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As filed with the Securities and Exchange Commission on June 24, 2008
Registration No. 333-      
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
SandRidge Energy, Inc.*
(Exact name of registrant as specified in its charter)
 
         
Delaware   1311   20-8084793
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification Number)
 
1601 N.W. Expressway, Suite 1600
Oklahoma City, Oklahoma 73118
(405) 753-5500
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
Tom L. Ward
Chairman, Chief Executive Officer and President
1601 N.W. Expressway, Suite 1600
Oklahoma City, Oklahoma 73118
(405) 753-5500
(Name, address, including zip code, and telephone number, including area code, of agent for service)
 
Copy to:
 
Vinson & Elkins L.L.P.
2500 First City Tower, 1001 Fannin
Houston, Texas 77002
(713) 758-2222
Attn: James M. Prince
 
Approximate date of commencement of proposed sale to the public:  As soon as practicable after this Registration Statement becomes effective.
 
If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box.  o
 
If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier registration statement for the same offering.  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):
 
             
Large accelerated filer o
  Accelerated filer o   Non-accelerated filer þ
(Do not check if a smaller reporting company)
  Smaller reporting company o
 
* Includes certain subsidiaries of SandRidge Energy, Inc. identified below.
 
CALCULATION OF REGISTRATION FEE
 
                         
            Proposed Maximum
    Proposed Maximum
    Amount of
Title of Each Class of
    Amount to be
    Offering
    Aggregate
    Registration
Securities to be Registered     Registered     Price per Note(1)     Offering Price(1)     Fee
Senior Notes Due 2015
    $650,000,000     100%     $650,000,000     $25,545
Guarantees of Senior Notes Due 2015(2)
               
Senior Floating Rate Notes Due 2014
    $350,000,000     100%     $350,000,000     $13,755
Guarantees of Senior Floating Rate Notes Due 2014(2)
               
Total
            $1,000,000,000     $39,300
                         
 
(1) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(f)(2) of the rules and regulations under the Securities Act.
(2) No further fee is payable pursuant to Rule 457(n) of the rules and regulations under the Securities Act, and no separate consideration will be received for the guarantees.
 
ADDITIONAL GUARANTOR REGISTRANTS
 
                 
        Primary Standard
     
    State of
  Industrial
     
Exact Name of Additional Registrant as
  Incorporation or
  Classification
    IRS Employee
Specified in its Charter
  Organization   Code Number     Identification No.
 
SandRidge Onshore, LLC
  Delaware     1311     47-0953489
Lariat Services, Inc. 
  Texas     1311     75-2500702
SandRidge Operating Company
  Texas     1311     75-2541245
Integra Energy, LLC
  Texas     1311     75-2887527
SandRidge Exploration and Production, LLC
  Delaware     1311     87-0776535
SandRidge Tertiary, LLC
  Texas     1311     20-1918006
SandRidge Midstream, Inc. 
  Texas     1311     75-2541148
SandRidge Offshore, LLC
  Delaware     1311     11-3758786
SandRidge Holdings, Inc. 
  Delaware     1311     20-5878401
 
Each Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrants shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
 


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PROSPECTUS
 
SandRidge Energy, Inc.
 
Offers to Exchange up to
$650,000,000 of 85/8% Senior Notes Due 2015
that have been registered under the Securities Act of 1933
for
$650,000,000 of 85/8% Senior Notes Due 2015
that have not been registered under the Securities Act of 1933
and
$350,000,000 of Senior Floating Rate Notes Due 2014
that have been registered under the Securities Act of 1933
for
$350,000,000 of Senior Floating Rate Notes Due 2014
that have not been registered under the Securities Act of 1933
 
Terms of the Exchange Offers
 
  •  We are offering to exchange up to:
 
  •  $650,000,000 aggregate principal amount of registered 85/8% Senior Notes Due 2015, for any and all of our $650,000,000 aggregate principal amount of unregistered 85/8% Senior Notes Due 2015; and
 
  •  $350,000,000 aggregate principal amount of registered Senior Floating Rate Notes Due 2014, for any and all of our $350,000,000 aggregate principal amount of unregistered Senior Floating Rate Notes Due 2014.
 
We refer to the registered notes collectively as the “exchange notes” and the unregistered notes collectively as the “outstanding notes”. We refer to the exchange notes and the outstanding notes collectively as the “notes”. The exchange notes are being issued under the indenture pursuant to which we previously issued the outstanding notes.
 
  •  We will exchange all outstanding notes that you validly tender and do not validly withdraw before the applicable exchange offer expires for an equal principal amount of exchange notes of the same series.
 
  •  The terms of the exchange notes of each series are substantially identical to those of the outstanding notes of the same series, except that the transfer restrictions, registration rights and provisions for additional interest relating to the outstanding notes do not apply to the exchange notes.
 
  •  The outstanding notes are, and the exchange notes will be, guaranteed by each of our existing and future domestic restricted subsidiaries.
 
  •  Each exchange offer expires at 5:00 p.m., New York City time, on          , 2008, unless extended. We do not currently intend to extend the exchange offers.
 
  •  Tenders of outstanding notes may be withdrawn at any time prior to the expiration of the applicable exchange offer.
 
  •  The exchange of outstanding notes for exchange notes will not be a taxable event for U.S. federal income tax purposes.
 
This investment involves risks. Please read “Risk Factors” beginning on page 5 for a discussion of the risks that you should consider prior to tendering your outstanding notes in the exchange offers.
 
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
 
The date of this prospectus is          , 2008.


 

This prospectus incorporates important business and financial information about us that is not included in or delivered with this document. This information is available to you without charge upon written or oral request to: SandRidge Energy, Inc., 1601 N.W. Expressway, Suite 1600, Oklahoma City, Oklahoma 73118, Attention: Corporate Secretary, (405) 753-5500. The exchange offer is expected to expire on               , 2008 and you must make your exchange decision by the expiration date. To obtain timely delivery, you must request the information no later than               , 2008, or the date which is five business days before the expiration date of this exchange offer.
 
This prospectus is part of a registration statement we filed with the Securities and Exchange Commission, referred to in this prospectus as the SEC or the Commission. In making your investment decision, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. If you received any unauthorized information, you must not rely on it. We are not making an offer to sell these securities in any state or jurisdiction where the offer is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus.
 
Each broker-dealer that receives exchange notes for its own account pursuant to an exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for outstanding notes where such outstanding notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the consummation of an exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. Please read “Plan of Distribution.”
 
TABLE OF CONTENTS
 
         
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    F-1  
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 Opinion of Vinson & Elkins LLP
 Computation of Ratio of Earnings to Fixed Charges
 Consent of PricewaterhouseCoopers LLP
 Consent of Grant Thornton LLP
 Consent of DeGolyer and MacNaughton
 Consent of Netherland, Sewell & Associates, Inc.
 Consent of Harper & Associates, Inc.


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PROSPECTUS SUMMARY
 
We have provided definitions for some of the natural gas and oil industry terms used in this prospectus in the “Glossary of Natural Gas and Oil Terms” included in this prospectus. In this prospectus, when we use the terms “SandRidge,” the “Company,” “we,” “our,” or “us,” we mean SandRidge Energy, Inc. and its subsidiaries on a consolidated basis, unless otherwise indicated or the context requires otherwise. “SandRidge Tertiary” refers to our wholly-owned subsidiary, SandRidge Tertiary LLC, formerly PetroSource Production Company, LLC, and “Lariat” refers to our wholly-owned subsidiary, Lariat Services, Inc.
 
Our Company
 
We are an independent natural gas and oil company headquartered in Oklahoma City, Oklahoma with our principal focus on exploration and production activities. We also own and operate natural gas gathering, marketing and processing facilities, CO2 treating and transportation facilities, and tertiary oil recovery operations. In addition, we own and operate drilling rigs and a related oil field services business. We focus our exploration and production activities in West Texas, the Cotton Valley Trend in East Texas, the Gulf Coast, the Mid-Continent and the Gulf of Mexico.
 
Our principal executive offices are located at 1601 N.W. Expressway, Suite 1600, Oklahoma City, Oklahoma 73118 and our telephone number is (405) 753-5500. Our website is http://www.sandridgeenergy.com.
 
The Exchange Offers
 
On May 1, 2008, we issued the outstanding notes in a private placement. In connection with this issuance, we entered into a registration rights agreement in which we agreed, among other things, to deliver this prospectus to you and to use our best efforts to complete the exchange offer. The following is a summary of the exchange offer.
 
Outstanding notes Our 85/8% Senior Notes Due 2015 and our Senior Floating Rate Notes Due 2014, which were issued on May 1, 2008.
 
Exchange notes Our 85/8% Senior Notes Due 2015 and Senior Floating Rate Notes Due 2014. The terms of each series of exchange notes are substantially identical to those terms of the same series of outstanding notes, except that the transfer restrictions, the registration rights and provisions for additional interest relating to the outstanding notes do not apply to the exchange notes.
 
The exchange offers We are offering to exchange upon the terms set forth in this prospectus and the accompanying letter of transmittal:
 
• up to $650,000,000 aggregate principal amount of our 85/8% Senior Notes Due 2015 that have been registered under the Securities Act of 1933, as amended (the “Securities Act”), in exchange for an equal outstanding principal amount of our 85/8% Senior Notes Due 2015 that have not been registered under the Securities Act; and
 
• up to $350,000,000 aggregate principal amount of our Senior Floating Rate Notes Due 2014 that have been registered under the Securities Act in exchange for an equal outstanding principal amount of our Senior Floating Rate Notes Due 2014 that have not been registered under the Securities Act;
 
to satisfy our obligations under the registration rights agreement that we entered into when we issued the outstanding notes in transactions exempt from registration under the Securities Act.


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Expiration date Each exchange offer will expire at 5:00 p.m., New York City time, on          , 2008, unless we decide to extend it.
 
Conditions to the exchange offers The registration rights agreement does not require us to accept outstanding notes for exchange if the applicable exchange offer or the making of any exchange by a holder of the outstanding notes would violate any applicable law or interpretation of the staff of the SEC. A minimum aggregate principal amount of outstanding notes being tendered is not a condition to either exchange offer.
 
Procedures for tendering outstanding notes All of the outstanding notes are held in book-entry form through the facilities of The Depository Trust Company, or DTC. To participate in either exchange offer, you must follow the automatic tender offer program, or ATOP, procedures established by DTC for tendering notes held in book-entry form. The ATOP procedures require that the exchange agent receive, prior to the expiration date of the applicable exchange offer, a computer-generated message known as an “agent’s message” that is transmitted through ATOP and that DTC confirm that DTC has received instructions to exchange your notes and you agree to be bound by the terms of the letter of transmittal in Annex A hereto.
 
For more details, please read “The Exchange Offers — Terms of the Exchange” and “The Exchange Offers — Procedures for Tendering.”
 
Guaranteed delivery procedures None.
 
Withdrawal of tenders You may withdraw your tender of outstanding notes at any time prior to the expiration date of the applicable exchange offer. To withdraw, you must submit a notice of withdrawal to the exchange agent using ATOP procedures before 5:00 p.m., New York City time, on the expiration date of the applicable exchange offer. Please read “The Exchange Offers — Withdrawal Rights.”
 
Acceptance of Outstanding Notes and Delivery of Exchange Notes If you fulfill all conditions required for proper acceptance of outstanding notes, we will accept any and all outstanding notes that you properly tender in the applicable exchange offer before 5:00 p.m., New York City time, on the expiration date of the applicable exchange offer. We will return any outstanding note that we do not accept for exchange to you without expense promptly after the expiration date. We will deliver the exchange notes promptly after the expiration date and acceptance of the outstanding notes for exchange. Please read “The Exchange Offers — Terms of the Exchange Offers.”
 
U.S. federal income tax considerations The exchange of exchange notes for outstanding notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read the discussion under the caption “Certain U.S. Federal Tax Considerations” for more information regarding the tax consequences to you of the exchange offer.
 
Use of proceeds The issuance of the exchange notes will not provide us with any new proceeds. We are making each exchange offer solely to satisfy our obligations under the registration rights agreement.


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Fees and expenses We will pay all of our expenses related to the exchange offers.
 
Exchange Agent We have appointed Wells Fargo Bank, National Association as exchange agent for each exchange offer. You can find the address, telephone number and fax number of the exchange agent under the caption “The Exchange Offers — Exchange Agent.”
 
