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, 2008
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission File Number: 1-33784
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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123 Robert S. Kerr Avenue
Oklahoma City, Oklahoma
(Address of principal
executive offices)
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73102
(Zip Code)
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(405) 429-5500
(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. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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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 aggregate market value of our common stock held by
non-affiliates on June 30, 2008 was approximately
$8.0 billion based on the closing price as quoted on the
New York Stock Exchange. As of February 20, 2009, there
were 167,625,519 shares of our common stock outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2009 Annual Meeting of
Shareholders are incorporated by reference in Part III.
SANDRIDGE
ENERGY, INC.
2008
ANNUAL REPORT ON
FORM 10-K
TABLE OF
CONTENTS
2
PART I
General
SandRidge Energy, Inc. is an independent natural gas and oil
company headquartered in Oklahoma City, Oklahoma concentrating
on exploration, development and production activities. We are
focused on 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 in Pecos County and
Terrell County, Texas, where we have operated since 1986 and
currently have 655,926 net acres under lease. The WTO
includes the Piñon Field as well as the Allison Ranch,
South Sabino, Thistle, Big Canyon and McKay Creek exploration
areas.
We have assembled an extensive natural gas and crude oil
property base on which we have identified approximately 7,900
potential drilling locations as of December 31, 2008,
including approximately 3,100 locations in the WTO. As of
December 31, 2008, our estimated proved reserves,
approximately 96% of which were prepared by third party
engineers, were 2,158.6 Bcfe, of which 88% were natural
gas. As of December 31, 2008, we had 2,059 gross
(1,515.8 net) producing wells, substantially all of which we
operate, and we had natural gas and oil interests in
1,655,956 gross (1,247,664 net) leased acres. Additionally,
we averaged 29 rigs drilling in the WTO, five rigs drilling in
East Texas, three rigs drilling in the Mid-Continent and three
rigs drilling in other areas during 2008. We had nine rigs
drilling in the WTO, five rigs drilling in East Texas, one rig
drilling in Oklahoma and two rigs drilling in other areas as of
December 31, 2008.
We also operate businesses that are complementary to our primary
exploration, development and production activities which provide
us with operational flexibility and an advantageous cost
structure. We own related gas gathering and treating facilities,
a gas marketing business and an oil field services business,
including our drilling rig business, Lariat Services, Inc.
(Lariat). As of December 31, 2008, our drilling
rig fleet consisted of 43 rigs 31 rigs owned
directly by us and 12 rigs owned by Larclay, L.P.
(Larclay), a limited partnership in which we have a
50% interest. Currently, 28 of our owned rigs and 11 of the
Larclay rigs are operational. We also capture and transport
CO2
to the Permian Basin.
Our principal executive offices are located at 123 Robert S.
Kerr Avenue, Oklahoma City, Oklahoma 73102 and our telephone
number is
(405) 429-5500.
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
(SEC). 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 or accessed via the SECs
website address at www.sec.gov.
References to SandRidge, us,
we, Company and our in this
report refer to SandRidge Energy, Inc. together with its
subsidiaries. SandRidge
CO2
refers to our wholly owned subsidiary SandRidge
CO2,
LLC, and SandRidge Tertiary refers to our wholly
owned subsidiary SandRidge Tertiary, LLC.
Recent
Developments
During the second half of 2008, unprecedented levels of
volatility in the financial and commodity markets made it
necessary for us to reduce and refocus our exploration and
development activities, reduce our budget for capital
expenditures, explore the potential sale of certain assets and
seek additional capital.
Private Placement of Convertible Perpetual Preferred
Stock. In January 2009, we completed a private
placement of 2,650,000 shares of 8.5% convertible perpetual
preferred stock to qualified institutional buyers eligible under
Rule 144A under the Securities Act of 1933, as amended (the
Securities Act). The placement included
400,000 shares of convertible perpetual preferred stock
issued upon the full exercise of the initial purchasers
option to cover over-allotments. Net proceeds from the offering
were approximately $243.9 million after deducting offering
expenses of approximately $8.0 million. We used the net
proceeds of the offering to repay outstanding borrowings under
our senior credit facility and for general corporate purposes.
3
Each share of the convertible perpetual preferred stock has a
liquidation preference of $100 and is entitled to an annual
dividend of $8.50 payable semi-annually in cash, common stock or
any combination thereof, beginning on February 15, 2010. No
dividends will accrue or accumulate prior to August 15,
2009. Additionally, each share is initially convertible into
12.48 shares of our common stock, at the holders
option, at any time on or after April 15, 2009 based on an
initial conversion price of $8.01 and subject to customary
adjustments in certain circumstances.
Marketing of Midstream Assets. In January
2009, we announced our intent to offer for sale certain of our
gas gathering and related assets located in the WTO. This
process is ongoing as of the date of this filing.
2009 Capital Expenditure Budget. We are
introducing a 2009 production guidance range of 110.0 Bcfe
to 120.0 Bcfe based on a capital expenditure guidance range
of $500.0 million to $700.0 million. Based on the
current and anticipated near-term drilling activity and
associated expenditures, it is currently expected that full year
results will trend toward the lower half of these ranges.
Drilling Activity. We began to decrease the
number of rigs running on our properties during December 2008 in
preparation for reduced 2009 activity levels. At
February 20, 2009, we had 9 rigs running compared to a high
of 47 rigs operating in the second quarter of 2008.
East Texas/North Louisiana Haynesville Shale
Play: We control approximately 36,000 acres
in the developing Haynesville shale play of East Texas and North
Louisiana. We drilled two vertical test wells within the Oakhill
field area in Rusk County to evaluate the potential for
Haynesville shale production. The initial well had a total of
260 feet of Haynesville shale thickness and tested at a
rate of 1.5 MMcfe per day. The second well encountered
288 feet of shale thickness and is awaiting completion.
Business
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, drilling and
developing our large acreage position. Our primary exploration
and development focus will be in the WTO, where we owned
interests in 777,475 gross (655,926 net) acres at
December 31, 2008 and operated up to 35 rigs during 2008
(nine as of December 31, 2008). We have identified
approximately 3,100 potential drilling locations in the WTO and
believe that we will be able to expand the number of drilling
locations in the WTO through exploratory drilling and use of our
3-D seismic
technology.
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Apply Technological Improvements to Our Exploration and
Development Program. We use our
3-D seismic
acquisition program and our enhanced interpretation technologies
to achieve high drilling and exploration success rates. We
strive to maximize value by minimizing time from spud to first
sales with advanced drilling, completion and production methods
that historically have not been widely used in the WTO.
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Seek Opportunistic Acquisitions in Our Core Geographic
Areas. 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 Operations. We operate
97.3% of our production in the WTO, East Texas, the Gulf Coast
area and the Mid-Continent in addition to controlling our fleet
of drilling rigs. We believe this allows us to better control
overall costs and maintain a high degree of operating
flexibility, which permits us to manage our operating costs and
control capital expenditures and the timing of development and
exploration activities.
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4
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, the Gulf Coast area and
the Mid-Continent, as well as other non-core operating areas.
The following table identifies certain information concerning
our exploration and production business as of December 31,
2008 unless otherwise noted:
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Estimated Net
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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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Proved
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Identified
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Reserves
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PV-10
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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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(in 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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1,342.6
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1,223.2
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173.8
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21.2
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777,475
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655,926
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3,121
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East Texas
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399.3
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462.0
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46.1
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23.8
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59,564
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29,989
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1,567
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Gulf Coast
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75.4
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148.5
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24.8
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8.3
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60,059
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34,764
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43
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Mid-Continent
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93.0
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146.8
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38.8
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6.6
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583,333
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417,573
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2,474
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Other:
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Gulf of Mexico
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44.5
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32.8
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6.9
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17.6
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76,559
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37,434
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67
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Other West Texas
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87.3
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148.7
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20.1
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11.9
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60,632
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39,236
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441
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Tertiary recovery- West Texas
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116.0
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95.1
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3.1
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102.1
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9,064
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8,195
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67
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Other
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0.5
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1.4
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0.1
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14.3
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29,270
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24,547
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151
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Total
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2,158.6
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2,258.5
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313.7
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18.9
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1,655,956
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1,247,664
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7,931
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(1) |
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PV-10
generally differs from Standardized Measure of Discounted Net
Cash Flows, or Standardized Measure, 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, 2008,
see Proved Reserves. Our Standardized
Measure was $2.2 billion at December 31, 2008. |
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Average daily net production for the month of December 2008. |
West
Texas Overthrust (WTO)
We have drilled and developed natural gas in the WTO since 1986.
This area is located in Pecos County and Terrell County 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 (also known as 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
17,000 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 under-explored. The high
CO2
content of the natural gas, lack of infrastructure in the
region, historical limitations of conventional subsurface
geological and geophysical methods and commodity prices have
discouraged exploration of the area. Our access to and control
of the necessary infrastructure combined with application of
modern seismic techniques allow us to continue to identify
further exploration and development opportunities in the WTO.
5
3-D
Seismic Program. In May 2007, we began a
multi-year seismic program to acquire 1,500 square miles of
modern 3-D
seismic data in the WTO. We believe this enhanced
3-D seismic
program will lower exploratory drilling risk and improve
completion efficiency by identifying structural detail of
potential reservoirs. With the aid of
3-D seismic
data and historical well information, we believe we can
high-grade our drilling locations in order to achieve low
finding costs. As of December 31, 2008, we had acquired
1,292 square miles of
3-D seismic
data, of which 1,050 square miles had been processed and is
currently being interpreted.
Piñon Field. The Piñon Field,
located in Pecos County, is our most significant producing
field, accounting for 62.2% of our proved reserve base as of
December 31, 2008 and approximately 68% of our 2008
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 Tesnus
sands (depths ranging from 3,500 to 5,000 feet), the Upper
Caballos chert (depths ranging from 5,000 to 8,000 feet)
and the Lower Caballos chert (depths ranging from 7,000 to
10,000 feet). During 2008, we expanded the Piñon Field
utilizing data from our
3-D seismic
program and historical well information to identify new
reservoirs in the fields three primary thrusts (Dugout
Creek, Warwick and Frog Creek). As of December 31, 2008,
our estimated proved natural gas and oil reserves in the
Piñon Field were 1,342.6 Bcfe, 54.8% of which were
proved undeveloped reserves based on estimates prepared by
Netherland, Sewell & Associates, Inc., an independent
oil and gas consulting firm. Our interests in the Piñon
Field as of December 31, 2008 included 660 producing wells
and a 96.0% average working interest in the producing area of
the Piñon Field. We were operating nine drilling rigs in
the Piñon Field as of December 31, 2008 and we drilled
252 wells in this field during 2008.
West Texas Overthrust Prospects. Through our
regional exploratory efforts, to date we have identified five
exploration areas: Allison Ranch, South Sabino, Thistle, Big
Canyon and McKay Creek.
3-D seismic
data has been recently acquired over these five exploration
areas, which should allow us to further develop these
prospective areas for future exploration.
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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Net PUD
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Gross PUD
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Gross PUD
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Total Gross
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2008 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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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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Working
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735.5
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1,024.1
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744
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3,121
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9
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(1) |
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As of December 31, 2008. |
Century Plant. In June 2008, we entered into
an agreement with a subsidiary of Occidental Petroleum
Corporation (Occidental) to construct a
CO2
treating plant (the Century Plant) and associated
compression and pipeline facilities for $800.0 million.
Occidental will pay a minimum of 100% of the contract price
(including any subsequent agreed-on revisions) to us through
periodic cost reimbursements based upon the percentage of the
project completed. The Century Plant, to be located in Pecos
County, Texas, is designed to have treating capacity of
800.0 MMcf per day of natural gas and is expected to be
completed in two phases with the first phase coming on line in
the second quarter of 2010 and the second phase coming on line
in the second quarter of 2011.
Upon
start-up,
the Century Plant will be owned and operated by Occidental. We
will deliver high
CO2
natural gas to the Century Plant pursuant to a
30-year
treating agreement executed simultaneously with the construction
agreement, and Occidental will separate and remove the
CO2
from the delivered natural gas. Occidental will retain
substantially all
CO2
removed at the Century Plant and our other existing
CO2
treating plants. We will retain all methane from the Century
Plant and our other existing plants.
High
CO2
Treating. The most productive reservoir in the
Piñon Field is the Warwick Caballos chert high
CO2
reservoir. However,
CO2
is a waste product and we cannot produce high
CO2
gas without removing the
CO2
from the gas stream. Production from this reservoir is currently
limited by treating capacity at our legacy natural gas treating
plants. Our current expansion of the capacity of our existing
plants and the construction of the Century Plant will expand
CO2
treating capacity in the area and will allow us to accelerate
the development of the Warwick thrust.
6
East
Texas Cotton Valley Trend
We own significant natural gas and oil interests in the natural
gas bearing Cotton Valley Trend, which covers parts of East
Texas and northern Louisiana. As of December 31, 2008, we
held interests in 59,564 gross (29,989 net) acres in East
Texas. At that time, our estimated net proved reserves in East
Texas were 399.3 Bcfe, with net production of approximately
46.1 MMcfe per day for the month of December 2008. We focus
our operations in the Cotton Valley Trend on the tight sand
reservoirs of the Pettit and Travis Peak formations with depths
ranging from 6,500 to 10,500 feet. These sands are
typically distributed over a large area, which has led to a near
100% drilling success rate in this area. Due 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
20 acres per well. We drilled 54 wells (53.3 net
wells) in the Cotton Valley Trend in 2008. As of
December 31, 2008, we had five rigs running in this region
and expect to drill an additional 29 wells during 2009.
Gulf
Coast
As of December 31, 2008, we owned natural gas and oil
interests in 60,059 gross (34,764 net) acres in the Gulf
Coast area, which encompasses the large coastal plain from the
southernmost tip of Texas through the southern portion of
Louisiana. As of December 31, 2008, our estimated net
proved reserves in the Gulf Coast area were 75.4 Bcfe, with
net production of approximately 24.8 MMcfe per day for the
month of December 2008.
Mid-Continent
We own interests in properties in Oklahoma, Arkansas and
southern Kansas that make up our Mid-Continent area. As of
December 31, 2008, we held interests in approximately
583,333 gross (417,573 net) leasehold and option acres in
these areas. As of December 31, 2008, our estimated proved
reserves in the Mid-Continent area were 93.0 Bcfe, based on
estimates prepared by our internal engineers. Our average daily
net production for the month of December 2008 was approximately
38.8 MMcfe per day.
Other
Areas
Gulf of Mexico. As of December 31, 2008,
we owned natural gas and oil interests in 76,559 gross
(37,434 net) acres in state and federal waters off the coast of
Texas and Louisiana. As of December 31, 2008, our estimated
net proved reserves in the Gulf of Mexico were 44.5 Bcfe,
with net production of approximately 6.9 MMcfe per day for
the month of December 2008. Our operations in the Gulf of Mexico
extend from the coast to more than 100 miles offshore and
occur in waters ranging from 30 feet to 1,100 feet.
Other West Texas. Other non-tertiary assets we
own in West Texas, outside of the WTO, include our Brooklaw
Field and the Goldsmith Adobe Unit in the Permian Basin. As of
December 31, 2008, we owned interests in 60,632 gross
(39,236 net) acres in these prospects. As of December 31,
2008, our estimated net proved reserves were 87.3 Bcfe with
net production of approximately 20.1 MMcfe per day for the
month of December 2008. We have identified 441 potential
drilling locations in these fields, including 134 proved
undeveloped locations.
Tertiary
Oil Recovery
Wellman Unit. The Wellman Unit, located in the
Wellman Field in Terry County, Texas produces from the Canyon
Reef limestone formation of Permian age from an average depth of
9,500 feet. 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 83.8 Mmboe to date. We
re-initiated injection of
CO2
in November 2005. Our injection rate of
CO2
averaged 9.5 MMcf per day in 2008 and we expect to reach an
average injection rate of 29.4 MMcf per day over the next
10 years. The Wellman Field has responded to this
injection, and we averaged net oil production of 396 Bbls
per day of new oil in December 2008. As of December 31,
2008, net proved reserves attributable to the Wellman Unit were
6.6 Mmboe. We also own a
CO2
recycling plant at this unit with a capacity of 28.0 MMcf
per day. The plant includes 6,000 horsepower of
CO2
compression and 4,850
7
horsepower of 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 George Allen
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 evaluating a nine-pattern pilot project.
CO2
injection began in December 2007 following implementation of the
first two patterns and averaged approximately 2.0 MMcf per
day during 2008. We are currently evaluating the remaining seven
flood patterns for
CO2
injection.
CO2
injection into the nine patterns is expected to reach
15.0 MMcf per day when fully developed. As of
December 31, 2008, net proved reserves attributable to the
George Allen Field were 7.6 Mmboe.
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 fourteen active
CO2
floods and six more at various stages of readiness. The South
Mallet Unit has produced 27.9 Mmboe to date. We are
currently evaluating five flood patterns for
CO2
injection. We expect to reach an ultimate
CO2
injection rate of approximately 18 MMcf per day into
thirteen patterns. As of December 31, 2008, net proved
reserves attributable to the South Mallet Unit were
5.0 Mmboe.
Jones Ranch Area. Several miles west of the
George Allen Unit, in Gaines County, SandRidge Tertiary has
acquired various leases in the Jones Ranch Area. These leases,
covering approximately 2,400 gross acres, produce from
various depths and formations. We are evaluating these leases
for both conventional development and tertiary potential.
Proved
Reserves
The following historical estimates of net proved natural gas and
oil reserves are based on reserve reports as of
December 31, 2008, December 31, 2007 and
December 31, 2006, substantially all of which were prepared
by independent petroleum engineers. The
PV-10 and
Standardized Measure shown in the table below are not intended
to represent the current market value of our estimated natural
gas and oil reserves. The reserve reports were based on our
current drilling schedule and prices at December 31, 2008,
and we estimate that 94.1% of our current proved undeveloped
reserves will be developed by 2011 and all of our current proved
undeveloped reserves will be developed by 2012. Refer to
Risk Factors in Item 1A of this report and
Managements Discussion and Analysis of Financial
Condition and Results of Operations in Item 7 of this
report in evaluating the material presented below.
Netherland, Sewell & Associates, Inc., independent oil
and gas consultants, prepared the reports of estimated proved
reserves of natural gas and oil for our net interest in certain
natural gas and crude oil properties, which constituted
approximately 90.2% of our total proved reserves as of
December 31, 2008, approximately 89% of our total proved
reserves as of December 31, 2007 and 92% of our total
proved reserves as of December 31, 2006. DeGolyer and
MacNaughton prepared the reports of estimated proved reserves
(our tertiary oil reserves located in West Texas), for SandRidge
Tertiary, LLC, formerly PetroSource Production Company, LLC,
which constituted approximately 5.4% of our total proved
reserves as of December 31, 2008, approximately 8% of our
total proved reserves as of December 31, 2007 and
approximately 7% of our total proved reserves as of
December 31, 2006. The remaining 4.4%, 3% and 1% of our
estimated proved reserves as of December 31, 2008, 2007 and
2006 were based on internally prepared estimates.
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Estimated Proved Reserves(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Bcf)(2)
|
|
|
1,899.6
|
|
|
|
1,297.0
|
|
|
|
850.7
|
|
Oil (MmBbls)
|
|
|
43.2
|
|
|
|
36.5
|
|
|
|
25.2
|
|
Total (Bcfe)
|
|
|
2,158.6
|
|
|
|
1,516.2
|
|
|
|
1,001.8
|
|
PV-10 (in
millions)(3)
|
|
$
|
2,258.5
|
|
|
$
|
3,550.5
|
|
|
$
|
1,734.3
|
|
Standardized Measure of Discounted Net Cash Flows (in
millions)(4)
|
|
$
|
2,220.6
|
|
|
$
|
2,718.5
|
|
|
$
|
1,440.2
|
|
|
|
|
(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, 2008, 2007 and 2006. The calculated weighted
average prices were $4.94 per Mcf of natural gas and $39.42 per
barrel of oil at December 31, 2008, $6.46 per Mcf of
natural gas and $87.47 per barrel of oil at December 31,
2007 and $5.32 per Mcf of natural gas and $54.62 per barrel of
oil at December 31, 2006. |
|
(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 crude 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 table provides a reconciliation of our Standardized
Measure to
PV-10: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Standardized Measure of Discounted Net Cash Flows
|
|
$
|
2,220.6
|
|
|
$
|
2,718.5
|
|
|
$
|
1,440.2
|
|
Present value of future income tax discounted at 10%
|
|
|
37.9
|
|
|
|
832.0
|
|
|
|
294.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10
|
|
$
|
2,258.5
|
|
|
$
|
3,550.5
|
|
|
$
|
1,734.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 oil,
natural gas and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions such as 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.
9
Reserves that 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;
|
|
|
|
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;
|
|
|
|
oil, natural gas and natural gas liquids that may occur in
undrilled prospects; and
|
|
|
|
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 included in our lease operating expenses
as treating and gathering fees. All natural gas delivered to
sales points with
CO2
levels within pipeline specifications is included in sales and
reserves volumes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
87,402
|
|
|
|
51,958
|
|
|
|
13,410
|
|
Oil (MBbls)(1)
|
|
|
2,334
|
|
|
|
2,042
|
|
|
|
322
|
|
Combined equivalent volumes (MMcfe)
|
|
|
101,405
|
|
|
|
64,211
|
|
|
|
15,342
|
|
Average daily combined equivalent volumes (MMcfe/d)
|
|
|
277.1
|
|
|
|
175.9
|
|
|
|
42.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Average Prices(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
7.95
|
|
|
$
|
6.51
|
|
|
$
|
6.19
|
|
Oil (per Bbl)(1)
|
|
$
|
91.54
|
|
|
$
|
68.12
|
|
|
$
|
56.61
|
|
Combined equivalent (per Mcfe)
|
|
$
|
8.96
|
|
|
$
|
7.45
|
|
|
$
|
6.60
|
|
|
|
|
(1) |
|
Includes natural gas liquids. |
|
(2) |
|
Reported prices represent actual average prices for the periods
presented and do not give effect to derivative contract
settlements. |
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Expenses per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
|
|
$
|
0.11
|
|
|
$
|
0.12
|
|
|
$
|
0.22
|
|
Processing, treating and gathering(1)
|
|
|
0.33
|
|
|
|
0.28
|
|
|
|
0.37
|
|
Other lease operating expenses
|
|
|
1.13
|
|
|
|
1.25
|
|
|
|
1.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total lease operating expenses
|
|
$
|
1.57
|
|
|
$
|
1.65
|
|
|
$
|
2.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
$
|
0.30
|
|
|
$
|
0.30
|
|
|
$
|
0.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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, 2008.
Productive wells consist of producing wells and wells capable of
producing, including natural gas wells awaiting pipeline
connections 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
|
|
|
660
|
|
|
|
632.7
|
|
East Texas
|
|
|
232
|
|
|
|
218.4
|
|
Gulf Coast
|
|
|
141
|
|
|
|
86.2
|
|
Mid-Continent
|
|
|
611
|
|
|
|
242.5
|
|
Other:
|
|
|
|
|
|
|
|
|
Gulf of Mexico
|
|
|
42
|
|
|
|
21.2
|
|
Other West Texas
|
|
|
283
|
|
|
|
272.9
|
|
Tertiary recovery West Texas
|
|
|
43
|
|
|
|
40.9
|
|
Other
|
|
|
47
|
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,059
|
|
|
|
1,515.8
|
|
|
|
|
|
|
|
|
|
|
11
Developed
and Undeveloped Acreage
The following table sets forth information regarding our
developed and undeveloped acreage at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage(1)
|
|
|
Undeveloped Acreage(2)
|
|
Area
|
|
Gross(3)
|
|
|
Net(4)
|
|
|
Gross(3)
|
|
|
Net(4)
|
|
|
WTO
|
|
|
19,394
|
|
|
|
18,797
|
|
|
|
758,081
|
|
|
|
637,129
|
|
East Texas
|
|
|
31,328
|
|
|
|
23,945
|
|
|
|
28,236
|
|
|
|
6,044
|
|
Gulf Coast
|
|
|
44,250
|
|
|
|
24,820
|
|
|
|
15,809
|
|
|
|
9,944
|
|
Mid-Continent
|
|
|
92,016
|
|
|
|
54,059
|
|
|
|
491,317
|
|
|
|
363,514
|
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico
|
|
|
71,128
|
|
|
|
32,003
|
|
|
|
5,431
|
|
|
|
5,431
|
|
Other West Texas
|
|
|
32,432
|
|
|
|
23,252
|
|
|
|
28,200
|
|
|
|
15,984
|
|
Tertiary recovery West Texas
|
|
|
9,064
|
|
|
|
8,195
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
163
|
|
|
|
38
|
|
|
|
29,107
|
|
|
|
24,509
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
299,775
|
|
|
|
185,109
|
|
|
|
1,356,181
|
|
|
|
1,062,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. The
following table sets forth as of December 31, 2008 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, 2009
|
|
|
222,258
|
|
|
|
145,691
|
|
December 31, 2010
|
|
|
240,761
|
|
|
|
183,925
|
|
December 31, 2011
|
|
|
429,803
|
|
|
|
320,767
|
|
December 31, 2012 and later
|
|
|
404,456
|
|
|
|
352,492
|
|
Other(1)
|
|
|
68,581
|
|
|
|
61,968
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,365,859
|
|
|
|
1,064,843
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
presented is not necessarily indicative of future performance,
and should not be interpreted to present any correlation between
the number of productive wells drilled, quantities of reserves
found or economic
12
value. Productive wells are those that produce commercial
quantities of hydrocarbons, regardless of whether they produce a
reasonable rate of return. Gross wells refer to the total number
of wells in which we had a working interest and net wells refer
to gross wells multiplied by our weighted average working
interest. As of December 31, 2008, we had 54 wells in
process.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Gross
|
|
|
Percent
|
|
|
Net
|
|
|
Percent
|
|
|
Gross
|
|
|
Percent
|
|
|
Net
|
|
|
Percent
|
|
|
Gross
|
|
|
Percent
|
|
|
Net
|
|
|
Percent
|
|
|
Development:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
398
|
|
|
|
98.5
|
%
|
|
|
372.4
|
|
|
|
98.5
|
%
|
|
|
281
|
|
|
|
99.3
|
%
|
|
|
244.4
|
|
|
|
99.5
|
%
|
|
|
82
|
|
|
|
94
|
%
|
|
|
50.8
|
|
|
|
95
|
%
|
Dry
|
|
|
6
|
|
|
|
1.5
|
%
|
|
|
5.7
|
|
|
|
1.5
|
%
|
|
|
2
|
|
|
|
0.7
|
%
|
|
|
1.3
|
|
|
|
0.5
|
%
|
|
|
5
|
|
|
|
6
|
%
|
|
|
2.5
|
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
404
|
|
|
|
100
|
%
|
|
|
378.1
|
|
|
|
100
|
%
|
|
|
283
|
|
|
|
100
|
%
|
|
|
245.7
|
|
|
|
100
|
%
|
|
|
87
|
|
|
|
100
|
%
|
|
|
53.3
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
48
|
|
|
|
96
|
%
|
|
|
46.4
|
|
|
|
95.9
|
%
|
|
|
27
|
|
|
|
82
|
%
|
|
|
24.3
|
|
|
|
84
|
%
|
|
|
19
|
|
|
|
76
|
%
|
|
|
13.0
|
|
|
|
72
|
%
|
Dry
|
|
|
2
|
|
|
|
4
|
%
|
|
|
2.0
|
|
|
|
4.1
|
%
|
|
|
6
|
|
|
|
18
|
%
|
|
|
4.7
|
|
|
|
16
|
%
|
|
|
6
|
|
|
|
24
|
%
|
|
|
5.0
|
|
|
|
28
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
50
|
|
|
|
100
|
%
|
|
|
48.4
|
|
|
|
100
|
%
|
|
|
33
|
|
|
|
100
|
%
|
|
|
29.0
|
|
|
|
100
|
%
|
|
|
25
|
|
|
|
100
|
%
|
|
|
18.0
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
446
|
|
|
|
98.2
|
%
|
|
|
418.8
|
|
|
|
98.2
|
%
|
|
|
308
|
|
|
|
98
|
%
|
|
|
268.7
|
|
|
|
98
|
%
|
|
|
101
|
|
|
|
90
|
%
|
|
|
63.8
|
|
|
|
89
|
%
|
Dry
|
|
|
8
|
|
|
|
1.8
|
%
|
|
|
7.7
|
|
|
|
1.8
|
%
|
|
|
8
|
|
|
|
2
|
%
|
|
|
6.0
|
|
|
|
2
|
%
|
|
|
11
|
|
|
|
10
|
%
|
|
|
7.5
|
|
|
|
11
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
454
|
|
|
|
100
|
%
|
|
|
426.5
|
|
|
|
100
|
%
|
|
|
316
|
|
|
|
100
|
%
|
|
|
274.7
|
|
|
|
100
|
%
|
|
|
112
|
|
|
|
100
|
%
|
|
|
71.3
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
Rigs
The following table sets forth information with respect to the
rigs operating on our acreage as of December 31, 2008.
|
|
|
|
|
|
|
|
|
Area
|
|
Owned(1)
|
|
|
Third-Party
|
|
|
WTO
|
|
|
9
|
|
|
|
|
|
East Texas
|
|
|
2
|
|
|
|
3
|
|
Gulf Coast
|
|
|
|
|
|
|
|
|
Mid-Continent
|
|
|
|
|
|
|
1
|
|
Other West Texas
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
13
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes rigs owned by Lariat and by Larclay. |
Marketing
and Customers
We sell natural gas, oil and natural gas liquids to a variety of
customers including utilities, natural gas and oil companies,
and trading and energy marketing companies. During 2008 and
2007, we sold our production to over twenty different
purchasers, one of which, Plains Energy, accounted for
approximately 10% and 11%, respectively, of our total revenue.
Given the number of purchasers for our products, it is unlikely
that the loss of a single customer in the areas in which we sell
our products would materially affect our sales.
See Note 23 in the consolidated financial statements
included in Item 8 of this report for information regarding
our major customers.
Title to
Properties
As is customary in the oil and gas industry, we initially
conduct only a cursory review of the title to our properties for
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.
13
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 oil and gas
industry. Our natural gas and crude 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
The drilling and related oil field services that we provide to
our exploration and production business and to third parties in
West Texas are described below.
Drilling
Operations
We drill for our own account in the WTO through our drilling and
oil field services subsidiary, Lariat. 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. In addition, we own a 50% interest in a limited
partnership, Larclay, which owns and operates drilling rigs. Our
rig fleet, including rigs owned by Larclay, is designed to drill
in our specific areas of operation and has an average horsepower
of over 800 and an average depth capacity of greater than
10,500 feet. As of December 31, 2008, our drilling rig
fleet consisted of 39 operational rigs, 28 of which we owned
directly and 11 of which were owned by Larclay. As of
December 31, 2008, 13 of our rigs were working on
properties that we operated.
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 United
States. Due in part to the shortage of experienced drilling
employees and various operational challenges, we deemed it
prudent to retrofit five of these rigs to a conventional
operation. The last of the five rigs to be retrofitted became
operational in the second quarter of 2008.
The table below identifies certain information concerning our
contract drilling operations and our directly-owned rigs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Number of operational rigs owned at end of period
|
|
|
28
|
|
|
|
25
|
|
|
|
25
|
|
Average number of operational rigs owned during the period
|
|
|
27.6
|
|
|
|
26.0
|
|
|
|
21.9
|
|
Average drilling revenue per day per rig working for third
parties(1)(2)
|
|
$
|
14,217
|
|
|
$
|
21,468
|
|
|
$
|
24,646
|
|
|
|
|
(1) |
|
Represents revenues from our rigs working for third parties
divided by the total number of days our drilling rigs were used
by third parties 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, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating for
|
|
|
|
|
|
|
|
|
|
SandRidge
|
|
|
Third Parties
|
|
|
Idle
|
|
|
Operational(1)
|
|
|
Lariat
|
|
|
13
|
|
|
|
3
|
|
|
|
12
|
|
|
|
28
|
|
Larclay
|
|
|
0
|
|
|
|
1
|
|
|
|
10
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
13
|
|
|
|
4
|
|
|
|
22
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes two Lariat rigs that were being refurbished, one Lariat
rig that was non-operational and one Larclay rig that has not
been assembled. |
14
Oil Field
Services
Our oil field services business began in 1986 and conducts
operations that complement our drilling services operations.
These services include providing drilling rigs, pulling units,
trucking, rental tools, location and road construction and
roustabout services to us and our subsidiaries as well as to
third parties. Approximately 11% of our oil field services in
2008 were performed for third parties, a decline from the
approximately 28% in 2007 due to an increase in the average
number of our rigs that were operating on our properties, an
increase in our ownership interest in our natural gas and crude
oil properties and a decline in average revenue earned per day
for rigs working for third parties. Our capital expenditures for
2008 related to our oil field services were $52.9 million
and we have budgeted a range of $10.0 million to $20.0
million in capital expenditures in 2009 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 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, see
Managements Discussion and Analysis of Financial
Condition and Results of Operations Segment
Overview Drilling and Oil Field Services
Segment in Item 7 of this report.
