, LP, as Seller and Riata Energy, Inc.,
Riata Piceance, LLC, MidContinent Resources, LLC, and ROC Gas
Company, as Buyer
|
|
10.14 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.12
|
|
Purchase and Sale Agreement, dated December 4, 2005 by and
between Wallace Jordan, LLC and Daniel White Jordan, as Sellers
and Riata Energy, Inc., Sierra Madera CO 2 Pipeline, LLC, Riata
Piceance, LLC, and ROC Gas Company, as Buyers
|
|
10.15 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.13
|
|
Purchase and Sale Agreement, dated August 29, 2006 by and
among Alsate Management and Investment Company and Longfellow
Ranch Partners, LP
|
|
10.16 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.14
|
|
Purchase and Sale Agreement, dated June 7, 2007 by and
between Wallace Jordan, LLC and SandRidge Energy, Inc.
|
|
10.17 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Filed Herewith(*) or
|
|
|
Exhibit
|
|
|
|
Incorporated by
|
|
File
|
Number
|
|
Description
|
|
Reference to Exhibit No.
|
|
Number
|
|
|
10
|
.15
|
|
Office Lease Agreement, dated March 6, 2006 by and between
1601 Tower Properties, L.L.C. and Riata Energy, Inc.
|
|
10.18 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.15.1
|
|
First Amendment, dated October 19, 2006 to Office Lease
Agreement, dated March 6, 2006
|
|
10.19 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.15.2
|
|
Second Amendment, dated January 26, 2007 to Office Lease
Agreement
|
|
10.20 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
10
|
.16
|
|
Letter Agreement for Acquisition of Properties, dated
September 21, 2007 by and between SandRidge Energy, Inc.,
Longfellow Energy, LP, Dalea Partners, LP and N. Malone
Mitchell, 3rd
|
|
10.21 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
21
|
.1
|
|
Subsidiaries of SandRidge Energy, Inc.
|
|
21.1 to Registration Statement on Form S-1 filed on
January 30, 2008
|
|
333-148956
|
|
23
|
.1
|
|
Consent of PricewaterhouseCoopers LLP
|
|
*
|
|
|
|
23
|
.2
|
|
Consent of DeGolyer and MacNaughton
|
|
*
|
|
|
|
23
|
.3
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
*
|
|
|
|
23
|
.4
|
|
Consent of Harper & Associates, Inc.
|
|
*
|
|
|
|
24
|
.1
|
|
Power of Attorney (included on signature page)
|
|
*
|
|
|
|
31
|
.1
|
|
Section 302 Certification Chief Executive
Officer
|
|
*
|
|
|
|
31
|
.2
|
|
Section 302 Certification Chief Financial
Officer
|
|
*
|
|
|
|
32
|
.1
|
|
Section 906 Certifications of Chief Executive Officer and
Chief Financial Officer
|
|
*
|
|
|
|
|
|
|
|
Management contract or compensatory plan or arrangement |
Note: Debt instruments of the Company defining the
rights of long-term debt holders in principal amounts not
exceeding 10 percent of its consolidated assets have been
omitted and will be provided to the Commission upon request.