Consequences of not exchanging your outstanding notes If you do not exchange your outstanding notes in the applicable exchange offer, you will no longer be able to require us to register your outstanding notes under the Securities Act, except in the limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the outstanding notes unless we have registered the outstanding notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.
 
For information regarding the consequences of not tendering your outstanding notes and our obligation to file a registration statement, please read “The Exchange Offers — Consequences of Failure to Exchange Outstanding Securities” and “Description of the Notes.”
 
Description of the Exchange Notes
 
The terms of the exchange notes and those of the outstanding notes are substantially identical, except that the transfer restrictions, registration rights and provisions for additional interest relating to the outstanding notes do not apply to the exchange notes. As a result, the exchange notes will not bear legends restricting their transfer and will not have the benefit of the registration rights and additional interest provisions contained in the outstanding notes. The exchange notes represent the same debt as the outstanding notes for which they are being exchanged. Both the outstanding notes and the exchange notes are governed by the same indenture.
 
The following is a summary of the terms of the exchange notes. It may not contain all the information that is important to you. For a more detailed description of the exchange notes, please read “Description of the Notes.”
 
Issuer SandRidge Energy, Inc.
 
Securities offered $650,000,000 aggregate principal amount of 85/8% Senior Notes Due 2015.
 
$350,000,000 aggregate principal amount of Senior Floating Rate Notes Due 2014.
 
The exchange notes are being offered as additional debt securities under the indenture pursuant to which we previously issued the outstanding notes.
 
Maturity date of the 85/8% Senior Notes April 1, 2015
 
Maturity date of the Senior Floating Rate Notes April 1, 2014
 
PIK interest At our election, we may from time to time prior to April 30, 2011 upon notice elect to pay interest on the 85/8% Senior Notes in kind


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by the issuance of additional principal amount of 85/8% Senior Notes.
 
Interest payment dates Interest on the 85/8% Senior Notes is payable semi-annually on each April 1 and October 1 of each year beginning on October 1, 2008. Interest on the Senior Floating Rate Notes is payable quarterly in cash in arrears on each January 1, April 1, July 1 and October 1 of each year beginning on July 1, 2008. Interest on the exchange notes will accrue from April 1, 2008 in the case of the 85/8% Senior Notes and from July 1, 2008 in the case of the Senior Floating Rate Notes.
 
Guarantees The exchange notes are unconditionally guaranteed by our existing restricted subsidiaries and will be guaranteed by our future domestic restricted subsidiaries.
 
Use of proceeds The issuance of the exchange notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under our registration rights agreement.
 
Ranking The exchange notes of each series are unsecured and rank equally in right of payment with the exchange notes of the other series and with all of our other existing and future senior indebtedness. The exchange notes are senior in right of payment to all our future subordinated indebtedness.
 
Transfer restrictions The exchange notes generally will be freely transferable, but will also be new securities for which there will not initially be a market. There can be no assurance as to the development or liquidity of any market for the exchange notes.
 
Risk Factors
 
Investing in the exchange notes involves substantial risk. Please read “Risk Factors” beginning on page 5 for a discussion of certain factors you should consider in evaluating an investment in the exchange notes.


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RISK FACTORS
 
An investment in the exchange notes involves a significant degree of risk. You should consider carefully these risks together with all of the other information included in this prospectus before deciding whether to participate in the exchange offers. All of the risks described below could materially and adversely affect our business prospects, financial condition, operating results and cash flows, which in turn could adversely affect our ability to satisfy our obligations under the exchange notes and the guarantees of the exchange notes.
 
Risks Related to Our Business
 
Natural gas and oil prices are volatile, and a decline in natural gas and oil prices can significantly affect our financial results and impede our growth.
 
Our revenue, profitability and cash flow depend upon the prices and demand for natural gas and oil. The markets for these commodities are very volatile. Even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in natural gas and oil prices have a significant impact on the value of our reserves and on our cash flow. Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas and oil and a variety of additional factors that are beyond our control, such as:
 
  •  the domestic and foreign supply of natural gas and oil;
 
  •  the price of foreign imports;
 
  •  worldwide economic conditions;
 
  •  political and economic conditions in oil producing countries, including the Middle East and South America;
 
  •  the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
 
  •  the level of consumer product demand;
 
  •  weather conditions;
 
  •  technological advances affecting energy consumption;
 
  •  availability of pipeline infrastructure, treating, transportation and refining capacity;
 
  •  domestic and foreign governmental regulations and taxes; and
 
  •  the price and availability of alternative fuels.
 
Lower natural gas and oil prices may not only decrease our revenues on a per share basis, but also may reduce the amount of natural gas and oil that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves.
 
We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business.
 
As of March 31, 2008, our total indebtedness was $1.3 billion, which represented approximately 37% of our total capitalization and on May 20, 2008, we issued $750 million of our Senior Notes due 2018. 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 you. For example, it could:
 
  •  make us more vulnerable to adverse changes in general economic, industry and competitive conditions and adverse changes in governmental 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;
 
  •  limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
 
  •  place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our leverage prevents us from pursuing; and
 
  •  limit our ability to borrow additional amounts for working capital, capital expenditures, acquisitions, debt service requirements, execution of our business strategy or other purposes.
 
Any of these above listed factors could materially adversely affect 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 could 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, taxes, drilling and operating expenses, capital expenditures and availability of funds. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control.
 
The present value of future net cash flows from our proved reserves will not necessarily be the same as the current market value of our estimated natural gas and oil reserves.
 
We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of estimate. Actual future net cash flows from our natural gas and oil properties also will be affected by factors such as:
 
  •  actual prices we receive for natural gas and oil;
 
  •  actual cost of development and production expenditures;
 
  •  the amount and timing of actual production;
 
  •  supply of and demand for natural gas and oil; and
 
  •  changes in governmental regulations or taxation.
 
The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.
 
Unless we replace our natural gas and oil reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
 
Our future natural gas and oil reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.


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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 March 31, 2008, only 857 of our 5,020 identified potential future well locations had 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 prospectus. A prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of natural gas or oil. Our prospects and drilling locations are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.
 
The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. During 2007, we participated in drilling a total of 316 gross wells, of which eight have been identified as dry holes. During the three months ended March 31, 2008, we drilled 111 wells, none of which 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 it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as soil or ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties, which risks and liabilities could have a material adverse effect on our results of operations and financial condition.
 
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 57% of the estimated proved reserves that we own or have under lease in the WTO and of our total proved reserves as of March 31, 2008 are proved undeveloped reserves. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Therefore, ultimate recoveries from these fields may not match current expectations. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves.


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A significant portion of our operations are located in WTO, making us vulnerable to risks associated with operating in one major geographic area.
 
As of March 31, 2008, approximately 60% of our proved reserves and approximately 51% of our daily production were located in the West Texas Overthrust, or WTO. In addition, a substantial portion of our WTO natural gas contains a high concentration of CO2 and requires treating. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation and treatment capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance or unanticipated occurrences.
 
Many of our prospects in the WTO may contain natural gas that is high in CO2 content, which can negatively affect our economics.
 
The reservoirs of many of our prospects in the WTO may contain natural gas that is high in CO2 content. The natural gas produced from these reservoirs must be treated for the removal of CO2 prior to marketing. If we cannot obtain sufficient capacity at treatment facilities for our natural gas with a high CO2 concentration, or if the cost to obtain such capacity significantly increases, we could be forced to delay production and development or experience increased production costs.
 
Furthermore, when we treat the gas for the removal of CO2, some of the methane is used to run the treatment plant as fuel gas and other methane and heavier hydrocarbons, such as ethane, propane and butane, cannot be separated from the CO2 and is lost. This is known as plant shrink. Historically our plant shrink has been approximately 12% in the WTO. We do not know the amount of CO2 we will encounter in any well until it is drilled. As a result, sometimes we encounter CO2 levels in our wells that are higher than expected. The amount of CO2 in the gas produced affects the heating content of the gas. For example, if a well is 65% CO2, the gas produced often has a heating content of between 300 and 350 MBtu per Mcf. Giving consideration for plant shrink, as many as four Mcf of high CO2 gas must be produced to sell one MmBtu of natural gas. We report our volumes of natural gas reserves and production net of CO2 volumes that are removed prior to sales.
 
Since the treatment expenses are incurred on an Mcf basis, we will incur a higher effective treating cost per MmBtu of natural gas sold for natural gas with a higher CO2 content. As a result, high CO2 gas wells must produce at much higher rates than low CO2 gas wells to be economic, especially in a low natural gas price environment.
 
A significant decrease in natural gas production in our areas of midstream gas services operation, due to the decline in production from existing wells, depressed commodity prices or otherwise, would adversely affect our revenues and cash flow for our midstream gas services segment.
 
The profitability of our midstream business is materially impacted by the volume of natural gas we gather, transmit and process at our facilities. Most of the reserves backing up our midstream assets are operated by our exploration and production segment. A material decrease in natural gas production in our areas of operation would result in a decline in the volume of natural gas delivered to our pipelines and facilities for gathering, transmitting and processing. We have no control over many factors affecting production activity, including prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital. Failure to connect new wells to our gathering systems would result in the amount of natural gas we gather, transmit and process being reduced substantially over time and could, upon exhaustion of the current wells, cause us to abandon our gathering systems and, possibly cease gathering, transmission and processing operations. Our ability to connect to new wells will be dependent on the level of drilling activity in our areas of operations and competitive market factors. The effect of any material decrease in the volume of natural gas handled by our midstream assets would be to reduce our revenues, operating income and our ability to make payments on the exchange notes.


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Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of natural gas and oil. 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.
 
In addition, the use of 2-D and 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses due to such expenditures. As a result, our drilling activities may not be geologically successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area may not improve.
 
We often gather 2-D and 3-D seismic data over large areas. Our interpretation of seismic data delineates for us those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, it would result in our having made substantial expenditures to acquire and analyze 2-D and 3-D data without having an opportunity to benefit from those expenditures.
 
Drilling for and producing natural gas and oil are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
 
Our drilling and operating activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas and oil can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
 
  •  unusual or unexpected geological formations and miscalculations;
 
  •  pressures;
 
  •  fires;
 
  •  blowouts;
 
  •  loss of drilling fluid circulation;
 
  •  title problems;
 
  •  facility or equipment malfunctions;
 
  •  unexpected operational events;
 
  •  shortages of skilled personnel;
 
  •  shortages or delivery delays of equipment and services;
 
  •  compliance with environmental and other regulatory requirements; and
 
  •  adverse weather conditions.
 
Any of these risks can cause substantial losses, including personal injury or loss of life; damage to or destruction of property, natural resources and equipment; pollution; environmental contamination or loss of wells; and regulatory fines or penalties.
 
Insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. We do not carry environmental insurance, for example. We could incur losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not


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covered in full or in part by insurance could have a material adverse impact on our business activities, financial condition, results of operations and our ability to make payments on the exchange notes.
 
Market conditions or operational impediments may hinder our access to natural gas and oil markets or delay our production.
 
Market conditions or a lack of satisfactory natural gas and oil transportation arrangements may hinder our access to natural gas and oil markets or delay our production. The availability of a ready market for our natural gas and oil production depends on a number of factors, including the demand for and supply of natural gas and oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities. For example, we are currently experiencing capacity limitations on sour gas treating in the Piñon Field. Our failure to obtain such services on acceptable terms or expand our midstream assets could materially harm our business. We may be required to shut in wells for a lack of a market or because access to natural gas pipelines, gathering system capacity or processing facilities may be limited or unavailable. If that were to occur, then we would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market.
 
Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and oil reserves.
 
The natural gas and oil industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of natural gas and oil reserves. To date, we have financed capital expenditures primarily with proceeds from the sale of equity, debt and cash generated by operations. We intend to finance our future capital expenditures with the sale of equity, asset sales, cash flow from operations and current and new financing arrangements. Our cash flow from operations and access to capital are subject to a number of variables, including:
 
  •  our proved reserves;
 
  •  the level of natural gas and oil we are able to produce from existing wells;
 
  •  the prices at which natural gas and oil are sold; and
 
  •  our ability to acquire, locate and produce new reserves.
 
If our revenues decrease as a result of lower natural gas and oil prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. In order to fund our capital expenditures, we must seek additional financing. Our revolving credit facility and term loan contain covenants restricting our ability to incur additional indebtedness without the consent of the lenders. Our lenders may withhold this consent in their sole discretion.
 