Our
Customers
We perform approximately two-thirds of our drilling services in
support of our exploration and production business and
approximately one-third for other operators in West Texas. For
the year ended December 31, 2008, we generated revenues of
$10.7 million for drilling services performed for third
parties, with Pioneer Natural Resources accounting for
approximately $9.3 million of those revenues.
Midstream
Gas Services
We provide gathering, compression, processing and treating
services of natural gas in West Texas. 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 information regarding our primary
midstream assets as of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant Capacity
|
|
Average
|
|
Third-Party
|
Gas Plants (West Texas)
|
|
(MMcf/d)
|
|
Utilization(1)
|
|
Usage
|
|
Pikes Peak
|
|
|
81
|
|
|
|
98
|
%
|
|
|
<1
|
%
|
Grey Ranch(2)
|
|
|
160
|
|
|
|
89
|
%
|
|
|
16
|
%
|
|
|
|
(1) |
|
Average utilization for the year ended December 31, 2008. |
|
(2) |
|
We experienced a fire at our Grey Ranch plant located in Pecos
County, Texas on June 27, 2008. The plant was shut down for
repairs until its return to service October 31, 2008. Prior
to the fire, the plant had
95 MMcf/d
of treating capacity. As of December 31, 2008, the plant
was operating with the expanded capacity of
160 MMcf/d
as a result of expansions made to the plant during the repair of
fire damage. |
|
|
|
|
|
|
|
|
|
|
|
CO2
Compression
|
|
|
Average
|
|
SandRidge
CO2
Facilities (West Texas)
|
|
Capacity
(MMcf/d)
|
|
|
Utilization(1)
|
|
|
Pikes Peak
|
|
|
38
|
|
|
|
78
|
%
|
Mitchell
|
|
|
26
|
|
|
|
95
|
%
|
Grey Ranch(2)
|
|
|
100
|
|
|
|
19
|
%
|
Terrell
|
|
|
38
|
|
|
|
64
|
%
|
|
|
|
(1) |
|
Average utilization for the year ended December 31, 2008. |
|
(2) |
|
Includes the period that the Grey Ranch plant was shut down and
operating at limited capacity due to a fire that occurred on
June 27, 2008. |
15
West
Texas
In Pecos County, we operate and own the Pikes Peak gas
treating plant, which has the capacity to treat 81 MMcf per
day of natural 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 data included in the table above for the
Pikes Peak and Grey Ranch plants is based on a natural gas
stream that averaged 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. In addition, we have access for up to 65 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 653 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, 2008,
we owned and operated approximately 80,000 horsepower of gas
compression in West Texas. We anticipate installing an
additional 20,000 horsepower in 2009.
Other
Areas
As of December 31, 2008, we owned approximately
110 miles of pipeline gathering systems and operated more
than 11,000 horsepower of natural gas compression in East Texas
and approximately 44 miles of pipeline gathering systems in
the Gulf Coast area.
In May 2008, we completed the sale of substantially all of our
assets located in the Piceance Basin of Colorado, including
gathering and compression systems as well as undeveloped
acreage, working interests in wells and other facilities related
to natural gas and oil wells.
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 2008, we spent
approximately $164.0 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 79 MMcf per day in additional
treating capacity. We anticipate adding approximately
60 MMcf per day in additional treating capacity in 2009. We
have budgeted approximately $65.0 million in 2009 capital
expenditures for our midstream gas services and other segments.
Marketing
Through Integra Energy LLC, (Integra Energy), our
wholly owned subsidiary, we buy and sell the natural gas from
SandRidge-operated wells and third-party-operated wells within
our West Texas operations. 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 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
100 MmBtu per day of firm
16
transportation service subscribed on the Oasis Pipeline and
75 MmBtu per day on the Mid-Continent Express Pipeline for
a portion of our Piñon Field production for 2009. The
commitment to the Mid-Continent Express Pipeline commences upon
completion of its construction, currently estimated to be in the
summer of 2009.
Other
Operations
Our
CO2
capturing operations are conducted through SandRidge
CO2.
As of December 31, 2008, SandRidge
CO2
owned 231 miles of
CO2
pipelines in West Texas with approximately 88,000 horsepower of
owned and leased
CO2
compression available and approximately 54,000 horsepower
currently operational. The captured
CO2
is primarily used and sequestered in tertiary oil recovery
operations. As of December 31, 2008, SandRidge
CO2
was capturing approximately 85.0 MMcf per day of
CO2.
We delivered the majority of this to Occidental Permian Ltd.
(Occidental) and Chevron Corp. In December 2008, we
captured and sold an average of 67.4 MMcf of
CO2
per day and utilized 15.1 MMcf per day in our equity
projects.
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. 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 1.6 million
metric tonnes of
CO2
per year which is sequestered in enhanced oil recovery projects.
The captured
CO2
may prove beneficial to us if the capture results in ERCs that
can be traded or used by us to meet future regulatory compliance
obligations that may otherwise be costly to satisfy. ERCs of
just over 200,000 tonnes were sold on the voluntary market
during 2008. See Environmental
Regulations Future Laws and Regulations.
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 oil and gas
industry is intensely competitive, and we face competition in
each of our business segments.
We believe our geographic concentration of operations and
vertical integration enables us to compete effectively with
other exploration and production operations. However, we are
competing 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 depends on 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 crude oil properties.
With respect to our drilling business, we believe the type, age
and condition of our drilling rigs, the quality of our crews 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 and the experience of our rig crews 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 is the case in the current economic
environment. 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.
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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 natural 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.
We believe our supply of
CO2
and technical expertise enable us to compete effectively in our
CO2
gathering and sales business. However, we face the same
competitive pressures in this business that we do in our
traditional oil field services segments.
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
Regulations
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 or
production 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 treating 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 oil and gas
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
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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, treating 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.
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
United States 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 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 control
emissions of potentially harmful air emissions through
permitting and monitoring regulations. We are required to obtain
various permits to ensure that emissions from our operations
remain within permitted levels. To comply with the terms of
these permits, and, as part of our ongoing efforts to operate in
an environmentally responsible manner, we have installed and
maintained complex emission control technologies throughout our
systems that we expect will cause us to incur increased capital
and operating costs at new and existing facilities. We have
committed approximately $3.5 million to compressor engine
emission reduction projects to enable compliance at our Grey
Ranch compression station and our Pikes Peak treating plant.
Additionally, our midstream operations have implemented a
voluntary compliance audit under the Texas Environmental Health
and Safety Audit Privilege Act. Substantial additional expenses
and capital costs may be required in 2009 and beyond for us to
maintain or achieve compliance with current and future laws
governing air emissions.
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 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 natural gas and oil 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,
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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, conduct annual spill drills 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 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 contribute to warming
the Earths atmosphere. In response to such studies, the
United States Congress is actively considering legislation to
restrict or regulate emissions of greenhouse gases. More than
one-third of the states, either individually or through
multi-state regional initiatives, have begun implementing 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, in July 2008, the EPA issued an Advance Notice
of Proposed Rulemaking regarding possible future regulation of
greenhouse emissions under the Clean Air Act in response to the
United States Supreme Courts decision in Massachusetts,
et al. v. EPA, decided in 2007, which may result in the
imposition of restrictions on the emission of greenhouse gases,
even if Congress does not adopt new legislation specifically
addressing emissions of greenhouse gases. Other nations have
already agreed to regulate emissions of greenhouse gases
pursuant to the 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 United States, 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
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 establishing
chemicals of interest and their respective threshold quantities
that will trigger compliance with the 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.
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Other
Regulation of the Oil and Gas Industry
The oil and gas industry is extensively regulated by numerous
federal, state and local authorities, including Native American
tribes. Legislation affecting the oil and gas 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 oil and gas industry and its individual members, some of
which carry substantial penalties for noncompliance. Although
the regulatory burden on the oil and gas 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
tribal areas where we operate also regulate one or more of the
following activities:
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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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the 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 crude 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. Regulations of the
Minerals Management Service of the United States Department of
the Interior (MMS) 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 United States 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. Various federal laws enacted
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since 1978 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 natural gas purchases and sales that permits
all purchasers of natural 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, 2008, we had 2,094 full-time
employees and one part-time employee, including more than 210
geologists, geophysicists, petroleum engineers, technicians,
land and regulatory professionals. Of our 2,095 employees,
528 are located at our headquarters in Oklahoma City, Oklahoma,
and the remaining employees are working in our various field
offices and at our drilling sites.
Offices
In July 2007, we purchased property in downtown Oklahoma City,
Oklahoma, which serves as our corporate headquarters. We also
own office and shop space in Fort Stockton, Midland and
Odessa, Texas. As of December 31, 2008, we leased
57,417 square feet of office space in Oklahoma City,
Oklahoma. The term of the lease expires in August 2009. In
addition, we lease or sublease office space in Oklahoma,
Louisiana and Texas.
Glossary
of Natural Gas and Oil Terms
The following is a description of the meanings of some of the
oil and gas industry terms used in this report.
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 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 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.
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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.
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 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 oil, condensate or natural gas liquids.
MmBbls. Million barrels of 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.
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MMcfe. Million cubic feet equivalent,
determined using the ratio of six Mcf of natural gas to one Bbl
of 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 that,
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:
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:
The estimated quantities of oil, natural gas and natural gas
liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate
is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic
producibility is supported by either actual production or
conclusive formation test. The area of a reservoir considered
proved includes (A) that portion delineated by drilling and
defined by gas-oil
and/or
oil-water contacts, if any, and (B) the immediately
adjoining 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 that 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) oil, natural gas and natural gas liquids, the
recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir
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characteristics or economic factors; (C) oil, natural gas
and natural gas liquids, that may occur in undrilled prospects;
and (D) 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:
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 crude
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.
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.
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.
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 revenues, 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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25
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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 regions,
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, including hurricanes and tropical storms in
and around the Gulf of Mexico;
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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, such as those experienced in
the fourth quarter of 2008, 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 and, therefore,
could have a material adverse effect on our financial condition
and results of operations. This also may result in our having to
make substantial downward adjustments to our estimated proved
reserves.
Volatility
in the capital markets could affect the value of certain assets
as well as our ability to obtain capital.
Global financial markets and economic conditions have been, and
continue to be, disrupted and volatile due to a variety of
factors, including significant write-offs in the financial
services sector and current weak economic conditions. In some
cases, the markets have produced downward pressure on stock
prices and credit capacity for certain issuers without regard to
those issuers underlying financial
and/or
operating strength. As a result, the cost of raising money in
the debt and equity capital markets has increased substantially
while the availability of funds from those markets has
diminished significantly. In particular, as a result of concerns
about the stability of financial markets generally and the
solvency of lending counterparties specifically, the cost of
obtaining money from the credit markets generally has increased
as many lenders and institutional investors have increased
interest rates, enacted tighter lending standards, refused to
refinance existing debt on similar terms or at all and reduced,
or in some cases ceased, to provide funding to borrowers. In
addition, lending counterparties under existing revolving credit
facilities and other debt instruments may be unwilling or unable
to meet their funding obligations. These factors may adversely
affect the value of certain of our assets and our ability to
draw on our senior credit facility. If the current credit
conditions of United States and international capital markets
persist or deteriorate, we may be required to impair the
carrying value of assets associated with derivative contracts to
account for non-performance by counterparties to those
contracts. Moreover, government responses to the disruptions in
the financial markets may not restore consumer confidence,
stabilize the markets or increase liquidity and the availability
of credit.
On October 3, 2008, Lehman Brothers Commodity Services,
Inc. (Lehman Brothers), a lender under our senior
credit facility, filed for bankruptcy. At the time that its
parent, Lehman Brothers Holdings, Inc., declared bankruptcy on
September 15, 2008, Lehman Brothers elected not to fund its
pro rata share, or 0.29%, of borrowings requested by us under
the senior credit facility. As a result, we do not anticipate
that Lehman Brothers will fund its pro rata share of any future
borrowing requests. We currently do not expect this reduced
availability of amounts under the senior credit facility to
impact our liquidity or business operations.
If other financial institutions that have extended credit
commitments to us are adversely affected by the current
conditions of the United States and international capital
markets, they may become unable to fund borrowings under their
credit commitments to us, which could have a material adverse
effect on our financial condition and our ability to borrow
additional funds, if needed, for working capital, capital
expenditures and other corporate purposes.
26
Future
price declines may result in further reductions of the asset
carrying values of our natural gas and crude oil
properties.
We utilize the full cost method of accounting for costs related
to our natural gas and crude oil properties. Under this
accounting method, all costs for both productive and
nonproductive properties are capitalized and amortized on an
aggregate basis over the estimated lives of the properties using
the unit-of-production method. However, the amount of these
costs that can be carried as capitalized assets is subject to a
ceiling, which limits such pooled costs to the aggregate of the
present value of future net revenues of proved natural gas and
oil reserves attributable to proved properties, discounted at
10%, plus the lower of cost or market value of unproved
properties. The full cost ceiling is evaluated at the end of
each quarter using the prices for natural gas and oil in effect
at the end of the quarter, adjusted for the impact of
derivatives accounted for as cash flow hedges. As none of our
derivatives are accounted for as cash flow hedges, the impact of
our derivative contracts has been excluded from the
determination of our full cost ceiling. Our ceiling limitation
as of December 31, 2008 resulted in a non-cash impairment
charge of $1,855.0 million. Further declines in natural gas
and oil prices without other mitigating circumstances, could
result in additional losses of future net revenues, including
losses attributable to quantities that cannot be economically
produced at lower prices, which could cause us to make
additional writedowns of capitalized costs of our natural gas
and crude oil properties and non-cash charges against future
earnings. The amount of such future writedowns and non-cash
charges could be substantial. If natural gas and oil commodity
prices remain at these current levels or decline further through
the end of the first quarter of 2009, we estimate we would have
a further reduction in our asset carrying value for our natural
gas and crude oil properties.
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, 2008, our total indebtedness was
$2.4 billion, which represented approximately 75% 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 indebtedness
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.
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Any of the above listed factors could have a material adverse
effect on our business, financial condition and results of
operations.
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
27
estimated quantities and present value of reserves shown in this
report. See Business Our Businesses and
Primary Operations in Item 1 of this report 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 last day of
the reporting period. 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 crude 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 oil and
gas 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, 2008, only 1,514 of our 7,931 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 report. 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
28
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 2008, we participated in
drilling a total of 454 gross wells, of which eight were
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 an in-depth review of every individual property involved
in each acquisition generally is not feasible. 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, and such risks and liabilities could have a material
adverse effect on our results of operations and financial
condition.
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 54.8% of the estimated proved reserves that we
owned or had under lease in the WTO as of December 31, 2008
were proved undeveloped reserves and 56.3% of our total reserves
were 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 the WTO,
making us vulnerable to risks associated with operating in one
major geographic area.
As of December 31, 2008, approximately 62% of our proved
reserves and approximately 55% 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.
Such delays or interruptions could have a material adverse
effect on our financial condition and results of operations.
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. 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. Since the
treatment expenses are incurred on a Mcf basis, we will incur a
higher effective treating cost per MmBtu of natural gas sold for
natural
29
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.
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 12% in the WTO. After giving
effect to plant shrink, as many as 4 Mcf of high
CO2
natural 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.
All of
our consolidated drilling and services revenues are derived from
companies in the oil and gas industry.
Companies to which we provide drilling and related services are
affected by the oil and gas industry risks mentioned above.
Market prices of natural gas and oil, limited access to capital
and reductions in capital expenditures could result in oil and
gas companies canceling or curtailing their drilling programs,
which could reduce the demand for our drilling and related
services. Any prolonged reduction in the overall level of
exploration and development activities, whether resulting from
changes in natural gas and oil prices or otherwise, could impact
our drilling and services segment by negatively affecting:
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revenues, cash flow and profitability;
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our ability to retain skilled rig personnel whom we would need
in the event of an upturn in the demand for drilling and related
services; and
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the fair value of our rig fleet.
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A
significant decrease in natural gas production in our areas of
midstream gas services operations, 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, transport and
treat at our facilities. Most of the reserves supporting 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, transporting and treating. 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, transport and treat being reduced
substantially over time and could, upon exhaustion of the
current wells, cause us to abandon our gathering systems and,
possibly cease gathering, transporting and treating 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. Because of our reduced capital
expenditures budget for 2009, we expect that we will connect
fewer new wells in the near future, which in turn may result in
our midstream assets handling lower natural gas volumes than
previously projected. Any material decrease in the volume of
natural gas handled by our midstream assets would reduce our
revenues, operating income and cash flows.
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. In addition, the
use of such technology requires greater predrilling
expenditures, 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.
30
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, we will have
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 if dry holes are drilled and if productive wells 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 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.
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
31
substantial part, on the availability and capacity of gathering
systems, pipelines and treating facilities. For example, we are
currently experiencing capacity limitations on high
CO2
gas treating in the Piñon Field. Our failure to obtain such
services on acceptable terms or expand our midstream assets
could have a material adverse effect on 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
treating facilities may be limited or unavailable. We would be
unable to realize revenue from any shut-in 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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our proved reserves;
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the level of natural gas and oil we are able to produce from
existing wells;
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the prices at which natural gas and oil are sold; and
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our ability to acquire, locate and produce new reserves.
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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 may seek
additional financing. Our senior credit facility and senior note
indentures, however, contain covenants restricting our ability
to incur additional indebtedness without the consent of the
lenders. Our lenders may withhold this consent at their sole
discretion.
Continuing disruptions in the global financial and capital
markets also could adversely affect our ability 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.
The
agreements governing our existing indebtedness have
restrictions, financial covenants and borrowing base
redeterminations which could adversely affect our
operations.
Our senior credit facility and senior notes 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. If commodity prices remain at
their current level for an extended period or continue to
decline, this could adversely affect our ability to meet
covenants. Our failure to comply with any of the restrictions
and covenants under the senior credit facility, senior notes 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.
Our senior credit facility limits the amounts we can borrow to a
borrowing base amount. The borrowing base is subject to review
semi-annually; however, the lenders reserve the right to have
one additional re-determination of the borrowing base per
calendar year. Unscheduled re-determinations may be made at our
request, but are limited to two requests per year. The borrowing
base is determined based upon proved developed producing
reserves, proved developed non-producing reserves, and proved
undeveloped reserves. Outstanding borrowings in excess of the
borrowing base must be repaid immediately, or we must pledge
other natural gas and crude 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
32
facility. If the indebtedness under our senior credit facility
and senior notes were to be accelerated, our assets may not be
sufficient to repay such indebtedness in full.
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 contracts for a portion of our natural gas and oil
production, including collars, basis swaps and fixed-price
swaps. As of December 31, 2008, we had natural gas and
crude oil derivative contracts, excluding basis swaps, of
79.8 Bcfe at an average price of $8.60 per Mcfe in place
for 2009 and 68.4 Bcfe at an average price of $7.77 per
Mcfe in place for 2010. The Company also had natural gas basis
swaps in place through 2011 for 125.9 Bcf at an average
price of $0.73 per Mcf. We have not designated any of our
derivative contracts as hedges for accounting purposes and
record all derivative contracts on our balance sheet at fair
value. Changes in the fair value of our derivative contracts are
recognized in current period earnings. Accordingly, our earnings
may fluctuate significantly as a result of changes in fair value
of our derivative contracts. Derivative contracts also expose us
to the risk of financial loss in some circumstances, including
when:
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production is less than expected;
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the counterparty to the derivative contract defaults on its
contract obligations; or
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|
|
there is a change in the expected differential between the
underlying price in the derivative contract and actual prices
received.
|
In addition, these types of derivative contracts limit the
benefit we would receive from increases in the prices for
natural gas and oil.
Competition
in the oil and gas industry is intense, which may adversely
affect our ability to succeed.
The oil and gas industry is intensely competitive, and we
compete with companies that have greater resources than we do.
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 crude 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 crude oil properties. See Business
Competition in Item 1 of this report.
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.
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
33
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 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 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
Environmental Regulations in Item 1 of this report.
Certain environmental laws impose strict joint and several
liability that may require us 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, property or natural resources 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 such compliance 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 United States have
begun implementing legal measures to reduce emissions of
greenhouse gases, including carbon dioxide and
methane, a primary component of natural gas, in response to
scientific studies suggesting that these gases may be
contributing to the warming of the Earths atmosphere. On
the United States federal level, President Obama has expressed
support for, and it is anticipated that the current session of
Congress will consider legislation to restrict or regulate
emissions of 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 Regulations in
Item 1 of this report.
The
Century Plant may not be constructed, operate or perform as
intended.
There are significant risks associated with the construction,
operation and performance of a project like the Century Plant.
There are a limited number of firms and individuals with the
expertise and experience necessary to complete construction
projects of this size and nature. There is no assurance that the
materials necessary for construction of the plant will be in
ready supply when we need them or delivered to us on a timely
basis. Accordingly, we may not be able to complete construction
of the Century Plant within the time frame currently
anticipated, and we could experience cost overruns that will not
be covered by Occidental under our contract with Occidental.
Finally, there is no guaranty that, once the Century Plant is
constructed, we will be able to find, produce
34
and deliver enough high
CO2
gas to satisfy our delivery obligations to Occidental or that
the Century Plant will operate at its designed capacity or
otherwise perform as anticipated.
If we
fail to maintain an adequate system of internal control over
financial reporting, it could adversely affect our ability to
accurately report our results.
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 material fraud. If we
cannot provide reliable financial reports or prevent fraud, 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. 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.
|
|
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.
|
|
Item 3.
|
Legal
Proceedings
|
SandRidge is a defendant in lawsuits from time to time in the
normal course of business. In managements opinion, we are
not currently involved in any legal proceedings that,
individually or in the aggregate, could have a material effect
on our financial condition, operations or cash flows.
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
Not applicable.
35
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
|
Price
Range of Common Stock
Our common stock is listed on the New York Stock Exchange
(NYSE) under the symbol SD. The range of
high and low sales prices for our common stock for the period
from November 6, 2007, when trading of our common stock
commenced, through December 31, 2008 as reported by the
NYSE, is as follows:
|
|
|
|
|
|
|
|
|
|
|
High
|
|
|
Low
|
|
|
2007
|
|
|
|
|
|
|
|
|
Fourth Quarter (from November 6, 2007 through
December 31, 2007)
|
|
$
|
36.11
|
|
|
$
|
29.53
|
|
2008
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
41.05
|
|
|
$
|
28.50
|
|
Second Quarter
|
|
$
|
69.00
|
|
|
$
|
37.88
|
|
Third Quarter
|
|
$
|
69.41
|
|
|
$
|
17.46
|
|
Fourth Quarter
|
|
$
|
19.54
|
|
|
$
|
4.85
|
|
On February 20, 2009, the closing sales price for our
common stock was $6.44.
On February 20, 2009, there were 263 record holders of our
common stock.
We have neither declared nor paid any cash dividends, and we do
not anticipate declaring any dividends on our common stock in
the foreseeable future. We expect to retain our cash for the
operation and expansion of our business, including exploration,
development and production activities. In addition, the terms of
our indebtedness restrict our ability to pay dividends to
holders of our common 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.
Issuer
Purchases of Equity Securities
As part of our incentive compensation program, we make required
tax payments on behalf of employees as their restricted 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 are recorded as treasury stock. During the
quarter ended December 31, 2008, the following shares of
common stock were withheld in satisfaction of tax withholding
obligations arising from the vesting of restricted stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
Period
|
|
Shares Purchased
|
|
|
Paid per Share
|
|
|
or Programs
|
|
|
Programs
|
|
|
October 1, 2008-October 31, 2008
|
|
|
47
|
|
|
$
|
10.70
|
|
|
|
N/A
|
|
|
|
N/A
|
|
November 1, 2008-November 30, 2008
|
|
|
1,341
|
|
|
$
|
10.09
|
|
|
|
N/A
|
|
|
|
N/A
|
|
December 1,
2008-December 31,
2008
|
|
|
283
|
|
|
$
|
8.19
|
|
|
|
N/A
|
|
|
|
N/A
|
|
36
|
|
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 Oil &
Gas, LLC (NEG), effective November 21, 2006.
The information should be read in conjunction with
Managements Discussion and Analysis of Financial
Condition and Results of Operations in Item 7 of this
report and our consolidated financial statements and notes
thereto contained in Item 8 of this report. The following
information is not necessarily indicative of our future results.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, except per share data)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
1,181,814
|
|
|
$
|
677,452
|
|
|
$
|
388,242
|
|
|
$
|
287,693
|
|
|
$
|
175,995
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
159,004
|
|
|
|
106,192
|
|
|
|
35,149
|
|
|
|
16,195
|
|
|
|
10,230
|
|
Production taxes
|
|
|
30,594
|
|
|
|
19,557
|
|
|
|
4,654
|
|
|
|
3,158
|
|
|
|
2,497
|
|
Drilling and services
|
|
|
26,186
|
|
|
|
44,211
|
|
|
|
98,436
|
|
|
|
52,122
|
|
|
|
26,442
|
|
Midstream and marketing
|
|
|
186,655
|
|
|
|
94,253
|
|
|
|
115,076
|
|
|
|
141,372
|
|
|
|
96,180
|
|
Depreciation, depletion and amortization natural gas
and crude oil
|
|
|
290,917
|
|
|
|
173,568
|
|
|
|
26,321
|
|
|
|
9,313
|
|
|
|
4,909
|
|
Depreciation, depletion and amortization other
|
|
|
70,448
|
|
|
|
53,541
|
|
|
|
29,305
|
|
|
|
14,893
|
|
|
|
7,765
|
|
Impairment
|
|
|
1,867,497
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
109,372
|
|
|
|
61,780
|
|
|
|
55,634
|
|
|
|
11,908
|
|
|
|
6,554
|
|
(Gain) loss on derivative contracts
|
|
|
(211,439
|
)
|
|
|
(60,732
|
)
|
|
|
(12,291
|
)
|
|
|
4,132
|
|
|
|
878
|
|
(Gain) loss on sale of assets
|
|
|
(9,273
|
)
|
|
|
(1,777
|
)
|
|
|
(1,023
|
)
|
|
|
547
|
|
|
|
(210
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
2,519,961
|
|
|
|
490,593
|
|
|
|
351,261
|
|
|
|
253,640
|
|
|
|
155,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from operations
|
|
|
(1,338,147
|
)
|
|
|
186,859
|
|
|
|
36,981
|
|
|
|
34,053
|
|
|
|
20,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
3,569
|
|
|
|
4,694
|
|
|
|
991
|
|
|
|
206
|
|
|
|
56
|
|
Interest expense
|
|
|
(147,027
|
)
|
|
|
(117,185
|
)
|
|
|
(16,904
|
)
|
|
|
(5,277
|
)
|
|
|
(1,678
|
)
|
Minority interest
|
|
|
(855
|
)
|
|
|
276
|
|
|
|
(296
|
)
|
|
|
(737
|
)
|
|
|
(262
|
)
|
Income (loss) from equity investments
|
|
|
1,398
|
|
|
|
4,372
|
|
|
|
967
|
|
|
|
(384
|
)
|
|
|
(36
|
)
|
Other income, net
|
|
|
1,454
|
|
|
|
729
|
|
|
|
118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(141,461
|
)
|
|
|
(107,114
|
)
|
|
|
(15,124
|
)
|
|
|
(6,192
|
)
|
|
|
(1,920
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
|
(1,479,608
|
)
|
|
|
79,745
|
|
|
|
21,857
|
|
|
|
27,861
|
|
|
|
18,830
|
|
Income tax (benefit) expense
|
|
|
(38,328
|
)
|
|
|
29,524
|
|
|
|
6,236
|
|
|
|
9,968
|
|
|
|
6,433
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from continuing operations
|
|
|
(1,441,280
|
)
|
|
|
50,221
|
|
|
|
15,621
|
|
|
|
17,893
|
|
|
|
12,397
|
|
Income from discontinued operations, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
229
|
|
|
|
451
|
|
Extraordinary gain(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
|
(1,441,280
|
)
|
|
|
50,221
|
|
|
|
15,621
|
|
|
|
18,122
|
|
|
|
25,392
|
|
Preferred stock dividends and accretion
|
|
|
16,232
|
|
|
|
39,888
|
|
|
|
3,967
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss applicable) income available to common stockholders
|
|
$
|
(1,457,512
|
)
|
|
$
|
10,333
|
|
|
$
|
11,654
|
|
|
$
|
18,122
|
|
|
$
|
25,392
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, except per share data)
|
|
|
Earnings Per Share Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from continuing operations
|
|
$
|
(9.26
|
)
|
|
$
|
0.46
|
|
|
$
|
0.21
|
|
|
$
|
0.31
|
|
|
$
|
0.22
|
|
Income from discontinued operations, net of income tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.01
|
|
|
|
0.01
|
|
Extraordinary gain on acquisition
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.22
|
|
Preferred stock dividends
|
|
|
(0.10
|
)
|
|
|
(0.37
|
)
|
|
|
(0.05
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income per share (applicable) available to common
stockholders
|
|
$
|
(9.36
|
)
|
|
$
|
0.09
|
|
|
$
|
0.16
|
|
|
$
|
0.32
|
|
|
$
|
0.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
155,619
|
|
|
|
108,828
|
|
|
|
73,727
|
|
|
|
56,559
|
|
|
|
56,312
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
155,619
|
|
|
|
110,041
|
|
|
|
74,664
|
|
|
|
56,737
|
|
|
|
56,312
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
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. |
|
(2) |
|
The number of shares has been adjusted to reflect a 281.562-to-1
stock split in December 2005. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
636
|
|
|
$
|
63,135
|
|
|
$
|
38,948
|
|
|
$
|
45,731
|
|
|
$
|
12,973
|
|
Property, plant and equipment, net
|
|
$
|
3,175,559
|
|
|
$
|
3,337,410
|
|
|
$
|
2,134,718
|
|
|
$
|
337,881
|
|
|
$
|
114,818
|
|
Total assets
|
|
$
|
3,655,058
|
|
|
$
|
3,630,566
|
|
|
$
|
2,388,384
|
|
|
$
|
458,683
|
|
|
$
|
197,017
|
|
Long-term debt
|
|
$
|
2,375,316
|
|
|
$
|
1,067,649
|
|
|
$
|
1,066,831
|
|
|
$
|
43,133
|
|
|
$
|
59,340
|
|
Redeemable convertible preferred stock(1)
|
|
$
|
|
|
|
$
|
450,715
|
|
|
$
|
439,643
|
|
|
$
|
|
|
|
$
|
|
|
Total stockholders equity
|
|
$
|
793,521
|
|
|
$
|
1,766,891
|
|
|
$
|
649,818
|
|
|
$
|
289,002
|
|
|
$
|
59,330
|
|
Total liabilities and stockholders equity
|
|
$
|
3,655,058
|
|
|
$
|
3,630,566
|
|
|
$
|
2,388,384
|
|
|
$
|
458,683
|
|
|
$
|
197,017
|
|
|
|
|
(1) |
|
On May 7, 2008, we converted all of our then outstanding
redeemable convertible preferred stock into shares of common
stock. |
|
|
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 report, including:
Business in Item 1, Selected Financial
Data in Item 6 and Financial Statements and
Supplementary Data in Item 8. 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 crude oil, economic and
competitive conditions, regulatory changes, estimates of proved
reserves, potential failure to achieve production from
development projects, capital expenditures and other
38
uncertainties, as well as those factors discussed below and
elsewhere in this report, particularly in Risk
Factors in Item 1A of this report 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 an independent natural gas and crude 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. The WTO
includes the Piñon Field as well as the Allison Ranch,
South Sabino, Big Canyon and McKay Creek exploration areas. We
also operate interests in the Cotton Valley Trend in East Texas,
the Gulf Coast area, the Mid-Continent and the Gulf of Mexico.
On November 21, 2006, we acquired all of the outstanding
membership interests in 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. In addition to the NEG
acquisition, we have completed numerous acquisitions of
additional working interests in the WTO during the period from
late 2005 through 2008.
We currently generate the majority of our revenues, earnings and
cash flow from the production and sale of natural gas and crude
oil. Our revenues, profitability and future growth depend
substantially on prevailing prices for natural gas and crude oil
and on our ability to find and economically develop and produce
natural gas and crude oil reserves. Prices for natural gas and
crude oil fluctuate widely. In order to reduce our exposure to
these fluctuations, we enter into derivative commodity contracts
for a portion of our anticipated future natural gas and crude
oil production. Reducing our exposure to price volatility helps
ensure that we have adequate funds available for our capital
expenditure programs.
We operate businesses that are complementary to our exploration,
development and production activities. We own related gas
gathering and treating facilities, a gas marketing business and
an oil field services business. The extent to which each of
these supplemental businesses contributes to our consolidated
net income largely is determined by the amount of work each
performs for third parties. Revenues and costs related to work
performed by our businesses for our own account are eliminated
in consolidation and, therefore, do not contribute to our
consolidated net income. Our ownership and control of these
businesses, however, provide us with operational flexibility and
an advantageous cost structure.
Recent
Developments
During the second half of 2008, unprecedented levels of
volatility in the financial and commodity markets made it
necessary for us to reduce and refocus our exploration and
development activities, reduce our budget for capital
expenditures, explore the potential sale of certain assets and
seek additional capital.