In addition, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our natural gas and oil reserves.
 
The agreements governing our existing indebtedness have restrictions and financial covenants which could adversely affect our operations.
 
Our senior credit facility and the indentures governing the notes and our 8% Senior Notes Due 2018 restrict our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We also are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any


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of the restrictions and covenants under the senior credit facility or indentures could result in a default under those agreements, which could cause all of our indebtedness to be immediately due and payable.
 
Our revolving 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 redetermination of the borrowing base per calendar year. Unscheduled redeterminations may be made at our request, but are limited to two requests per year. The borrowing base is determined based on 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 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 revolving credit facility.
 
If the indebtedness under our revolving credit facility and indentures were to be accelerated, our assets may not be sufficient to repay such indebtedness in full. In particular, holders of the exchange notes will be paid only if we have assets remaining after we pay amounts due on our secured indebtedness, including our revolving credit facility. We have pledged a significant portion of our assets as collateral under our revolving credit facility. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
 
Our derivative activities could result in financial losses or could reduce our earnings.
 
To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of natural gas and oil, we currently, and may in the future, enter into derivative instruments for a portion of our natural gas and oil production, including collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments. Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
 
  •  production is less than expected;
 
  •  the counter-party to the derivative instrument defaults on its contract obligations; or
 
  •  there is a change in the expected differential between the underlying price in the derivative instrument and the actual prices received.
 
In addition, these types of derivative arrangements limit the benefit we would receive from increases in the prices for natural gas and oil.
 
Competition in the natural gas and oil industry is intense, which may adversely affect our ability to succeed.
 
The natural gas and oil industry is intensely competitive, and we compete with companies that have greater resources. Many of these companies not only explore for and produce natural gas and oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas and oil properties and exploratory prospects or identify, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas and oil market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas and oil properties.


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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 project is unable to function as planned due to changing requirements or public opposition, we may suffer expensive delays, extended periods of non-operation or significant loss of value in a project. All such costs may have a negative effect on our business and results of operations.
 
Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental agencies and other bodies vested with much authority relating to the exploration for, and the development, production and transportation of, natural gas and oil. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on us. For instance, the U.S. Department of the Interior’s Minerals Management Service (“MMS”) may suspend or terminate our operations on federal leases for failure to pay royalties or comply with safety and environmental regulations.
 
Our operations expose us to potentially substantial costs and liabilities with respect to environmental, health and safety matters.
 
We may incur substantial costs and liabilities as a result of environmental, health and safety requirements applicable to us and 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.
 
Under certain environmental laws that impose strict, joint and several liability, we may be required to remediate our contaminated properties regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were or were not in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons, 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 them could significantly and adversely affect our business, financial condition or results of operations. In addition, many countries as well as several states and regions of the U.S. have agreed to regulate emissions of “greenhouse gases.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning of natural gas and oil, are


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greenhouse gases. The carbon dioxide may be released or captured as part of our operations. Current or future regulation of greenhouse gases could adversely impact our financial condition and results of operations and demand for some of our services or products in the future.
 
If we fail to maintain an adequate system of internal control over financial reporting this could adversely affect our ability to accurately report our results.
 
We are not currently required to comply with Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make an assessment of the effectiveness of our internal controls over financial reporting for that purpose. Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. A material weakness is a deficiency, or a combination of deficiencies, in our internal control over financial reporting that results in a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. We will be required to comply with Section 404 of the Sarbanes-Oxley Act of 2002 effective as of December 31, 2008. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls could harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.
 
Risks Relating to the Notes and the Exchange Offers
 
If you fail to exchange outstanding notes, existing transfer restrictions will remain in effect and the market value of outstanding notes may be adversely affected because they may be more difficult to sell.
 
If you fail to exchange outstanding notes for exchange notes under the exchange offers, then you will continue to be subject to the existing transfer restrictions on the outstanding notes. In general, the outstanding notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except in connection with these exchange offers or as required by the registration rights agreement, we do not intend to register resales of the outstanding notes.
 
The tender of outstanding notes under the exchange offers will reduce the principal amount of the currently outstanding notes. Due to the corresponding reduction in liquidity, this may have an adverse effect upon, and increase the volatility of, the market price of any currently outstanding notes that you continue to hold following completion of the exchange offers.
 
We may incur substantial additional indebtedness, including debt ranking equal to the notes.
 
Subject to the restrictions in the indenture governing the exchange notes and outstanding notes and in other instruments governing our other outstanding debt, we and our subsidiaries may be able to incur substantial additional debt in the future. Although the indenture governing the exchange notes and outstanding notes and the instruments governing certain of our other outstanding debt contain restrictions on the incurrence of additional debt, these restrictions are subject to a number of significant qualifications and exceptions, and debt incurred in compliance with these restrictions could be substantial. To the extent new debt is added to our current debt levels, the substantial leverage-related risks described above would increase.
 
If we or any of our subsidiaries that is a guarantor of the exchange notes and outstanding notes (a “Guarantor”) incur any additional debt that ranks equally with the notes (or with the guarantee thereof), including trade payables, the holders of that debt will be entitled to share ratably with holders of the notes in


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any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or such Guarantor. This may have the effect of reducing the amount of proceeds paid to holders of the notes in connection with such a distribution.
 
We may not be able to generate sufficient cash to service all of our indebtedness, including the notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.
 
Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness, including the notes.
 
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance our indebtedness, including the notes. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments and the indenture governing the notes may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our senior credit facility and the indentures governing the notes and our other series of outstanding notes restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.
 
Your right to receive payments on the exchange notes, like the outstanding notes, is effectively junior to the right of lenders who have a security interest in our assets to the extent of the value of those assets.
 
Our obligations under the exchange notes, like the outstanding notes, and the Guarantors’ obligations under their guarantees of the exchange notes, like the outstanding notes, are unsecured, but our obligations under our senior credit facility and each Guarantor’s obligations under its guarantee of our senior credit facility are secured by a security interest in substantially all of our domestic tangible and intangible assets, including the stock of substantially all of our wholly-owned subsidiaries. If we are declared bankrupt or insolvent, or if we default under our senior credit facility, the funds borrowed thereunder, together with accrued interest, could become immediately due and payable. If we were unable to repay such indebtedness, the lenders under our senior credit facility could foreclose on the pledged assets to the exclusion of holders of the notes, even if an event of default exists under the indenture governing the notes at such time. Furthermore, if the lenders foreclose and sell the pledged equity interests in any Guarantor in a transaction permitted under the terms of the indenture governing the notes, then such Guarantor will be released from its guarantee of the notes automatically and immediately upon such sale. In any such event, because the notes will no longer be secured by any of such assets or by the equity interests in any such Guarantor, it is possible that there would be no assets remaining from which your claims could be satisfied or, if any assets remained, they might be insufficient to satisfy your claims in full. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
 
As of June 20, 2008, we had no borrowings outstanding under our senior credit facility, though, at that time, outstanding letters of credit reduced borrowing capacity under the senior credit facility by $22 million. As of June 20, 2008, we had approximately $60.2 million of other outstanding secured long-term debt. Subject to the limits set forth in the indentures governing the notes and our 8% Senior Notes Due 2018, we may also incur additional secured debt.


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Our ability to repay our debt, including the notes, is affected by the cash flow generated by our subsidiaries.
 
Our subsidiaries own some of our assets and conduct some of our operations. Accordingly, repayment of our indebtedness, including the notes, will be dependent on the generation of cash flow by our subsidiaries and their ability to make such cash available to us, by dividend, debt repayment or otherwise. Unless they are Guarantors, our subsidiaries will not have any obligation to pay amounts due on the notes or to make funds available for that purpose. Our subsidiaries may not be able to, or may not be permitted to, make distributions to enable us to make payments in respect of our indebtedness, including the notes. Each subsidiary is a distinct legal entity and, under certain circumstances, legal and contractual restrictions may limit our ability to obtain cash from our subsidiaries. While the indenture governing the notes limits the ability of our subsidiaries to incur consensual encumbrances or restrictions on their ability to pay dividends or make other intercompany payments to us, these limitations are subject to certain qualifications and exceptions. In the event that we do not receive distributions from our subsidiaries, we may be unable to make required principal and interest payments on our indebtedness, including the notes.
 
Claims of holders of the exchange notes, like holders of outstanding notes, will be structurally subordinated to claims of creditors of certain of our subsidiaries that will not guarantee the exchange notes.
 
We conduct some of our operations through our subsidiaries, and certain of our immaterial domestic subsidiaries have not guaranteed the notes. Subject to certain limitations, the indenture governing the notes permits us to form or acquire additional subsidiaries that are not guarantors of the notes and to permit such non-guarantor subsidiaries to acquire additional assets and incur additional indebtedness. Holders of the exchange notes would not have any claim as a creditor against any of our non-guarantor subsidiaries to the assets and earnings of those subsidiaries. The claims of the creditors of those subsidiaries, including their trade creditors, banks and other lenders, would have priority over any of our claims or those of our other subsidiaries as equity holders of the non-guarantor subsidiaries. Consequently, in any insolvency, liquidation, reorganization, dissolution or other winding-up of any of the non-guarantor subsidiaries, creditors of those subsidiaries would be paid before any amounts would be distributed to us or to any of the Guarantors as equity, and thus be available to satisfy our obligations under the notes and other claims against us or the Guarantors.
 
For the quarter ended March 31, 2008, our non-guarantor subsidiaries accounted for approximately $5.2 million, or 1.9%, of our revenues. As of March 31, 2008, our non-guarantor subsidiaries accounted for approximately $51.2 million, or 1.3%, of our consolidated total assets and $11.8 million, or 0.7%, of our total liabilities, in each case after giving effect to intercompany eliminations. The indenture governing the notes permits these subsidiaries to incur certain additional debt and will not limit their ability to incur other liabilities that are not considered indebtedness under the indenture.
 
If we default on our obligations to pay our other indebtedness, we may not be able to make payments on the notes.
 
Any default under the agreements governing our indebtedness, including a default under our senior credit facility, that is not waived by the required lenders, and the remedies sought by the holders of such indebtedness, could prevent us from paying principal, premium, if any, and interest on the notes and substantially decrease the market value of the notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants in the instruments governing our indebtedness (including covenants in our senior credit facility and the indentures governing the notes and our 8% Senior Notes Due 2018), we could be in default under the terms of the agreements governing such indebtedness. In the event of such default,
 
  •  the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest;


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  •  the lenders under our senior credit facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and
 
  •  we could be forced into bankruptcy or liquidation.
 
If our operating performance declines, we may in the future need to obtain waivers from the required lenders under our senior credit facility to avoid being in default. If we breach our covenants under our senior credit facility and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under our senior credit facility, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.
 
We may not be able to repurchase the notes upon a change of control.
 
Upon the occurrence of specific kinds of change of control events, we may be required to offer to repurchase all notes then outstanding at 101% of their principal amount plus accrued and unpaid interest, if any. The source of funds for any such purchase of the notes will be our available cash or cash generated from our operations or the operations of our subsidiaries or other sources, including borrowings, sales of assets or sales of equity. We may not be able to repurchase the notes upon a change of control because we may not have sufficient financial resources to purchase all of the exchange notes that are tendered upon a change of control. Our failure to repurchase the exchange notes upon a change of control would cause a default under the indenture governing the notes and could lead to a cross default under the indenture for our 8% Senior Notes Due 2018 or our senior credit facility.
 
Insolvency and fraudulent transfer laws and other limitations may preclude the recovery of payment under the notes and the guarantees.
 
Federal and state fraudulent transfer laws permit a court, if it makes certain findings, to avoid all or a portion of the obligations of the Guarantors pursuant to their guarantees of the notes, or to subordinate a Guarantor’s obligations under such guarantee to claims of its other creditors, reducing or eliminating the holders of the notes’ ability to recover under such guarantees. Although laws differ among these jurisdictions, in general, under applicable fraudulent transfer or conveyance laws, the notes or guarantees could be voided as a fraudulent transfer or conveyance if (1) we or any of the Guarantors, as applicable, issued the notes or incurred the guarantees with the intent of hindering, delaying or defrauding creditors; or (2) we or any of the Guarantors, as applicable, received less than reasonably equivalent value or fair consideration in return for either issuing the notes or incurring the guarantees and, in the case of (2) only, one of the following is also true:
 
  •  we or any of the Guarantors, as applicable, were insolvent or rendered insolvent by reason of the issuance of the notes or the incurrence of the guarantees or subsequently become insolvent for other reasons;
 
  •  the issuance of the notes or the incurrence of the guarantees left us or any of the Guarantors, as applicable, with an unreasonably small amount of capital to carry on the business;
 
  •  we or any of the Guarantors intended to, or believed that we or such Guarantor would, incur debts beyond our or such Guarantor’s ability to pay such debts as they mature; or
 
  •  we or any of the Guarantors was a defendant in an action for money damages, or had a judgment for money damages docketed against us or such Guarantor if, in either case, after final judgment, the judgment is unsatisfied.