Private Placement of Convertible Perpetual Preferred
Stock. In January 2009, we commenced and
completed a private placement of 2,650,000 shares of a new
series of 8.5% convertible perpetual preferred stock to
qualified institutional buyers eligible under Rule 144A
under the Securities Act. Net proceeds from the offering were
approximately $243.9 million after deducting offering
expenses of approximately $8.0 million. We used the net
proceeds of the offering to repay outstanding borrowings under
our senior credit facility and for general corporate purposes.
Each share of the convertible perpetual preferred stock has a
liquidation preference of $100 and is entitled to an annual
dividend of $8.50 payable semi-annually in cash, common stock or
any combination thereof, beginning on February 15, 2010. No
dividends will accrue or accumulate prior to August 15,
2009. Additionally, each share is initially convertible into
12.48 shares of our common stock, at the holders
option, at any time on or after April 15, 2009 based on an
initial conversion price of $8.01 and subject to customary
adjustments in certain circumstances.
39
Marketing of Midstream Assets. In January
2009, we announced our intent to offer for sale certain of our
gas gathering and related assets located in the WTO. This
process is ongoing as of the date of this filing.
2009 Capital Expenditure Budget. We are
introducing a 2009 production guidance range of 110.0 Bcfe
to 120.0 Bcfe based on a capital expenditure guidance range
of $500.0 million to $700.0 million. Based on the
current and anticipated near-term drilling activity and
associated expenditures, it is currently expected that full year
results will trend toward the lower half of these ranges.
Drilling Activity. We began to decrease the
number of rigs running on our properties during December 2008 in
preparation for reduced 2009 activity levels. At
February 20, 2009, we had 9 rigs running compared to a high
of 47 rigs operating in the second quarter of 2008.
East Texas/North Louisiana Haynesville Shale
Play: We control approximately 36,000 acres
in the developing Haynesville shale play of East Texas and North
Louisiana. We drilled two vertical test wells within the Oakhill
field area in Rusk County to evaluate the potential for
Haynesville shale production. The initial well had a total of
260 feet of Haynesville shale thickness and tested at a
rate of 1.5 MMcfe per day. The second well encountered
288 feet of shale thickness and is awaiting completion.
Segment
Overview
We operate in four related business segments: exploration and
production, drilling and oil field services, midstream gas
services and other ancillary business activities. Management
evaluates the performance of our business segments based on
operating income, which is computed as segment operating
revenues less operating expenses and depreciation, depletion,
amortization and impairment. 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 business segments.
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
912,496
|
|
|
$
|
478,747
|
|
|
$
|
106,413
|
|
Drilling and oil field services
|
|
|
46,991
|
|
|
|
73,202
|
|
|
|
138,657
|
|
Midstream gas services
|
|
|
204,138
|
|
|
|
107,578
|
|
|
|
122,892
|
|
Other
|
|
|
18,189
|
|
|
|
17,925
|
|
|
|
20,280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
1,181,814
|
|
|
|
677,452
|
|
|
|
388,242
|
|
Segment operating (loss) income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
|
(1,263,249
|
)
|
|
|
198,913
|
|
|
|
17,069
|
|
Drilling and oil field services
|
|
|
(5,393
|
)
|
|
|
10,473
|
|
|
|
32,946
|
|
Midstream gas services
|
|
|
2,087
|
|
|
|
6,783
|
|
|
|
3,528
|
|
Other
|
|
|
(71,592
|
)
|
|
|
(29,310
|
)
|
|
|
(16,562
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating (loss) income
|
|
|
(1,338,147
|
)
|
|
|
186,859
|
|
|
|
36,981
|
|
Interest income
|
|
|
3,569
|
|
|
|
4,694
|
|
|
|
991
|
|
Interest expense
|
|
|
(147,027
|
)
|
|
|
(117,185
|
)
|
|
|
(16,904
|
)
|
Other income (expense)
|
|
|
1,997
|
|
|
|
5,377
|
|
|
|
789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
$
|
(1,479,608
|
)
|
|
$
|
79,745
|
|
|
$
|
21,857
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
87,402
|
|
|
|
51,958
|
|
|
|
13,410
|
|
Crude oil (MBbls)
|
|
|
2,334
|
|
|
|
2,042
|
|
|
|
322
|
|
Combined equivalent volumes (MMcfe)
|
|
|
101,405
|
|
|
|
64,211
|
|
|
|
15,342
|
|
Average daily combined equivalent volumes (MMcfe/d)
|
|
|
277.1
|
|
|
|
175.9
|
|
|
|
42.0
|
|
Average prices- as reported(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
7.95
|
|
|
$
|
6.51
|
|
|
$
|
6.19
|
|
Crude oil (per Bbl)(2)
|
|
$
|
91.54
|
|
|
$
|
68.12
|
|
|
$
|
56.61
|
|
Combined equivalent (per Mcfe)
|
|
$
|
8.96
|
|
|
$
|
7.45
|
|
|
$
|
6.60
|
|
Average prices- including impact of derivative contract
settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
7.90
|
|
|
$
|
7.18
|
|
|
$
|
7.25
|
|
Crude oil (per Bbl)(2)
|
|
$
|
88.09
|
|
|
$
|
68.10
|
|
|
$
|
56.61
|
|
Combined equivalent (per Mcfe)
|
|
$
|
8.83
|
|
|
$
|
7.98
|
|
|
$
|
7.52
|
|
Drilling and oil field services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of operational drilling rigs owned at end of period
|
|
|
28
|
|
|
|
25
|
|
|
|
25
|
|
Average number of operational drilling rigs owned during the
period
|
|
|
27.6
|
|
|
|
26.0
|
|
|
|
21.9
|
|
|
|
|
(1) |
|
Prices represent actual average prices for the periods presented
and do not give effect to derivative transactions. |
|
(2) |
|
Includes natural gas liquids. |
Exploration
and Production Segment
We explore for, develop and produce natural gas and crude 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, of
our non-operated wells.
41
The primary factors affecting the financial results of our
exploration and production segment are the prices we receive for
our natural gas and crude oil production, the quantity of our
natural gas and crude oil production and changes in the fair
value of commodity derivative contracts we use to reduce the
volatility of the prices we receive for our natural gas and
crude oil production. Because we are vertically integrated, our
exploration and production activities affect the results of our
drilling and oil field services and midstream gas services
segments, especially in times of weak demand for natural gas and
crude oil. Our acquisition of NEG in November 2006 substantially
increased our revenues and operating income in our exploration
and production segment. As additional acquisitions have further
increased our working interest in the WTO, a larger percentage
of the work performed by our services segments has been
performed for our own account.
As of December 31, 2008, we had 2,158.6 Bcfe of
estimated net proved reserves with a
PV-10 of
$2,258.5 million, which is an increase from
1,516.2 Bcfe of estimated net proved reserves with a
PV-10 of
$3,550.5 million as of December 31, 2007. Our
Standardized Measure of Discounted Future Net Cash Flows was
$2,220.6 million at December 31, 2008 as compared to
$2,718.5 million at December 31, 2007 and
$1,440.2 million at December 31, 2006. For a
discussion of
PV-10 and
reconciliation to Standardized Measure of Discounted Net Cash
Flows, see Business Our Business and Primary
Operations Proved Reserves in Item 1 of
this report. The decrease in
PV-10 in
2008 was primarily attributable to lower commodity prices at
December 31, 2008 compared to December 31, 2007. The
SEC requires public companies utilizing the full cost method of
accounting for oil and gas properties to perform a ceiling
limitation calculation at the end of each quarterly reporting
period. Under SEC guidelines, natural gas and crude oil reserves
are calculated based on posted prices on the last day of the
reporting period with consideration of price changes only to the
extent provided by contractual arrangements. As of
December 31, 2008, these prices were $5.71 per Mcf of
natural gas and $44.60 per barrel of oil. While the overall
estimated reserve quantities assigned to our properties
increased from December 31, 2007 to December 31, 2008,
prices used to determine the future value of our reserves
declined to such an extent as to necessitate a ceiling
impairment of $1,855.0 million.
Exploration
and Production Segment Year Ended December 31,
2008 Compared to Year Ended December 31, 2007
Exploration and production segment revenues increased to
$912.5 million in the year ended December 31, 2008
from $478.7 million in 2007, an increase of 90.6%, as a
result of a 57.9% increase in combined production volumes and a
20.3% increase in the average price we received for the natural
gas and crude oil we produced. During 2008, we increased natural
gas production by 35.4 Bcf to 87.4 Bcf and increased
crude oil production by 292 MBbls to 2,334 MBbls. The
total combined 37.2 Bcfe increase in production was due
primarily to successful drilling in the WTO and an increase in
our average working interest in the WTO (96.2% at
December 31, 2008 from 93.0% at December 31, 2007). We
owned interests in a total of 2,059 producing wells at
December 31, 2008 compared to 1,654 producing wells at
December 31, 2007.
The average price we received for our natural gas production for
the year ended December 31, 2008 increased $1.44 per Mcf,
or 22.1%, to $7.95 per Mcf from $6.51 per Mcf in 2007. The
average price received for our crude oil production increased to
$91.54 per Bbl from $68.12 per Bbl in 2007. The average price we
received for our natural gas and crude oil production was
negatively impacted by the significant decline in natural gas
and crude oil prices experienced by the oil and gas industry in
the fourth quarter of 2008. The average price received for our
natural gas and crude oil production during the first nine
months of 2008 was $9.09 per Mcf and $104.73 per Bbl,
respectively, compared to the average price received for our
natural gas and crude oil production during the fourth quarter
of 2008 of $5.01 per Mcf and $51.92 per Bbl, respectively.
Including the impact of derivative contract settlements, the
effective average price received for natural gas for the year
ended December 31, 2008 was $7.90 per Mcf compared to $7.18
per Mcf during 2007. Our crude oil derivative contract
settlements decreased our effective price received for crude oil
by $3.45 per Bbl to $88.09 per Bbl for the year ended
December 31, 2008. For the year ended December 31,
2007, our oil derivative contract settlements had a minimal
impact on our effective price received for crude oil, which was
$68.10. Our derivative contracts are not designated as hedges
and, as a result, gains or losses on commodity derivative
contracts are recorded as a component of operating expenses.
Internally, management views the settlement of such derivative
contracts as adjustments to the price received for natural gas
and crude oil production to determine effective
prices. As of December 31, 2008, we had natural gas
and crude oil derivative
42
contracts, excluding basis swaps, of 79.8 Bcfe at an
average price of $8.60 per Mcfe in place for 2009 and
68.4 Bcfe at an average price of $7.77 per Mcfe in place
for 2010. The Company also had natural gas basis swaps in place
through 2011 for 125.9 Bcf at an average price of $0.73 per
Mcf.
For the year ended December 31, 2008, we had an operating
loss of $1,263.2 million in our exploration and production
segment, compared to operating income of $198.9 million in
2007. The $433.7 million increase in exploration and
production segment revenues and $211.4 million net gain on
our commodity derivative contracts, of which $224.4 million
was unrealized, were offset by a full cost ceiling impairment of
$1,855.0 million, a $52.8 million increase in
production expenses and a $117.3 million increase in
depreciation, depletion and amortization (DD&A)
on natural gas and crude oil properties due to the increase in
production. The full cost ceiling impairment was the result of
the decline of the future value of our reserves due to the
natural gas and crude oil prices at December 31, 2008 which
offset the increase in overall estimated reserve quantities
assigned to our properties. Natural gas and crude oil prices
were $5.71 per Mcf and $44.60 per Bbl at December 31, 2008
compared to $6.80 per Mcf and $95.98 per Bbl at
December 31, 2007. The increase in production expenses was
attributable to the increase in the number of operating wells we
own and the increase in our average working interests in those
wells. DD&A increased due to an increase in our depreciable
properties, higher future development costs and increased
production.
During 2007 and 2008, we entered into natural gas and crude oil
swaps and natural gas basis swaps. Given the long-term nature of
our investment in the WTO development program, we believe it
prudent to enter into natural gas and crude oil swaps and
natural gas basis swaps for a portion of our production in order
to stabilize future cash inflows for planning purposes. During
the year ended December 31, 2008, the exploration and
production segment reported a $211.4 million net gain on
our commodity derivative contracts ($13.0 million realized
loss and $224.4 million unrealized gain) compared to a
$60.7 million net gain ($34.5 million realized gain
and $26.2 million unrealized gain) in 2007. Unrealized
gains or losses on derivative contracts represent the change in
fair value of open derivative contracts during the period. The
unrealized gain on natural gas and crude oil derivative
contracts recorded during the year ended December 31, 2008
was attributable to a decrease in average natural gas and crude
oil prices at December 31, 2008 compared to the average
natural gas and crude oil prices at December 31, 2007 or
the contract price for contracts entered into during 2008.
Exploration
and Production Segment Year Ended December 31,
2007 Compared to Year Ended December 31, 2006
For the year ended December 31, 2007, exploration and
production segment revenues increased to $478.7 million
from $106.4 million in 2006. The increase in 2007 revenues
compared to 2006 was attributable to increased production
primarily due to acquisitions and successful drilling activity.
Production volumes increased to 64.2 Bcfe in 2007 from
15.3 Bcfe in 2006, representing an increase of
48.9 Bcfe, or 318.5%. Average combined prices increased
$0.85, or 12.9%, to $7.45 per Mcfe in 2007 compared to $6.60 per
Mcfe in 2006.
Exploration and production segment operating income increased
$181.8 million in 2007 to $198.9 million from
$17.1 million 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 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 gain on our derivative positions
($34.5 million realized gain and $26.2 million
unrealized gain) compared to a $12.3 million net gain
($14.2 million realized gain and $1.9 million
unrealized loss) in 2006.
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. We also
drill wells for other natural gas and crude oil companies,
primarily located in the West Texas region. As of
December 31, 2008, our drilling rig fleet consisted of 39
operational rigs, 28 of which we owned directly and 11 of which
were owned by Larclay. Our oil field services business conducts
operations that complement our drilling
43
services operation. These services include providing pulling
units, trucking, rental tools, location and road construction
and roustabout services to us and our subsidiaries as well as to
third parties.
In 2006, Lariat and its partner, Clayton Williams Energy, Inc.
(CWEI), formed a limited partnership, Larclay, in
which we and CWEI each have a 50% interest. Larclay 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 or our
prospects or for contracting to third parties on daywork
drilling contracts. All but one of these rigs have been
assembled. Larclay financed the acquisition cost of the rigs
with a loan from a third party, secured by the purchased rigs,
and a loan from CWEI. In addition, CWEI has guaranteed a portion
of the third party debt. Lariat operates the rigs owned by the
partnership. If Larclay has an operating shortfall, Lariat and
CWEI are obligated to provide loans to the partnership. In April
2008, Lariat and CWEI each made loans of $2.5 million to
Larclay under promissory notes. The notes bear interest at a
floating rate based on a London Interbank Offered Rate
(LIBOR) average plus 3.25% (5.1875% at
December 31, 2008) as provided in the Larclay
partnership agreement. In June 2008, Larclay executed a
$15.0 million revolving promissory note with each of Lariat
and CWEI. Amounts drawn under each revolving promissory note
bear interest at a floating rate based on a LIBOR average plus
3.25% (5.1875% at December 31, 2008) as provided in
the Larclay partnership agreement. Lariat and CWEI each advanced
$5.0 million to Larclay under the revolving promissory
notes during the year ended December 31, 2008. The cash
shortfalls that Larclay experienced in 2008 resulted from
principal payments due pursuant to its rig loan agreement. As a
result of current economic conditions and continued cash
shortfalls for Larclay, we have fully impaired both our
investment in and notes receivable due from Larclay, resulting
in impairment expense of approximately $12.5 million, as of
December 31, 2008.
Although Lariats 50% interest in Larclay affords us access
to Larclays eleven operational rigs, we do not control
Larclay. We account for our investment in Larclay under the
equity method of accounting, and, therefore, do not consolidate
the results of its operations with ours. Only the activities of
our wholly owned drilling and oil field services subsidiaries
are included in the financial results of our drilling and oil
field services segment. 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 account and for
others, generally on a daywork, and less often on a turnkey,
contract basis. We generally assess the complexity and risks 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
in use. 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, 2008, sixteen
of our directly owned rigs were operating under daywork
contracts and thirteen of these were working for our account.
Turnkey Contracts. Under a typical turnkey
contract, a customer pays 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. As of December 31,
2008, none of our rigs was operating under a turnkey contract.
Drilling
and Oil Field Services Segment Year Ended
December 31, 2008 Compared to Year Ended December 31,
2007
Drilling and oil field services segment revenues decreased to
$47.0 million for the year ended December 31, 2008
from $73.2 million for the year ended December 31,
2007 resulting in an operating loss of $5.4 million during
2008 compared to operating income of $10.5 million during
2007. 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
44
our full cost pool. The decline in revenues is primarily
attributable to an increase in the number of rigs operating on
our properties, an increase in our ownership interest in our
natural gas and crude oil properties resulting in decreases in
services performed for third parties, and a decline in revenue
earned per day by rigs working for third parties during 2008
compared to 2007. During 2008, an average of 24.6 of the 27.6
operational rigs we owned were working for our account compared
to an average of 20.0 of the 26.0 operational rigs working for
our account during 2007. As a result, during the year ended
December 31, 2008, 89.2% of drilling and oil field service
segment revenues were generated by work performed on our own
account and eliminated in consolidation compared to 72.0% during
2007. Additionally, the average daily rate received per rig
working for third parties declined to an average of $14,217 per
rig per working day during 2008 from an average of $21,468 per
rig per working day during 2007. During the year ended
December 31, 2007, two of our rigs working for third
parties operated under turnkey contracts, while none of our rigs
operated under turnkey contracts during the year ended
December 31, 2008. Additionally, the daywork and turnkey
contracts in place for 2007 generated higher per day revenue due
to higher rates in place for those contracts. The operating loss
of $5.4 million in 2008 is attributed to the
$12.5 million impairment on the investment in and notes
receivable due from Larclay.
Drilling
and Oil Field Services Segment Year Ended
December 31, 2007 Compared to Year Ended December 31,
2006
During 2007, our drilling and oil field services segment
reported $73.2 million in revenues, a decrease of
$65.5 million, or 47.2%, from 2006. Operating income
decreased to $10.5 million in 2007 from $32.9 million
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 crude oil properties. With the
NEG acquisition and other WTO property acquisitions during 2007,
our average working interest increased to approximately 93% in
the wells we operated in the WTO. During the year ended
December 31, 2007, 72.0% of drilling and oil field service
segment revenues were generated by work performed on our own
account and eliminated in consolidation compared to 34.3% in
2006.
Midstream
Gas Services Segment
We provide gathering, compression, processing and treating
services of natural gas in West Texas, primarily through our
wholly owned subsidiary, SandRidge Energy Midstream, Inc.
(formerly known as ROC Gas Company, Inc.). Through our gas
marketing subsidiary, 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, gas marketing 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 natural gas we sell and the amount we pay
for natural gas, which are reported as midstream and marketing
expense. The primary factors affecting our midstream gas
services are the quantity of natural gas we gather, treat and
market and the prices we pay and receive for natural gas.
Midstream
Gas Services Segment Year Ended December 31,
2008 Compared to Year Ended December 31, 2007
Midstream gas services segment revenues for the year ended
December 31, 2008 was $204.1 million compared to
$107.6 million in 2007. The increase in midstream gas
services revenues is attributable to larger third-party volumes
transported and marketed through our gathering systems during
2008 compared to 2007 as well as an overall increase in natural
gas prices in 2008 compared to 2007. Operating income generated
by our midstream gas services segment decreased
$4.7 million in 2008 to $2.1 million from
$6.8 million in 2007 due to an increase in depreciation
expense attributable to higher carrying values of midstream
gathering and treating assets.
Midstream
Gas Services Segment Year Ended December 31,
2007 Compared to Year Ended December 31, 2006
Midstream gas services segment revenues decreased
$15.3 million to $107.6 million for the year ended
December 31, 2007 from $122.9 million in 2006. The
decrease in midstream gas services revenues is attributable to
45
the increase in our working interest in the WTO as a result of
the NEG and other acquisitions. Operating income increased to
$6.8 million in 2007 from $3.5 million in 2006
primarily due to lower gas prices paid.
Other
Segment
Our other segment consists primarily of our
CO2
gathering and sales operations and corporate operations. We
conduct our
CO2
gathering and sales operations through our wholly owned
subsidiary, SandRidge
CO2,
LLC (formerly operated through PetroSource Energy Company, LLC).
SandRidge
CO2
gathers
CO2
from natural gas treatment plants located in West Texas and
transports and sells this
CO2
for use in tertiary crude oil recovery operations conducted by
us and third parties.
The operating loss in the other segment was $71.6 million
for 2008 compared to $29.3 million for 2007 and
$16.6 million for 2006. The increases in operating losses
from 2006 through 2008 are primarily attributable to increases
in corporate and support staff necessary to accommodate the
growth in our exploration and development programs and our
production levels during that time.
Results
of Operations
Year
Ended December 31, 2008 Compared to the Year Ended
December 31, 2007
Revenues. Total revenues increased 74.4% to
$1,181.8 million for the year ended December 31, 2008
from $677.5 million in 2007. This increase was due to a
$431.1 million increase in natural gas and crude oil sales
and $99.8 million increase in midstream and marketing
revenues, partially offset by lower revenues in our drilling and
services operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and crude oil
|
|
$
|
908,689
|
|
|
$
|
477,612
|
|
|
$
|
431,077
|
|
|
|
90.3
|
%
|
Drilling and services
|
|
|
47,199
|
|
|
|
73,197
|
|
|
|
(25,998
|
)
|
|
|
(35.5
|
)%
|
Midstream and marketing
|
|
|
207,602
|
|
|
|
107,765
|
|
|
|
99,837
|
|
|
|
92.6
|
%
|
Other
|
|
|
18,324
|
|
|
|
18,878
|
|
|
|
(554
|
)
|
|
|
(2.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
1,181,814
|
|
|
$
|
677,452
|
|
|
$
|
504,362
|
|
|
|
74.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas and crude oil revenues increased
$431.1 million to $908.7 million for the year ended
December 31, 2008, compared to $477.6 million in 2007,
primarily as a result of the increase in natural gas and crude
oil production volumes and prices received on our production.
Total natural gas production increased 68.2% to 87.4 Bcf in
2008 compared to 52.0 Bcf in 2007, while crude oil
production increased 14.3% to 2,334 MBbls in 2008 from
2,042 MBbls in 2007. The average price received, excluding
the impact of derivative contracts, for our natural gas and
crude oil production increased 20.3% in 2008 to a combined
equivalent price of $8.96 per Mcfe compared to $7.45 per Mcfe in
2007. The average price we received for our natural gas and
crude oil production was negatively impacted by the significant
decline in natural gas and crude oil prices experienced by the
oil and gas industry in the fourth quarter of 2008.
Drilling and services revenues decreased 35.5% to
$47.2 million in 2008 compared to $73.2 million in
2007. The decline in revenues is primarily attributable to an
increase in the average number of our rigs operating on our
properties, the increase in our ownership interest in our
natural gas and crude oil properties resulting in decreases in
services performed for third parties, and the decline in revenue
earned per day by rigs working for third parties. The average
daily rate we received per rig working for third parties
declined to an average of $14,217 per rig per working day during
2008 from an average of $21,468 per rig per working day during
2007.
Midstream and marketing revenues increased $99.8 million,
or 92.6%, to $207.6 million for the year ended
December 31, 2008, compared to $107.8 million in 2007.
This increase is primarily due to larger production volumes
transported and marketed for third parties with ownership in our
wells or ownership in other wells
46
connected to our gathering systems during 2008 compared to 2007.
Higher natural gas prices prevalent during the first nine months
of 2008 compared to 2007 also contributed to the increase.
Operating Costs and Expenses. Total operating
costs and expenses increased to $2,520.0 million during
2008, compared to $490.6 million in 2007, primarily as a
result of our full cost ceiling impairment along with increases
in our production-related costs, midstream and marketing
expenses, general and administrative expenses and depreciation,
depletion and amortization. These increases were partially
offset by decreases in costs attributable to our drilling and
services operations as well as increased gains on commodity
derivative contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
$
|
159,004
|
|
|
$
|
106,192
|
|
|
$
|
52,812
|
|
|
|
49.7
|
%
|
Production taxes
|
|
|
30,594
|
|
|
|
19,557
|
|
|
|
11,037
|
|
|
|
56.4
|
%
|
Drilling and services
|
|
|
26,186
|
|
|
|
44,211
|
|
|
|
(18,025
|
)
|
|
|
(40.8
|
)%
|
Midstream and marketing
|
|
|
186,655
|
|
|
|
94,253
|
|
|
|
92,402
|
|
|
|
98.0
|
%
|
Depreciation, depletion, and amortization natural
gas and crude oil
|
|
|
290,917
|
|
|
|
173,568
|
|
|
|
117,349
|
|
|
|
67.6
|
%
|
Depreciation, depletion and amortization other
|
|
|
70,448
|
|
|
|
53,541
|
|
|
|
16,907
|
|
|
|
31.6
|
%
|
Impairment
|
|
|
1,867,497
|
|
|
|
|
|
|
|
1,867,497
|
|
|
|
100.0
|
%
|
General and administrative
|
|
|
109,372
|
|
|
|
61,780
|
|
|
|
47,592
|
|
|
|
77.0
|
%
|
Gain on derivative contracts
|
|
|
(211,439
|
)
|
|
|
(60,732
|
)
|
|
|
(150,707
|
)
|
|
|
248.2
|
%
|
Gain on sale of assets
|
|
|
(9,273
|
)
|
|
|
(1,777
|
)
|
|
|
(7,496
|
)
|
|
|
421.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
$
|
2,519,961
|
|
|
$
|
490,593
|
|
|
$
|
2,029,368
|
|
|
|
413.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expense includes the costs associated with our
exploration and production activities, including, but not
limited to, lease operating expense and treating costs.
Production expenses increased $52.8 million to
$159.0 million for the year ended December 31, 2008,
compared to $106.2 million in 2007, primarily due to
increased production from our 2008 drilling activity and the
increase in the number of producing wells in which we have a
working interest. Production taxes increased $11.0 million,
or 56.4%, to $30.6 million for the year ended
December 31, 2008, compared to $19.6 million in 2007,
primarily as a result of the increase in production and the
increased prices received for production during the year ended
December 31, 2008. The effect on production taxes of the
increased prices received for our production was offset by an
increase in production tax exemptions realized during 2008
compared to 2007. As a result, production taxes on a
unit-of-production basis remained constant at $0.30 per Mcfe for
2008 and 2007.
Drilling and services expenses, which includes operating
expenses of the drilling, oil field services and
CO2
services companies, decreased $18.0 million, or 40.8%, to
$26.2 million in 2008 compared to $44.2 million in
2007, primarily because of the increase in the number and
working interest ownership of the wells we drilled for our own
account, which resulted in a decrease in services performed for
third parties.
Midstream and marketing expenses increased $92.4 million,
or 98.0%, to $186.7 million in 2008 compared to
$94.3 million in 2007, due primarily to the larger
production volumes transported and marketed during the year
ended December 31, 2008 on behalf of third parties compared
to 2007.
DD&A for our natural gas and crude oil properties increased
to $290.9 million during 2008 from $173.6 million in
2007. Our DD&A per Mcfe increased $0.17 to $2.87 from $2.70
in 2007. The increase is primarily attributable to the increase
in our depreciable properties, higher future development costs
and increased production. Our production increased 57.9% to
101.4 Bcfe in 2008 from 64.2 Bcfe in 2007.
DD&A for our other assets consists primarily of
depreciation of our drilling rigs, midstream gathering and
compression facilities and other equipment. The
$16.9 million increase in DD&A for our other assets
was
47
attributable primarily to higher carrying costs of our rigs, due
to upgrades and retrofitting during 2007, and our midstream
gathering and treating assets, due to upgrades made throughout
2007 and 2008. We calculate depreciation of property and
equipment using the straight-line method over the estimated
useful lives of the assets, which range from 3 to 39 years.
Our drilling rigs and related oil field services equipment are
depreciated over an average seven-year useful life.
At December 31, 2008, we recorded a non-cash impairment
charge of $1,855.0 million on our properties as total
capitalized costs of our natural gas and crude oil properties
exceeded our full cost ceiling limitation. There was no full
cost ceiling impairment as of December 31, 2007. The
additional impairment expenses related to the impairment of our
investment in and notes receivable due from Larclay.
General and administrative expenses increased 77.0% to
$109.4 million in 2008 from $61.8 million in 2007. The
increase was attributable to an increase in corporate salaries
and wages, including non-cash stock compensation expense. The
increase in corporate salaries is primarily due to the increase
in corporate and support staff added to accommodate our growth.
As of December 31, 2008, we had 528 corporate employees
compared to 335 at December 31, 2007. Included in corporate
salaries and wages was non-cash stock compensation expense of
$18.8 million in 2008 and $7.2 million in 2007.
Corporate salaries and wages were partially offset by
capitalized general and administrative expenses of
$14.5 million for 2008 and $4.6 million for 2007. In
accordance with the full cost method of accounting, we
capitalize, into the full cost pool, 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.
Due to the decline in average natural gas and crude oil prices
during the second half of 2008, we recorded a gain of
$211.4 million ($224.4 million unrealized gain and
$13.0 million realized loss) on our derivatives contracts
for 2008 compared to a $60.7 million gain
($26.2 million unrealized gain and $34.5 million
realized gain) in 2007. The unrealized gain recorded during 2008
was attributable to a decrease in average natural gas prices at
December 31, 2008 compared to the average natural gas
prices at December 31, 2007 or the various contract dates
for contracts entered into during 2008.
Other Income (Expense). Total net other
expense increased to $141.5 million for the year ended
December 31, 2008 from $107.1 million in 2007. The
increase is reflected in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
$
|
3,569
|
|
|
$
|
4,694
|
|
|
$
|
(1,125
|
)
|
|
|
(24.0
|
)%
|
Interest expense
|
|
|
(147,027
|
)
|
|
|
(117,185
|
)
|
|
|
(29,842
|
)
|
|
|
25.5
|
%
|
Minority interest
|
|
|
(855
|
)
|
|
|
276
|
|
|
|
(1,131
|
)
|
|
|
(409.8
|
)%
|
Income from equity investments
|
|
|
1,398
|
|
|
|
4,372
|
|
|
|
(2,974
|
)
|
|
|
(68.0
|
)%
|
Other income, net
|
|
|
1,454
|
|
|
|
729
|
|
|
|
725
|
|
|
|
99.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense), net
|
|
|
(141,461
|
)
|
|
|
(107,114
|
)
|
|
|
(34,347
|
)
|
|
|
32.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
|
(1,479,608
|
)
|
|
|
79,745
|
|
|
|
(1,559,353
|
)
|
|
|
(1,955.4
|
)%
|
Income tax (benefit) expense
|
|
|
(38,328
|
)
|
|
|
29,524
|
|
|
|
(67,852
|
)
|
|
|
(229.8
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,441,280
|
)
|
|
$
|
50,221
|
|
|
$
|
(1,491,501
|
)
|
|
|
(2,969.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income decreased to $3.6 million in 2008 from
$4.7 million in 2007. This decrease was generally due to
lower excess cash levels during 2008 compared to 2007.
Interest expense increased to $147.0 million, net of
$0.4 million of capitalized interest, in 2008, from
$117.2 million, net of $2.0 million of capitalized
interest, in 2007. The increase in interest expense for 2008 was
the result of higher average debt balances outstanding during
2008 compared to 2007. An $8.7 million unrealized loss
related to our interest rate swap also contributed to the
increase in interest expense for 2008. In March 2007, the
48
unamortized debt issuance costs totaling $12.5 million
related to our senior bridge facility were expensed resulting in
higher interest expense.
During the year ended December 31, 2008, we reported income
from equity investments of $1.4 million compared to
$4.4 million in 2007 due to decreases in profitability
experienced by our unconsolidated equity investees, Larclay and
Grey Ranch, L.P.
We reported an income tax benefit of $38.3 million for the
year ended December 31, 2008 compared to income tax expense
of $29.5 million in 2007. The 2008 income tax benefit
represented an effective income tax rate of 2.6% compared to
37.0% in 2007. The low effective income tax rate associated with
the loss before income taxes of $1,479.6 million is
predominantly due to a valuation allowance being established
against our net deferred tax asset. Our deferred tax position
changed from a net deferred tax liability as of
December 31, 2007 to a net deferred tax asset as of
December 31, 2008 due to the recording of a full cost
ceiling impairment of $1,855.0 million. The valuation
allowance serves to reduce the tax benefits recognized from the
net deferred tax asset to an amount that is more likely than not
to be realized based on the weight of all available evidence.
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. Although 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 increased due to the addition of new staff. Interest
expense increased due to the additional borrowings incurred in
conjunction with the NEG acquisition.
Revenues. Total revenues 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 crude oil sales
and was partially offset by lower revenues in our other segments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 52.0 Bcf in 2007 compared to 13.4 Bcf 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 revenues 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 our rigs operating on our properties
and an increase in our ownership interest in our natural gas and
crude oil properties.
Midstream and marketing revenues decreased $15.1 million,
or 12%, with revenues of $107.8 million for the year ended
December 31, 2007, compared to $122.9 million in 2006.
The NEG acquisition significantly decreased
49
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 revenues.
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 in 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 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 natural 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 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 also increased production. Our production
increased 320% to 64.2 Bcfe from 15.3 Bcfe in 2006.
The $24.2 million increase in DD&A for our other
assets 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 totaled
approximately $293.0 million.
General and administrative expenses increased 11% to
$61.8 million in 2007 from $55.6 million in 2006. The
increase was principally attributable to a $17.3 million
increase in corporate salaries and wages due to a significant
increase in corporate and support staff. As of December 31,
2007, we had 2,227 employees 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
50
$1.6 million decrease in stock compensation expense. 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. There were no general and administrative expenses
capitalized in 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 derivative contracts
compared to a $12.3 million gain ($1.9 million
unrealized loss and $14.2 million realized gain) in 2006.
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
December 31, 2006 or the various contract dates for
contracts entered into during 2007.
Other Income (Expense). Total net 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
|
|
$
|
4,694
|
|
|
$
|
991
|
|
|
$
|
3,703
|
|
|
|
373.7
|
%
|
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
|
%
|
Other income, net
|
|
|
729
|
|
|
|
118
|
|
|
|
611
|
|
|
|
517.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense, net
|
|
|
(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 $4.7 million in 2007 from
$1.0 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 repaid the senior bridge facility
and expensed the related unamortized debt issuance costs of
$12.5 million, which resulted in higher interest expense.
During the year ended December 31, 2007 we reported income
from equity investments of $4.4 million 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 treating plant, which experienced increased
profitability due to higher levels of utilization in 2007
compared to 2006. Approximately $1.5 million of the
increase was attributable to income from Larclay as all of
Larclays rigs had been delivered and all but one rig was
operational by December 31, 2007.
We reported income tax expense of $29.5 million for the
year ended December 31, 2007 compared to $6.2 million
in 2006. The 2007 income tax expense represented an effective
income tax rate of 37.0% compared to 28.5% in 2006. The lower
effective income tax rate in 2006 was attributable to favorable
percentage depletion deductions during that period.
Liquidity
and Capital Resources
Summary
Our operating cash flow is influenced mainly by the prices that
we receive for our natural gas and crude oil production; the
quantity of natural gas we produce and, to a lesser extent, the
quantity of crude oil we produce; the success of our development
and exploration activities; the demand for our drilling rigs and
oil field services and the
51
rates we receive for these services; and the margins we obtain
from our natural gas and
CO2
gathering and treating contracts.
Debt and equity capital markets experienced adverse conditions
during the latter part of 2008. Continued volatility in the
capital markets may increase costs associated with issuing debt
due to increased interest rates, and may affect our ability to
access these markets. Currently, we do not believe our liquidity
has been, or in the near future will be, materially affected by
recent events in the global financial markets. Nevertheless, we
continue to monitor events and circumstances surrounding each of
the 27 lenders under our senior credit facility. To date, the
only disruption in our ability to access the full amounts
available under our senior credit facility was the bankruptcy of
Lehman Brothers Commodity Services, Inc. (Lehman
Brothers), a lender responsible for 0.29% of the
obligations under our senior credit facility. We cannot predict
with any certainty the impact to us of any further disruptions
in the credit markets.
Our senior credit facility limits the amounts we can borrow to a
borrowing base amount, currently $1.1 billion. The
borrowing base is subject to review semi-annually; however, the
lenders reserve the right to have one additional
re-determination of the borrowing base per calendar year. We may
request up to two unscheduled re-determinations per year. The
borrowing base is determined based upon proved developed
producing reserves, proved developed non-producing reserves, and
proved undeveloped reserves. Our borrowing base is redetermined
in April and October of each year based on proved reserves. Our
ability to develop properties and changes in commodity prices
may affect the borrowing base of our senior credit facility.
On November 9, 2007, we completed the initial public
offering of our common stock. We sold 32,379,500 shares of
our common stock, including 4,170,000 shares sold directly
to an entity controlled by our Chief Executive Officer and
President. After deducting underwriting discounts of
approximately $44.0 million and offering expenses of
approximately $3.1 million, we 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
|
|
|
|
|
|
|
In May 2008, we privately placed $750.0 million of our
8.0% Senior Notes due 2018. We used $478.0 million of
the $735.0 million net proceeds received from the offering
to repay the total balance outstanding on our senior credit
facility. The remaining proceeds were used to fund a portion of
our capital expenditures for 2008.
As of December 31, 2008, our cash and cash equivalents were
$0.6 million, and we had approximately $494.0 million
available to be drawn, excluding amounts to be funded by Lehman
Brothers, under our senior credit facility based on a borrowing
base of $1.1 billion. Amounts outstanding under our senior
credit facility at December 31, 2008 totaled
$573.5 million. As of December 31, 2008, we had
approximately $2.4 billion in total debt outstanding. As of
February 20, 2009, the balance outstanding under our senior
credit facility was $565.3 million, and $502.2 million
was available to be drawn under our senior credit facility after
consideration of our $24.5 million in outstanding letters
of credit and excluding amounts to be funded by Lehman Brothers.
In January 2009, we completed a private placement of
2,650,000 shares of 8.5% convertible perpetual preferred
stock to qualified institutional buyers eligible under
Rule 144A under the Securities Act. The placement included
400,000 shares of convertible perpetual preferred stock
issued upon the full exercise of the initial purchasers
option to cover over-allotments. Net proceeds from the offering
were approximately $243.9 million after deducting offering
expenses of approximately $8.0 million. We used the net
proceeds of the offering to repay outstanding borrowings under
our senior credit facility and for general corporate purposes.
Based upon the current level of operations and anticipated
growth, we believe our cash flows from operations, current cash
and investments on hand, availability under our senior credit
facility, proceeds from our private offering of 8.5% convertible
perpetual preferred stock and anticipated proceeds from the sale
of our midstream assets located in the Piñon Field,
together with potential access to the credit markets, will be
sufficient to meet our
52
capital expenditures budget, debt service requirements and
working capital needs for the next 12 months. We have the
ability to reduce our capital expenditures budget if cash flows
are not available.
Capital
Expenditures
We dedicate and expect to continue to dedicate a substantial
portion of our capital expenditure program toward the
exploration, development, production and acquisition of natural
gas and crude oil reserves.
Our capital expenditures, on an accrual basis, by segment for
the past three years are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Capital Expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
1,909,078
|
|
|
$
|
1,046,552
|
|
|
$
|
170,872
|
|
Drilling and oil field services
|
|
|
52,869
|
|
|
|
123,232
|
|
|
|
89,810
|
|
Midstream gas services
|
|
|
160,460
|
|
|
|
63,828
|
|
|
|
16,975
|
|
Other
|
|
|
55,440
|
|
|
|
47,236
|
|
|
|
28,884
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, excluding acquisitions
|
|
|
2,177,847
|
|
|
|
1,280,848
|
|
|
|
306,541
|
|
Acquisitions
|
|
|
|
|
|
|
116,650
|
|
|
|
1,054,075
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,177,847
|
|
|
$
|
1,397,498
|
|
|
$
|
1,360,616
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For 2009, we have budgeted a range of $500.0 million to
$700.0 million for capital expenditures, excluding
acquisitions. 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. We may increase or decrease planned capital
expenditures depending on natural gas prices, asset sales and
the availability of capital through the issuance of additional
long-term debt or equity.
Working
Capital
Our working capital balance fluctuates as a result of the timing
and amount of borrowings or repayments under our credit
arrangements and changes in the fair value of our outstanding
commodity derivative instruments. Absent any significant effects
from our commodity derivative instruments, we typically have a
working capital deficit or a relatively small amount of positive
working capital because our capital spending generally exceeds
our cash flows from operations and we generally use excess cash,
when available, to pay down borrowings outstanding under our
credit arrangements.
We maintain access to funds that may be needed to meet capital
requirements through our senior credit facility. As of
December 31, 2008, we had approximately $494.0 million
available to be drawn under our senior credit facility,
excluding amounts to be funded by Lehman Brothers. At
December 31, 2008, we had a working capital deficit of
$46.7 million compared to a deficit of $5.7 million at
December 31, 2007. Current assets increased
$129.5 million at December 31, 2008, compared to
current assets at December 31, 2007, primarily due to a
$179.2 million increase in our current derivative contract
assets resulting from the decline in natural gas and crude oil
market prices compared to the contract prices. Current
liabilities increased $170.5 million primarily as a result
of an increase of $150.7 million in accounts payable.
53
Cash
Flows
Our cash flows are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Cash Flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows provided by operating activities
|
|
$
|
579,189
|
|
|
$
|
357,452
|
|
|
$
|
67,349
|
|
Cash flows used in investing activities
|
|
|
(1,909,443
|
)
|
|
|
(1,385,581
|
)
|
|
|
(1,340,567
|
)
|
Cash flows provided by financing activities
|
|
|
1,267,755
|
|
|
|
1,052,316
|
|
|
|
1,266,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
$
|
(62,499
|
)
|
|
$
|
24,187
|
|
|
$
|
(6,783
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities. Net cash provided by
operating activities for the years ended December 31, 2008
and 2007 were $579.2 million and $357.5 million,
respectively. The increase in cash provided by operating
activities from 2007 to 2008 was primarily due to our
$504.4 million increase in revenues as a result of our
57.9% increase in production volumes related to our drilling
activities during 2008. These increases were partially offset by
increases in midstream and marketing expenses and general and
administrative costs such as salaries and wages.
Cash flows provided by operating activities increased
$290.1 million to $357.5 million in 2007 from
$67.3 million in 2006 primarily due to our
$34.6 million increase in net income as a result of our
approximately 320% increase in production volumes related to 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.
Investing Activities. Cash flows used in
investing activities increased to $1,909.4 million during
2008 from $1,385.6 million in 2007 due to the expansion of
our capital expenditure program in 2008. During 2008, our
capital expenditures, excluding capital expenditures accrued at
December 31, 2008, were $1,818.7 million in our
exploration and production segment, $52.9 million for
drilling and oil field services, $131.4 million for
midstream gas services and $55.4 million for other capital
expenditures.
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 expanded 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.
Financing Activities. Since December 2005, we
have used equity issuances and borrowings to supplement our cash
flows from operations to fund our growth. Proceeds from
borrowings increased to $3,252.2 million for the year ended
December 31, 2008 compared to $1,331.5 million for
2007, mainly as a result of our issuance of $750.0 million
in 8.0% Senior Notes due 2018 in May 2008. We repaid
borrowings of approximately $1,944.5 million during 2008,
leaving net borrowings of approximately $1,307.7 million
for the year. Our financing activities provided
$1,267.8 million in cash for the year ended
December 31, 2008 compared to $1,052.3 million for the
year ended December 31, 2007.
During 2007, we raised $1,114.7 million 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.
54
Indebtedness
Senior Credit Facility. On November 21,
2006, we entered into a $750.0 million senior secured
revolving credit facility with Bank of America, N.A., as
administrative agent. The senior credit facility matures on
November 21, 2011 and is 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 bank group consists of 27 financial
institutions. The largest commitment from any lender in the
syndicate is 6.31% of the facility. The credit agreement for the
facility contains various covenants that limit our ability, and
the ability of certain of our subsidiaries 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 ability and
the ability of certain of our subsidiaries to incur additional
indebtedness with certain exceptions, including under the senior
notes (as discussed below).
On October 3, 2008, Lehman Brothers, a lender under our
senior credit facility, filed for bankruptcy. At the time that
its parent, Lehman Brothers Holdings, Inc., declared bankruptcy
on September 15, 2008, Lehman Brothers elected not to fund
its pro rata share, or 0.29%, of borrowings requested by us
under the senior credit facility. Accordingly, we do not
anticipate that Lehman Brothers will fund its pro rata share of
any future borrowing requests. We currently do not expect this
reduced availability of amounts under the senior credit facility
to impact our liquidity or business operations.
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), which may not exceed 4.5:1.0
calculated using the last four completed fiscal quarters,
(ii) 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) current ratio, which must be at least 1.0:1.0. In the
current ratio calculation, as defined in the senior credit
facility, any amounts available to be drawn under the senior
credit facility are included in current assets, and unrealized
assets and liabilities resulting from mark-to-market adjustments
on our derivative contracts are disregarded. As of
December 31, 2008, we were in compliance with all of the
financial covenants under the senior credit facility.
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 of our intercompany
debt; and substantially all of our assets, including proved
natural gas and crude oil reserves representing at least 80% of
the discounted present value (as defined in the senior credit
facility) of our proved natural gas and crude 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.
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 annual
interest rate paid on amounts outstanding under our senior
credit facility for the year ended December 31, 2008 was
3.82%.
The borrowing base of the senior credit facility is subject to
review semi-annually; however, the lenders reserve the right to
have one additional redetermination of the borrowing base per
calendar year. We also may request up to two unscheduled
redeterminations per year. The borrowing base is determined
based on proved developed producing reserves, proved developed
non-producing reserves and proved undeveloped reserves. The
borrowing base, as of December 31, 2008, was
$1.1 billion. As of December 31, 2008, we had total
outstanding indebtedness of $573.5 million under our senior
credit facility.
Other Indebtedness. We have financed a portion
of our drilling rig fleet and related oil field services
equipment through the issuance of notes secured by the
equipment. At December 31, 2008, the aggregate outstanding
balance of these notes was $33.0 million, with annual fixed
interest rates ranging from 7.64% to 8.67%. The notes have a
final maturity date of December 1, 2011 and require
aggregate monthly installments of
55
principal and interest in the amount of $1.2 million. The
notes have a prepayment penalty (currently ranging from 1% to
2%) that is triggered if we repay the notes prior to maturity.
On November 15, 2007, we entered into a $20.0 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. We purchased the property in July 2007 to serve
as our corporate headquarters. The mortgage bears interest at
6.08% per annum 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. We made payments of principal and interest on
this note totaling $0.8 million and $1.2 million,
respectively, during 2008.
We have financed the purchase of other equipment used in our
business. At December 31, 2006, the aggregate outstanding
balance on these financings was $4.5 million. We
substantially repaid such borrowings during July 2007.
8.625% Senior Term Loan and Senior Floating Rate Term
Loan. On March 22, 2007, we issued
$1.0 billion principal amount of unsecured senior term
loans. A portion of the proceeds of the senior term loans was
used to repay the senior bridge facility described below under
Senior Bridge Facility. The senior term
loans included both a floating rate tranche and fixed rate
tranche as described below.
The floating rate tranche consisted of a $350.0 million
senior term loan at a variable rate with interest payable
quarterly and principal due on April 1, 2014. The variable
rate term loan bore 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%.
The fixed rate tranche consisted of a $650.0 million senior
term loan at a fixed rate of 8.625% per annum with principal due
on April 1, 2015. Under the terms of the fixed rate term
loan, interest was payable quarterly and during the first four
years interest could be paid, at our option, either entirely in
cash or entirely with additional fixed rate term loans.
As discussed below, the senior term loans were exchanged
pursuant to the senior term loan credit agreement.
8.625% Senior Notes Due 2015 and Senior Floating Rate
Notes Due 2014. On May 1, 2008, we completed
an offer to exchange the senior term loans for senior unsecured
notes with registration rights, as required under the senior
term loan credit agreement. We issued $650.0 million of
8.625% Senior Notes due 2015 in exchange for an equal
outstanding principal amount of our fixed rate term loan and
$350.0 million of Senior Floating Rate Notes due 2014 in
exchange for an equal outstanding principal amount of our
variable rate term loan. The newly issued senior notes had terms
that were substantially identical to those of the exchanged
senior term loans. During the third quarter of 2008, we filed a
registration statement to enable holders of the notes to
exchange them for substantially identical notes that are
registered under the Securities Act. All unregistered notes had
been exchanged for registered notes by October 27, 2008.
In January 2008, we entered into a $350.0 million notional
amount interest rate swap agreement with a financial institution
that effectively fixed our interest rate on the variable rate
term loan at an annual rate of 6.26%. As a result of the
exchange of the variable rate term loan to Senior Floating Rate
Notes, the interest rate swap is now being used to fix the
variable LIBOR interest rate on the Senior Floating Rate Notes
at an annual rate of 6.26% through April 2011.
We may redeem some or all of the Senior Floating Rate Notes at
specified redemption prices on or after April 1, 2009 and
may redeem some or all of the 8.625% Senior Notes at
specified redemption prices on or after April 1, 2011.
We incurred $26.1 million of debt issuance costs in
connection with the senior term loans. As the senior term loans
were exchanged for senior unsecured notes with substantially
identical terms, the remaining unamortized debt issuance costs
of the senior term loans are being amortized over the term of
the 8.625% Senior Notes and the Senior Floating Rate Notes.
8.0% Senior Notes Due 2018. In May 2008,
we privately placed $750.0 million of our unsecured
8.0% Senior Notes due 2018. We used $478.0 million of
the $735.0 million net proceeds to repay the total balance
outstanding at that time on our senior credit facility. The
remaining proceeds were used to fund a portion of our 2008
capital
56
expenditure program. The notes bear interest at a fixed rate of
8.0% per annum, payable semi-annually, with the principal due on
June 1, 2018. The notes are redeemable, in whole or in
part, prior to their maturity at specified redemption prices.
The notes became freely tradable on November 17, 2008,
180 days after their issuance, pursuant to Rule 144
under the Securities Act.
We incurred $16.0 million of debt issuance costs in
connection with the 8.0% Senior Notes. These costs are
being amortized over the term of these notes.
Debt covenants under the 8.0% Senior Notes as well as the
8.625% Senior Notes and the Senior Floating Rate Notes
include financial covenants similar to those of the senior
credit facility. The covenants include limitations on the
incurrence of indebtedness, payment of dividends, asset sales,
certain asset purchases, transactions with related parties and
consolidation or merger agreements. As of December 31,
2008, we were in compliance with all of the covenants under all
of the senior notes.
Senior Bridge Facility. On November 21,
2006, we entered into an $850.0 million senior unsecured
bridge facility in conjunction with our acquisition of NEG. We
repaid this facility in full in March 2007 with proceeds from
our senior term loans.
Redeemable
Convertible Preferred Stock
Prior to the conversion of our redeemable convertible preferred
stock to common stock during 2008, each holder of our redeemable
convertible preferred stock was entitled to quarterly cash
dividends at the annual rate of 7.75% of the accreted value,
$210 per share, of their redeemable convertible preferred stock.
Each share of redeemable convertible preferred stock was
convertible into approximately 10.2 shares of common stock
at the option of the holder, subject to certain anti-dilution
adjustments.
During March 2008, holders of 339,823 shares of our
redeemable convertible preferred stock elected to convert those
shares into 3,465,593 shares of our common stock. In May
2008, we converted the remaining outstanding
1,844,464 shares of our redeemable convertible preferred
stock into 18,810,260 shares of our common stock as
permitted under the terms of the redeemable convertible
preferred stock. These conversions resulted in total charges to
retained earnings of $7.2 million in accelerated accretion
expense related to the converted redeemable convertible
preferred shares. We paid all dividends on our redeemable
convertible preferred stock in cash, including
$33.3 million in 2007 and $17.6 million in 2008. On
and after the conversion date, dividends ceased to accrue and
rights of common unit holders to exercise outstanding warrants
to purchase shares of redeemable convertible preferred stock
terminated.
Contractual
Obligations
A summary of our contractual obligations as of December 31,
2008 is provided in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
After
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2013
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Long-term debt
|
|
$
|
16,532
|
|
|
$
|
12,005
|
|
|
$
|
580,751
|
|
|
$
|
1,051
|
|
|
$
|
1,120
|
|
|
$
|
1,763,857
|
|
|
$
|
2,375,316
|
|
Interest on senior notes(1)
|
|
|
142,339
|
|
|
|
142,339
|
|
|
|
142,339
|
|
|
|
142,339
|
|
|
|
142,339
|
|
|
|
341,647
|
|
|
|
1,053,342
|
|
Firm transportation
|
|
|
22,810
|
|
|
|
36,195
|
|
|
|
31,320
|
|
|
|
31,406
|
|
|
|
25,392
|
|
|
|
84,688
|
|
|
|
231,811
|
|
Third-party drilling rig commitments(2)
|
|
|
15,832
|
|
|
|
1,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,066
|
|
Dispute settlement payments(3)
|
|
|
5,000
|
|
|
|
5,000
|
|
|
|
5,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,000
|
|
Asset retirement obligations
|
|
|
275
|
|
|
|
6,940
|
|
|
|
1,211
|
|
|
|
2,911
|
|
|
|
446
|
|
|
|
72,989
|
|
|
|
84,772
|
|
Operating leases and other
|
|
|
1,533
|
|
|
|
383
|
|
|
|
530
|
|
|
|
497
|
|
|
|
714
|
|
|
|
2,281
|
|
|
|
5,938
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
204,321
|
|
|
$
|
204,096
|
|
|
$
|
761,151
|
|
|
$
|
178,204
|
|
|
$
|
170,011
|
|
|
$
|
2,265,462
|
|
|
$
|
3,783,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Based on interest rates as of December 31, 2008. |
57
|
|
|
(2) |
|
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. |
|
(3) |
|
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 indicated. |
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 MMS requirements, 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. No escrow funds were
returned to us during 2008.
One of the escrow accounts requires 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 2008,
we deposited approximately $0.8 million in the escrow
account.
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 Note 1 Summary of
Organization and Significant Accounting Policies to the
consolidated financial statements included in Item 8 of
this report for a discussion of our significant accounting
policies.
Proved Reserves. Over 95% 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 crude oil that 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, 2008, 2007 and 2006, we revised
our proved reserves from prior years reports by
approximately 452.6 Bcfe, 351.6 Bcfe and
26.6 Bcfe, respectively, due to market prices at the end of
the applicable period or production performance indicating more
(or less) reserves in place or larger (or smaller) reservoir
size than initially estimated or additional proved reserve
bookings within the original field boundaries. 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 crude oil
properties. The accounting for our business is
subject to special accounting rules that are unique to the oil
and natural gas industry. There are two allowable methods of
accounting for oil and natural gas business activities: the
successful efforts method and the full cost method. We follow
the full cost method of accounting. All direct costs and certain
indirect costs associated with the acquisition, exploration and
development of natural gas and crude oil properties are
capitalized. Exploration and development
58
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 crude oil reserves. Amortization of natural gas
and crude oil properties is provided using the
unit-of-production method based on estimated proved natural gas
and crude oil reserves. Sales and abandonments of natural gas
and crude 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 crude 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.
Under the successful efforts method, geological and geophysical
costs and costs of carrying and retaining undeveloped properties
are charged to expense as incurred. Costs of drilling
exploratory wells that do not result in proved reserves are
charged to expense. Depreciation, depletion, amortization and
impairment of oil and natural gas properties are generally
calculated on a well by well or lease or field basis versus the
aggregated full cost pool basis. Additionally, gain
or loss is generally recognized on all sales of oil and natural
gas properties under the successful efforts method. As a result,
our financial statements will differ from companies that apply
the successful efforts method since we will generally reflect a
higher level of capitalized costs as well as a higher oil and
natural gas depreciation, depletion and amortization rate, and
we will not have exploration expenses that successful efforts
companies frequently have.
In accordance with full cost accounting rules, capitalized costs
are subject to a limitation. The capitalized cost of natural gas
and crude 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 natural gas and crude oil reserves,
discounted at 10% per annum, plus the lower of cost or fair
value of unproved properties, plus estimated salvage value, less
related tax effects (the ceiling limitation). The
full cost ceiling limitation is calculated using natural gas and
crude 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 the ceiling limitation, the excess must be charged to
expense. Once incurred, a write-down is not reversible at a
later date. At December 31, 2008, total capitalized costs
of our natural gas and crude oil properties exceeded our ceiling
limitation resulting in a non-cash ceiling impairment of
$1,855.0 million.
Unevaluated Properties. The balance of
unevaluated properties consists 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 six-year period from the date of acquisition, contingent on
our capital expenditures and drilling program.
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. Natural
gas and crude oil revenues are recorded when title passes to the
customer, net of royalties, discounts and allowances, as
applicable. We account for natural gas and crude oil
59
production imbalances using the sales method, whereby we
recognize revenue on all natural gas and crude oil sold to our
customers notwithstanding the fact that its ownership may be
less than 100% of the natural gas and crude oil sold.
Liabilities are recorded for imbalances greater than our
proportionate share of remaining estimated natural gas and crude
oil 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 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
these contracts typically ranges 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, 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
typically range 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
collectability 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 treating 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 reflected in
operations.
Income Taxes. Deferred income taxes are
recorded for temporary differences between financial statement
and income tax bases. 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.
As of December 31, 2008, we had recorded a full valuation
allowance against our net deferred tax asset. Our deferred tax
position changed from a net deferred tax liability as of
December 31, 2007 to a net deferred tax asset as of
December 31, 2008 due to the recording of a full cost
ceiling impairment of $1,855.0 million. The valuation
60
allowance serves to reduce the tax benefits recognized from the
net deferred tax asset to an amount that is more likely than not
to be realized based on the weight of all available evidence.
Derivative Financial Instruments. To manage
risks related to increases in interest rates and changes in
natural gas and crude oil prices, we enter into interest rate
swaps and natural gas and crude oil futures contracts.
We recognize all of our derivative contracts as either assets or
liabilities at fair value. The accounting for changes in the
fair value (i.e., gains or losses) of a derivative contract
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 contracts 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 contracts not
designated as hedging instruments, the gain or loss is
recognized in current earnings during the period of change. None
of our derivatives was designated as a hedging instrument during
2008, 2007 and 2006.
New
Accounting Pronouncements
For a discussion of recently adopted accounting standards, see
Note 1 to our consolidated financial statements included in
Item 8 of this report.
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 within the meaning of
Section 27A of the Securities Act and Section 21E of
the Securities Exchange Act of 1934, as amended (the
Exchange Act). These forward-looking statements may
include projections and estimates concerning 2009 capital
expenditures, our liquidity and capital resources, the timing
and success of specific projects, outcomes and effects of
litigation, claims and disputes, elements of our business
strategy and other statements concerning our operations,
economic performance and financial condition. 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.
We have based these forward-looking statements on our current
expectations and assumptions about future events. These
statements are based on certain assumptions and analyses made by
us in light of our experience and our perception of historical
trends, current conditions and expected future developments as
well as other factors we believe are appropriate under the
circumstances. The forward-looking statements in this report
speak only as of the date of this report; we disclaim any
obligation to update or revise these statements unless required
by securities law, and we caution you not to rely on them
unduly. While our management considers these expectations and
assumptions to be reasonable, they are inherently subject to
significant business, economic, competitive, regulatory and
other risks, contingencies and uncertainties relating to, among
other matters, the risks discussed in Risk Factors
in Item 1A of this report including the following:
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|
|
|
|
the volatility of natural gas and crude oil prices;
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|
|
|
uncertainties in estimating natural gas and crude oil reserves;
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|
|
|
the need to replace the natural gas and crude 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 crude 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;
|
|
|
|
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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61
|
|
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|
|
limitations of seismic data;
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|
|
risks associated with drilling natural gas and crude oil wells;
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|
availability of satisfactory natural gas and crude 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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competition in the oil and gas industry;
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|
general economic conditions, either internationally or
domestically or in the jurisdictions in which we operate;
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|
costs to comply with current and future governmental regulation
of the oil and gas 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
|
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 actual delivery
of a commodity quantity to satisfy settlement.
Commodity Price Risk. Our most significant
market risk relates to the prices we receive for our natural gas
and crude oil production. For example, crude oil prices have
declined from a record high of $147.55 per barrel in July 2008
to approximately $33.87 per barrel in December 2008. Meanwhile,
natural gas futures prices during 2008 ranged from as high as
$14.27 per Mcf in July 2008 to as low as $5.29 per Mcf in
December 2008. In light of the historical volatility of these
commodities, we periodically have entered into, and expect in
the future to enter into, derivative arrangements aimed at
reducing the variability of natural gas and crude oil prices we
receive for our production. From time to time, we enter into
commodity pricing derivative contracts for a portion of our
anticipated production volumes depending upon managements
view of opportunities under the then current market conditions.
We do not intend to enter into derivative contracts 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 derivative transactions to 85% of
expected production volumes from estimated proved reserves.
Future credit agreements could require a minimum level of
commodity price hedging.
The use of derivative contracts also involves the risk that the
counterparties will be unable to meet their obligations under
the contracts. Our derivative contracts are with multiple
counterparties to minimize our exposure to any individual
counterparty. We currently have seventeen approved derivative
counterparties, sixteen of which are lenders under our senior
credit facility. We currently have derivative contracts
outstanding with twelve of these counterparties. We have no
derivative contracts in 2009 and beyond with counterparties
outside of those that are also part of our senior credit
facility. Lehman Brothers is a counterparty on one of our
derivative contracts. Due to the bankruptcy of Lehman Brothers
and its parent, Lehman Brothers Holdings, Inc., we did not
assign any value to this derivative contract (notional of
7,300 MMcf) at December 31, 2008.
We use, and may continue to use, a variety of commodity-based
derivative contracts, including collars, fixed-price swaps and
basis protection swaps. Our fixed price swap transactions are
settled based upon NYMEX prices, and our basis protection swap
transactions are settled based upon the index price of natural
gas at the Waha hub, a West Texas gas marketing and delivery
center. Settlement for natural gas derivative contracts occurs
in the production month.
While we believe that the natural gas and crude 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
62
as hedges for accounting purposes. We record all derivative
contracts on the balance sheet at fair value, which reflects
changes in natural gas and crude oil prices. We establish fair
value of our derivative contracts by price quotations obtained
from counterparties to the derivative contracts. Changes in fair
values of our derivative contracts 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 contracts. Changes
in fair value are principally measured based on period-end
prices compared to the contract price.
At December 31, 2008, our open natural gas and crude oil
commodity derivative contracts consisted of the following:
Natural
Gas
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Notional
|
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|
Weighted Avg.
|
|
Period and Type of Contract
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|
(MMcf)(1)
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Fixed Price
|
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|
January 2009 March 2009
|
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Price swap contracts
|
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20,700
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|
|
$
|
9.14
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|
Basis swap contracts
|
|
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15,300
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|
$
|
(0.74
|
)
|
April 2009 June 2009
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|
|
|
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|
Price swap contracts
|
|
|
20,930
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|
$
|
7.96
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|
Basis swap contracts
|
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|
15,470
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|
$
|
(0.74
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)
|
July 2009 September 2009
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|
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|
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Price swap contracts
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18,710
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|
$
|
8.09
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Basis swap contracts
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15,640
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|
$
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(0.74
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)
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October 2009 December 2009
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Price swap contracts
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18,400
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|
$
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8.54
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|
Basis swap contracts
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15,640
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|
$
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(0.74
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)
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January 2010 March 2010
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Price swap contracts
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16,875
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$
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8.08
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Basis swap contracts
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14,400
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|
$
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(0.73
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)
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April 2010 June 2010
|
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|
|
|
|
|
|
|
Price swap contracts
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17,063
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|
|
$
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7.38
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Basis swap contracts
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14,560
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|
|
$
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(0.73
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)
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July 2010 September 2010
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|
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Price swap contracts
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17,250
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$
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7.61
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Basis swap contracts
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14,720
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$
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(0.73
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)
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October 2010 December 2010
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|
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Price swap contracts
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17,250
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$
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8.03
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Basis swap contracts
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14,720
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$
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(0.73
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)
|
January 2011 March 2011
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|
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Basis swap contracts
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1,350
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$
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(0.47
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)
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April 2011 June 2011
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|
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Basis swap contracts
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1,365
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$
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(0.47
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)
|
July 2011 September 2011
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|
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|
|
|
|
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Basis swap contracts
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1,380
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$
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(0.47
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)
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October 2011 December 2011
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Basis swap contracts
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1,380
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$
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(0.47
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)
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(1) |
|
Assumes ratio of 1:1 for Mcf to MMBtu and excludes a total
notional of 7,300 MMcf from 2009 for the Lehman
Brothers basis swap contract. |
63
Crude
Oil
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Notional
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Weighted Avg.
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Period and Type of Contract
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(in MBbls)
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Fixed Price
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January 2009 March 2009
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Price swap contracts
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45
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$
|
126.38
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|
April 2009 June 2009
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|
|
|
|
|
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Price swap contracts
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46
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$
|
126.71
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July 2009 September 2009
|
|
|
|
|
|
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|
Price swap contracts
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|
46
|
|
|
$
|
126.61
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|
October 2009 December 2009
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|
|
|
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Price swap contracts
|
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46
|
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|
$
|
126.51
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The following table summarizes the cash settlements and
valuation gains and losses on our commodity derivative contracts
for the years ended December 31, 2008, 2007 and 2006 (in
thousands):
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2008
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2007
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2006
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Realized loss (gain)
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|
$
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12,981
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|
|
$
|
(34,494
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)
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|
$
|
(14,169
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)
|
Unrealized (gain) loss
|
|
|
(224,420
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)
|
|
|
(26,238
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)
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|
1,878
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|
|
|
|
|
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|
|
|
|
|
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|
Gain on derivative contracts
|
|
$
|
(211,439
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)
|
|
$
|
(60,732
|
)
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|
$
|
(12,291
|
)
|
|
|
|
|
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|
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Credit Risk. Credit risk relates to the risk
of loss as a result of non-performance by one or more of our
counterparties under any of our credit arrangements. Recently,
the ability of certain investment banks and other financial
institutions to meet their financial obligations has been of
increasing concern. A portion of our liquidity is concentrated
in derivative contracts that enable us to mitigate a portion of
our exposure to natural gas and crude oil prices and interest
rate volatility. We periodically review the credit quality of
each counterparty to our derivative contracts and the level of
financial exposure we have to each counterparty to limit our
credit risk exposure with respect to these contracts.