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USE OF PROCEEDS
 
The exchange offers are intended to satisfy our obligations under the registration rights agreement we entered into in connection with the issuance of the outstanding notes. We will not receive any cash proceeds from the issuance of the exchange notes in the exchange offers. In consideration for issuing the exchange notes as contemplated in this prospectus, we will receive in exchange outstanding notes in like principal amount. We will cancel all outstanding notes surrendered in exchange for exchange notes in the exchange offers. As a result, the issuance of the exchange notes will not result in any increase or decrease in our indebtedness.


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RATIO OF EARNINGS TO FIXED CHARGES
 
We have computed our ratio of earnings to fixed charges for the three months ended March 31, 2008 and 2007 and for each of our fiscal years ended December 31, 2003, 2004, 2005, 2006 and 2007. The computation of earnings to fixed charges is set forth on Exhibit 12.1 to the registration statement of which this prospectus forms a part.
 
Ratio of earnings to fixed charges is calculated by dividing earnings by fixed charges from operations for the periods indicated. For purposes of calculating the ratio of earnings to fixed charges, (a) earnings represents pre-tax income from continuing operations plus fixed charges and (b) fixed charges represents interest expensed and capitalized, amortization of financing costs and required dividends on preference securities.
 
You should read the ratio information below in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and the notes thereto included elsewhere in this prospectus.
 
                                                         
    For the Years Ended December 31,     For the Three Months Ended March 31,  
    2003     2004     2005     2006     2007     2007     2008  
 
Ratio of earnings to fixed charges
    19.4       12.2       6.3       2.2       1.7       (a )     (b )
 
 
(a) Due to our loss for the three months ended March 31, 2007, the ratio coverage was less than 1:1. We would have needed earnings of $29,994,000 to achieve coverage of 1:1.
(b) Due to our loss for the three months ended March 31, 2008, the ratio coverage was less than 1:1. We would have needed additional earnings of $87,163,000 to achieve coverage of 1:1.


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THE EXCHANGE OFFERS
 
Purpose and Effect of the Exchange Offers
 
We issued the outstanding notes, which consist of $650,000,000 in aggregate principal amount of 85/8% Senior Notes Due 2015 and $350,000,000 in aggregate principal amount of Senior Floating Rate Notes Due 2014, in a private placement on May 1, 2008. The outstanding notes were issued to qualified institutional buyers pursuant to Section 4(2) of the Securities Act in exchange for debt outstanding under our senior unsecured credit agreement. Accordingly, the outstanding notes are subject to transfer restrictions. In general, you may not offer or sell the outstanding notes unless either the offer and sale thereof are registered under the Securities Act or are exempt from or not subject to registration under the Securities Act and applicable state securities laws.
 
In the registration rights agreement, we agreed to use our best efforts to cause an exchange offer registration statement to be declared effective by November 1, 2008. Now, to satisfy our obligations under the registration rights agreement, we are offering holders of the outstanding notes who are able to make certain representations described below the opportunity to exchange their outstanding notes for the exchange notes in the exchange offers. The exchange offers will be open for a period of at least 20 business days. During the exchange offer period, we will issue the exchange notes in exchange for all outstanding notes properly surrendered and not withdrawn before the expiration date. The exchange notes will be registered and the transfer restrictions, registration rights and provisions for additional interest relating to the outstanding notes will not apply to the exchange notes.
 
Terms of the Exchange Offers
 
Subject to the terms and conditions described in this prospectus and in the applicable letter of transmittal, we will accept for exchange any outstanding notes properly tendered and not withdrawn prior to 5:00 p.m., New York City time, on the expiration date of the applicable exchange offer. We will issue exchange notes in principal amount equal to the principal amount of outstanding notes surrendered in the exchange offers. Outstanding notes may be tendered only for exchange notes and only in denominations of $1,000 and integral multiples of $1,000 in excess of $1,000.
 
Neither exchange offer is conditioned upon any minimum aggregate principal amount of outstanding notes being tendered in such exchange offer. Each exchange offer will be conducted independently from the other exchange offer, and consummation of one exchange offer will not be conditioned upon consummation of the other.
 
As of the date of this prospectus, $650,000,000 in aggregate principal amount of 85/8% Senior Notes Due 2015 and $350,000,000 in aggregate principal amount of Senior Floating Rate Notes Due 2014 are outstanding. This prospectus is being sent to DTC, the sole registered holder of the outstanding notes, and to all persons whom we can identify as beneficial owners of the outstanding notes. There will be no fixed record date for determining registered holders of outstanding notes entitled to participate in the exchange offers.
 
We intend to conduct the exchange offers in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the rules and regulations of the SEC. Outstanding notes not tendered for exchange in the exchange offers will remain outstanding and continue to accrue interest. These outstanding notes will be entitled to the rights and benefits such holders have under the indenture relating to the notes and the registration rights agreement.
 
We will be deemed to have accepted for exchange properly tendered outstanding notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the exchange notes from us.
 
If you tender outstanding notes in the exchange offers, you will not be required to pay brokerage commissions or fees or, except to the extent indicated by the instructions to the letter of transmittal, transfer


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taxes with respect to the exchange of outstanding notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offer. Please read “— Fees and Expenses” for more details regarding fees and expenses incurred in connection with the exchange offers. We will return any outstanding notes that we do not accept for exchange for any reason without expense to their tendering holders promptly after the expiration or termination of the applicable exchange offer.
 
Expiration, Extension and Amendment
 
Each exchange offer will expire at 5:00 p.m., New York City time, on          , 2008, unless, in our sole discretion, we extend it. We may extend one exchange offer without extending the other.
 
We expressly reserve the right, at any time or various times, to extend the period of time during which either exchange offer is open. We may delay acceptance of any outstanding notes by giving oral or written notice of such extension to their holders at any time until the exchange offer expires or terminates. During any such extensions, all outstanding notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.
 
To extend either exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of outstanding notes of the extension no later than 9:00 a.m. New York City time on the business day after the previously scheduled expiration date.
 
Procedures for Tendering
 
To participate in the exchange offers, you must properly tender your outstanding notes to the exchange agent as described below. We will only issue exchange notes in exchange for outstanding notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of your outstanding notes, and you should follow carefully the instructions on how to tender your outstanding notes. It is your responsibility to properly tender your outstanding notes. We have the right to waive any defects. We are not, however, required to waive defects, and neither we nor the exchange agent is required to notify you of any defects in your tender.
 
If you have any questions or need help in exchanging your outstanding notes, please call the exchange agent whose address and phone number are described in the letter of transmittal included as Annex A to this prospectus.
 
All of the outstanding notes were issued in book-entry form, and all of the outstanding notes are currently represented by global certificates registered in the name of Cede & Co., the nominee of DTC. We have confirmed with DTC that the outstanding notes may be tendered using ATOP. The exchange agent will establish an account with DTC for purposes of each exchange offer promptly after the commencement of such exchange offer, and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their outstanding notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an “agent’s message” to the exchange agent. The agent’s message will state that DTC has received instructions from the participant to tender outstanding notes and that the participant agrees to be bound by the terms of the letter of transmittal.
 
By using the ATOP procedures to exchange outstanding notes, you will not be required to deliver a letter of transmittal to the exchange agent. You will, however, be bound by its terms just as if you had signed it.
 
There is no procedure for guaranteed late delivery of the outstanding notes.
 
Determinations Under the Exchange Offers
 
We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered outstanding notes and withdrawal of tendered outstanding notes. Our determination will be final and binding. We reserve the absolute right to reject any outstanding notes not properly tendered or any outstanding notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular outstanding notes.


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Our interpretation of the terms and conditions of the exchange offers, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of outstanding notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of outstanding notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of outstanding notes will not be deemed made until such defects or irregularities have been cured or waived. Any outstanding notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder as soon as practicable following the expiration date of the applicable exchange offer.
 
When We Will Issue Exchange Notes
 
In all cases, we will issue exchange notes for outstanding notes that we have accepted for exchange under the applicable exchange offer only after the exchange agent receives, prior to 5:00 p.m., New York City time, on the expiration date of such exchange offer,
 
  •  A book-entry confirmation of such outstanding notes into the exchange agent’s account at DTC; and
 
  •  A properly transmitted agent’s message.
 
Return of Outstanding Notes Not Accepted or Exchanged
 
If we do not accept tendered outstanding notes for exchange or if outstanding notes are submitted for a greater principal amount than you desire to exchange, the unaccepted or non-exchanged outstanding notes will be returned without expense to their tendering holder. Such non-exchanged outstanding notes will be credited to an account maintained with DTC. These actions will occur as promptly as practicable after the expiration or termination of the applicable exchange offer.
 
Valid Tender
 
By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:
 
  •  Any exchange notes that you receive will be acquired in the ordinary course of your business;
 
  •  You have no arrangement or understanding with any person or entity to participate in the distribution of the exchange notes;
 
  •  You are not engaged in and do not intend to engage in the distribution of the exchange notes;
 
  •  If you are a broker-dealer who will receive exchange notes for your own account in exchange for outstanding notes, you acquired those outstanding notes as a result of market-making activities or other trading activities and you will deliver this prospectus, as required by law, in connection with any resale of the exchange notes; and
 
  •  You are not an “affiliate,” as defined in Rule 405 under the Securities Act, of us.
 
Withdrawal Rights
 
Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 5:00 p.m., New York City time, on the expiration date of the exchange offer. For a withdrawal to be effective you must comply with the appropriate ATOP procedures. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn outstanding notes and otherwise comply with the ATOP procedures.
 
We will determine all questions as to the validity, form, eligibility and time of receipt of a notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any outstanding notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offers.


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Any outstanding notes that have been tendered for exchange but that are not exchanged for any reason will be credited to an account maintained with DTC for the outstanding notes. This return or crediting will take place as soon as practicable after withdrawal, rejection of tender, expiration or termination of the applicable exchange offer. You may retender properly withdrawn outstanding notes by following the procedures described under “— Procedures for Tendering” above at any time on or prior to the expiration date of the applicable exchange offer.
 
Resales of Exchange Notes
 
Based on interpretations by the staff of the SEC, as described in no-action letters issued to third parties that are not related to us, we believe that exchange notes issued in the exchange offers in exchange for outstanding notes may be offered for resale, resold or otherwise transferred by holders of the exchange notes without compliance with the registration and prospectus delivery provisions of the Securities Act, if:
 
  •  The exchange notes are acquired in the ordinary course of the holder’s business;
 
  •  The holders have no arrangement or understanding with any person to participate in the distribution of the exchange notes;
 
  •  The holders are not “affiliates” of ours within the meaning of Rule 405 under the Securities Act; and
 
  •  The holders are not broker-dealers who purchased outstanding notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act.
 
However, the SEC has not considered the exchange offers described in this prospectus in the context of a no-action letter. The staff of the SEC may not make a similar determination with respect to the exchange offers as in the other circumstances. Each holder who wishes to exchange outstanding notes for exchange notes will be required to represent that it meets the above four requirements.
 
Any holder who is an affiliate of ours or who intends to participate in an exchange offer for the purpose of distributing exchange notes or any broker-dealer who purchased outstanding notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act:
 
  •  Cannot rely on the applicable interpretations of the staff of the SEC mentioned above;
 
  •  Will not be permitted or entitled to tender its outstanding notes in the exchange offers; and
 
  •  Must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any secondary resale transaction.
 
Each broker-dealer that receives exchange notes for its own account in exchange for outstanding notes must acknowledge that the outstanding notes were acquired by it as a result of market-making activities or other trading activities and agree that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the exchange notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. Please read “Plan of Distribution.” A broker-dealer may use this prospectus, as it may be amended or supplemented from time to time, in connection with the resales of exchange notes received in exchange for outstanding notes that the broker-dealer acquired as a result of market-making or other trading activities. Any holder that is a broker-dealer participating in an exchange offer must notify the exchange agent at the telephone number set forth in the enclosed letter of transmittal and must comply with the procedures for broker-dealers participating in the exchange offer. We have not entered into any arrangement or understanding with any person to distribute the exchange notes to be received in the exchange offers.


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Exchange Agent
 
Wells Fargo Bank, National Association has been appointed as the exchange agent for the exchange offers. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal should be directed to the exchange agent addressed as follows:
 
Wells Fargo Bank, National Association
 
         
By Facsimile for Eligible Institutions:
  By Registered and Certified Mail:   Confirm by Telephone:
(214) 777-4086
  Wells Fargo Bank, NA   (214) 740-1573
Attention: Patrick T. Giordano
  Corporate Trust Operations    
    MAC N9303-121    
    PO Box 1517    
    Minneapolis, MN 55480    
         
    By Regular Mail or Overnight Courier:    
    Wells Fargo Bank, NA    
    Corporate Trust Operations    
    MAC N9303-121    
         
    Sixth & Marquette Avenue    
    Minneapolis, MN 55479    
         
    In person by hand only:    
    Wells Fargo Bank, NA    
    12th Floor — Northstar East Building    
    Corporate Trust Operations    
    608 Second Avenue South    
    Minneapolis, MN    
 
Fees and Expenses
 
We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by telegraph, telephone or in person by our officers and regular employees and those of our affiliates.
 
We have not retained any dealer manager in connection with the exchange offers and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offers. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out of pocket expenses.
 
We will pay the cash expenses to be incurred in connection with the exchange offers. They include:
 
  •  SEC registration fees;
 
  •  Fees and expenses of the exchange agent and trustee;
 
  •  Accounting and legal fees and printing costs; and
 
  •  Related fees and expenses.
 
Transfer Taxes
 
We will pay all transfer taxes, if any, applicable to the exchange of outstanding notes under the exchange offers. Each tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of outstanding notes under the exchange offers.


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Consequences of Failure to Exchange Outstanding Securities
 
If you do not exchange your outstanding notes for exchange notes under the applicable exchange offer, the outstanding notes you hold will continue to be subject to the existing restrictions on transfer. In general, you may not offer or sell the outstanding notes except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not intend to register outstanding notes under the Securities Act unless the registration rights agreement requires us to do so.
 
Accounting Treatment
 
We will record the exchange notes in our accounting records at the same carrying value as the outstanding notes. This carrying value is the aggregate principal amount of the outstanding notes, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offers, other than the recognition of the fees and expenses of the offering as stated under “— Fees and Expenses.”
 
Other
 
Participation in the exchange offers is voluntary, and you should consider carefully whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.
 
We may in the future seek to acquire any untendered outstanding notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any outstanding notes that are not tendered in the applicable exchange offer or to file a registration statement to permit resales of any untendered outstanding notes.


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CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS
 
Various statements contained in this prospectus, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. The forward-looking statements in this prospectus speak only as of the date of this prospectus; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed under the heading “Risk Factors” and the following:
 
  •  the volatility of natural gas and oil prices;
 
  •  discovery, estimation, development and replacement of natural gas and oil reserves;
 
  •  cash flow and liquidity;
 
  •  financial position;
 
  •  business strategy;
 
  •  amount, nature and timing of capital expenditures, including future development costs;
 
  •  availability and terms of capital;
 
  •  timing and amount of future production of natural gas and oil;
 
  •  availability of drilling and production equipment;
 
  •  timing of drilling rig fabrication and delivery;
 
  •  customer contracting of drilling rigs;
 
  •  availability of oil field labor;
 
  •  availability and regulation of CO2;
 
  •  operating costs and other expenses;
 
  •  prospect development and property acquisitions;
 
  •  availability of pipeline infrastructure to transport natural gas production;
 
  •  marketing of natural gas and oil;
 
  •  competition in the natural gas and oil industry;
 
  •  governmental regulation and taxation of the natural gas and oil industry; and
 
  •  developments in oil-producing and natural gas-producing countries.


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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA
 
The following tables set forth selected historical consolidated financial data for the three months ended March 31, 2008 and 2007 and for the years ended December 31, 2007, 2006, 2005, 2004 and 2003. The historical financial data as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005 are derived from our audited consolidated financial statements and the notes thereto included in this prospectus. The unaudited condensed consolidated balance sheet data and statement of operations data at March 31, 2007 and 2008 and for the three month periods ended March 31, 2007 and 2008 are derived from our unaudited condensed combined financial statements and the notes thereto included in this prospectus. The historical financial data as of December 31, 2005, 2004 and 2003 and for the years ended December 31, 2004 and 2003 are derived from our audited consolidated financial statements which are not included in this prospectus. The selected financial data should be read in conjunction with, and is qualified in its entirety by reference to, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and the notes thereto included elsewhere in this prospectus.
 
                                                         
    Years Ended December 31,     Three Months Ended March 31,  
    2003(1)     2004(2)     2005     2006     2007     2007     2008  
    (in thousands, except per share data)  
 
Statement of Operations Data:
                                                       
Revenues
  $ 155,337     $ 175,995     $ 287,693     $ 388,242     $ 677,452     $ 149,064     $ 269,086  
Expenses:
                                                       
Production
    7,980       10,230       16,195       35,149       106,192       21,974       34,188  
Production taxes
    2,099       2,497       3,158       4,654       19,557       2,933       9,220  
Drilling and services
    13,847       26,442       52,122       98,436       44,211       18,777       7,169  
Midstream marketing
    94,620       96,180       141,372       115,076       94,253       23,420       40,418  
Depreciation, depletion and amortization — natural gas and crude oil
    3,298       4,909       9,313       26,321       173,568       32,684       65,076  
Depreciation, depletion and amortization — other
    5,284       7,765       14,893       29,305       53,541       10,160       17,965  
General and administrative
    3,705       6,554       11,908       55,634       61,780       12,468       20,994  
Loss (gain) on derivative contracts
    3,450       878       4,132       (12,291 )     (60,732 )     23,181       136,844  
Loss (gain) on sale of assets
    (1,284 )     (210 )     547       (1,023 )     (1,777 )     (1 )     23  
                                                         
Total operating expenses
    132,999       155,245       253,640       351,261       490,593       145,596       331,897  
                                                         
Income (loss) from operations
    22,338       20,750       34,053       36,981       186,859       3,468       (62,811 )
                                                         
Other income (expense):
                                                       
Interest income
    103       56       206       1,109       5,423       1,088       796  
Interest expense
    (1,208 )     (1,678 )     (5,277 )     (16,904 )     (117,185 )     (35,429 )     (25,172 )
Minority interest
    (96 )     (262 )     (737 )     (296 )     276       (146 )     (835 )
Income (loss) from equity investments
    1,056       (36 )     (384 )     967       4,372       1,025       859  
                                                         
Total other expense
    (145 )     (1,920 )     (6,192 )     (15,124 )     (107,114 )     (33,462 )     (24,352 )
                                                         
Income (loss) before income taxes
    22,193       18,830       27,861       21,857       79,745       (29,994 )     (87,163 )
Income tax expense (benefit)
    7,585       6,433       9,968       6,236       29,524       (10,501 )     (30,538 )
                                                         
Income from continuing operations
    14,608       12,397       17,893       15,621       50,221       (19,493 )     (56,625 )
Income (loss) from discontinued operations, net of tax
    (85 )     451       229                          
Cumulative effect of accounting change
    (1,636 )                                    
Extraordinary gain
          12,544                                
                                                         
Net income (loss)
    12,887       25,392       18,122       15,621       50,221       (19,493 )     (56,625 )
Preferred stock dividends and accretion
                      3,967       39,888       8,966       9,582  
                                                         
Income (loss) available (applicable) to common stockholders
  $ 12,887     $ 25,392     $ 18,122     $ 11,654     $ 10,333     $ (28,459 )   $ (66,207 )
                                                         


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    Historical  
    Years Ended December 31,     Three Months Ended March 31,  
    2003(1)     2004(2)     2005     2006     2007     2007     2008  
    (In thousands except per share data)  
 
Earnings Per Share Information:
                                                       
Basic
                                                       
Income (loss) from continuing operations
  $ 0.26     $ 0.22     $ 0.31     $ 0.21     $ 0.46     $ (0.21 )   $ (0.40 )
Income from discontinued operations, net of income tax
          0.01       0.01                          
Extraordinary gain on acquisition
          0.22                                
Cumulative effect of change in accounting principle, net of income tax
    (0.03 )                                    
Preferred stock dividends
                      (0.05 )     (0.37 )     (0.10 )     (0.07 )
                                                         
Income (loss) per share available to common stockholders
  $ 0.23     $ 0.45     $ 0.32     $ 0.16     $ 0.09     $ (0.31 )   $ (0.47 )
Weighted average number of shares outstanding(3):
    56,312       56,312       56,559       73,727       108,828       92,442       141,044  
Diluted
                                                       
Income (loss) from continuing operations
  $ 0.26     $ 0.22     $ 0.31     $ 0.21     $ 0.46     $ (0.21 )   $ (0.40 )
Income from discontinued operations, net of income tax
          0.01       0.01                          
Extraordinary gain on acquisition
          0.22                                
Cumulative effect of change in accounting principle, net of income tax
    (0.03 )                                    
Preferred stock dividends
                      (0.05 )     (0.37 )     (0.10 )     (0.07 )
                                                         
Income (loss) per share available to common stockholders
  $ 0.23     $ 0.45     $ 0.32     $ 0.16     $ 0.09     $ (0.31 )   $ (0.47 )
                                                         
Weighted average number of shares outstanding(3):
    56,312       56,312       56,737       74,664       110,041       92,442       141,044  
 
 
(1) We adopted the provisions of SFAS 143 “Accounting for Retirement Obligations,” resulting in a cumulative effect of change in accounting principal of $1.6 million.
 
(2) We recognized an extraordinary gain from the recognition of the excess of fair value over acquisition cost of $12.5 million related to an acquisition we made in 2004.
 
(3) The number of shares has been adjusted to reflect a 281.562-to-1 stock split in December 2005.
 
                                                         
    As of December 31,     As of March 31,  
    2003     2004     2005     2006     2007     2007     2008  
    (In thousands)  
 
Balance Sheet Data:
                                                       
Cash and cash equivalents
  $ 176     $ 12,973     $ 45,731     $ 38,948     $ 63,135     $ 193,459     $ 726  
Property, plant and equipment, net
  $ 70,289     $ 114,818     $ 337,881     $ 2,134,718     $ 3,337,410     $ 2,274,247     $ 3,675,594  
Total assets
  $ 127,744     $ 197,017     $ 458,683     $ 2,388,384     $ 3,630,566     $ 2,689,004     $ 3,907,832  
Long-term debt
  $ 24,740     $ 59,340     $ 43,133     $ 1,066,831     $ 1,067,649     $ 1,074,254     $ 1,278,932  
Redeemable convertible preferred stock
  $     $     $     $ 439,643     $ 450,715     $ 449,643     $ 380,893  
Total stockholders’ equity
  $ 33,940     $ 59,330     $ 289,002     $ 649,818     $ 1,766,891     $ 932,801     $ 1,778,989  
Total liabilities and stockholders’ equity
  $ 127,744     $ 197,017     $ 458,683     $ 2,388,384     $ 3,630,566     $ 2,689,004     $ 3,907,832  


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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. You should read this discussion in conjunction with our audited and unaudited consolidated financial statements and the related notes beginning on page F-1 of this prospectus.
 
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 uncertainties, as well as those factors discussed below and elsewhere in this prospectus. Please see “Risk Factors” and “Cautionary Statements Regarding Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
 
The financial information with respect to the three month periods ended March 31, 2008 and March 31, 2007 that is discussed below is unaudited. In the opinion of management, this information contains all adjustments, consisting only of normal recurring accruals, necessary to state fairly the unaudited condensed consolidated financial statements. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.
 
Overview of Our Company
 
We are a rapidly expanding 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, Thistle, Big Canyon, and McKay Creek exploration areas. We also own and operate drilling rigs and conduct related oil field services, and we own and operate interests in gas gathering, marketing and processing facilities and CO2 gathering and transportation facilities.
 