Additionally, we apply a credit default risk rating factor for
our counterparties in determining the fair value of our
derivative contracts.
Our ability to fund our capital expenditure budget is partially
dependent upon the availability of funds under our senior credit
facility. In order to mitigate the credit risk associated with
individual financial institutions committed to participate in
our senior credit facility, our bank group consists of 27
financial institutions with commitments ranging from 0.25% to
6.31%. Lehman Brothers, a lender under our senior credit
facility, declared bankruptcy on October 3, 2008. As a
result of the bankruptcy of Lehman Brothers and its parent
company, Lehman Brothers Holdings, Inc., on September 15,
2008, Lehman Brothers elected not to fund its pro rata share, or
0.29%, of borrowings requested by us under the facility.
Although we do not currently expect this reduced availability of
amounts under the senior credit facility to impact our liquidity
or business operations, the inability of one or more of our
other lenders to fund their obligations under the facility could
have a material adverse effect on our financial condition.
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 to (i) changes
in market interest rates reflected in the fair value of the debt
and (ii) 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.
We use sensitivity analysis to determine the impact that market
risk exposures may have on our variable interest rate
borrowings. Based on the $350.0 million outstanding balance
of our Senior Floating Rate Notes at December 31, 2008, a
one percent change in the applicable rates, with all other
variables held constant, would have resulted in a change in our
interest expense of approximately $3.5 million for the year
ended December 31, 2008.
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 agreement. In
January 2008, we entered into a
64
$350.0 million notional amount interest rate swap agreement
with a financial institution that effectively fixed our interest
rate on the variable rate term loan for the period from
April 1, 2008 through April 1, 2011. As a result of
the exchange of the variable rate term loan to Senior Floating
Rate Notes, the interest rate swap is being used to fix the
variable LIBOR interest rate on the Senior Floating Rate Notes
at 6.26% through April 2011. This swap has not been designated
as a hedge.
An unrealized loss of $8.7 million was recorded in interest
expense in the consolidated statement of operations for the
change in fair value of the interest rate swap for the year
ended December 31, 2008.
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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.
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Item 9.
|
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure
|
Not applicable.
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|
Item 9A.
|
Controls
and Procedures
|
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
Rule 13a-15(b)
under the Exchange Act 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.
Managements Report on Internal Control over Financial
Reporting and Report of Independent Registered Public Accounting
Firm. The information required to be furnished
pursuant to this item is set forth under the captions
Managements Report on Internal Control over
Financial Reporting and Report of Independent
Registered Public Accounting Firm in Item 8 of this
report.
Changes in Internal Control over Financial
Reporting. There were no changes in our internal
control over financial reporting during the quarter ended
December 31, 2008 that have materially affected, or are
reasonably likely to materially affect, our internal control
over financial reporting.
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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 the following sections of our definitive proxy
statement, which will be filed no later than April 30,
2009: Director Biographical Information,
Executive Officers, Compliance with
Section 16(a) of the Exchange Act and Corporate
Governance Matters.
|
|
Item 11.
|
Executive
Compensation
|
The information required by this item is incorporated herein by
reference to the following sections of our definitive proxy
statement, which will be filed no later than April 30,
2009: Director Compensation, Outstanding
Equity Awards and Executive Officers and
Compensation.
65
|
|
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 the following sections of our definitive proxy
statement, which will be filed no later than April 30,
2009: Equity Compensation Plan Information and
Security Ownership of Certain Beneficial Owners and
Management.
|
|
Item 13.
|
Certain
Relationships and Related Transactions and Director
Independence
|
The information required by this item is incorporated herein by
reference to the following sections of our definitive proxy
statement, which will be filed no later than April 30,
2009: Related Party Transactions and Corporate
Governance Matters.
|
|
Item 14.
|
Principal
Accountant Fees and Services
|
The information required by this item is incorporated herein by
reference to the section captioned Ratification of
Selection of Independent Registered Public Accounting Firm
in our definitive proxy statement, which will be filed no later
than April 30, 2009.
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.
66
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
Page(s)
|
|
|
|
|
F-2
|
|
|
|
|
F-3
|
|
|
|
|
F-4
|
|
|
|
|
F-5
|
|
|
|
|
F-6
|
|
|
|
|
F-7
|
|
|
|
|
F-8
|
|
F-1
Managements
Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining
adequate internal control over financial reporting as defined in
Rule 13a-15(f)
under the Exchange Act. Under the supervision and with the
participation of our management, including our Chief Executive
Officer and Chief Financial Officer, we conducted an evaluation
of the effectiveness of our internal control over financial
reporting based on the framework established in Internal
Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway
Commission. Because of its inherent limitations, internal
control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies and
procedures may deteriorate.
Based on our evaluation under the framework established in
Internal Control Integrated Framework, our
management concluded, that as of December 31, 2008, our
internal control over financial reporting was effective.
The effectiveness of our internal control over financial
reporting as of December 31, 2008 has been audited by
PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report that follows.
|
|
|
/s/ Tom
L. Ward
Tom
L. Ward
President and Chief Executive Officer
|
|
/s/ Dirk
M. Van Doren
Dirk
M. Van Doren
Executive Vice President and Chief Financial Officer
|
F-2
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, 2008 and
2007, and the results of their operations and their cash flows
for each of the three years in the period ended
December 31, 2008 in conformity with accounting principles
generally accepted in the United States of America. Also in our
opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of
December 31, 2008, based on criteria established in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). The Companys management is responsible
for these financial statements, for maintaining effective
internal control over financial reporting and for its assessment
of the effectiveness of internal control over financial
reporting, included in the accompanying Managements
Report on Internal Control Over Financial Reporting. Our
responsibility is to express opinions on these financial
statements and on the Companys internal control over
financial reporting based on our audits (which was an integrated
audit in 2008). We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether
the financial statements are free of material misstatement and
whether effective internal control over financial reporting was
maintained in all material respects. Our audits of the financial
statements included 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. Our audit of internal
control over financial reporting included obtaining an
understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audits also
included performing such other procedures as we considered
necessary in the circumstances. We believe that our audits
provide a reasonable basis for our opinions.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of
management and directors of the company; and (iii) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers
LLP
PricewaterhouseCoopers LLP
Houston, Texas
February 26, 2009
F-3
SandRidge
Energy, Inc. and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
636
|
|
|
$
|
63,135
|
|
Accounts receivable, net:
|
|
|
|
|
|
|
|
|
Trade
|
|
|
102,746
|
|
|
|
94,741
|
|
Related parties
|
|
|
6,327
|
|
|
|
20,018
|
|
Derivative contracts
|
|
|
201,111
|
|
|
|
21,958
|
|
Inventories
|
|
|
3,686
|
|
|
|
3,993
|
|
Deferred income taxes
|
|
|
|
|
|
|
1,820
|
|
Other current assets
|
|
|
41,407
|
|
|
|
20,787
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
355,913
|
|
|
|
226,452
|
|
Natural gas and crude oil properties, using full cost method of
accounting
|
|
|
|
|
|
|
|
|
Proved
|
|
|
4,676,072
|
|
|
|
2,848,531
|
|
Unproved
|
|
|
215,698
|
|
|
|
259,610
|
|
Less: accumulated depreciation, depletion and impairment
|
|
|
(2,369,840
|
)
|
|
|
(230,974
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
2,521,930
|
|
|
|
2,877,167
|
|
|
|
|
|
|
|
|
|
|
Other property, plant and equipment, net
|
|
|
653,629
|
|
|
|
460,243
|
|
Derivative contracts
|
|
|
45,537
|
|
|
|
270
|
|
Investments
|
|
|
6,088
|
|
|
|
7,956
|
|
Restricted deposits
|
|
|
32,843
|
|
|
|
31,660
|
|
Other assets
|
|
|
39,118
|
|
|
|
26,818
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,655,058
|
|
|
$
|
3,630,566
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
16,532
|
|
|
$
|
15,350
|
|
Accounts payable and accrued expenses:
|
|
|
|
|
|
|
|
|
Trade
|
|
|
366,337
|
|
|
|
215,497
|
|
Related parties
|
|
|
230
|
|
|
|
395
|
|
Derivative contracts
|
|
|
5,106
|
|
|
|
|
|
Asset retirement obligation
|
|
|
275
|
|
|
|
864
|
|
Billings in excess of costs incurred
|
|
|
14,144
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
402,624
|
|
|
|
232,106
|
|
Long-term debt
|
|
|
2,358,784
|
|
|
|
1,052,299
|
|
Other long-term obligations
|
|
|
11,963
|
|
|
|
16,817
|
|
Derivative contracts
|
|
|
3,639
|
|
|
|
|
|
Asset retirement obligation
|
|
|
84,497
|
|
|
|
57,716
|
|
Deferred income taxes
|
|
|
|
|
|
|
49,350
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
2,861,507
|
|
|
|
1,408,288
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 18)
|
|
|
|
|
|
|
|
|
Minority interest
|
|
|
30
|
|
|
|
4,672
|
|
Redeemable convertible preferred stock, $0.001 par value,
2,625 shares authorized; no shares issued and outstanding
at December 31, 2008 and 2,184 shares issued and
outstanding at December 31, 2007
|
|
|
|
|
|
|
450,715
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value; 47,375 shares
authorized; no shares issued and outstanding in 2008 and 2007
|
|
|
|
|
|
|
|
|
Common stock, $0.001 par value, 400,000 shares
authorized; 167,372 issued and 166,046 outstanding at
December 31, 2008 and 143,299 issued and 141,843
outstanding at December 31, 2007
|
|
|
163
|
|
|
|
140
|
|
Additional paid-in capital
|
|
|
2,170,986
|
|
|
|
1,686,113
|
|
Treasury stock, at cost
|
|
|
(19,332
|
)
|
|
|
(18,578
|
)
|
(Accumulated deficit) retained earnings
|
|
|
(1,358,296
|
)
|
|
|
99,216
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
793,521
|
|
|
|
1,766,891
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
3,655,058
|
|
|
$
|
3,630,566
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
SandRidge
Energy, Inc. and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and crude oil
|
|
$
|
908,689
|
|
|
$
|
477,612
|
|
|
$
|
101,252
|
|
Drilling and services
|
|
|
47,199
|
|
|
|
73,197
|
|
|
|
139,049
|
|
Midstream and marketing
|
|
|
207,602
|
|
|
|
107,765
|
|
|
|
122,896
|
|
Other
|
|
|
18,324
|
|
|
|
18,878
|
|
|
|
25,045
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
1,181,814
|
|
|
|
677,452
|
|
|
|
388,242
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
159,004
|
|
|
|
106,192
|
|
|
|
35,149
|
|
Production taxes
|
|
|
30,594
|
|
|
|
19,557
|
|
|
|
4,654
|
|
Drilling and services
|
|
|
26,186
|
|
|
|
44,211
|
|
|
|
98,436
|
|
Midstream and marketing
|
|
|
186,655
|
|
|
|
94,253
|
|
|
|
115,076
|
|
Depreciation, depletion and amortization natural gas
and crude oil
|
|
|
290,917
|
|
|
|
173,568
|
|
|
|
26,321
|
|
Depreciation, depletion and amortization other
|
|
|
70,448
|
|
|
|
53,541
|
|
|
|
29,305
|
|
Impairment
|
|
|
1,867,497
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
109,372
|
|
|
|
61,780
|
|
|
|
55,634
|
|
Gain on derivative contracts
|
|
|
(211,439
|
)
|
|
|
(60,732
|
)
|
|
|
(12,291
|
)
|
Gain on sale of assets
|
|
|
(9,273
|
)
|
|
|
(1,777
|
)
|
|
|
(1,023
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
2,519,961
|
|
|
|
490,593
|
|
|
|
351,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from operations
|
|
|
(1,338,147
|
)
|
|
|
186,859
|
|
|
|
36,981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
3,569
|
|
|
|
4,694
|
|
|
|
991
|
|
Interest expense
|
|
|
(147,027
|
)
|
|
|
(117,185
|
)
|
|
|
(16,904
|
)
|
Minority interest
|
|
|
(855
|
)
|
|
|
276
|
|
|
|
(296
|
)
|
Income from equity investments
|
|
|
1,398
|
|
|
|
4,372
|
|
|
|
967
|
|
Other income, net
|
|
|
1,454
|
|
|
|
729
|
|
|
|
118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other (expense) income
|
|
|
(141,461
|
)
|
|
|
(107,114
|
)
|
|
|
(15,124
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income tax (benefit) expense
|
|
|
(1,479,608
|
)
|
|
|
79,745
|
|
|
|
21,857
|
|
Income tax (benefit) expense
|
|
|
(38,328
|
)
|
|
|
29,524
|
|
|
|
6,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
|
(1,441,280
|
)
|
|
|
50,221
|
|
|
|
15,621
|
|
Preferred stock dividends and accretion
|
|
|
16,232
|
|
|
|
39,888
|
|
|
|
3,967
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss applicable) income available to common stockholders
|
|
$
|
(1,457,512
|
)
|
|
$
|
10,333
|
|
|
$
|
11,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(9.26
|
)
|
|
$
|
0.46
|
|
|
$
|
0.21
|
|
Preferred stock dividends
|
|
|
(0.10
|
)
|
|
|
(0.37
|
)
|
|
|
(0.05
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted (loss) income per share (applicable) available
to common stockholders
|
|
$
|
(9.36
|
)
|
|
$
|
0.09
|
|
|
$
|
0.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
155,619
|
|
|
|
108,828
|
|
|
|
73,727
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
155,619
|
|
|
|
110,041
|
|
|
|
74,664
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
SandRidge
Energy, Inc. and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
Earnings
|
|
|
|
|
|
|
Common
|
|
|
Paid-In
|
|
|
Deferred
|
|
|
Treasury
|
|
|
(Accumulated
|
|
|
|
|
|
|
Stock
|
|
|
Capital
|
|
|
Compensation
|
|
|
Stock
|
|
|
Deficit)
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
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
|
|
Accretion on redeemable convertible preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(157
|
)
|
|
|
(157
|
)
|
Purchase of treasury shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(500
|
)
|
|
|
|
|
|
|
(500
|
)
|
Stock-based compensation
|
|
|
|
|
|
|
8,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,792
|
|
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 plans
|
|
|
|
|
|
|
379
|
|
|
|
|
|
|
|
917
|
|
|
|
|
|
|
|
1,296
|
|
Stock-based compensation
|
|
|
|
|
|
|
7,202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,202
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,221
|
|
|
|
50,221
|
|
Redeemable convertible preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(42,277
|
)
|
|
|
(42,277
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
140
|
|
|
|
1,686,113
|
|
|
|
|
|
|
|
(18,578
|
)
|
|
|
99,216
|
|
|
|
1,766,891
|
|
Accretion on redeemable convertible preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,636
|
)
|
|
|
(7,636
|
)
|
Conversion of redeemable convertible preferred stock to common
stock
|
|
|
23
|
|
|
|
458,328
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
458,351
|
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,553
|
)
|
|
|
|
|
|
|
(3,553
|
)
|
Common stock issued under retirement plans
|
|
|
|
|
|
|
3,167
|
|
|
|
|
|
|
|
2,799
|
|
|
|
|
|
|
|
5,966
|
|
Stock-based compensation
|
|
|
|
|
|
|
18,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,784
|
|
Stock-based compensation excess tax benefit
|
|
|
|
|
|
|
4,594
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,594
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,441,280
|
)
|
|
|
(1,441,280
|
)
|
Redeemable convertible preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,596
|
)
|
|
|
(8,596
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
$
|
163
|
|
|
$
|
2,170,986
|
|
|
$
|
|
|
|
$
|
(19,332
|
)
|
|
$
|
(1,358,296
|
)
|
|
$
|
793,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-6
SandRidge
Energy, Inc. and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,441,280
|
)
|
|
$
|
50,221
|
|
|
$
|
15,621
|
|
Adjustments to reconcile net (loss) income to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for doubtful accounts
|
|
|
1,748
|
|
|
|
|
|
|
|
2,528
|
|
Depreciation, depletion and amortization
|
|
|
361,365
|
|
|
|
227,109
|
|
|
|
55,626
|
|
Impairment
|
|
|
1,867,497
|
|
|
|
|
|
|
|
|
|
Debt issuance cost amortization
|
|
|
5,623
|
|
|
|
15,998
|
|
|
|
299
|
|
Deferred income taxes
|
|
|
(47,530
|
)
|
|
|
28,923
|
|
|
|
348
|
|
Provision for inventory obsolescence
|
|
|
|
|
|
|
203
|
|
|
|
|
|
Unrealized (gain) loss on derivative contracts
|
|
|
(215,675
|
)
|
|
|
(26,238
|
)
|
|
|
1,878
|
|
Gain on sale of assets
|
|
|
(9,273
|
)
|
|
|
(1,777
|
)
|
|
|
(1,023
|
)
|
Interest income restricted deposits
|
|
|
(402
|
)
|
|
|
(1,354
|
)
|
|
|
(151
|
)
|
Income from equity investments
|
|
|
(1,398
|
)
|
|
|
(4,372
|
)
|
|
|
(956
|
)
|
Stock-based compensation
|
|
|
18,784
|
|
|
|
7,202
|
|
|
|
8,792
|
|
Minority interest
|
|
|
855
|
|
|
|
(276
|
)
|
|
|
296
|
|
Changes in operating assets and liabilities increasing
(decreasing) cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
3,735
|
|
|
|
(19,061
|
)
|
|
|
(2,648
|
)
|
Inventories
|
|
|
307
|
|
|
|
(1,730
|
)
|
|
|
(938
|
)
|
Other current assets
|
|
|
(20,603
|
)
|
|
|
12,374
|
|
|
|
(22,238
|
)
|
Other assets and liabilities, net
|
|
|
127
|
|
|
|
(5,069
|
)
|
|
|
(2,131
|
)
|
Accounts payable and accrued expenses
|
|
|
41,165
|
|
|
|
75,299
|
|
|
|
12,046
|
|
Billings in excess of costs
|
|
|
14,144
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
579,189
|
|
|
|
357,452
|
|
|
|
67,349
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures for property, plant and equipment
|
|
|
(2,058,415
|
)
|
|
|
(1,280,848
|
)
|
|
|
(306,541
|
)
|
Acquisitions of assets, net of cash received of $0, $0 and
$21,100
|
|
|
|
|
|
|
(116,650
|
)
|
|
|
(1,054,075
|
)
|
Proceeds from sale of assets
|
|
|
158,781
|
|
|
|
9,034
|
|
|
|
19,742
|
|
Proceeds from sale of investments
|
|
|
|
|
|
|
|
|
|
|
2,373
|
|
Contributions on equity investments
|
|
|
(1,528
|
)
|
|
|
|
|
|
|
(3,388
|
)
|
Loans to equity investee
|
|
|
(7,500
|
)
|
|
|
|
|
|
|
|
|
Refunds of restricted deposits
|
|
|
|
|
|
|
10,328
|
|
|
|
|
|
Fundings of restricted deposits
|
|
|
(781
|
)
|
|
|
(7,445
|
)
|
|
|
(1,051
|
)
|
Restricted cash
|
|
|
|
|
|
|
|
|
|
|
2,373
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(1,909,443
|
)
|
|
|
(1,385,581
|
)
|
|
|
(1,340,567
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from borrowings
|
|
|
3,252,209
|
|
|
|
1,331,541
|
|
|
|
1,261,910
|
|
Repayments of borrowings
|
|
|
(1,944,542
|
)
|
|
|
(1,332,219
|
)
|
|
|
(518,870
|
)
|
Dividends paid-preferred
|
|
|
(17,552
|
)
|
|
|
(33,321
|
)
|
|
|
|
|
Minority interest distributions
|
|
|
(5,497
|
)
|
|
|
(144
|
)
|
|
|
(618
|
)
|
Proceeds from issuance of common stock
|
|
|
|
|
|
|
1,114,660
|
|
|
|
100,776
|
|
Proceeds from issuance of redeemable convertible preferred stock
|
|
|
|
|
|
|
|
|
|
|
439,486
|
|
Stock-based compensation excess tax benefit
|
|
|
4,594
|
|
|
|
|
|
|
|
|
|
Purchase of treasury stock
|
|
|
(3,553
|
)
|
|
|
(1,661
|
)
|
|
|
(500
|
)
|
Debt issuance costs
|
|
|
(17,904
|
)
|
|
|
(26,540
|
)
|
|
|
(15,749
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
1,267,755
|
|
|
|
1,052,316
|
|
|
|
1,266,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
|
|
|
(62,499
|
)
|
|
|
24,187
|
|
|
|
(6,783
|
)
|
CASH AND CASH EQUIVALENTS, beginning of year
|
|
|
63,135
|
|
|
|
38,948
|
|
|
|
45,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, end of year
|
|
$
|
636
|
|
|
$
|
63,135
|
|
|
$
|
38,948
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosure of Cash Flow Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest, net of amounts capitalized
|
|
$
|
131,183
|
|
|
$
|
83,567
|
|
|
$
|
15,079
|
|
Cash paid for income taxes
|
|
|
2,191
|
|
|
|
2,371
|
|
|
|
1,599
|
|
Supplemental Disclosure of Noncash Investing and Financing
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued capital expenditures
|
|
$
|
119,432
|
|
|
$
|
|
|
|
$
|
|
|
Redeemable convertible preferred stock dividends, net of
dividends paid
|
|
|
|
|
|
|
8,956
|
|
|
|
|
|
Insurance premium financed
|
|
|
|
|
|
|
1,496
|
|
|
|
5,023
|
|
Accretion on redeemable convertible preferred stock
|
|
|
7,636
|
|
|
|
1,421
|
|
|
|
157
|
|
Common stock issued in connection with acquisitions
|
|
|
|
|
|
|
|
|
|
|
236,284
|
|
Assumption of restricted deposits and notes payable in
connection with acquisition
|
|
|
|
|
|
|
|
|
|
|
313,628
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-7
SandRidge
Energy, Inc. and Subsidiaries
|
|
1.
|
Summary
of Significant Accounting Policies
|
Nature of Business. SandRidge Energy, Inc.
(successor to Riata Energy, Inc.) and its subsidiaries
(collectively, the Company or SandRidge)
is an independent natural gas and oil company concentrating on
exploration, development and production activities. The Company
also owns and operates natural gas gathering and treating
facilities and
CO2
treating and transportation facilities and has marketing and
tertiary oil recovery operations. In addition, Lariat Services,
Inc. (Lariat), a wholly owned subsidiary, owns and
operates drilling rigs and a related oil field services
business. The Companys primary exploration, development
and production areas are concentrated in West Texas. The Company
also operates interests in the Mid-Continent, the Cotton Valley
Trend in East Texas, the Gulf Coast and the Gulf of Mexico.
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 to prior period financial statements to conform
to 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 natural gas and crude oil 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 natural gas and crude oil 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
exploration 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 natural gas and crude oil, each of which depend on numerous
factors beyond the Companys control such as economic
conditions, regulatory developments and competition from other
energy sources. The energy markets historically have been
volatile and natural gas and crude oil prices may be subject to
significant fluctuations in the future. A substantial or
extended decline in natural gas and crude oil prices could have
a material adverse effect on the Companys financial
position, results of operations, cash flows and quantities of
natural gas and crude oil 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 as these
instruments are readily convertible to known amounts of cash and
bear insignificant risk of changes in value due to their short
maturity period.
Accounts Receivable, Net. The Company has
receivables for sales of natural gas, crude oil and natural gas
liquids, as well as receivables related to the exploration and
treating services for natural gas, crude oil and natural gas
liquids. Management has established an allowance for doubtful
accounts. The allowance is evaluated by management and is based
on managements review of the collectability 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.
F-8
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Investments. Investments in affiliated
companies are accounted for under the equity method in
circumstances where the Company is deemed to exercise
significant influence over the operating and investing policies
of the investee but does not have control. Under the equity
method, the Company recognizes its share of the investees
earnings in its consolidated statements of operations.
Investments in affiliated companies not accounted for under the
equity method are accounted for under the cost method.
Debt Issuance Costs. The Company amortizes
debt issuance costs related to its long-term debt as interest
expense over the scheduled maturity period of the debt.
Unamortized debt issuance costs were approximately
$38.2 million as of December 31, 2008 and
approximately $26.0 million as of December 31, 2007.
The Company includes the unamortized costs in other assets in
its consolidated balance sheets.
Revenue Recognition and Gas Balancing. Natural
gas and crude oil revenues are recorded when title passes to the
customer, net of royalties, discounts and allowances, as
applicable. The Company accounts for natural gas and crude oil
production imbalances using the sales method, whereby the
Company recognizes revenue on all natural gas and crude oil sold
to its customers notwithstanding the fact that its ownership may
be less than 100% of the natural gas and crude oil sold.
Liabilities are recorded by the Company for imbalances greater
than the Companys proportionate share of remaining
estimated natural gas and crude oil reserves. The Company has
recorded a liability for gas imbalance positions related to
natural gas properties with insufficient proved reserves of
$1.7 million and $1.6 million at December 31,
2008 and 2007, respectively. The Company includes the gas
imbalance positions in other long-term obligations in its
consolidated balance sheets.
The Company recognizes revenues and expenses generated from
daywork drilling contracts as the services are performed as the
Company does not bear the risk of completion of the well. Under
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 depth stated in the contract. The duration of daywork and
turnkey contracts typically ranges 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 typically range from 20 to 90 days.
Revenues from the midstream services segment are derived from
providing gathering, compression, treating, balancing and sales
services for producers and wholesale customers on its natural
gas gathering systems. Midstream gas services are primarily
undertaken to realize incremental margins on natural 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 plus or minus a negotiated differential. 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
collectability 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 future economic benefit. Expenditures that relate
to an existing condition caused by past operations and that have
no 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, 2008
and 2007 were not material.
Natural Gas and Crude Oil Operations. The
Company uses the full cost method to account for its natural gas
and crude oil properties. Under full cost accounting, all costs
directly associated with the acquisition, exploration
F-9
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
and development of natural gas and crude 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
2008, the Company capitalized internal costs of
$19.1 million to the full cost pool. The Company did not
capitalize any interest expense to the full cost pool in 2008.
During 2007, the Company capitalized internal costs and interest
expense of $4.6 million and $0.3 million,
respectively, to the full cost pool. No internal costs or
interest expense were capitalized to the full cost pool in 2006.
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 the 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, subjected to amortization. Sales and abandonments of
natural gas and crude 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 crude 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.
Under the full cost method of accounting, total capitalized
costs of natural gas and crude 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 the related 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. See Note 8.
The ceiling limitation calculation uses natural gas and crude
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 crude oil.
The Company may, from time-to-time, use derivative financial
instruments to hedge against the volatility of natural gas and
crude oil 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 and has therefore
not included its derivative contracts in estimating future cash
flows. 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 limitation calculation.
The costs associated with unproved properties, initially
excluded from the amortization base, 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.
F-10
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
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 various factors, including, but not
limited to, the following: intent to drill; remaining lease
term; geological and geophysical evaluations; drilling results
and activity; assignment of proved reserves; and 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 become subject to
amortization.
Property, Plant and Equipment, Net. Other
capitalized costs, including drilling equipment, natural gas
gathering and treating 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 such 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 considered 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
considered impaired, the loss is measured as the amount by which
the carrying amount of the asset exceeds its fair value.
When property and equipment components are disposed of, the cost
and the related accumulated depreciation are removed and any
resulting gain or loss is reflected in the consolidated
statements of operations.
Asset Retirement Obligation. The Company owns
natural gas and crude oil properties that require expenditures
to plug and abandon the wells when the natural gas and crude oil
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 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 consolidated statements
of operations.
Asset retirement obligations primarily represent the
Companys estimate of fair value to plug, abandon and
remediate the natural gas and crude oil properties at the end of
their productive lives, in accordance with applicable state
laws. The Company determines 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 obligation liability, a
corresponding adjustment is made to the related asset. The
following shows the activity of the asset retirement obligation
for the years ended December 31 (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Asset retirement obligation, January 1
|
|
$
|
58,580
|
|
|
$
|
45,216
|
|
|
$
|
6,979
|
|
Liability incurred upon acquiring and drilling wells
|
|
|
5,707
|
|
|
|
3,265
|
|
|
|
2,996
|
|
NEG acquisition
|
|
|
|
|
|
|
|
|
|
|
40,343
|
|
Revisions in estimated cash flows
|
|
|
15,976
|
|
|
|
5,971
|
|
|
|
(5,700
|
)
|
Liability settled in current period
|
|
|
(764
|
)
|
|
|
(9
|
)
|
|
|
|
|
Accretion of discount expense
|
|
|
5,273
|
|
|
|
4,137
|
|
|
|
598
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation, December 31
|
|
|
84,772
|
|
|
|
58,580
|
|
|
|
45,216
|
|
Less: current portion
|
|
|
275
|
|
|
|
864
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation, net of current
|
|
$
|
84,497
|
|
|
$
|
57,716
|
|
|
$
|
45,216
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-11
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The revisions in estimated cash flows for 2008 are primarily due
to changes in reserve lives based on lower natural gas and crude
oil prices at December 31, 2008.
Income Taxes. Deferred income taxes are
recorded for temporary differences between financial reporting
purposes and income tax bases. Temporary differences are
differences between the amounts of assets and liabilities
reported for financial reporting 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 Financial Accounting Standards Board (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 has elected an accounting policy in which interest
and penalties on income tax related balances are presented as a
component of income taxes.
Minority Interest. At December 31, 2008
and 2007, minority interest in the Companys consolidated
subsidiaries included a 1.29% interest in Cholla Pipeline, LP.
At December 31, 2007, minority interest in the
Companys consolidated subsidiaries also included a 26.19%
interest in Sagebrush Pipeline, LLC (Sagebrush). As
a result of the sale of Sagebrushs assets in May 2008, the
minority interest in Sagebrush was distributed. See Note 2.
Concentration of Risk. The Company maintains
cash balances at several financial institutions. Accounts at
each institution are insured by the Federal Deposit Insurance
Corporation up to $250,000. 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.
All of the Companys hedging transactions have been carried
out in the over-the-counter market. The use of hedging
transactions involves the risk that the counterparties may be
unable to meet the financial terms of the transactions. The
counterparties for all of the Companys hedging
transactions have an investment grade credit rating.
The Company monitors on an ongoing basis the credit ratings of
its hedging counterparties and considers its
counterparties credit default risk rating in determining
the fair value of its derivative contracts. At December 31,
2008, Barclays Capital, JPMorgan Chase Bank, Bank of America,
Morgan Stanley, Bank of Montreal and Credit Suisse were the
counterparties with respect to 81.7% of the Companys
hedged future production.
The purchasers of the Companys natural gas and crude oil
production consist primarily of independent marketers, major oil
and natural gas companies and gas pipeline companies. The
Company has not experienced any significant losses from
uncollectible accounts. In 2008 and 2007, the Company had one
individual purchaser accounting for 10.5% and 11.2%,
respectively, of its total sales. In 2006, the Company had no
individual purchasers accounting for more than 10% of its total
sales. The Company believes other purchasers are available in
its areas of operations and does not believe the loss of any one
of its purchasers would materially affect the Companys
ability to sell the natural gas and crude oil it produces.
Fair Value of Financial Instruments. The fair
values of the Companys cash and cash equivalents, accounts
receivable and accounts payable approximate their carrying
amounts due to their short-term nature. The fair value for the
Companys publicly traded senior notes, which was based on
market prices, was $961.3 million (carrying value of
$1.750 billion) at December 31, 2008. The
Companys carrying value for its senior credit facility and
remaining fixed rate debt instruments approximates fair value
based on current rates applicable to similar instruments. The
Company measured fair value of its long-term debt in accordance
with Statement of Financial Accounting Standards
(SFAS) No. 157, Fair Value
Measurements, giving consideration to the effect of the
F-12
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Companys credit risk. The estimated fair values of
derivative contracts are based on quotes obtained from the
counterparties to the derivative contracts. See Note 3.
Derivative Financial Instruments. To manage
risks related to increases in interest rates and changes in
natural gas and crude oil prices, the Company enters into
interest rate swaps and natural gas and crude oil derivative
contracts.
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 was designated as hedging instruments
during 2008, 2007 and 2006.
Stock-Based Compensation. Effective
January 1, 2006, the Company adopted SFAS No. 123R,
Share-Based Payment. SFAS No. 123R
establishes the accounting for equity instruments exchanged for
employee services. Under SFAS No. 123R, stock-based
compensation cost is measured based on the calculated fair value
of the award on the grant date. The expense is recognized over
the employees requisite service period, generally the
vesting period of the award. SFAS No. 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 as an operating activity. As of December 31,
2008, the Company had $4.6 million of excess tax benefits
related to stock-based compensation.