On November 21, 2006, we acquired all of the outstanding membership interests in NEG Oil & Gas LLC (“NEG”) for total consideration of approximately $1.5 billion, excluding cash acquired. With core assets in the Val Verde and Permian Basins of West Texas, including overlapping or contiguous interests in the WTO, the NEG acquisition has dramatically increased our exploration and production segment operations. 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 March 31, 2008. We also operate significant interests in the Cotton Valley Trend in East Texas, the Gulf Coast area, the Mid-Continent and the Gulf of Mexico.
 
During November 2007, we completed the initial public offering of our common stock. We used the proceeds from this offering to repay indebtedness outstanding under our senior credit facility as well as a note payable related to a 2007 acquisition and to fund the remainder of our 2007 capital expenditure program and a portion of our 2008 capital expenditure program.
 
Recent Developments
 
Increase in Borrowing Base.  In April 2008, our senior credit facility was increased to $1.75 billion from $750 million and our borrowing base was increased to $1.2 billion from $700.0 million. The $1.2 billion borrowing base contemplated a potential future fixed income transaction not to exceed $400.0 million. As a result of our May 2008 issuance of $750.0 million of senior notes, our borrowing base was reduced to $1.1 billion.
 
Exchange of Senior Term Loans.  On May 1, 2008, we issued $650.0 million in principal amount of 85/8% Senior Notes Due 2015 in exchange for an equal outstanding principal amount of our fixed rate term


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loans and $350.0 million of our Senior Floating Rate Notes Due 2014 in exchange for an equal outstanding principal amount of our variable rate term loans. The exchange was made pursuant to a private placement 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 have been issued with registration rights.
 
Conversion of Redeemable Convertible Preferred 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. This conversion resulted in a one-time charge to retained earnings of $6.1 million in accelerated accretion expense related to the remaining offering costs of the 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.
 
Sale of Assets.  In May 2008, we entered into an agreement, along with other parties, to sell substantially all of our assets located in the Piceance Basin of Colorado to a subsidiary of The Williams Companies, Inc. The total purchase price was $285 million with net proceeds to the Company of approximately $140 million, subject to closing adjustments and allocation of the sales price among multiple sellers. Assets sold included undeveloped acreage, working interests in wells, gathering and compression systems and other facilities related to the wells. The sale was completed on May 20, 2008.
 
Issuance of 8% Senior Notes.  On May 20, 2008, we issued $750 million of our 8% Senior Notes due 2018 in a private placement. We received net proceeds of approximately $734 million from the offering. We used approximately $478 million of the net proceeds to repay all of the outstanding balance on our senior credit facility. The remaining proceeds will be used to fund the remaining unfunded portion of our $1.5 billion capital expenditures budget for 2008.
 
Segment Overview
 
We operate in four related business segments: exploration and production, drilling and oil field services, midstream gas services and other. Management evaluates the performance of our business segments based on operating income, which is defined as segment operating revenue less operating expenses and depreciation, depletion and amortization. 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.
 
                                         
          Three Months Ended
 
    Year Ended December 31,     March 31,  
    2007     2006     2005     2008     2007  
 
Segment revenue:
                                       
Exploration and production
  $ 478,747     $ 106,413     $ 54,051     $ 206,922     $ 90,826  
Drilling and oil field services
    73,202       138,657       80,151       12,322       27,895  
Midstream gas services
    107,578       122,892       147,499       45,087       26,187  
Other
    17,925       20,280       5,992       4,755       4,156  
                                         
Total revenues
    677,452       388,242       287,693       269,086       149,064  
Segment operating income:
                                       
Exploration and production
    198,913       17,069       14,886       (47,389 )     371  
Drilling and oil field services
    10,473       32,946       18,295       (2,148 )     5,202  
Midstream gas services
    6,783       3,528       4,096       32       1,350  
Other
    (29,310 )     (16,562 )     (3,224 )     (13,306 )     (3,455 )
                                         
Total operating income (loss)
    186,859       36,981       34,053       (62,811 )     3,468  
Interest income
    5,423       1,109       206       796       1,088  
Interest expense
    (117,185 )     (16,904 )     (5,277 )     (25,172 )     (35,429 )
Other income (expense)
    4,648       671       (1,121 )     24       879  
                                         
Income (loss) before income taxes
  $ 79,745     $ 21,857     $ 27,861     $ (87,163 )   $ (29,994 )
                                         


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          Three Months Ended
 
    Year Ended December 31,     March 31,  
    2007     2006     2005     2008     2007  
 
Production data:
                                       
Natural gas (Mmcf)
    51,958       13,410       6,873       19,173       10,449  
Crude oil (MBbls)(1)
    2,042       322       72       611       393  
Combined equivalent volumes (Mmcfe)
    64,211       15,342       7,305       22,839       12,807  
Average daily combined equivalent volumes (Mmcfe/d)
    175.9       42.0       20.0       251.0       142.3  
Average prices- as reported(2):
                                       
Natural gas (per Mcf)
  $ 6.51     $ 6.19     $ 6.54     $ 7.86     $ 6.60  
Crude oil (per Bbl)(1)
  $ 68.12     $ 56.61     $ 48.19     $ 89.81     $ 54.06  
Combined equivalent (per Mcfe)
  $ 7.45     $ 6.60     $ 6.63     $ 9.00     $ 7.04  
Average prices- including impact of derivative contract settlements:
                                       
Natural gas (per Mcf)
  $ 7.18     $ 7.25     $ 6.54     $ 8.32     $ 6.45  
Crude oil (per Bbl)(1)
  $ 68.10     $ 56.61     $ 48.19     $ 87.42     $ 54.06  
Combined equivalent (per Mcfe)
  $ 7.98     $ 7.52     $ 6.63     $ 9.32     $ 6.92  
Drilling and oil field services:
                                       
Number of operational drilling rigs owned at end of period
    25.0       25.0       19.0       26.0       25.0  
Average number of operational drilling rigs owned during the period
    26.0       21.9       14.3       26.0       25.0  
Average drilling revenue per rig per day(3)
  $ 17,177     $ 17,034     $ 11,503     $ 17,500     $ 16,600  
 
 
(1) Includes natural gas liquids.
 
(2) Prices represent actual average prices for the periods presented and do not give effect to derivative transactions.
 
(3) Does not include revenues for related rental equipment.
 
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, and contract for third party drilling, as needed, in the exploration and development of our operated wells and, to a lesser extent, on our non-operated wells.
 
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 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. The NEG acquisition in 2006 substantially increased our revenues and operating income in our exploration and production segment. However, because our working interest in the Piñon Field increased to approximately 93%, there are greater intercompany eliminations that affect the consolidated financial results of our drilling and oil field services and midstream gas services segments.
 
Exploration and production segment revenues increased to $206.9 million in the three months ended March 31, 2008 from $90.8 million in the three months ended March 31, 2007, an increase of 127.8%, as a result of a 78.1% increase in combined production volumes and a 27.8% increase in the combined average price we received for the natural gas and crude oil we produced. In the three month period ended March 31, 2008 we increased natural gas production by 8.8 Bcf to 19.2 Bcf and increased crude oil production by

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218 MBbls to 611 MBbls from the comparable period in 2007. The total combined 10.0 Bcfe increase in production was due primarily to an increase in our average working interest in the WTO from 81% at March 31, 2007 to 93% at March 31, 2008 and successful drilling in the WTO throughout 2007 and the first quarter of 2008. The Company had 1,869 producing wells at March 31, 2008 as compared to 1,333 producing wells at March 31, 2007.
 
The average price we received for our natural gas production for the three month period ended March 31, 2008 increased 19.1%, or $1.26 per Mcf, to $7.86 per Mcf from $6.60 per Mcf in the comparable period in 2007. The average price received for our crude oil production increased 66.1%, or $35.75 per barrel, to $89.81 per barrel during the three months ended March 31, 2008 from $54.06 per barrel during the same period in 2007. Including the impact of derivative contract settlements, the effective price received for natural gas for the three month period ended March 31, 2008 was $8.32 per Mcf as compared to $6.45 per Mcf during the same period in 2007. Including the impact of derivative contract settlements, the effective price received for crude oil for the three month period ended March 31, 2008 was $87.42. Our derivative contracts had no impact on effective oil prices during the three months ended March 31, 2007. During 2007 and continuing into 2008, we entered into derivatives contracts to mitigate the impact of commodity price fluctuations on our 2007, 2008 and 2009 production. Our derivative contracts are not designated as accounting hedges and, as a result, gains or losses on commodity derivative contracts are recorded as an operating expense. 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.”
 
For the three months ended March 31, 2008, we had a $47.4 million operating loss in our exploration and production segment, compared to $0.4 million in operating income for the same period in 2007. Our $116.1 million increase in exploration and production revenues was offset by a $12.2 million increase in production expenses, a $32.4 million increase in depreciation, depletion and amortization, or DD&A, due to the increase in production and a $136.8 million loss on our derivative contracts. The increase in production expenses was attributable to the increase in number of operating wells we own and an increase in our average working interest in those wells. During the three month period ended March 31, 2008, the exploration and production segment reported a $136.8 million net loss on our commodity derivative positions ($7.3 million realized gain and $144.1 million unrealized loss) compared to a $23.2 million loss ($1.5 million realized loss and $21.7 million unrealized loss) in the comparable period in 2007. During 2007 and first quarter 2008, we selectively entered into natural gas and oil swaps and natural gas basis swaps in order to mitigate the effects of fluctuations in prices received for our production. Given the long term nature of our investment in the WTO development program and the relatively high level of natural gas prices compared to our budgeted prices, management believes it prudent to enter into natural gas and crude oil swaps and natural gas basis swaps for a portion of our production. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative positions during the period. The change in fair value is principally measured based on period end prices as compared to the contract price. The unrealized loss on natural gas and crude oil derivative contracts recorded in the three month period ended March 31, 2008 was attributable to an increase in average natural gas and crude oil prices at March 31, 2008 as compared to the average natural gas and crude oil prices at December 31, 2007 or the contract price for contracts entered into during the period. Future volatility in natural gas and crude oil prices could have an adverse effect on the operating results of our exploration and production segment.
 
Exploration and production segment revenues increased to $478.7 million in the year ended December 31, 2007 from $106.4 million in 2006, an increase of 350%, as a result of a 320% increase in production volumes and a 13% increase in the average price we received for the natural gas and oil we produced. During 2007, we increased natural gas production by 38.5 Bcf to 52.0 Bcf and increased crude oil production by 1,720 MBbls to 2,042 MBbls. The total combined 48.9 Bcfe increase in production was due primarily to acquisitions and successful drilling in the WTO.
 
The average price we received for our natural gas production for the year ended December 31, 2007 increased 5%, or $0.32 per Mcf, to $6.51 per Mcf from $6.19 per Mcf in 2006. The average price received for our crude oil production increased to $68.12 from $56.61 per Bbl in 2006. Including the impact of derivative contract settlements, the effective price received for natural gas for the year ended December 31, 2007 was


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$7.18 per Mcf as compared to $7.25 per Mcf during the comparable period in 2006. Our oil derivative contract settlements decreased our effective price received for oil by $0.02 per Bbl to $68.10 per Bbl for the year ended December 31, 2007. Our derivative contracts had no impact on effective oil prices during the year ended December 31, 2006.
 
For the year ended December 31, 2007, we had $198.9 million in operating income in our exploration and production segment, compared to $17.1 million in operating income in 2006. The $372.4 million increase in exploration and production segment revenues was partially offset by a $71.0 million increase in production expenses and a $147.2 million increase in depreciation, depletion and amortization, or DD&A. The increase in production expenses was attributable to the additional properties acquired in the NEG acquisition and operating expenses on our new wells. During the year ended December 31, 2007, the exploration and production segment reported a $60.7 million net gain on our derivative positions ($34.5 million realized gains and $26.2 million unrealized gains) compared to a $12.3 million net gain ($14.2 million realized gains and $1.9 million unrealized losses) in the comparable period in 2006. During 2007, we selectively entered into natural gas swaps and basis swaps by capitalizing on what we perceived as spikes in the price of natural gas or favorable basis differences between the NYMEX price and natural gas prices at our principal West Texas pricing point of Waha Hub. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative positions during the period. The change in fair value is principally measured based on period end prices as compared to the contract price. Future volatility in natural gas and oil prices could have an adverse effect on the operating results of our exploration and production segment.
 