Recent Accounting Pronouncements. Effective
January 1, 2008, SandRidge implemented
SFAS No. 157 for its financial assets and liabilities
measured on a recurring basis. SFAS No. 157 defines
fair value, establishes a framework for measuring fair value and
expands required disclosures about fair value measurements.
SFAS No. 157 did not have an effect on the
Companys financial statements on the date of adoption
other than requiring additional disclosures regarding fair value
measurements. See Note 3.
In February 2008, the FASB issued Staff Position
FAS 157-2,
Effective Date of FASB Statement No. 157
(FSP 157-2).
FSP 157-2
delays the effective date of SFAS No. 157 to fiscal
years beginning after November 15, 2008 for all
nonfinancial assets and nonfinancial liabilities, except those
recognized or disclosed at fair value in the financial
statements on a recurring basis, at least annually. The Company
plans to implement this standard on January 1, 2009. The
adoption of
FSP 157-2
is not expected to have a material impact on the Companys
financial condition, operations or cash flows.
Effective upon issuance, the FASB issued Staff Position
FAS 157-3,
Determining the Fair Value of a Financial Asset When the
Market for That Asset is Not Active,
(FSP 157-3)
in October 2008.
FSP 157-3
clarifies the application of SFAS No. 157 in
determining the fair value of a financial asset when the market
for that financial asset is not active. As of December 31,
2008, the Company had no financial assets with a market that was
not active. Accordingly,
FSP 157-3
had no effect on the Companys current financial statements.
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.
SFAS No. 141(R) also establishes disclosure
requirements that will enable users to evaluate the nature and
financial effects of the business combination.
SFAS No. 141(R) is effective for business combinations
with acquisition dates on or after fiscal years beginning after
December 15, 2008. The Company will evaluate this standard
with respect to business combinations with acquisition dates on
or after January 1, 2009.
F-13
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
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.
SFAS No. 160 also establishes disclosure requirements
to 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 implementation of
SFAS No. 160 is not expected to have a material impact
on the Companys financial condition or operations as the
effect will be on presentation and disclosure.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities, which changes disclosure requirements for
derivative instruments and hedging activities.
SFAS No. 161 requires enhanced disclosure, including
qualitative disclosures about objectives and strategies for
using derivatives, quantitative disclosures about fair value
amounts of gains and losses on derivative instruments and
disclosures about credit-risk-related contingent features in
derivative agreements. SFAS No. 161 is effective for
fiscal years beginning after November 15, 2008. The Company
plans to implement this standard on January 1, 2009. As
SFAS No. 161 pertains to disclosure requirements, no
effect to the Companys financial condition, operations or
cash flows is expected.
On December 31, 2008, the Securities and Exchange
Commission (SEC) issued Release
No. 33-8995,
Modernization of Oil and Gas Reporting, which
revises disclosure requirements for oil and gas companies. In
addition to changing the definition and disclosure requirements
for oil and gas reserves, the new rules change the requirements
for determining oil and gas reserve quantities. These rules
permit the use of new technologies to determine proved reserves
under certain criteria and allow companies to disclose their
probable and possible reserves. The new rules also require
companies to report the independence and qualifications of their
reserves preparer or auditor and file reports when a third party
is relied upon to prepare reserves estimates or conducts a
reserves audit. The new rules also require that oil and gas
reserves be reported and the full cost ceiling limitation be
calculated using a twelve-month average price rather than
period-end prices. The use of a twelve-month average price could
have had an effect on the Companys 2008 depletion rates
for its natural gas and crude oil properties. The new rule is
effective for annual reports on
Form 10-K
for fiscal years ending on or after December 31, 2009,
pending the potential alignment of certain accounting standards
by the FASB with the new rule. The Company plans to implement
the new requirements in its Annual Report on
Form 10-K
for the year ended December 31, 2009. The Company is
currently evaluating the impact of this new rule on its
consolidated financial statements.
|
|
2.
|
Acquisitions
and Dispositions
|
2006
Acquisitions and Dispositions
The Company closed the following acquisitions in 2006:
|
|
|
|
|
In March 2006, the Company acquired from an executive officer
and director an additional 12.5% interest in PetroSource Energy
Company, LLC (PetroSource), a consolidated
subsidiary. 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.
|
|
|
|
In May 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.
|
|
|
|
In May 2006, the Company purchased several natural gas and crude
oil properties from an oil and gas company. The purchase price
was approximately $12.9 million, comprised of
$8.2 million in cash, and
|
F-14
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
251,351 shares of Company common stock, valued at
$4.7 million. The cash and equity consideration were paid
in July 2006.
|
|
|
|
|
|
In June 2006, the Company purchased certain producing well
interests from an executive officer and director. The purchase
price was approximately $9.0 million in cash.
|
|
|
|
In June 2006, the Company acquired the remaining 1% interest in
PetroSource 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
|
|
|
|
|
|
|
|
|
|
Property, Plant
|
|
|
Minority
|
|
|
of Subordinated
|
|
|
Stock No.
|
|
|
Common
|
|
|
|
|
Acquisition 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
|
|
Natural gas and crude oil 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.
|
|
|
|
In November 2006, the Company acquired all of the outstanding
membership interests in NEG Oil & Gas LLC
(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. To finance the NEG
acquisition, the Company entered into a $750.0 million
senior secured credit facility and an $850.0 million senior
unsecured bridge loan facility. The Company also issued
$550.0 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, the Company completed its
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, the Company
increased its values assigned to the properties acquired and
reduced the value assigned to goodwill of $26.2 million.
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-15
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, 2006. The pro forma financial
information is presented for informational purposes only and
does not necessarily reflect the results of operations that
would have been achieved if the acquisition had taken place on
January 1, 2006 or the 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 have differed materially
from this pro forma financial information. The following table
presents the actual results for the year ended December 31,
2006 and the respective unaudited pro forma information to
reflect the NEG acquisition (in thousands, except per share
amounts):
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
|
Actual
|
|
|
Pro Forma
|
|
|
|
(Unaudited)
|
|
|
Revenues
|
|
$
|
388,242
|
|
|
$
|
565,256
|
|
Net income
|
|
$
|
15,621
|
|
|
$
|
36,337
|
|
Basic and diluted earnings per share available to common
stockholders:
|
|
|
|
|
|
|
|
|
Income from operations
|
|
$
|
0.21
|
|
|
$
|
0.40
|
|
Net income available to common stockholders
|
|
$
|
0.16
|
|
|
$
|
0.04
|
|
F-16
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
2007
Acquisitions
The Company closed the following acquisitions in 2007:
|
|
|
|
|
In October 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 $25.0 million cash consideration paid was
funded through a draw on the Companys senior credit
facility. All principal and accrued interest (accruing at 7%
annually) due on the note payable were repaid in November 2007
with proceeds from the Companys initial public offering of
its common stock. For additional discussion of the
Companys initial public offering, refer to Note 20
herein.
|
|
|
|
In November 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.
|
|
|
|
In November 2007, the Company purchased leasehold acreage and
producing well interests located predominantly in the West Texas
Overthrust (WTO) from a group of entities controlled
by a significant shareholder. The purchase price of
approximately $32.0 million was paid in cash.
|
2008
Acquisitions and Dispositions
The Company closed the following acquisitions and dispositions
in 2008:
|
|
|
|
|
In May 2008, the Company sold all of its assets located in the
Piceance Basin of Colorado. Assets sold included undeveloped
acreage, working interests in wells, gathering and compression
systems and other facilities related to the wells. Net proceeds
to the Company were approximately $147.2 million after
closing adjustments. The portion of the Companys net
proceeds attributable to the disposed gathering and compression
systems and facilities exceeded the book basis of those assets
resulting in a gain on sale of approximately $7.2 million
after closing adjustments. The sale of the acreage and working
interests in wells was accounted for as an adjustment to the
full cost pool with no gain or loss recognized.
|
|
|
|
In July 2008, the Company purchased land, minerals, developed
and undeveloped leasehold and interests in producing properties
through various transactions for an aggregate purchase price of
approximately $67.6 million, which was paid in cash.
|
|
|
|
In October 2008, the Company purchased certain working interests
and related reserves in Company wells owned by the
Companys Chairman and Chief Executive Officer and certain
of his affiliates. The purchase price of approximately
$67.3 million, after closing adjustments, was paid in cash.
|
|
|
3.
|
Fair
Value Measurements
|
Effective January 1, 2008, the Company implemented
SFAS No. 157 for its financial assets and liabilities
measured on a recurring basis. SFAS No. 157 applies to
all financial assets and liabilities that are measured and
reported on a fair value basis. In February 2008, the FASB
issued
FSP 157-2,
which delayed the effective date of SFAS No. 157 by
one year for certain nonfinancial assets and liabilities.
As defined in SFAS No. 157, fair value is the price
that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants
at the measurement date. SFAS No. 157 requires
disclosure that establishes a framework for measuring fair value
and expands disclosure about fair value
F-17
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
measurements. SFAS No. 157 requires fair value
measurements to be classified and disclosed in one of the
following categories:
|
|
|
Level 1:
|
|
Unadjusted quoted prices in active markets that are accessible
at the measurement date for identical, unrestricted assets or
liabilities.
|
Level 2:
|
|
Quoted prices in markets that are not active, or inputs which
are observable, either directly or indirectly, for substantially
the full term of the asset or liability.
|
Level 3:
|
|
Measured based on prices or valuation models that required
inputs that are both significant to the fair value measurement
and less observable for objective sources (i.e., supported by
little or no market activity).
|
As required by SFAS No. 157, financial assets and
liabilities are classified based on the lowest level of input
that is significant to the fair value measurement. The
Companys assessment of the significance of a particular
input to the fair value measurement requires judgment, which may
affect the valuation of the fair value of assets and liabilities
and their placement within the fair value hierarchy levels. The
determination of the fair values, stated below, takes into
account the market for the Companys financial assets and
liabilities, the associated credit risk and other factors as
required under SFAS No. 157. The Company considers
active markets as those in which transactions for the assets or
liabilities occur in sufficient frequency and volume to provide
pricing information on an ongoing basis.
As required by SFAS No. 157, the Company has
classified its derivative contracts into one of three levels
based upon the data relied upon to determine the fair value. The
fair values of the Companys natural gas and crude oil
swaps, crude oil collars and interest rate swap are based upon
quotes obtained from counterparties to the derivative contracts.
The Company reviews other readily available market prices for
its derivative contracts as there is an active market for these
contracts; however, the Company does not have access to specific
valuation models used by the counterparties. Included in these
models are discount factors that the Company must estimate in
its calculation. Additionally, the Company applies a credit
default risk rating factor for its counterparties in determining
the fair value of its derivative contracts. Based on the inputs
for the fair value measurement, the Company classified its
derivative contract assets and liabilities as Level 3. The
following table summarizes the valuation of the Companys
financial assets and liabilities as of December 31, 2008
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
|
|
|
|
|
|
Quoted Prices in
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
Active Markets for
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
|
Identical Assets
|
|
|
Observable
|
|
|
Unobservable
|
|
|
Assets/
|
|
|
|
or Liabilities
|
|
|
Inputs
|
|
|
Inputs
|
|
|
(Liabilities) at
|
|
Description
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Fair Value
|
|
|
Assets (liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and crude oil derivative contracts
|
|
$
|
|
|
|
$
|
|
|
|
$
|
246,648
|
|
|
$
|
246,648
|
|
Interest rate swap
|
|
|
|
|
|
|
|
|
|
|
(8,745
|
)
|
|
|
(8,745
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
237,903
|
|
|
$
|
237,903
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-18
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The table below sets forth a reconciliation of the
Companys financial assets and liabilities measured at fair
value on a recurring basis using significant unobservable inputs
(Level 3) during the year ended December 31, 2008
(in thousands):
|
|
|
|
|
|
|
Derivatives
|
|
|
Balance of Level 3, December 31, 2007
|
|
$
|
22,228
|
|
Total gains or losses (realized/unrealized)
|
|
|
203,998
|
|
Purchases, issuances and settlements
|
|
|
11,677
|
|
Transfers in and out of Level 3
|
|
|
|
|
|
|
|
|
|
Balance of Level 3, December 31, 2008
|
|
$
|
237,903
|
|
|
|
|
|
|
Changes in unrealized gains (losses) on derivative contracts
held as of December 31, 2008
|
|
$
|
215,675
|
|
|
|
|
|
|
A summary of trade accounts receivable is as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Natural gas and crude oil sales
|
|
$
|
72,266
|
|
|
$
|
72,393
|
|
Natural gas and oil services
|
|
|
20,476
|
|
|
|
6,622
|
|
Joint interest billing
|
|
|
13,816
|
|
|
|
17,874
|
|
Other
|
|
|
62
|
|
|
|
90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
106,620
|
|
|
|
96,979
|
|
Less allowance for doubtful accounts
|
|
|
(3,874
|
)
|
|
|
(2,238
|
)
|
|
|
|
|
|
|
|
|
|
Total trade accounts receivable, net
|
|
$
|
102,746
|
|
|
$
|
94,741
|
|
|
|
|
|
|
|
|
|
|
The following table shows the balance in the allowance for
doubtful accounts and activity for the years ended
December 31, 2006, 2007 and 2008 (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, 2006
|
|
$
|
851
|
|
|
$
|
2,528
|
|
|
$
|
(354
|
)
|
|
$
|
3,025
|
|
Year ended December 31, 2007
|
|
$
|
3,025
|
|
|
$
|
|
|
|
$
|
(787
|
)
|
|
$
|
2,238
|
|
Year ended December 31, 2008
|
|
$
|
2,238
|
|
|
$
|
1,748
|
|
|
$
|
(112
|
)
|
|
$
|
3,874
|
|
|
|
|
(1) |
|
Deductions represent the write-off of receivables. |
The Companys customer, SemGroup, L.P. and certain of its
subsidiaries (collectively, SemGroup), filed for
bankruptcy on July 22, 2008. During the third quarter of
2008, the Company established an allowance in the amount of
$1.5 million for all amounts due from SemGroup.
F-19
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Other current assets consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Prepaid insurance
|
|
$
|
9,374
|
|
|
$
|
9,379
|
|
Prepaid drilling
|
|
|
2,657
|
|
|
|
5,924
|
|
Materials and supplies
|
|
|
155
|
|
|
|
4,751
|
|
Deposits
|
|
|
26,806
|
|
|
|
60
|
|
Other
|
|
|
2,415
|
|
|
|
673
|
|
|
|
|
|
|
|
|
|
|
Total other current assets
|
|
$
|
41,407
|
|
|
$
|
20,787
|
|
|
|
|
|
|
|
|
|
|
|
|
6.
|
Property,
Plant and Equipment
|
Property, plant and equipment consists of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Natural gas and crude oil properties:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
4,676,072
|
|
|
$
|
2,848,531
|
|
Unproved
|
|
|
215,698
|
|
|
|
259,610
|
|
|
|
|
|
|
|
|
|
|
Total natural gas and crude oil properties
|
|
|
4,891,770
|
|
|
|
3,108,141
|
|
Less accumulated depreciation, depletion and impairment(1)
|
|
|
(2,369,840
|
)
|
|
|
(230,974
|
)
|
|
|
|
|
|
|
|
|
|
Net natural gas and crude oil properties capitalized costs
|
|
|
2,521,930
|
|
|
|
2,877,167
|
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
11,250
|
|
|
|
1,149
|
|
Non natural gas and crude oil equipment
|
|
|
764,792
|
|
|
|
539,893
|
|
Buildings and structures
|
|
|
71,859
|
|
|
|
38,288
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
847,901
|
|
|
|
579,330
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(194,272
|
)
|
|
|
(119,087
|
)
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
|
653,629
|
|
|
|
460,243
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
$
|
3,175,559
|
|
|
$
|
3,337,410
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes ceiling limitation impairment charge of
$1,855.0 million at December 31, 2008. |
The amount of capitalized interest included in the above non
natural gas and crude oil equipment balance at December 31,
2008 and 2007 was approximately $3.8 million and
$3.4 million, respectively.
In July 2007, the Company purchased property to serve as its
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.
In May 2008, the Company completed the sale of all of its assets
located in the Piceance Basin of Colorado. See Note 2.
The average composite rates used for depreciation, depletion and
amortization were $2.82 per Mcfe in 2008, $2.64 per Mcfe in 2007
and $1.68 per Mcfe in 2006.
F-20
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Costs
Excluded from Amortization
Costs associated with unproved properties of $215.7 million
as of December 31, 2008 were excluded from amounts subject
to amortization. The following table summarizes the costs
related to unproved properties which have been excluded from
natural gas and crude oil properties being amortized at
December 31, 2008 and the year in which they were incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluded
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs at
|
|
|
|
Year Cost Incurred
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2008
|
|
|
Property acquisition
|
|
$
|
179,888
|
|
|
$
|
|
|
|
$
|
35,810
|
|
|
$
|
215,698
|
|
Exploration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
179,888
|
|
|
$
|
|
|
|
$
|
35,810
|
|
|
$
|
215,698
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company expects to complete the majority of the evaluation
activities within six years from the applicable date of
acquisition, contingent on the Companys capital
expenditures and drilling program. In addition, the
Companys internal engineers evaluate all properties on at
least an annual basis.
|
|
7.
|
Investment
in Affiliated Companies
|
The Company accounts for certain investments under the equity
method when the Company owns more than 20% and has significant
influence, but does not control the investee company. The
Companys equity method investments include the following:
Grey Ranch, L.P. Grey Ranch, L.P. (Grey
Ranch) is primarily engaged in treating and transportation
of natural gas. The Company purchased its investment during
2003. At December 31, 2008 and 2007, the Company owned 50%
of Grey Ranch and had approximately $6.1 million and
$4.2 million, respectively, recorded in the consolidated
balance sheets relating to this investment.
Larclay, L.P. The Company and Clayton Williams
Energy, Inc. (CWEI) each own a 50% interest in
Larclay, L.P. (Larclay), a limited partnership
formed to acquire drilling rigs and provide land drilling
services. The Company serves as the operations manager of the
partnership. CWEI was responsible for securing financing and the
purchase of the rigs. The partnership financed the acquisition
cost of the rigs with a loan from a third party, secured by the
purchased rigs, and a loan from CWEI. In addition, CWEI has
guaranteed a portion of the third party debt. As a result of
current economic conditions and the resulting on-going cash
shortfalls experienced by Larclay, the Company recorded an
impairment for its investment in Larclay as of December 31,
2008. See Note 8 for a discussion of impairment. At
December 31, 2007, the Company had approximately
$3.8 million included in the consolidated balance sheets
relating to this investment.
Full Cost Ceiling Limitation. Under the full
cost method of accounting, the net book value of oil and gas
properties, less related deferred income taxes, may not exceed a
calculated ceiling. The ceiling limitation is the
discounted estimated after-tax future net revenue from proved
natural gas and crude oil properties, excluding future cash
outflows associated with settling asset retirement obligations
included in the net book value of natural gas and crude oil
properties, plus the cost of properties not subject to
amortization. In calculating future net revenues, prices and
costs used are those as of the end of the appropriate period.
These prices are not changed except where different prices are
fixed and determinable from applicable contracts for the
remaining term of those contracts. The Company
F-21
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
has entered into various commodity derivative contracts;
however, these derivative contracts are not accounted for as
cash flow hedges. Accordingly, the effect of these derivative
contracts has not been considered in calculating the full cost
ceiling limitation as of December 31, 2008.
The net book value, less related deferred tax liabilities, is
compared to the ceiling limitation on a quarterly and annual
basis. Any excess of the net book value, less related deferred
taxes, is written off as an expense. An expense recorded in one
period may not be reversed in a subsequent period even though
higher natural gas and crude oil prices may have increased the
ceiling limitation in the subsequent period.
During the fourth quarter of 2008, the Company reduced the
carrying value of its oil and gas properties by
$1,855.0 million due to the full cost ceiling limitations.
The after-tax effect of this reduction in 2008 was
$1,677.5 million.
Larclay, L.P. Lariat and CWEI each own a 50%
interest in Larclay, a limited partnership formed in 2006 to
acquire drilling rigs and provide land drilling services. At
December 31, 2008, Lariats investment in Larclay was
$4.8 million. During 2008, Larclay experienced cash
shortfalls as a result of its principal payments due pursuant to
its rig loan agreement. As permitted under the Larclay
partnership agreement, Lariat provided loans to Larclay to
offset the cash shortfalls. At December 31, 2008, the notes
outstanding to Larclay and related interest receivable were
$7.5 million and $0.2 million, respectively. With the
significant decline in natural gas and crude oil prices in the
fourth quarter of 2008, the demand for Larclays drilling
rigs and land drilling services has decreased. Due to current
economic conditions, current natural gas and crude oil prices
and the continued cash shortfalls for Larclay, Lariat has fully
impaired both the investment in and notes receivable due from
Larclay as of December 31, 2008. This resulted in an
impairment expense of approximately $12.5 million included
in the consolidated statement of operations.
Restricted deposits represent bank trust and escrow accounts
required by the Minerals Management Service of the United States
Department of the Interior, 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 relate to properties acquired
as part of the NEG acquisition in November 2006. See Note 2.
One of the agreements requires the Company to deposit additional
funds in an escrow account equal to 10% of the net proceeds, as
defined, from certain of its offshore properties. In 2007, the
Company was released from obligations under two of the escrow
agreements. As a result, funds totaling $10.3 million were
released from escrow accounts and returned to the Company.
During 2008 and 2007, the Company deposited approximately
$0.8 million and $7.4 million, respectively, in escrow
accounts.
F-22
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
10.
|
Accounts
Payable and Accrued Expenses
|
Trade accounts payable and accrued expenses consist of the
following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Accounts payable
|
|
$
|
302,407
|
|
|
$
|
154,423
|
|
Redeemable convertible preferred stock dividends
|
|
|
|
|
|
|
8,956
|
|
Payroll and benefits
|
|
|
20,703
|
|
|
|
15,690
|
|
Drilling advances
|
|
|
4,074
|
|
|
|
5,817
|
|
Settlement agreement current (See Note 12)
|
|
|
5,000
|
|
|
|
5,000
|
|
Accrued interest
|
|
|
26,790
|
|
|
|
24,201
|
|
Other
|
|
|
7,363
|
|
|
|
1,410
|
|
|
|
|
|
|
|
|
|
|
Total trade accounts payable and accrued expenses
|
|
$
|
366,337
|
|
|
$
|
215,497
|
|
|
|
|
|
|
|
|
|
|
|
|
11.
|
Billings
in Excess of Costs Incurred
|
In June 2008, the Company entered into an agreement with a
subsidiary of Occidental Petroleum Corporation
(Occidental) to construct a
CO2
treating plant (the Century Plant) and associated
compression and pipeline facilities for $800.0 million.
Occidental will pay a minimum of 100% of the contract price,
plus any subsequent
agreed-upon
revisions, to the Company through periodic cost reimbursements
based upon the percentage of the project completed. Upon
start-up,
the Century Plant, located in Pecos County, Texas, will be owned
and operated by Occidental for the purpose of separating and
removing
CO2
from delivered natural gas. The Company will deliver high
CO2
natural gas to the Century Plant. Pursuant to a
30-year
treating agreement executed simultaneously with the construction
agreement, Occidental will remove
CO2
from the Companys delivered natural gas. The Company will
retain all methane gas from the Century Plant and its other
existing plants.
The Company accounts for construction of the Century Plant using
the completed-contract method, under which contract revenues and
costs are recognized when work under the contract is completed
or substantially completed. In the interim, costs incurred on
and billings related to contracts in process are accumulated on
the balance sheet. Provisions for a contract loss are recognized
when it is determined that a loss will be incurred. During 2008,
the Company issued and received payment for progress billings
totaling $112.0 million. Billings in excess of costs
incurred during 2008 were $14.1 million and were reported
as a current liability in the consolidated balance sheet at
December 31, 2008.
F-23
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Long-term obligations consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Senior credit facility
|
|
$
|
573,457
|
|
|
$
|
|
|
Other notes payable:
|
|
|
|
|
|
|
|
|
Drilling rig fleet and related crude oil field services equipment
|
|
|
33,030
|
|
|
|
47,836
|
|
Mortgage
|
|
|
18,829
|
|
|
|
19,651
|
|
Other equipment and vehicles
|
|
|
|
|
|
|
162
|
|
8.625% Senior Term Loan
|
|
|
|
|
|
|
650,000
|
|
Senior Floating Rate Term Loan
|
|
|
|
|
|
|
350,000
|
|
8.625% Senior Notes due 2015
|
|
|
650,000
|
|
|
|
|
|
Senior Floating Rate Notes due 2014
|
|
|
350,000
|
|
|
|
|
|
8.0% Senior Notes due 2018
|
|
|
750,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
2,375,316
|
|
|
|
1,067,649
|
|
Less: Current maturities of long-term debt
|
|
|
16,532
|
|
|
|
15,350
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
2,358,784
|
|
|
$
|
1,052,299
|
|
|
|
|
|
|
|
|
|
|
Senior Credit Facility. On November 21,
2006, the Company entered into a $750.0 million senior
secured revolving credit facility (the senior credit
facility). As discussed further below, the borrowing base
has been increased and was $1.1 billion at
December 31, 2008. The senior credit facility matures on
November 21, 2011 and is 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 ability of the Company and certain of its subsidiaries 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 ability of the Company and certain of its
subsidiaries to incur additional indebtedness with certain
exceptions, including under the senior notes.
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), which may not exceed 4.5:1.0
calculated using the last four completed fiscal quarters,
(ii) 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) current ratio, which must be at least 1.0:1.0. In the
current ratio calculation, as defined in the senior credit
facility, any amounts available to be drawn under the senior
credit facility are included in current assets, and unrealized
assets and liabilities resulting from mark-to-market adjustments
on the Companys derivative contracts are disregarded. As
of December 31, 2008, the Company was in compliance with
all of the financial covenants under the senior credit facility.
The obligations under the senior credit facility are guaranteed
by certain Company subsidiaries. Additionally, 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 substantially all of the Companys
assets, including proved natural gas and crude oil reserves
representing at least 80% of the discounted present value (as
defined in the senior credit facility) of proved natural gas and
crude oil reserves reviewed in determining the borrowing base
for the senior credit facility.
F-24
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
At the Companys election, interest under the senior credit
facility is determined by reference to (i) the London
Interbank Offered Rate (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 the senior credit facility was
3.82% for the year ended December 31, 2008. The interest
rate on the senior credit facility was 2.19% at
December 31, 2008.
Borrowings under the senior credit facility may not exceed the
lower of the borrowing base or the committed loan amount, which
was increased to $1.75 billion in April 2008. The borrowing
base of proved reserves was initially set at
$300.0 million. The borrowing base was subsequently
increased to $400.0 million in May 2007,
$700.0 million in September 2007 and $1.2 billion in
April 2008. As a result of the private placement of
$750.0 million of senior notes in May 2008, discussed
below, the borrowing base was reduced to $1.1 billion. The
Companys borrowing base is redetermined in April and
October of each year based on proved reserves. Our ability to
develop properties and changes in commodity prices have an
impact on the borrowing base. The Company incurred additional
costs related to the senior credit facility as a result of
changes to the borrowing base. These costs have been deferred
and are included in other assets in the consolidated balance
sheets. At December 31, 2008, the Company had
$573.5 million outstanding and approximately
$494.0 million available to be drawn under this facility,
excluding amounts to be funded by Lehman Brothers Commodity
Services, Inc. (Lehman Brothers).
On October 3, 2008, Lehman Brothers, a lender under the
Companys senior credit facility, filed for bankruptcy. At
the time that its parent, Lehman Brothers Holdings, Inc.,
declared bankruptcy on September 15, 2008, Lehman Brothers
elected not to fund its pro rata share, or 0.29%, of borrowings
requested by the Company under the senior credit facility.
Accordingly, the Company does not anticipate that Lehman
Brothers will fund its pro rata share of any future borrowing
requests. The Company currently does not expect this reduced
availability of amounts under the senior credit facility to
impact its liquidity or business operations.
Other Indebtedness. The Company has financed a
portion of its drilling rig fleet and related oil field services
equipment through notes. At December 31, 2008, the
aggregate outstanding balance of these notes was
$33.0 million, with annual fixed interest rates ranging
from 7.64% to 8.67%. The notes have a final maturity date of
December 1, 2011, require aggregate monthly installments of
principal and interest in the amount of $1.2 million and
are secured by the equipment. The notes have a prepayment
penalty (currently ranging from 1% to 2%) that is triggered if
the Company repays the notes prior to maturity.
On November 15, 2007, the Company entered into a note
payable with a lending institution in the amount of
$20.0 million as a mortgage on the downtown Oklahoma City
property purchased by the Company in July 2007 to serve as its
corporate headquarters. 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 made 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. These notes were substantially repaid during
2007. As of December 31, 2008, there were no amounts
outstanding under these notes. The Company financed its
insurance premium payment made in 2007. Also, in 2007, the
Company repaid a $4.0 million loan incurred in 2005 for the
purpose of completing a gas processing plant and pipeline in
Colorado.
8.625% Senior Term Loan and Senior Floating Rate Term
Loan. On March 22, 2007, the Company issued
$1.0 billion of unsecured 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 20.
A portion of the proceeds from the senior
F-25
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
term loans was used to repay the Companys
$850.0 million senior bridge facility, described below
under Senior Bridge Facility, which was
repaid in full in March 2007. The senior term loans included
both a floating rate term loan and a fixed rate term loan, as
described below.
The Company issued a $350.0 million senior term loan at a
variable rate with interest payable quarterly and principal due
on April 1, 2014. The variable rate term loan bore
interest, at the Companys 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%.
The Company issued a $650.0 million senior term loan at a
fixed rate of 8.625% with the principal due on April 1,
2015. Under the terms of the fixed rate term loan, interest was
payable quarterly and during the first four years interest was
payable, at the Companys option, either entirely in cash
or entirely with additional fixed rate term loans.
8.625% Senior Notes Due 2015 and Senior Floating Rate
Notes Due 2014. In May 2008, the Company
completed an offer to exchange its senior term loans for senior
unsecured notes with registration rights, as required under the
senior term loan credit agreement. The Company issued
$650.0 million of 8.625% Senior Notes due 2015
(8.625% Senior Notes) in exchange for an equal
outstanding principal amount of its fixed rate senior term loan
and $350.0 million of Senior Floating Rate Notes due 2014
(Senior Floating Rate Notes) in exchange for an
equal outstanding principal amount of its floating rate senior
term loan. The exchange was made pursuant to a non-public
exchange offer that commenced on March 28, 2008 and expired
on April 28, 2008. The newly issued senior notes have terms
that are substantially identical to those of the exchanged
senior term loans, except that the senior notes were issued with
registration rights. These senior notes are jointly and
severally, unconditionally guaranteed on an unsecured basis by
all of the Companys wholly owned subsidiaries, except
certain minor subsidiaries. See Note 24.
In conjunction with the issuance of the senior notes, the
Company agreed to file a registration statement with the SEC in
connection with its offer to exchange the notes for
substantially identical notes that are registered under the
Securities Act of 1933, as amended (Securities Act).
The Company filed a registration statement relating to the
exchange offer during the third quarter of 2008, and all
unregistered notes were exchanged for registered notes by
October 27, 2008.
The 8.625% Senior Notes bear interest at a fixed rate of
8.625% per annum with the principal due on April 1, 2015.
Under the terms of the 8.625% Senior Notes, interest is
payable semi-annually and, through the interest payment due on
April 1, 2011, interest may be paid, at the Companys
option, either entirely in cash or entirely with additional
fixed rate senior notes. If the Company elects to pay the
interest due during any period in additional fixed rate senior
notes, the interest rate will increase to 9.375% during that
period. All interest payments made to date related to the fixed
rate senior notes have been paid in cash. The Senior Floating
Rate Notes bear interest at LIBOR plus 3.625% (7.51% at
December 31, 2008), except for the period from
April 1, 2008 to June 30, 2008, for which the interest
rate was 6.323%. Interest is payable quarterly with principal
due on April 1, 2014. The average interest rate paid on
amounts outstanding under the Senior Floating Rate Notes for the
year ended December 31, 2008 was 7.27%.
In January 2008, the Company entered into an interest rate swap
to fix the variable LIBOR interest rate on the floating rate
senior term loan for the period from April 1, 2008 to
April 1, 2011. As a result of the exchange of the floating
rate senior term loan to Senior Floating Rate Notes, the
interest rate swap is now being used to fix the variable LIBOR
interest rate on the Senior Floating Rate Notes at an annual
rate of 6.26% through April 2011. This swap has not been
designated as a hedge.
The Company may redeem some or all of the Senior Floating Rate
Notes at specified redemption prices on or after April 1,
2009 and may redeem some or all of the 8.625% Senior Notes
at specified redemption prices on or after April 1, 2011.
The Company incurred $26.1 million of debt issuance costs
in connection with the senior term loans. As the senior term
loans were exchanged for senior notes with substantially
identical terms, the remaining unamortized debt issuance costs
on the senior term loans will be amortized over the terms of the
8.625% Senior Notes and the Senior Floating Rate Notes.
These costs are included in other assets in the consolidated
balance sheets.
F-26
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
8.0% Senior Notes Due 2018. In May 2008,
the Company issued $750.0 million of unsecured
8.0% Senior Notes due 2018 (8.0% Senior
Notes). The Company used $478.0 million of the
$735.0 million net proceeds from the offering to repay the
total balance outstanding on the senior credit facility at that
time. The remaining proceeds were used to fund a portion of the
Companys 2008 capital expenditure program. The notes bear
interest at a fixed rate of 8.0% per annum, payable
semi-annually, with the principal due on June 1, 2018. The
notes are redeemable, in whole or in part, prior to their
maturity at specified redemption prices. The 8.0% Senior
Notes are jointly and severally, unconditionally guaranteed on
an unsecured basis by all of the Companys wholly owned
subsidiaries, except certain minor subsidiaries. See
Note 24. The notes became freely tradable on
November 17, 2008, 180 days after their issuance,
pursuant to Rule 144 under the Securities Act.
The Company incurred $16.0 million of debt issuance costs
in connection with the offering of the 8.0% Senior Notes.
These costs are included in other assets in the consolidated
balance sheet and amortized over the term of the notes.
The indentures governing all of the senior notes contain
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. As of December 31, 2008, the Company
was in compliance with all of the covenants contained in the
indentures governing the senior notes.
Senior Bridge Facility. On November 21,
2006, the Company entered into an $850.0 million senior
unsecured bridge facility (the senior bridge
facility). 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 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. The senior bridge facility was
repaid in March 2007 with a portion of the proceeds from the
issuance of the Companys senior term loans. The Company
expensed remaining unamortized debt issuance costs related to
the senior bridge facility of approximately $12.5 million
to interest expense in March 2007.
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:
|
|
|
|
|
2009
|
|
$
|
16,532
|
|
2010
|
|
|
12,005
|
|
2011
|
|
|
580,751
|
|
2012
|
|
|
1,051
|
|
2013
|
|
|
1,120
|
|
Thereafter
|
|
|
1,763,857
|
|
|
|
|
|
|
Total debt
|
|
$
|
2,375,316
|
|
|
|
|
|
|
|
|
13.
|
Other
Long-Term Obligations
|
The Company has recorded a long-term obligation for amounts to
be paid under a 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
payment made on July 1, 2008 was included in accounts
payable-trade in the consolidated balance sheet as of
December 31, 2007, and the payment to be made on
July 1, 2009 has been included in accounts payable-trade in
the consolidated balance sheet as of December 31, 2008. The
non-current unpaid settlement amounts of $10.0 million and
$15.0 million have been included in other long-term
obligations in the consolidated balance sheets as of
December 31, 2008 and December 31, 2007, respectively.
F-27
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
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, 2011.
A counterparty to one of the Companys derivative
contracts, Lehman Brothers, declared bankruptcy on
October 3, 2008. Due to Lehman Brothers bankruptcy
and the declaration of bankruptcy by its parent, Lehman Brothers
Holdings, Inc., on September 15, 2008, the Company has not
assigned any value to this derivative contract as of
December 31, 2008.
At December 31, 2008, the Companys open natural gas
and crude oil commodity derivative contracts consisted of the
following:
Natural
Gas
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Weighted Avg.
|
|
Period and Type of Contract
|
|
(MMcf)(1)
|
|
|
Fixed Price
|
|
|
January 2009 March 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
20,700
|
|
|
$
|
9.14
|
|
Basis swap contracts
|
|
|
15,300
|
|
|
$
|
(0.74
|
)
|
April 2009 June 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
20,930
|
|
|
$
|
7.96
|
|
Basis swap contracts
|
|
|
15,470
|
|
|
$
|
(0.74
|
)
|
July 2009 September 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
18,710
|
|
|
$
|
8.09
|
|
Basis swap contracts
|
|
|
15,640
|
|
|
$
|
(0.74
|
)
|
October 2009 December 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
18,400
|
|
|
$
|
8.54
|
|
Basis swap contracts
|
|
|
15,640
|
|
|
$
|
(0.74
|
)
|
January 2010 March 2010
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
16,875
|
|
|
$
|
8.08
|
|
Basis swap contracts
|
|
|
14,400
|
|
|
$
|
(0.73
|
)
|
April 2010 June 2010
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
17,063
|
|
|
$
|
7.38
|
|
Basis swap contracts
|
|
|
14,560
|
|
|
$
|
(0.73
|
)
|
July 2010 September 2010
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
17,250
|
|
|
$
|
7.61
|
|
Basis swap contracts
|
|
|
14,720
|
|
|
$
|
(0.73
|
)
|
October 2010 December 2010
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
17,250
|
|
|
$
|
8.03
|
|
Basis swap contracts
|
|
|
14,720
|
|
|
$
|
(0.73
|
)
|
January 2011 March 2011
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
1,350
|
|
|
$
|
(0.47
|
)
|
April 2011 June 2011
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
1,365
|
|
|
$
|
(0.47
|
)
|
July 2011 September 2011
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
1,380
|
|
|
$
|
(0.47
|
)
|
October 2011 December 2011
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
1,380
|
|
|
$
|
(0.47
|
)
|
|
|
|
(1) |
|
Assumes ratio of 1:1 for Mcf to MMBtu and excludes a total
notional of 7,300 MMcf from 2009 for the Lehman
Brothers basis swap contract. |
F-28
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Crude
Oil
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Weighted Avg.
|
|
Period and Type of Contract
|
|
(in MBbls)
|
|
|
Fixed Price
|
|
|
January 2009 March 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
45
|
|
|
$
|
126.38
|
|
April 2009 June 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
46
|
|
|
$
|
126.71
|
|
July 2009 September 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
46
|
|
|
$
|
126.61
|
|
October 2009 December 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
46
|
|
|
$
|
126.51
|
|
These derivatives have not been designated as hedges. The
Company records all derivatives in the consolidated balance
sheets 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 table
summarizes the cash settlements and valuation gains and losses
on the commodity derivative contracts for the years ended
December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Realized loss (gain)
|
|
$
|
12,981
|
|
|
$
|
(34,494
|
)
|
|
$
|
(14,169
|
)
|
Unrealized (gain) loss
|
|
|
(224,420
|
)
|
|
|
(26,238
|
)
|
|
|
1,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) loss on derivative contracts
|
|
$
|
(211,439
|
)
|
|
$
|
(60,732
|
)
|
|
$
|
(12,291
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In January 2008, the Company entered into an interest rate swap
to fix the variable LIBOR interest rate on its floating rate
senior term loan at 6.26% per annum for the period April 1,
2008 to April 1, 2011. Due to the exchange of the floating
rate senior term loan for Senior Floating Rate Notes, the
interest rate swap is now being used to fix the variable LIBOR
interest rate on the Senior Floating Rate Notes at 6.26% per
annum through April 2011.
An unrealized loss of $8.7 million and realized gains of
$1.3 million related to the interest rate swap were
included in interest expense in the consolidated statement of
operations for the year ended December 31, 2008.
|
|
15.
|
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. 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. The plan was also modified to make the
matching contributions payable in Company common stock. Accrued
payables for the employer matching contribution in the amounts
of $0.3 million and $5.2 million are reflected in the
consolidated balance sheets as of December 31, 2008 and
2007, respectively. In February 2008, the Company satisfied its
matching obligation related to employees contributions
made in 2007 through a transfer of treasury stock. During June
2007, the Company satisfied its matching obligation related to
employees contributions made in 2006 through a transfer of
treasury stock. See Note 20. For 2008, 2007 and 2006,
retirement plan expense was approximately $7.8 million,
$4.9 million and $1.5 million, respectively.
Deferred Compensation Plan. Effective
February 1, 2007 the Company established a non-qualified
deferred compensation plan that allows eligible highly
compensated employees to elect to defer income in excess of the
IRA annual limitations on qualified 401(k) retirement plans. The
2008 annual 401(k) deferral limit for employees under
age 50 was $15,500. Employees turning age 50 or over
in 2008 could defer up to $20,500. The Company makes
F-29
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
matching contributions on non-qualified contributions up to a
maximum of 15% of employee gross earnings. Accrued payables for
the employer matching contribution in the amounts of
$0.1 million and $0.8 million were included in the
consolidated balance sheets as of December 31, 2008 and
2007, respectively. In July 2008, the Company satisfied its
matching obligation related to employees contributions
made in 2007 and first quarter of 2008 through a transfer of
treasury stock. See Note 20. For 2008 and 2007, deferred
compensation expense was approximately $2.3 million and
$0.6 million, respectively.
Deferred income taxes reflect the net tax effects of temporary
differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts
used for income tax reporting. Deferred tax assets are reduced
by a valuation allowance if it is deemed more likely than not
that some or all of the deferred assets will not be realized
based on the weight of all available evidence. As of
December 31, 2008, the Company had recorded a full
valuation allowance against its net deferred tax asset.
Significant components of the Companys deferred tax assets
and liabilities are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Derivative contracts
|
|
$
|
85,645
|
|
|
$
|
8,002
|
|
Investment in partnerships
|
|
|
|
|
|
|
933
|
|
Property, plant & equipment
|
|
|
|
|
|
|
45,537
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
85,645
|
|
|
|
54,472
|
|
|
|
|
|
|
|
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
|
559,946
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
|
1,414
|
|
|
|
1,744
|
|
Net operating loss carryforwards-acquired
|
|
|
1,622
|
|
|
|
2,397
|
|
Investment in and notes receivable from partnerships
|
|
|
1,880
|
|
|
|
|
|
Stock-based compensation
|
|
|
6,691
|
|
|
|
961
|
|
Minimum tax credit carryforward
|
|
|
1,297
|
|
|
|
528
|
|
Other
|
|
|
2,870
|
|
|
|
1,312
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
575,720
|
|
|
|
6,942
|
|
|
|
|
|
|
|
|
|
|
Valuation allowance
|
|
|
(490,075
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
|
|
|
$
|
47,530
|
|
|
|
|
|
|
|
|
|
|
The provisions for income taxes consisted of the following
components for the years ended December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
4,537
|
|
|
$
|
|
|
|
$
|
3,235
|
|
State
|
|
|
4,665
|
|
|
|
601
|
|
|
|
2,653
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,202
|
|
|
|
601
|
|
|
|
5,888
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(46,180
|
)
|
|
|
28,121
|
|
|
|
345
|
|
State
|
|
|
(1,350
|
)
|
|
|
802
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(47,530
|
)
|
|
|
28,923
|
|
|
|
348
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (benefit) provision for income taxes
|
|
$
|
(38,328
|
)
|
|
$
|
29,524
|
|
|
$
|
6,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-30
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
A reconciliation of the provision for income taxes 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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Computed at federal statutory rates
|
|
$
|
(517,863
|
)
|
|
$
|
27,911
|
|
|
$
|
7,650
|
|
State taxes, net of federal benefit
|
|
|
(12,153
|
)
|
|
|
912
|
|
|
|
1,724
|
|
Nondeductible expenses
|
|
|
967
|
|
|
|
312
|
|
|
|
84
|
|
Percentage depletion deduction
|
|
|
|
|
|
|
|
|
|
|
(3,488
|
)
|
Change in rate
|
|
|
|
|
|
|
|
|
|
|
326
|
|
Other
|
|
|
646
|
|
|
|
389
|
|
|
|
(60
|
)
|
Change in valuation allowance
|
|
|
490,075
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (benefit) provision for income taxes
|
|
$
|
(38,328
|
)
|
|
$
|
29,524
|
|
|
$
|
6,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company, as of December 31, 2008, has approximately
$1.3 million of alternative minimum tax credits available
that do not expire. In addition, the Company has approximately
$1.6 million of acquired federal net operating loss
carryovers that expire during the years 2022 through 2025.
There were no uncertain income tax positions required to be
recorded pursuant to FASB Interpretation No. 48
Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109
(FIN 48). The Company files 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 due to net operating loss utilization. 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 interest or penalties at December 31, 2008.
|
|
17.
|
Earnings
(Loss) Per Share
|
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).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Weighted average basic common shares outstanding
|
|
|
155,619
|
|
|
|
108,828
|
|
|
|
73,727
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock
|
|
|
|
|
|
|
1,213
|
|
|
|
937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average diluted common and potential common shares
outstanding
|
|
|
155,619
|
|
|
|
110,041
|
|
|
|
74,664
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, 2008, restricted stock
awards covering approximately 3.0 million shares were
excluded from the computation of net loss per share because
their effect would have been antidilutive.
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 for the years ended
December 31, 2008 and 2007.
F-31
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
18.
|
Commitments
and Contingencies
|
Operating Leases. The Company has obligations
under noncancelable operating leases, primarily for the use of
office space. Total rental expense under operating leases for
the years ended December 31, 2008, 2007 and 2006 was
approximately $2.4 million, $2.3 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, 2008 are as follows (in thousands):
|
|
|
|
|
Years ending December 31:
|
|
|
|
|
2009
|
|
$
|
1,083
|
|
2010
|
|
|
239
|
|
2011
|
|
|
224
|
|
2012
|
|
|
113
|
|
2013
|
|
|
116
|
|
Thereafter
|
|
|
48
|
|
|
|
|
|
|
|
|
$
|
1,823
|
|
|
|
|
|
|
Rig Commitments. The Company has contracts
with third-party drilling rig operators for the use of their
rigs at specified day rates. These commitments are not recorded
in the consolidated balance sheets. Minimum future commitments
as of December 31, 2008 are $15.8 million for 2009 and
$1.2 million for 2010.
Firm Transportation. The Company has
subscribed firm gas transportation service under two
Transportation Service Agreements (TSA). The TSA terms run
through 2012 on the Oasis Pipeline and through 2018 on the
Midcontinent Express Pipeline. These commitments are not
recorded in the consolidated balance sheets. Under the terms of
the TSAs, the Company is obligated to pay a demand charge and in
exchange, obtains the right to flow natural gas production
through these pipelines to more competitive marketing areas. The
amounts of the required payments for firm transportation as of
December 31, 2008 were as follows (in thousands):
|
|
|
|
|
Years ending December 31:
|
|
|
|
|
2009
|
|
$
|
22,810
|
|
2010
|
|
|
36,195
|
|
2011
|
|
|
31,320
|
|
2012
|
|
|
31,406
|
|
2013
|
|
|
25,392
|
|
Thereafter
|
|
|
84,688
|
|
|
|
|
|
|
|
|
$
|
231,811
|
|
|
|
|
|
|
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 or cash flows of the Company.
Loan to Equity Investee. The Company, through
its subsidiary Lariat, has entered into a revolving promissory
note with Larclay for an aggregate principal amount of up to
$15.0 million. See Notes 8 and 21.
|
|
19.
|
Redeemable
Convertible Preferred Stock
|
In November 2006, the Company sold 2,136,667 shares of
redeemable convertible preferred stock to finance a portion of
the NEG acquisition and received net proceeds of approximately
$439.5 million after deducting offering expenses of
approximately $9.3 million. Each holder of redeemable
convertible preferred stock was entitled to
F-32
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
quarterly cash dividends at the annual rate of 7.75% of the
accreted value, or $210 per share, of their redeemable
convertible preferred stock. Each share of redeemable
convertible preferred stock was initially convertible into ten
shares, and ultimately convertible into 10.2 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
|
|
|
Payment Date
|
|
January 31, 2007
|
|
November 21, 2006 February 1, 2007
|
|
$
|
3.21
|
|
|
$
|
6,859
|
|
|
February 15, 2007
|
May 8, 2007
|
|
February 2, 2007 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
|
March 7, 2008
|
|
February 2, 2008 May 1, 2008
|
|
|
4.01
|
|
|
|
8,095
|
|
|
(1)
|
May 7, 2008
|
|
May 2, 2008 May 7, 2008
|
|
|
4.01
|
|
|
|
501
|
|
|
May 7, 2008
|
|
|
|
(1) |
|
Includes $0.6 million of prorated dividends paid to holders
of redeemable convertible preferred shares at the time their
shares converted to common stock in March 2008. The remaining
dividends of $7.5 million were paid during May 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 converted
526,316 shares of common stock into 47,619 shares of
redeemable convertible preferred stock.
During March 2008, holders of 339,823 shares of the
Companys redeemable convertible preferred stock elected to
convert those shares into 3,465,593 shares of the
Companys common stock. Additionally, during May 2008,
the Company converted the remaining outstanding
1,844,464 shares of its redeemable convertible preferred
stock into 18,810,260 shares of its common stock as
permitted under the terms of the redeemable convertible
preferred stock. These conversions resulted in increases to
additional paid-in capital totaling $452.2 million, which
represents the difference between the par value of the common
stock issued and the carrying value of the redeemable
convertible shares converted. The Company also recorded charges
to retained earnings totaling $7.2 million in accelerated
accretion expense related to the converted redeemable
convertible preferred shares. Prorated dividends totaling
$0.5 million for the period from May 2, 2008 to the
date of conversion (May 7, 2008) were paid to the
holders of the converted shares on May 7, 2008. On and
after the conversion date, dividends ceased to accrue and the
rights of common unit holders to exercise outstanding warrants
to purchase redeemable convertible preferred shares terminated.
Approximately $8.6 million and $38.5 million in paid
and unpaid dividends have been included in the Companys
earnings per share calculations for the years ended
December 31, 2008 and 2007, respectively, as presented in
the consolidated statements of operations.
The following table presents information regarding
SandRidges common stock (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Shares authorized
|
|
|
400,000
|
|
|
|
400,000
|
|
Shares outstanding at end of period
|
|
|
166,046
|
|
|
|
141,843
|
|
Shares held in treasury
|
|
|
1,326
|
|
|
|
1,456
|
|
F-33
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
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 stock. As of December 31, 2007, there were
2,184,286 shares of redeemable convertible preferred stock
outstanding and no other shares of preferred stock were
outstanding. All shares of redeemable convertible preferred
stock outstanding were converted to shares of the Companys
common stock during 2008. See Note 19. There were no shares
of preferred stock outstanding as of December 31, 2008.
Common Stock Issuance. In January 2006, the
Company issued 239,630 shares of common stock upon exercise
of an over-allotment option related to a December 2005 private
placement of its common stock. 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 the Companys Chairman 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 the initial
public offering of its common stock. The Company sold
32,379,500 shares of its common stock, including
4,710,000 shares sold directly to an entity controlled by
the Companys Chairman and Chief Executive Officer, at a
price of $26.00 per share. After deducting underwriting
discounts of approximately $44.0 million and offering
expenses of approximately $3.1 million, the Company
received net proceeds of approximately $794.7 million. The
Company used the net proceeds from the offering 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
|
|
|
|
|
|
|
During March 2008, the Company issued 3,465,593 shares of
common stock upon the conversion of 339,823 shares of its
redeemable convertible preferred stock. In May 2008, the Company
converted the remaining outstanding 1,844,464 shares of its
redeemable convertible preferred stock into
18,810,260 shares of its common stock as permitted under
the terms of the redeemable convertible preferred stock. See
additional discussion in Note 19.
Treasury Stock. The Company makes required tax
payments on behalf of employees when their restricted 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
80,724 shares at a total value of $3.6 million and
44,649 shares at a total value of $0.8 million during
the years ended December 31, 2008 and 2007, 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
F-34
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
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.
In February 2008, the Company transferred 184,484 shares of
its treasury stock into an account established for the benefit
of the Companys 401(k) Plan. The transfer was made in
order to satisfy the Companys $5.0 million accrued
payable to match employee contributions made to the plan during
2007. The historical cost of the shares transferred totaled
approximately $2.4 million and resulted in an increase to
the Companys additional paid-in capital of approximately
$2.6 million.
During July 2008, the Company transferred 26,058 shares of
its treasury stock into an account established for the benefit
of the Companys non-qualified deferred compensation plan.
This transfer was made in order to satisfy the Companys
$1.0 million accrued payable to match participant
contributions made to the non-qualified plan through
March 31, 2008. The historical cost of the shares
transferred totaled approximately $0.4 million and resulted
in an increase to the Companys additional paid-in capital
of approximately $0.6 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 for 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 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 were
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,
2008 was as follows (shares in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
Number of
|
|
|
Average Grant
|
|
|
|
Shares
|
|
|
Date Fair Value
|
|
|
Unvested restricted shares outstanding at December 31, 2007
|
|
|
1,927
|
|
|
$
|
19.25
|
|
Granted
|
|
|
1,638
|
|
|
$
|
41.15
|
|
Vested
|
|
|
(440
|
)
|
|
$
|
30.47
|
|
Canceled
|
|
|
(132
|
)
|
|
$
|
19.41
|
|
|
|
|
|
|
|
|
|
|
Unvested restricted shares outstanding at December 31, 2008
|
|
|
2,993
|
|
|
$
|
30.71
|
|
|
|
|
|
|
|
|
|
|
F-35
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
For the years ended December 31, the Company recognized
stock-based compensation expense related to restricted stock of
approximately $18.8 million in 2008, $7.2 million in
2007 and $8.8 million in 2006. Stock-based compensation
expense is reflected in general and administrative expense in
the consolidated statements of operations.
As of December 31, 2008, there was approximately
$73.3 million of unrecognized compensation cost related to
unvested restricted stock awards, which is expected to be
recognized over a weighted average period of 3.0 years.
|
|
21.
|
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 related
parties for the years ended December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Sales to and reimbursements from related parties
|
|
$
|
90,170
|
|
|
$
|
118,631
|
|
|
$
|
14,102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of services from related parties
|
|
$
|
59,951
|
|
|
$
|
77,555
|
|
|
$
|
4,811
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In August 2006, the Company sold various non-energy related
assets to the Companys former President and Chief
Operating Officer 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 company owned by 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 $1.4 million, $1.3 million and $0.3 million
for the years ended December 31, 2008, 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.
In October 2008, the Company purchased certain working interests
and related reserves in company wells owned by its Chairman and
Chief Executive Officer and certain of his affiliates. The
purchase price was approximately $67.3 million. See
Note 2.
Larclay, L.P. Lariat and CWEI each own a 50%
interest in Larclay. Larclay currently owns twelve rigs, one of
which has not yet been assembled. Larclay financed the
acquisition cost of its twelve rigs with a loan from a third
party, secured by the purchased rigs, and a loan from CWEI. In
addition, CWEI has guaranteed a portion of the third party debt.
Lariat operates the rigs owned by the partnership.
If Larclay has an operating shortfall, Lariat and CWEI are
obligated to provide loans to the partnership. In April 2008,
Lariat and CWEI each made loans of $2.5 million to Larclay
under promissory notes. The notes bear interest at a floating
rate based on a LIBOR average plus 3.25% (5.1875% at
December 31, 2008) as provided in the Larclay
partnership agreement. In June 2008, Larclay executed a
$15.0 million revolving promissory note with each Lariat
and CWEI. Amounts drawn under each revolving promissory note
bear interest at a floating rate based on a LIBOR average plus
3.25% (5.1875% at December 31, 2008) as provided in
the Larclay partnership agreement. Lariat advanced
$5.0 million to Larclay under the revolving promissory note
during the year ended December 31, 2008. Total advances
outstanding to Larclay were $7.5 million ($2.5 million
promissory note and $5.0 million drawn on revolving
promissory note) at December 31, 2008. The cash shortfalls
experienced by Larclay in 2008
F-36
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
were the result of principal payments due pursuant to its rig
loan agreement. As a result of current economic conditions and
continued cash shortfalls for Larclay, the Company has impaired
both its investment in and notes receivable due from Larclay as
of December 31, 2008. See Note 8.
The following table summarizes the Companys other
transactions with Larclay for the years ended December 31,
2008, 2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Sales to and reimbursements from Larclay
|
|
$
|
42,757
|
|
|
$
|
53,256
|
|
|
$
|
1,592
|
|
Purchases of services from Larclay
|
|
$
|
34,747
|
|
|
$
|
33,297
|
|
|
$
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Accounts receivable from Larclay
|
|
$
|
6,060
|
|
|
$
|
16,625
|
|
Accounts payable to Larclay
|
|
$
|
152
|
|
|
$
|
274
|
|
See Note 2 for a discussion of additional related party
transactions.
Private Placement of Convertible Perpetual Preferred
Stock. In January 2009, the Company commenced and
completed a private placement of 2,650,000 shares of a new
series of 8.5% convertible perpetual preferred stock to
qualified institutional buyers eligible under Rule 144A
under the Securities Act. Net proceeds from the offering were
approximately $243.9 million after applying a discount to
the purchase price of the stock and deducting offering expenses
of approximately $8.0 million. The Company will use the net
proceeds of the offering to repay outstanding borrowings under
its senior credit facility and for general corporate purposes.
Marketing of Midstream Assets. In January
2009, the Company announced its intent to offer for sale certain
of its gas gathering and related assets located in the WTO. The
carrying value of these assets was $228.8 million at
December 31, 2008. This process is ongoing as of the date
of this filing.
|
|
23.
|
Industry
Segment Information
|
The Company operates in four related business segments:
exploration and production, drilling and oil field services,
midstream gas services and other ancillary business activities.
These segments represent the Companys four main business
units, each offering different products and services. The
exploration and production segment is engaged in the
development, acquisition and production of natural gas and crude
oil properties. The drilling and oil field services segment is
engaged in the land contract drilling of natural gas and crude
oil wells. The midstream gas services segment is engaged in the
purchasing, gathering, processing and treating of natural gas.
The other segment includes transporting
CO2
to market for use in tertiary oil recovery operations by the
Company and third parties and other miscellaneous operations.
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 the Companys
business segments based on operating income (loss), which is
defined as segment operating revenues less operating expenses
and depreciation, depletion,
F-37
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
amortization and impairment. Summarized financial information
concerning the Companys segments is shown in the following
table (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
912,716
|
|
|
$
|
479,321
|
|
|
$
|
106,990
|
|
Elimination of inter-segment revenue
|
|
|
220
|
|
|
|
574
|
|
|
|
577
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production, net of inter-segment revenue
|
|
|
912,496
|
|
|
|
478,747
|
|
|
|
106,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and oil field services
|
|
|
434,963
|
|
|
|
261,818
|
|
|
|
211,055
|
|
Elimination of inter-segment revenue
|
|
|
387,972
|
|
|
|
188,616
|
|
|
|
72,398
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and oil field services, net of inter-segment revenue
|
|
|
46,991
|
|
|
|
73,202
|
|
|
|
138,657
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream gas services
|
|
|
688,071
|
|
|
|
285,065
|
|
|
|
192,960
|
|
Elimination of inter-segment revenue
|
|
|
483,933
|
|
|
|
177,487
|
|
|
|
70,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream gas services, net of inter-segment revenues
|
|
|
204,138
|
|
|
|
107,578
|
|
|
|
122,892
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
22,791
|
|
|
|
29,286
|
|
|
|
21,411
|
|
Elimination of inter-segment revenue
|
|
|
4,602
|
|
|
|
11,361
|
|
|
|
1,131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other, net of inter-segment revenue
|
|
|
18,189
|
|
|
|
17,925
|
|
|
|
20,280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
1,181,814
|
|
|
$
|
677,452
|
|
|
$
|
388,242
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
(1,263,249
|
)
|
|
$
|
198,913
|
|
|
$
|
17,069
|
|
Drilling and oil field services
|
|
|
(5,393
|
)
|
|
|
10,473
|
|
|
|
32,946
|
|
Midstream gas services
|
|
|
2,087
|
|
|
|
6,783
|
|
|
|
3,528
|
|
Other
|
|
|
(71,592
|
)
|
|
|
(29,310
|
)
|
|
|
(16,562
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating (loss) income
|
|
|
(1,338,147
|
)
|
|
|
186,859
|
|
|
|
36,981
|
|
Interest expense, net
|
|
|
(143,458
|
)
|
|
|
(111,762
|
)
|
|
|
(15,795
|
)
|
Other income (expense), net
|
|
|
1,997
|
|
|
|
4,648
|
|
|
|
671
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
$
|
(1,479,608
|
)
|
|
$
|
79,745
|
|
|
$
|
21,857
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
2,986,070
|
|
|
$
|
3,143,137
|
|
|
$
|
2,091,459
|
|
Drilling and oil field services
|
|
|
275,164
|
|
|
|
271,563
|
|
|
|
175,169
|
|
Midstream gas services
|
|
|
284,281
|
|
|
|
127,822
|
|
|
|
75,606
|
|
Other
|
|
|
109,543
|
|
|
|
88,044
|
|
|
|
46,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,655,058
|
|
|
$
|
3,630,566
|
|
|
$
|
2,388,384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
1,909,078
|
|
|
$
|
1,046,552
|
|
|
$
|
170,872
|
|
Drilling and oil field services
|
|
|
52,869
|
|
|
|
123,232
|
|
|
|
89,810
|
|
Midstream gas services
|
|
|
160,460
|
|
|
|
63,828
|
|
|
|
16,975
|
|
Other
|
|
|
55,440
|
|
|
|
47,236
|
|
|
|
28,884
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
2,177,847
|
|
|
$
|
1,280,848
|
|
|
$
|
306,541
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
293,625
|
|
|
$
|
175,565
|
|
|
$
|
28,104
|
|
Drilling and oil field services
|
|
|
42,077
|
|
|
|
37,792
|
|
|
|
20,268
|
|
Midstream gas services
|
|
|
15,241
|
|
|
|
6,641
|
|
|
|
3,180
|
|
Other
|
|
|
10,422
|
|
|
|
7,111
|
|
|
|
4,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation, depletion and amortization
|
|
$
|
361,365
|
|
|
$
|
227,109
|
|
|
$
|
55,626
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-38
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Major Customer. During 2008 and 2007, the
Company had sales in excess of 10% of total revenues to a
natural gas and oil purchaser ($124.6 million or 10.5% of
total revenues and $76.1 million or 11.2% of total
revenues, respectively). There were no customers that accounted
for 10% or more of total revenues in 2006.
|
|
24.
|
Condensed
Consolidating Financial Information
|
The Company is providing condensed consolidating financial
information for its subsidiaries that are guarantors of its
public debt. Subsidiary guarantors are wholly owned and have,
jointly and severally, unconditionally guaranteed on an
unsecured basis the Companys 8.625% Senior Notes due
2015, Senior Floating Rate Notes due 2014 and 8.0% Senior
Notes due 2018. The subsidiary guarantees (i) rank equally
in right of payment with all of the existing and future senior
debt of the subsidiary guarantors; (ii) rank senior to all
of the existing and future subordinated debt of the subsidiary
guarantors; (iii) are effectively subordinated in right of
payment to any existing or future secured obligations of the
subsidiary guarantors to the extent of the value of the assets
securing such obligations; and (iv) are structurally
subordinated to all debt and other obligations of the
subsidiaries of the guarantors who are not themselves guarantors.
The Company has not presented separate financial and narrative
information for each of the subsidiary guarantors because it
believes that such financial and narrative information would not
provide any additional information that would be material in
evaluating the sufficiency of the guarantees.
The following condensed consolidating financial information
represents the financial information of SandRidge Energy, Inc.
and its wholly owned subsidiary guarantors, prepared on the
equity basis of accounting. The non-guarantor subsidiaries are
minor and, therefore, not presented separately. The information
is presented in accordance with the requirements of
Rule 3-10
under the SECs
Regulation S-X.
The financial information may not necessarily be indicative of
the financial position, results of operations, or cash flows had
the subsidiary guarantors operated as independent entities.