For the year ended December 31, 2006, exploration and production segment revenues increased to $106.4 million from $54.1 million in 2005. The increase in 2006 compared to 2005 was attributable to increased production due to successful drilling activity and approximately 40 days of production from the NEG acquisition effective November 21, 2006. NEG contributed approximately $36.9 million of revenues in the 2006 period. Production volumes increased to 15,342 Mmcfe in 2006 from 7,305 Mmcfe in 2005, representing an 8,037 Mmcfe, or 110% increase. Approximately 4,902 Mmcfe, or 61%, of the increase was attributable to NEG production for the period from November 21, 2006 to December 31, 2006. Average combined prices were essentially unchanged at $6.60 per Mcfe as compared to $6.63 per Mcfe in 2005.
 
Exploration and production segment operating income increased $2.2 million in 2006 to $17.1 million from $14.9 million in 2005. The increase was primarily attributable to the increased production revenues described above, approximately $12.3 million in derivative gains (including a $1.9 million unrealized loss) in 2006 as compared to a $4.1 million derivative loss (including a $1.3 million unrealized loss) in 2005, and the addition of NEG for the period from November 21, 2006 to December 31, 2006. The increase in exploration and production segment income was substantially offset by a $20.5 million, or 106%, increase in production costs, a $26.7 million, or 380%, increase in general and administrative expenses and a $19.3 million increase in DD&A. Approximately $7.0 million of the increase in production costs was attributable to the NEG acquisition with the remainder of the increase attributable to the increase in the number of wells operated in 2006 as compared to 2005. The increase in DD&A for our exploration and production segment was attributable to higher production and the increase in the full-cost pool due to the NEG acquisition.
 
As of December 31, 2007, we had 1,516.2 Bcfe of estimated net proved reserves with a PV-10 of $3,550.5 million, while at December 31, 2006 we had 1,001.8 Bcfe of estimated net proved reserves with a PV-10 of $1,734.3 million. Our Standardized Measure of Discounted Future Net Cash Flows was $2,718.5 million at December 31, 2007 as compared to $1,440.2 million at December 31, 2006 and $499.2 million at December 31, 2005. For a discussion of PV-10 and a reconciliation to Standardized Measure of Discounted Net Cash Flows, see “Business — Our Business and Primary Operations — Exploration and Production — Proved Reserves.” The increase in 2007 was primarily attributable to revisions of our previous estimates due to performance and results of our drilling activity. The increase in 2006 was primarily related to the addition of the NEG reserves which was partially offset by a decrease in the price of natural gas to $5.32 per Mcf at December 31, 2006 from $8.40 per Mcf at December 31, 2005.
 
Estimates of net proved reserves are inherently imprecise. In order to prepare our estimates, we must analyze available geological, geophysical, production and engineering data and project production rates and


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the timing of development expenditures. The process also requires economic assumptions about matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and the availability of funds. We may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control. Approximately 97% of our year-end reserve estimates are prepared by independent petroleum reserve engineers.
 
Over the past several years, higher natural gas and oil prices have led to higher demand for drilling rigs, operating personnel and field supplies and services. Higher prices have also caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher field costs. Our ownership of drilling rigs has also assisted us in stabilizing our overall cost structure. Given the inherent volatility of natural gas and oil prices that are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions, which generally were lower than the average sales prices received in 2007. We focus our efforts on increasing natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our overall cost structure to a level that allows for profitable production.
 
Like all exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, natural gas and oil production from a given well naturally decreases. Thus, a natural gas and oil exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on managing the costs associated with adding reserves through drilling and acquisitions as well as the costs associated with producing such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. In the WTO, this has not posed a problem. However, in other areas, the permitting and approval process has been more difficult in recent years due to increased activism from environmental and other groups. This has increased the time it takes to receive permits in some locations.
 
Drilling and Oil Field Services Segment
 
We drill for our own account primarily in the WTO through our drilling and oil field services subsidiary, Lariat Services, Inc. We also drill wells for other natural gas and crude oil companies, primarily located in the West Texas region. As of March 31, 2008, our drilling rig fleet consisted of 37 operational rigs, 26 we owned directly and 11 owned by Larclay, L.P., a limited partnership in which we have a 50% interest. We also own one rig that is currently being retrofitted. Our oil field services business conducts operations that complement our drilling services operations. These services include providing pulling units, trucking, rental tools, location and road construction and roustabout services to ourselves and to third parties. Additionally, we provide under-balanced drilling systems only for our own account.
 
In 2006, we and Clayton Williams Energy, Inc., or CWEI, formed Larclay, L.P., which acquired twelve sets of rig components and other related equipment to assemble into completed land drilling rigs. The drilling rigs were to be used for drilling on CWEI’s prospects, our prospects or for contracting to third parties on daywork drilling contracts. All of these rigs have been delivered, although one rig has not been assembled. CWEI was responsible for securing financing and the purchase of the rigs. The partnership financed 100% of the acquisition cost of the rigs utilizing a guarantee by CWEI. We operate the rigs owned by the partnership. The partnership and CWEI are responsible for all costs related to the initial construction and equipping of the drilling rigs. In the event of an operating shortfall within the partnership, we, along with CWEI, are responsible to fund the shortfall through loans to the partnership. We account for Larclay as an equity investment.
 
The financial results of our drilling and oil field services segment depend on many factors, particularly the demand for and the price we can charge for our services. We provide drilling services for our own account


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and for others, generally on a daywork, and less often on a turnkey, contract basis. We generally assess the complexity and risk of operations, the on-site drilling conditions, the type of equipment to be used, the anticipated duration of the work to be performed and the prevailing market rates in determining the contract terms we offer.
 
Daywork Contracts.  Under a daywork drilling contract, we provide a drilling rig with required personnel to our customer who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of the out-of-pocket drilling costs, and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs. As of March 31, 2008, 26 of our rigs were operating under daywork contracts and 24 of these were working for our account. As of March 31, 2008, the 11 operational rigs owned by Larclay were operating under daywork contracts and six of these were working for our account. Four of the remaining operational Larclay rigs were working for CWEI as of March 31, 2008.
 
Turnkey Contracts.  Under a typical turnkey contract, a customer will pay us to drill a well to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide most of the equipment and drilling supplies required to drill the well. We subcontract for related services such as the provision of casing crews, cementing and well logging. Generally, we do not receive progress payments and are paid only after the well is drilled. We enter into turnkey contracts in areas where our experience and expertise permit us to drill wells more profitably than under a daywork contract. As of March 31, 2008, none of our rigs were operating under a turnkey contract.
 
Drilling and oil field services segment revenue decreased to $12.3 million in the three month period ended March 31, 2008 from $27.9 million in the three month period ended March 31, 2007. This resulted in an operating loss of $2.1 million in the three month period ended March 31, 2008 compared to operating income of $5.2 million in the same period in 2007. The decline in revenues and operating income 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. 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 are capitalized as part of our full-cost pool. With the various WTO property acquisitions that occurred throughout 2007 and the first quarter of 2008, our average working interest has increased to approximately 93% (from 81% at March 31, 2007) in the wells we operate in the WTO, and the third-party interest has declined to less than 10%. Additionally, 24 of the 26 operational rigs we owned were working for our account at March 31, 2008, as compared to 14 of our 23 operational rigs working for our account at March 31, 2007. As a result, during the three month period ended March 31, 2008, approximately 84.6%, or $67.5 million, of our drilling and oil field service revenues were generated by work performed on our own account and eliminated in consolidation as compared to approximately 51.0%, or $29.0 million, for the comparable period in 2007. The average daily rate we received per rig of approximately $17,500, excluding revenues for related rental equipment and before intercompany eliminations, was slightly higher than the daily rate of $16,600 from the comparable period in 2007.
 
Drilling and oil field services segment revenue decreased to $73.2 million for the year ended December 31, 2007 from $138.7 million for the year ended December 31, 2006. Operating income decreased to $10.5 million during 2007 from $32.9 million in the same period in 2006. The decline in revenues and operating income is primarily attributable to an increase in the number of rigs operating on our properties and an increase in our ownership interest in our natural gas and oil properties. As of December 31, 2007, with the NEG acquisition and other WTO property acquisitions, our average working interest was approximately 93% in the wells we operate in the WTO, and the third-party interest has declined to less than 20%. During the year ended December 31, 2007, approximately 72% of drilling and oil field service segment revenue was generated by work performed on our own account and eliminated in consolidation as compared to approximately 34% for the comparable period in 2006. The number of drilling rigs we owned increased 19% to an average of 26 rigs during 2007 from an average of 21.9 rigs in 2006. The average daily rate we received per rig of $17,177, excluding revenues for related rental equipment and before intercompany eliminations, was


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essentially unchanged from 2006. Our rig utilization rate was 90%, representing 1,095 stacked rig days in 2007. The decline in operating income was principally attributable to the increase in the number and working interest ownership in wells drilled for our own account.
 
During 2006, our drilling and oil field services segment reported $138.7 million in revenues, an increase of $58.5 million, or 73%, from 2005. Operating income increased to $32.9 million in 2006 from $18.3 million in 2005. The increase in revenue and operating income was primarily attributable to an increase in the number of rigs we owned and an increase in the average revenue per rig per day we earned from the rigs. The number of rigs we owned increased 32% to 25 rigs as of December 31, 2006 and the average revenue we received per rig, excluding revenues for related rental equipment, increased 48% (before intercompany eliminations) to $17,034 per day from $11,503 per day. Our margins increased primarily due to our rig rates increasing faster than our operating costs.
 
We believe our ownership of drilling rigs and related oil field services will continue to be a major catalyst of our growth. As of December 31, 2007, our drilling fleet consisted of 44 rigs, including the twelve rigs owned by Larclay. As of December 31, 2007, 29 of our rigs are working on properties that we operate; six of our rigs are drilling on a contract basis for third parties; three are being retrofitted and six are idle or being repaired.
 
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 Midstream, Inc. (formerly known as ROC Gas Company, Inc.). Through our gas marketing subsidiary, Integra Energy LLC, we buy and sell natural gas produced from our operated wells as well as third-party operated wells. Gas marketing revenue is one of our largest revenue components; however, it is a very low margin business. On a consolidated basis, natural 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 revenue for the three months ended March 31, 2008 was $45.1 million compared to $26.2 million in the comparable period of 2007. The quarterly increase in midstream gas services revenues is attributable to larger third-party volumes transported and marketed through our gathering systems during the three months ended March 31, 2008 as compared to the same period in 2007. We generally charge a flat fee per unit transported and charge a percentage of sales for marketed volumes.
 
Midstream gas services segment revenue for the year ended December 31, 2007 was $107.6 million compared to $122.9 million in 2006. The decrease in midstream gas services revenues is attributable to the increase in our working interest in the WTO as a result of the NEG and other acquisitions.
 
Midstream gas services segment revenue decreased $24.6 million for the year ended December 31, 2006 from $147.5 million in 2005 to $122.9 million in 2006. The NEG acquisition significantly decreased our midstream gas services revenue as more gas was transported for our own account. We do not record midstream gas revenue for transportation, treating and processing of our own gas. Prior to the NEG acquisition, transportation, treating and processing of gas for NEG was recorded as midstream gas services revenue. Operating income increased $3.3 million in 2007 to $6.8 million due to lower gas prices paid and an increase in marketing and transportation for our own account. Operating income decreased to $3.5 million in 2006 from $4.1 million in the 2005 period, primarily due to the NEG acquisition and start-up operating expenses for our Sagebrush processing plant in 2006. The Sagebrush plant was placed into full operation during May 2007. We have the contractual right to periodically increase fees we receive for transportation and processing based on certain indexes.


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Other Segment
 
Our other segment consists primarily of our CO2 gathering and sales operations, corporate operations and other investments. 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 our and third parties’ tertiary oil recovery operations. The operating loss in the other segment was $13.3 million for the three months ended March 31, 2008 as compared to a loss of $3.5 million during the same period in 2007. The increase is primarily attributable to significant increases in corporate and support staff throughout 2007 and the first quarter of 2008.
 
Results of Operations
 
Three months ended March 31, 2008 compared to the three months ended March 31, 2007
 
Revenue.  Total revenue increased 80.5% to $269.1 million for the three months ended March 31, 2008 from $149.1 million in the same period in 2007. This increase was due to a $115.3 million increase in natural gas and crude oil sales. Lower drilling and oil field services revenues partially offset the increases noted in midstream gas services and other segments.
 