F-39
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Condensed
Consolidating Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
December 31, 2007
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
18
|
|
|
$
|
618
|
|
|
$
|
|
|
|
$
|
636
|
|
|
$
|
62,967
|
|
|
$
|
168
|
|
|
$
|
|
|
|
$
|
63,135
|
|
Accounts and notes receivable, net
|
|
|
863,129
|
|
|
|
66,463
|
|
|
|
(820,519
|
)
|
|
|
109,073
|
|
|
|
557,527
|
|
|
|
85,947
|
|
|
|
(528,715
|
)
|
|
|
114,759
|
|
Derivative contracts
|
|
|
201,111
|
|
|
|
|
|
|
|
|
|
|
|
201,111
|
|
|
|
21,958
|
|
|
|
|
|
|
|
|
|
|
|
21,958
|
|
Other current assets
|
|
|
3,194
|
|
|
|
41,899
|
|
|
|
|
|
|
|
45,093
|
|
|
|
5,936
|
|
|
|
20,664
|
|
|
|
|
|
|
|
26,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,067,452
|
|
|
|
108,980
|
|
|
|
(820,519
|
)
|
|
|
355,913
|
|
|
|
648,388
|
|
|
|
106,779
|
|
|
|
(528,715
|
)
|
|
|
226,452
|
|
Property, plant and equipment, net
|
|
|
1,106,623
|
|
|
|
2,068,936
|
|
|
|
|
|
|
|
3,175,559
|
|
|
|
967,259
|
|
|
|
2,370,151
|
|
|
|
|
|
|
|
3,337,410
|
|
Investment in subsidiaries
|
|
|
1,002,336
|
|
|
|
|
|
|
|
(1,002,336
|
)
|
|
|
|
|
|
|
1,817,330
|
|
|
|
|
|
|
|
(1,817,330
|
)
|
|
|
|
|
Other assets
|
|
|
135,161
|
|
|
|
39,809
|
|
|
|
(51,384
|
)
|
|
|
123,586
|
|
|
|
77,614
|
|
|
|
40,474
|
|
|
|
(51,384
|
)
|
|
|
66,704
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,311,572
|
|
|
$
|
2,217,725
|
|
|
$
|
(1,874,239
|
)
|
|
$
|
3,655,058
|
|
|
$
|
3,510,591
|
|
|
$
|
2,517,404
|
|
|
$
|
(2,397,429
|
)
|
|
$
|
3,630,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
163,068
|
|
|
$
|
1,024,018
|
|
|
$
|
(820,519
|
)
|
|
$
|
366,567
|
|
|
$
|
224,015
|
|
|
$
|
520,592
|
|
|
$
|
(528,715
|
)
|
|
$
|
215,892
|
|
Other current liabilities
|
|
|
5,106
|
|
|
|
30,951
|
|
|
|
|
|
|
|
36,057
|
|
|
|
|
|
|
|
16,214
|
|
|
|
|
|
|
|
16,214
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
168,174
|
|
|
|
1,054,969
|
|
|
|
(820,519
|
)
|
|
|
402,624
|
|
|
|
224,015
|
|
|
|
536,806
|
|
|
|
(528,715
|
)
|
|
|
232,106
|
|
Long-term debt
|
|
|
2,323,458
|
|
|
|
86,710
|
|
|
|
(51,384
|
)
|
|
|
2,358,784
|
|
|
|
1,000,000
|
|
|
|
103,683
|
|
|
|
(51,384
|
)
|
|
|
1,052,299
|
|
Asset retirement obligation
|
|
|
12,759
|
|
|
|
71,738
|
|
|
|
|
|
|
|
84,497
|
|
|
|
4,620
|
|
|
|
53,096
|
|
|
|
|
|
|
|
57,716
|
|
Other liabilities
|
|
|
13,660
|
|
|
|
1,942
|
|
|
|
|
|
|
|
15,602
|
|
|
|
15,000
|
|
|
|
1,817
|
|
|
|
|
|
|
|
16,817
|
|
Deferred income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49,350
|
|
|
|
|
|
|
|
|
|
|
|
49,350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
2,518,051
|
|
|
|
1,215,359
|
|
|
|
(871,903
|
)
|
|
|
2,861,507
|
|
|
|
1,292,985
|
|
|
|
695,402
|
|
|
|
(580,099
|
)
|
|
|
1,408,288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interest
|
|
|
|
|
|
|
30
|
|
|
|
|
|
|
|
30
|
|
|
|
|
|
|
|
4,672
|
|
|
|
|
|
|
|
4,672
|
|
Redeemable convertible preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
450,715
|
|
|
|
|
|
|
|
|
|
|
|
450,715
|
|
Stockholders equity
|
|
|
793,521
|
|
|
|
1,002,336
|
|
|
|
(1,002,336
|
)
|
|
|
793,521
|
|
|
|
1,766,891
|
|
|
|
1,817,330
|
|
|
|
(1,817,330
|
)
|
|
|
1,766,891
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
3,311,572
|
|
|
$
|
2,217,725
|
|
|
$
|
(1,874,239
|
)
|
|
$
|
3,655,058
|
|
|
$
|
3,510,591
|
|
|
$
|
2,517,404
|
|
|
$
|
(2,397,429
|
)
|
|
$
|
3,630,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-40
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Condensed
Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
329,109
|
|
|
$
|
855,184
|
|
|
$
|
(2,479
|
)
|
|
$
|
1,181,814
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
72,473
|
|
|
|
323,172
|
|
|
|
(2,479
|
)
|
|
|
393,166
|
|
General and administrative
|
|
|
40,638
|
|
|
|
68,734
|
|
|
|
|
|
|
|
109,372
|
|
Depreciation, depletion, amortization and impairment
|
|
|
957,509
|
|
|
|
1,271,353
|
|
|
|
|
|
|
|
2,228,862
|
|
Gain on derivative contracts
|
|
|
(211,439
|
)
|
|
|
|
|
|
|
|
|
|
|
(211,439
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
859,181
|
|
|
|
1,663,259
|
|
|
|
(2,479
|
)
|
|
|
2,519,961
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from operations
|
|
|
(530,072
|
)
|
|
|
(808,075
|
)
|
|
|
|
|
|
|
(1,338,147
|
)
|
Equity earnings from subsidiaries
|
|
|
(809,594
|
)
|
|
|
|
|
|
|
809,594
|
|
|
|
|
|
Interest expense
|
|
|
(142,843
|
)
|
|
|
(4,184
|
)
|
|
|
|
|
|
|
(147,027
|
)
|
Other income (expense), net
|
|
|
2,857
|
|
|
|
2,709
|
|
|
|
|
|
|
|
5,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income tax (benefit) expense
|
|
|
(1,479,652
|
)
|
|
|
(809,550
|
)
|
|
|
809,594
|
|
|
|
(1,479,608
|
)
|
Income tax (benefit) expense
|
|
|
(38,372
|
)
|
|
|
44
|
|
|
|
|
|
|
|
(38,328
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,441,280
|
)
|
|
$
|
(809,594
|
)
|
|
$
|
809,594
|
|
|
$
|
(1,441,280
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
139,281
|
|
|
$
|
538,171
|
|
|
$
|
|
|
|
$
|
677,452
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
33,643
|
|
|
|
228,793
|
|
|
|
|
|
|
|
262,436
|
|
General and administrative
|
|
|
32,446
|
|
|
|
29,334
|
|
|
|
|
|
|
|
61,780
|
|
Depreciation, depletion, and amortization
|
|
|
43,257
|
|
|
|
183,852
|
|
|
|
|
|
|
|
227,109
|
|
Gain on derivative contracts
|
|
|
(26,183
|
)
|
|
|
(34,549
|
)
|
|
|
|
|
|
|
(60,732
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
83,163
|
|
|
|
407,430
|
|
|
|
|
|
|
|
490,593
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
56,118
|
|
|
|
130,741
|
|
|
|
|
|
|
|
186,859
|
|
Equity earnings from subsidiaries
|
|
|
137,515
|
|
|
|
|
|
|
|
(137,515
|
)
|
|
|
|
|
Interest expense
|
|
|
(113,838
|
)
|
|
|
(3,347
|
)
|
|
|
|
|
|
|
(117,185
|
)
|
Other (expense) income, net
|
|
|
(81
|
)
|
|
|
10,152
|
|
|
|
|
|
|
|
10,071
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income tax expense
|
|
|
79,714
|
|
|
|
137,546
|
|
|
|
(137,515
|
)
|
|
|
79,745
|
|
Income tax expense
|
|
|
29,493
|
|
|
|
31
|
|
|
|
|
|
|
|
29,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
50,221
|
|
|
$
|
137,515
|
|
|
$
|
(137,515
|
)
|
|
$
|
50,221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
63,041
|
|
|
$
|
325,201
|
|
|
$
|
|
|
|
$
|
388,242
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
25,773
|
|
|
|
226,519
|
|
|
|
|
|
|
|
252,292
|
|
General and administrative
|
|
|
31,904
|
|
|
|
23,730
|
|
|
|
|
|
|
|
55,634
|
|
Depreciation, depletion, and amortization
|
|
|
24,500
|
|
|
|
31,126
|
|
|
|
|
|
|
|
55,626
|
|
(Gain) loss on derivative contracts
|
|
|
(12,327
|
)
|
|
|
36
|
|
|
|
|
|
|
|
(12,291
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
69,850
|
|
|
|
281,411
|
|
|
|
|
|
|
|
351,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from operations
|
|
|
(6,809
|
)
|
|
|
43,790
|
|
|
|
|
|
|
|
36,981
|
|
Equity earnings from subsidiaries
|
|
|
36,470
|
|
|
|
|
|
|
|
(36,470
|
)
|
|
|
|
|
Interest expense
|
|
|
(14,222
|
)
|
|
|
(2,682
|
)
|
|
|
|
|
|
|
(16,904
|
)
|
Other income (expense), net
|
|
|
425
|
|
|
|
1,355
|
|
|
|
|
|
|
|
1,780
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income tax expense
|
|
|
15,864
|
|
|
|
42,463
|
|
|
|
(36,470
|
)
|
|
|
21,857
|
|
Income tax expense
|
|
|
243
|
|
|
|
5,993
|
|
|
|
|
|
|
|
6,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
15,621
|
|
|
$
|
36,470
|
|
|
$
|
(36,470
|
)
|
|
$
|
15,621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-41
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Condensed
Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by operating activities
|
|
$
|
(309,359
|
)
|
|
$
|
888,548
|
|
|
$
|
|
|
|
$
|
579,189
|
|
Net cash used in investing activities
|
|
|
(1,042,633
|
)
|
|
|
(866,810
|
)
|
|
|
|
|
|
|
(1,909,443
|
)
|
Net cash provided by (used in) financing activities
|
|
|
1,289,043
|
|
|
|
(21,288
|
)
|
|
|
|
|
|
|
1,267,755
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
|
(62,949
|
)
|
|
|
450
|
|
|
|
|
|
|
|
(62,499
|
)
|
Cash and cash equivalents at beginning of year
|
|
|
62,967
|
|
|
|
168
|
|
|
|
|
|
|
|
63,135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
18
|
|
|
$
|
618
|
|
|
$
|
|
|
|
$
|
636
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by operating activities
|
|
$
|
(301,288
|
)
|
|
$
|
667,724
|
|
|
$
|
(8,984
|
)
|
|
$
|
357,452
|
|
Net cash used in investing activities
|
|
|
(728,697
|
)
|
|
|
(656,884
|
)
|
|
|
|
|
|
|
(1,385,581
|
)
|
Net cash provided by (used in) financing activities
|
|
|
1,061,505
|
|
|
|
(18,173
|
)
|
|
|
8,984
|
|
|
|
1,052,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
31,520
|
|
|
|
(7,333
|
)
|
|
|
|
|
|
|
24,187
|
|
Cash and cash equivalents at beginning of year
|
|
|
31,447
|
|
|
|
7,501
|
|
|
|
|
|
|
|
38,948
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
62,967
|
|
|
$
|
168
|
|
|
$
|
|
|
|
$
|
63,135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by operating activities
|
|
$
|
(33,775
|
)
|
|
$
|
94,570
|
|
|
$
|
6,554
|
|
|
$
|
67,349
|
|
Net cash used in investing activities
|
|
|
(1,212,910
|
)
|
|
|
(127,657
|
)
|
|
|
|
|
|
|
(1,340,567
|
)
|
Net cash provided by (used in) financing activities
|
|
|
1,233,555
|
|
|
|
39,434
|
|
|
|
(6,554
|
)
|
|
|
1,266,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
|
(13,130
|
)
|
|
|
6,347
|
|
|
|
|
|
|
|
(6,783
|
)
|
Cash and cash equivalents at beginning of year
|
|
|
44,577
|
|
|
|
1,154
|
|
|
|
|
|
|
|
45,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
31,447
|
|
|
$
|
7,501
|
|
|
$
|
|
|
|
$
|
38,948
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25.
|
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 crude 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.
F-42
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The Companys capitalized costs consisted of the following
(in thousands):
Capitalized
Costs Related to Oil and Gas Producing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Natural gas and crude oil properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
4,676,072
|
|
|
$
|
2,848,531
|
|
|
$
|
1,636,832
|
|
Unproved
|
|
|
215,698
|
|
|
|
259,610
|
|
|
|
282,374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas and crude oil properties
|
|
|
4,891,770
|
|
|
|
3,108,141
|
|
|
|
1,919,206
|
|
Less accumulated depreciation and depletion
|
|
|
(2,369,840
|
)
|
|
|
(230,974
|
)
|
|
|
(60,752
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net natural gas and crude oil properties capitalized costs
|
|
$
|
2,521,930
|
|
|
$
|
2,877,167
|
|
|
$
|
1,858,454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
Incurred in Property Acquisition, Exploration and Development
Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Acquisitions of properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
366,275
|
|
|
$
|
303,282
|
|
|
$
|
1,311,029
|
|
Unproved
|
|
|
16,982
|
|
|
|
|
|
|
|
268,839
|
|
Exploration(1)
|
|
|
391,672
|
|
|
|
361,973
|
|
|
|
18,612
|
|
Development
|
|
|
1,132,078
|
|
|
|
485,348
|
|
|
|
115,153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost incurred
|
|
$
|
1,907,007
|
|
|
$
|
1,150,603
|
|
|
$
|
1,713,633
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
2008 and 2007 amounts include seismic costs of
$68.8 million and $38.6 million, respectively. 2008
amount also includes pipe inventory costs of $47.2 million. |
F-43
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 2008, 2007 and 2006
are shown in the following table (in thousands):
Results
of Operations for Oil and Gas Producing Activities
|
|
|
|
|
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
|
|
|
|
|
|
|
For the Year Ended December 31, 2008
|
|
|
|
|
Revenues
|
|
$
|
908,689
|
|
Expenses:
|
|
|
|
|
Production costs
|
|
|
189,598
|
|
Depreciation, depletion, amortization and impairment expenses
|
|
|
2,140,685
|
|
|
|
|
|
|
Total expenses
|
|
|
2,330,283
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(1,421,594
|
)
|
Benefit of income taxes
|
|
|
(36,819
|
)
|
|
|
|
|
|
Results of operations for oil and gas producing activities
|
|
$
|
(1,384,775
|
)
|
|
|
|
|
|
Proved oil and gas reserves are the estimated quantities of 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 oil,
natural gas and natural gas liquids 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.
F-44
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The table below represents the Companys estimate of proved
natural gas and crude oil 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 SEC regulations. Estimates of substantially all
of the Companys proved reserves have been prepared by
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 SEC.
Netherland, Sewell & Associates, Inc. and DeGolyer and
MacNaughton, independent crude oil and gas consultants, have
prepared the estimates of proved reserves of natural gas and oil
attributable to substantially all of the Companys net
interest in natural gas and crude oil properties as of the end
of one or more of 2008, 2007 and 2006. Netherland,
Sewell & Associates, Inc. and DeGolyer and MacNaughton
are independent petroleum engineers, geologists, geophysicists
and petrophysicists and do not own an interest in the Company or
its properties and are not employed on a contingent basis.
Netherland, Sewell & Associates, Inc. prepared the
estimates of proved reserves for a majority of the
Companys properties other than those held by SandRidge
Tertiary, LLC (formerly PetroSource Production Co), which
constitute approximately 90% of the Companys total proved
reserves as of December 31, 2008. DeGolyer and MacNaughton
prepared the estimates of proved reserves for SandRidge
Tertiary, LLC, which constitute approximately 6% of our total
proved reserves as of December 31, 2008. 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.
During 2008, 2007 and 2006, the Company recognized additional
reserves attributable to extensions and discoveries as a result
of successful drilling in the Piñon Field. Drilling
expenditures of $129.8 million, $97.1 million and
$18.6 million resulted in the addition of 57.8 Bcfe,
44.7 Bcfe and 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 for 2008, 2007 and 2006, respectively. The
remaining 136.5 Bcfe, 55.1 Bcfe and 83.1 Bcfe of
net proved reserves for 2008, 2007 and 2006, respectively, are
proved undeveloped reserves associated with direct offsets to
the 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-45
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, 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
|
|
Revisions of previous estimates
|
|
|
6,738
|
|
|
|
412,155
|
|
Acquisitions of new reserves
|
|
|
513
|
|
|
|
38,008
|
|
Extensions and discoveries
|
|
|
1,728
|
|
|
|
241,596
|
|
Sales of reserves in place
|
|
|
(8
|
)
|
|
|
(1,750
|
)
|
Production
|
|
|
(2,334
|
)
|
|
|
(87,402
|
)
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008
|
|
|
43,164
|
|
|
|
1,899,636
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
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
|
|
As of December 31, 2008
|
|
|
15,342
|
|
|
|
851,357
|
|
|
|
|
(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 oil, natural gas and natural gas liquids 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,
|
|
|
2008
|
|
2007
|
|
2006
|
|
Natural gas (per Mcf)
|
|
$
|
4.94
|
|
|
$
|
6.46
|
|
|
$
|
5.32
|
|
Crude oil (per barrel)
|
|
$
|
39.42
|
|
|
$
|
87.47
|
|
|
$
|
54.62
|
|
F-46
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
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.
|
Standardized
Measure of Discounted Future Net Cash Flows Related to
Proved Oil and Gas Reserves
|
|
|
|
|
|
|
(In thousands)
|
|
|
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
|
|
|
|
|
|
|
As of December 31, 2008
|
|
|
|
|
Future cash inflows from production
|
|
$
|
11,092,154
|
|
Future production costs
|
|
|
(3,887,553
|
)
|
Future development costs(a)
|
|
|
(2,153,506
|
)
|
Future income tax expenses
|
|
|
(399,014
|
)
|
|
|
|
|
|
Undiscounted future net cash flows
|
|
|
4,652,081
|
|
10% annual discount
|
|
|
(2,431,505
|
)
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
2,220,576
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes abandonment costs. |
F-47
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, 2005
|
|
$
|
499,154
|
|
Changes during the year:
|
|
|
|
|
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
|
|
Changes during the year:
|
|
|
|
|
Revenues less production and other costs
|
|
|
(719,091
|
)
|
Net changes in prices, production and other costs
|
|
|
(1,747,962
|
)
|
Development costs incurred
|
|
|
1,132,078
|
|
Net changes in future development costs
|
|
|
(1,152,018
|
)
|
Extensions and discoveries
|
|
|
227,874
|
|
Revisions of previous quantity estimates
|
|
|
757,939
|
|
Accretion of discount
|
|
|
168,811
|
|
Net change in income taxes
|
|
|
794,001
|
|
Purchases of reserves in-place
|
|
|
47,767
|
|
Sales of reserves in-place
|
|
|
(2,076
|
)
|
Timing differences and other(a)
|
|
|
(5,284
|
)
|
|
|
|
|
|
Net change for the year
|
|
|
(497,961
|
)
|
|
|
|
|
|
Present value as of December 31, 2008
|
|
$
|
2,220,576
|
|
|
|
|
|
|
|
|
|
(a) |
|
The change in timing differences and other are related to
revisions in the Companys estimated time of production and
development. |
F-48
SandRidge
Energy, Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
26.
|
Quarterly
Financial Results (Unaudited)
|
The Companys operating results for each quarter of 2008
and 2007 are summarized below (in thousands, except per share
data).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
269,086
|
|
|
$
|
378,050
|
|
|
$
|
334,023
|
|
|
$
|
200,655
|
|
(Loss) income from operations
|
|
$
|
(62,811
|
)
|
|
$
|
(11,795
|
)
|
|
$
|
401,287
|
|
|
$
|
(1,664,828
|
)
|
Net (loss) income
|
|
$
|
(56,625
|
)
|
|
$
|
(20,343
|
)
|
|
$
|
230,346
|
|
|
$
|
(1,594,658
|
)
|
(Loss) income (applicable) available to common stockholders
|
|
$
|
(66,207
|
)
|
|
$
|
(26,993
|
)
|
|
$
|
230,346
|
|
|
$
|
(1,594,658
|
)
|
Net (loss) income per share (applicable) available to common
stockholders(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.47
|
)
|
|
$
|
(0.17
|
)
|
|
$
|
1.41
|
|
|
$
|
(9.78
|
)
|
Diluted
|
|
$
|
(0.47
|
)
|
|
$
|
(0.17
|
)
|
|
$
|
1.40
|
|
|
$
|
(9.78
|
)
|
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
149,064
|
|
|
$
|
159,063
|
|
|
$
|
153,648
|
|
|
$
|
215,677
|
|
Income from operations
|
|
$
|
3,468
|
|
|
$
|
75,160
|
|
|
$
|
59,716
|
|
|
$
|
48,515
|
|
Net (loss) income
|
|
$
|
(19,493
|
)
|
|
$
|
34,564
|
|
|
$
|
20,920
|
|
|
$
|
14,230
|
|
(Loss) income available (applicable) to common stockholders
|
|
$
|
(28,459
|
)
|
|
$
|
22,270
|
|
|
$
|
11,607
|
|
|
$
|
4,915
|
|
Basic and diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per share (applicable) available to common
stockholders(1)
|
|
$
|
(0.31
|
)
|
|
$
|
0.21
|
|
|
$
|
0.11
|
|
|
$
|
0.04
|
|
|
|
|
(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-49
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.
SANDRIDGE ENERGY, INC.
Tom L. Ward,
Chairman of the Board and Chief Executive Officer
February 26, 2009
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints Tom L. Ward, Richard J.
Gognat and Justin P. Byrne, and each of them severally, his true
and lawful attorney or attorneys-in-fact and agents, with full
power to act with or without the others and with full power of
substitution and resubstitution, to execute in his name, place
and stead, in any and all capacities, any or all amendments to
this report, and to file the same, with all exhibits thereto,
and other documents in connection therewith, with the Securities
and Exchange Commission, granting unto said attorneys-in-fact
and agents and each of them, full power and authority to do and
perform in the name of on behalf of the undersigned, in any and
all capacities, each and every act and thing necessary or
desirable to be done in and about the premises, to all intents
and purposes and as fully as they might or could do in person,
hereby ratifying, approving and confirming all that said
attorneys-in-fact and agents or their substitutes may lawfully
do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ Tom
L. Ward
Tom
L. Ward
|
|
President, Chief Executive Officer and Chairman of the Board
(Principal Executive Officer)
|
|
February 26, 2009
|
|
|
|
|
|
/s/ Dirk
M. Van Doren
Dirk
M. Van Doren
|
|
Chief Financial Officer and Executive Vice President (Principal
Financial Officer)
|
|
February 26, 2009
|
|
|
|
|
|
/s/ Randall
D. Cooley
Randall
D. Cooley
|
|
Senior Vice President Accounting (Principal
Accounting Officer)
|
|
February 26, 2009
|
|
|
|
|
|
/s/ Dan
Jordan
Dan
Jordan
|
|
Director
|
|
February 26, 2009
|
|
|
|
|
|
/s/ Bill
Gilliland
Bill
Gilliland
|
|
Director
|
|
February 26, 2009
|
|
|
|
|
|
/s/ Roy
T. Oliver, Jr.
Roy
T. Oliver, Jr.
|
|
Director
|
|
February 26, 2009
|
|
|
|
|
|
/s/ Stuart
W. Ray
Stuart
W. Ray
|
|
Director
|
|
February 26, 2009
|
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ D.
Dwight Scott
D.
Dwight Scott
|
|
Director
|
|
February 26, 2009
|
|
|
|
|
|
/s/ Jeff
Serota
Jeff
Serota
|
|
Director
|
|
February 26, 2009
|
EXHIBIT INDEX
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incorporated by Reference
|
Exhibit
|
|
|
|
|
|
SEC
|
|
|
|
|
|
Filed
|
No.
|
|
Exhibit Description
|
|
Form
|
|
File No.
|
|
Exhibit
|
|
Filing Date
|
|
Herewith
|
|
3.1
|
|
Certificate of Incorporation of SandRidge Energy, Inc.
|
|
S-1
|
|
333-148956
|
|
3.1
|
|
01/30/2008
|
|
|
3.2
|
|
Certificate of Designation of 8.5% Convertible Perpetual
Preferred Stock of SandRidge Energy, Inc.
|
|
8-K
|
|
001-33784
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3.1
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|
01/21/2009
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|
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3.3
|
|
Amended and Restated Bylaws of SandRidge Energy, Inc.
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10-Q
|
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001-33784
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|
3.3
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05/08/2008
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4.1
|
|
Specimen Stock Certificate representing common stock of
SandRidge Energy, Inc.
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S-1
|
|
333-148956
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|
4.1
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|
01/30/2008
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|
|
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
|
|
S-1
|
|
333-148956
|
|
4.3
|
|
01/30/2008
|
|
|
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
|
|
S-1
|
|
333-148956
|
|
4.7
|
|
01/30/2008
|
|
|
4.8
|
|
Registration Rights Agreement, dated March 20, 2007, by and
among SandRidge Energy, Inc. and the several purchasers party
thereto
|
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S-1
|
|
333-148956
|
|
4. 8
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|
01/30/2008
|
|
|
4.10
|
|
Shareholders Agreement, dated March 20, 2007, by and among
SandRidge Energy, Inc. and certain common shareholders
|
|
S-1
|
|
333-148956
|
|
4.10
|
|
01/30/2008
|
|
|
4.11
|
|
Indenture, dated May 1, 2008, by and among SandRidge Energy,
Inc., certain subsidiary guarantors named therein and Wells
Fargo Bank, National Association, as trustee
|
|
8-K
|
|
001-33784
|
|
4.1
|
|
05/02/2008
|
|
|
4.12
|
|
Registration Rights Agreement, dated May 1, 2008, by and among
SandRidge Energy, Inc. and certain guarantors named therein for
the benefit of noteholders
|
|
8-K
|
|
001-33784
|
|
4.2
|
|
05/02/2008
|
|
|
4.14
|
|
Indenture, dated May 20, 2008, by and among SandRidge Energy,
Inc., certain subsidiary guarantors named therein and Wells
Fargo Bank, National Association, as trustee
|
|
8-K
|
|
001-33784
|
|
4.1
|
|
05/21/2008
|
|
|
4.15
|
|
Registration Rights Agreement, dated May 20, 2008 by and among
SandRidge Energy, Inc., certain subsidiary guarantors named
therein, Banc of America Securities LLC, Barclays Capital, Inc.
and J.P. Morgan Securities Inc., as representatives of the
purchasers
|
|
8-K
|
|
001-33784
|
|
4.2
|
|
05/21/2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incorporated by Reference
|
Exhibit
|
|
|
|
|
|
SEC
|
|
|
|
|
|
Filed
|
No.
|
|
Exhibit Description
|
|
Form
|
|
File No.
|
|
Exhibit
|
|
Filing Date
|
|
Herewith
|
|
4.16
|
|
Registration Rights Agreement, dated February 16, 2009, among
SandRidge Energy, Inc., George B. Kaiser and Pooled CIT
Investments, O.K.
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|
|
|
|
|
|
|
|
|
*
|
10.1
|
|
Executive Nonqualified Excess Plan
|
|
8-K
|
|
001-33784
|
|
10.1
|
|
07/15/2008
|
|
|
10.2
|
|
2005 Stock Plan of SandRidge Energy, Inc.
|
|
S-1
|
|
333-148956
|
|
10.2
|
|
01/30/2008
|
|
|
10.2.1
|
|
Form of Restricted Stock Award Agreement under 2005 Stock Plan
|
|
10-K
|
|
001-33784
|
|
10.2.1
|
|
03/07/2008
|
|
|
10.5.1
|
|
Employment Agreement of Tom L. Ward, dated June 8, 2006
|
|
S-1
|
|
333-148956
|
|
10.11
|
|
01/30/2008
|
|
|
10.5.2
|
|
Employment Agreement of Dirk M. Van Doren, dated effective as of
January 1, 2008
|
|
10-Q
|
|
333-148956
|
|
10.5.2
|
|
05/08/2008
|
|
|
10.5.3
|
|
Employment Agreement of Matthew K. Grubb, dated effective as of
January 1, 2008
|
|
10-Q
|
|
333-148956
|
|
10.5.3
|
|
05/08/2008
|
|
|
10.5.4
|
|
Employment Agreement of Todd N. Tipton, dated effective as of
January 1, 2008
|
|
10-Q
|
|
333-148956
|
|
10.5.4
|
|
05/08/2008
|
|
|
10.5.5
|
|
Employment Agreement of Larry K. Coshow, dated effective as of
January 1, 2008
|
|
10-Q
|
|
333-148956
|
|
10.5.5
|
|
05/08/2008
|
|
|
10.5.6
|
|
Form of Employment Agreement for Senior Vice Presidents
|
|
10-Q
|
|
333-148956
|
|
10.5.6
|
|
05/08/2008
|
|
|
10.5.7
|
|
Employment Separation Agreement of Larry K. Coshow, dated April
14, 2008
|
|
10-Q
|
|
333-148956
|
|
10.5.7
|
|
05/08/2008
|
|
|
10.5.8
|
|
Employment Agreement of Rodney E. Johnson, dated effective as of
January 1, 2009
|
|
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|
|
|
|
|
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|
*
|
10.6
|
|
Form of Indemnification Agreement for directors and officers
|
|
S-1
|
|
333-148956
|
|
10.5
|
|
01/30/2008
|
|
|
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
|
|
S-1
|
|
333-148956
|
|
10.6
|
|
01/30/2008
|
|
|
10.7.1
|
|
Amendment No. 1 to Senior Credit Facility, dated November 21,
2006 by and among SandRidge Energy, Inc.
|
|
S-1
|
|
333-148956
|
|
10.6
|
|
01/30/2008
|
|
|
10.7.2
|
|
Amendment No. 2 to Senior Credit Facility, dated November 21,
2006
|
|
S-1
|
|
333-148956
|
|
10.10
|
|
01/30/2008
|
|
|
10.7.3
|
|
Amendment No. 3 to Senior Credit Facility, dated September 14,
2007
|
|
10-Q
|
|
333-148956
|
|
10.7.3
|
|
05/08/2008
|
|
|
10.7.4
|
|
Amendment No. 4 to Senior Credit Facility, dated April 4, 2008
|
|
10-Q
|
|
333-148956
|
|
10.4
|
|
08/07/2008
|
|
|
10.7.5
|
|
Amendment No. 5 to Senior Credit Facility, dated September 18,
2008
|
|
|
|
|
|
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incorporated by Reference
|
Exhibit
|
|
|
|
|
|
SEC
|
|
|
|
|
|
Filed
|
No.
|
|
Exhibit Description
|
|
Form
|
|
File No.
|
|
Exhibit
|
|
Filing Date
|
|
Herewith
|
|
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
|
|
S-1
|
|
333-148956
|
|
10.8
|
|
01/30/2008
|
|
|
10.14
|
|
Purchase and Sale Agreement, dated June 7, 2007 by and between
Wallace Jordan, LLC and SandRidge Energy, Inc.
|
|
S-1
|
|
333-148956
|
|
10.17
|
|
01/30/2008
|
|
|
10.15
|
|
Office Lease Agreement, dated March 6, 2006 by and between 1601
Tower Properties, L.L.C. and Riata Energy, Inc.
|
|
S-1
|
|
333-148956
|
|
10.18
|
|
01/30/2008
|
|
|
10.15.1
|
|
First Amendment, dated October 19, 2006 to Office Lease
Agreement, dated March 6, 2006
|
|
S-1
|
|
333-148956
|
|
10.19
|
|
01/30/2008
|
|
|
10.15.2
|
|
Second Amendment, dated January 26, 2007 to Office Lease
Agreement
|
|
S-1
|
|
333-148956
|
|
10.20
|
|
01/30/2008
|
|
|
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
|
|
S-1
|
|
333-148956
|
|
10.21
|
|
01/30/2008
|
|
|
10.17
|
|
Construction Management Agreement, dated June 29, 2008, by and
between Oxy USA Inc. and SandRidge Energy Exploration and
Production, LLC
|
|
10-Q
|
|
333-148956
|
|
10.1
|
|
08/07/2008
|
|
|
10.18
|
|
Gas Treating and CO2 Delivery Agreement, dated June 29, 2008, by
and between Oxy USA Inc. and SandRidge Energy Exploration and
Production, LLC
|
|
10-Q
|
|
333-148956
|
|
10.2
|
|
08/07/2008
|
|
|
10.19
|
|
Purchase and Sale Agreement, dated October 9, 2008, by and among
SandRidge Energy, Inc., Tom L. Ward, TLW Investments, L.L.C. and
TLW Investments, Inc.
|
|
8-K
|
|
333-148956
|
|
10.1
|
|
10/16/2008
|
|
|
21.1
|
|
Subsidiaries of SandRidge Energy, Inc.
|
|
S-1
|
|
333-148956
|
|
21.1
|
|
01/30/2008
|
|
|
23.1
|
|
Consent of PricewaterhouseCoopers LLP
|
|
|
|
|
|
|
|
|
|
*
|
23.2
|
|
Consent of DeGolyer and MacNaughton
|
|
|
|
|
|
|
|
|
|
*
|
23.3
|
|
Consent of Netherland, Sewell & 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
|
|
|
|
|
|
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incorporated by Reference
|
Exhibit
|
|
|
|
|
|
SEC
|
|
|
|
|
|
Filed
|
No.
|
|
Exhibit Description
|
|
Form
|
|
File No.
|
|
Exhibit
|
|
Filing Date
|
|
Herewith
|
|
32.1
|
|
Section 906 Certifications of Chief Executive Officer and Chief
Financial Officer
|
|
|
|
|
|
|
|
|
|
*
|
100.INS
|
|
XBRL Instance Document
|
|
|
|
|
|
|
|
|
|
*
|
100.SCH
|
|
XBRL Taxonomy Extension Schema Document
|
|
|
|
|
|
|
|
|
|
*
|
100.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
|
|
|
|
|
|
|
|
*
|
100.LAB
|
|
XBRL Taxonomy Extension Label Linkbase Document
|
|
|
|
|
|
|
|
|
|
*
|
100.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
|
|
|
|
|
|
|
|
|
*
|
100.DEF
|
|
XBRL Taxonomy Extension Definition Document
|
|
|
|
|
|
|
|
|
|
*
|
|
|
|
|
|
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.