                                 
    Three Months Ended
             
    March 31,              
    2008     2007     $ Change     % Change  
          (In thousands)              
 
Revenue:
                               
Natural gas and crude oil
  $ 205,487     $ 90,176     $ 115,311       127.9 %
Drilling and services
    12,334       27,895       (15,561 )     (55.8 )%
Midstream and marketing
    46,409       26,187       20,222       77.2 %
Other
    4,856       4,806       50       1.0 %
                                 
Total revenues
  $ 269,086     $ 149,064     $ 120,022       80.5 %
                                 
 
Total natural gas and crude oil revenues increased $115.3 million to $205.5 million for the three months ended March 31, 2008 compared to $90.2 million for the same period in 2007, primarily as a result of an increase in natural gas and crude oil production volumes and prices received for our production. Total natural gas production increased 83.5% to 19,173 Mmcf in 2008 compared to 10,449 Mmcf in 2007, while crude oil production increased 55.5% to 611 MBbls in 2008 from 393 MBbls in 2007. The increase was due to our successful drilling in the WTO and an increased working interest in 2008 in the WTO as compared to the same period in 2007. The average price received, excluding the impact of derivative contracts, for our natural gas and crude oil production increased 27.8% in the 2008 period to $9.00 per Mcfe compared to $7.04 per Mcfe in 2007.
 
Drilling and services revenue decreased 55.8% to $12.3 million for the three months ended March 31, 2008 compared to $27.9 million in the same period in 2007. The decline in revenues is due to an increase in the number of company-owned rigs operating on company-owned natural gas and crude oil properties and the increase in working interest in these properties. Additionally, the average daily revenue per rig, after considering the effect of the elimination of intercompany usage, increased to approximately $17,500 per day during the first three months of 2008 as compared to an average rate of approximately $16,600 per day during the same period in 2007.
 
Midstream and marketing revenue increased $20.2 million, or 77.2%, with revenues of $46.4 million in the three month period ended March 31, 2008 as compared to $26.2 million in the three month period ended March 31, 2007. This increase is due primarily to larger production volumes transported and marketed, during the three months ended March 31, 2008 as compared to the same period in 2007, for the third parties with ownership in our wells or ownership in other wells connected to our gathering systems.


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Other revenue increased to $4.9 million for the three months ended March 31, 2008 from $4.8 million for the same period in 2007. Other revenue is generated primarily by our CO2 gathering and sales operations.
 
Operating Costs and Expenses.  Total operating costs and expenses increased to $331.9 million for the three months ended March 31, 2008 compared to $145.6 million for the same period in 2007 due to increases in production-related costs, general and administrative expenses as a result of an increase in corporate staff, depreciation, depletion and amortization and losses on derivative contracts. These increases were partially offset by a decrease in expenses attributable to our drilling and services.
 
                                 
    Three Months Ended
             
    March 31,              
    2008     2007     $ Change     % Change  
          (In thousands)              
 
Operating costs and expenses:
                               
Production
  $ 34,188     $ 21,974     $ 12,214       55.6 %
Production taxes
    9,220       2,933       6,287       214.4 %
Drilling and services
    7,169       18,777       (11,608 )     (61.8 )%
Midstream and marketing
    40,418       23,420       16,998       72.6 %
Depreciation, depletion, and amortization — natural gas and crude oil
    65,076       32,684       32,392       99.1 %
Depreciation, depletion and amortization — other
    17,965       10,160       7,805       76.8 %
General and administrative
    20,994       12,468       8,526       68.4 %
Loss on derivative contracts
    136,844       23,181       113,663       490.3 %
Loss (gain) on sale of assets
    23       (1 )     24       2,400.0 %
                                 
Total operating costs and expenses
  $ 331,897     $ 145,596     $ 186,301       128.0 %
                                 
 
Production expense includes the costs associated with our production activities, including, but not limited to, lease operating expense and processing costs. Production expenses increased $12.2 million primarily due to an increase in the number of wells in which we have a working interest. We owned working interests in 1,869 producing wells at March 31, 2008 compared to 1,333 producing wells at March 31, 2007. Production taxes increased $6.3 million, or 214.4%, to $9.2 million primarily due to the increase in production and the increased prices received for production during the three months ended March 31, 2008.
 
Drilling and services expenses decreased 61.8% for the three months ended March 31, 2008 as compared to the same period in 2007 primarily because of the increase in the number and working interest ownership of the wells we drilled for our own account.
 
Midstream and marketing expenses increased $17.0 million or 72.6% to $40.4 million due to larger production volumes transported and marketed during the three months ended March 31, 2008 on behalf of third parties than during the comparable period in 2007.
 
DD&A for our natural gas and crude oil properties increased to $65.1 million for the three months ended March 31, 2008 from $32.7 million in the same period in 2007. Our DD&A per Mcfe increased $0.30 to $2.85 in the first quarter of 2008 from $2.55 in the comparable period in 2007. The increase is primarily attributable to an increase in our depreciable properties, higher future development costs and increased production. Our production increased 78.1% to 22.8 Bcfe from 12.8 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 increase in DD&A for our other assets was attributable primarily to higher carrying costs of our rigs due to upgrades and retrofitting and our midstream gathering and processing assets due to upgrades made throughout 2007. We calculate depreciation of property and equipment using the straight-line method over the estimated useful lives of the assets, which range from three to 25 years. Our drilling rigs and related oil field services equipment are depreciated over an average seven-year useful life.


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General and administrative expenses increased $8.5 million to $21.0 million for the three months ended March 31, 2008 from $12.5 million for the comparable period in 2007. The increase was principally attributable to an $8.8 million increase in corporate salaries and wages due to a significant increase in corporate and support staff. As of March 31, 2008, we had 2,385 employees as compared to 1,746 at March 31, 2007. General and administrative expenses include non-cash stock compensation expense of $3.2 million for the three months ended March 31, 2008 as compared to $1.1 million for the comparable period in 2007. The increases in salaries and wages as well as stock compensation were partially offset by $3.2 million in capitalized general and administrative expenses for the three months ended March 31, 2008. There were no general and administrative expenses capitalized during the three months ended March 31, 2007.
 
For the three month period ended March 31, 2008, we recorded a loss of $136.8 million ($144.1 million unrealized loss and $7.3 million realized gain) on our derivative contracts compared to a $23.2 million loss ($21.7 million unrealized loss and $1.5 million realized loss) for the comparable period in 2007. During 2007 and the first three months of 2008, we selectively entered into natural gas and crude oil swaps and basis swaps in order to mitigate the effects of fluctuations in prices received for our production. Given the long-term nature of our investment in the WTO development program and the relatively high level of natural gas prices compared to budgeted prices, we believe it is prudent to enter into natural gas swaps and basis swaps for a portion of our production. Unrealized gains or losses on natural gas and crude oil derivative contracts represent the change in fair value of open derivative positions during the period. The change in fair value is principally measured based on period end prices as compared to the prior period end prices or contract price for contracts entered into during the period. The unrealized loss recorded in the three month period ended March 31, 2008 related to natural gas and crude oil commodities was attributable to an increase in average natural gas and crude oil prices at March 31, 2008 as compared to the average natural gas and crude oil prices at December 31, 2007 or the contract price for contracts entered into during the period.
 
Other Income (Expense).  Total other expense decreased to $24.4 million in the three month period ended March 31, 2008 from $33.5 million in the three month period ended March 31, 2007. The decrease is reflected in the table below.
 
                                 
    Three Months Ended
             
    March 31,              
    2008     2007     $ Change     % Change  
          (In thousands)              
 
Other income (expense):
                               
Interest income
  $ 796     $ 1,088     $ (292 )     (26.8 )%
Interest expense
    (25,172 )     (35,429 )     10,257       (29.0 )%
Minority interest
    (835 )     (146 )     (689 )     471.9 %
Income from equity investments
    859       1,025       (166 )     (16.2 )%
                                 
Total other expense
    (24,352 )     (33,462 )     9,110       (27.2 )%
                                 
Loss before income tax expense (benefit)
    (87,163 )     (29,994 )     (57,169 )     190.6 %
Income tax expense (benefit)
    (30,538 )     (10,501 )     (20,037 )     190.8 %
                                 
Net loss
  $ (56,625 )   $ (19,493 )   $ (37,132 )     190.5 %
                                 
 
Interest income decreased to $0.8 million for the three months ended March 31, 2008 from $1.1 million for the same period in 2007. This decrease was generally due to lower excess cash levels during the three months ended March 31, 2008 as compared to the same period in 2007.
 
Interest expense decreased to $25.2 million for the three months ended March 31, 2008 from $35.4 million for the same period in 2007. This decrease was primarily attributable to the expensing, in March 2007, of approximately $12.5 million in unamortized debt issuance costs related to our senior bridge facility at the time it was repaid. Also contributing slightly to the decrease for the three months ended March 31, 2008 was an $0.8 million unrealized gain related to our interest rate swap. These decreases were partially offset by increased interest expense during the three months ended March 31, 2008 due to higher average debt balances outstanding during that period as compared to the same period in 2007.


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During the three months ended March 31, 2008, we reported income from equity investments of $0.9 million as compared to $1.0 million in the comparable period in 2007.
 
We reported an income tax benefit of $30.5 million for the three months ended March 31, 2008, as compared to a benefit of $10.5 million for the same period in 2007. The current period income tax benefit represents an effective income tax rate of 35% which is unchanged from the same period in 2007.
 
Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006
 
Impact of the NEG Acquisition.  The results of operations for the year ended December 31, 2006 include the results of NEG from November 21, 2006. The results of operations for the year ended December 31, 2007 include the NEG acquisition for the full year. While NEG was principally an exploration and production company, the acquisition affected several of our revenue and expense categories. Revenues and expenses related to our natural gas and crude oil operations increased due to increased production from the acquired NEG properties. Revenues and expenses relating to our drilling and services and midstream and marketing operations decreased due to increased intercompany eliminations as more services were provided on company-owned properties. General and administrative expenses increased due to the addition of new staff. Interest expense increased due to the additional borrowings incurred in conjunction with the NEG acquisition.
 
Revenue.  Total revenue increased 75% to $677.5 million for the year ended December 31, 2007 from $388.2 million in 2006. This increase was due to a $376.4 million increase in natural gas and oil sales and was partially offset by lower revenues in our other segments.
 
                                 
    Year Ended December 31,              
    2007     2006     $ Change     % Change  
          (In thousands)              
 
Revenue:
                               
Natural gas and crude oil
  $ 477,612     $ 101,252     $ 376,360       371.7 %
Drilling and services
    73,197       139,049       (65,852 )     (47.4 )%
Midstream and marketing
    107,765       122,896       (15,131 )     (12.3 )%
Other
    18,878       25,045       (6,167 )     (24.6 )%
                                 
Total revenues
  $ 677,452     $ 388,242     $ 289,210       74.5 %
                                 
 
Total natural gas and crude oil revenues increased $376.4 million to $477.6 million for the year ended December 31, 2007, compared to $101.3 million in 2006, primarily as a result of an increase in natural gas and crude oil production volumes. Total natural gas production increased 287% to 51,958 Mmcf in 2007 compared to 13,410 Mmcf in 2006, while crude oil production increased 534% to 2,042 MBbls in 2007 from 322 MBbls in 2006. The increase was due to the NEG acquisition and our successful drilling in the WTO. The average price received for our natural gas and crude oil production increased 13% in 2007 to $7.45 per Mcfe compared to $6.60 per Mcfe in 2006, excluding the impact of derivative contracts.
 
Drilling and services revenue decreased 47% to $73.2 million in 2007 compared to $139.0 million in 2006. The decline in revenues is primarily attributable to an increase in the number of rigs operating on our properties and an increase in our ownership interest in our natural gas and oil properties. The number of rigs we owned increased to 26.0 (average for the year ended December 31, 2007) in 2007 compared to 21.9 in 2006, an increase of 19%, and the average daily revenue per rig, after considering the effect of the elimination of intercompany usage, was essentially unchanged at $17,177 per day.
 
Midstream and marketing revenue decreased $15.1 million, or 12%, with revenues of $107.8 million for the year ended December 31, 2007, as compared to $122.9 million in 2006. The NEG acquisition significantly decreased our midstream gas services revenues as more gas was transported for our own account. Prior to the acquisition, transportation, treating and processing of gas for NEG was recorded as midstream gas services revenue. We have the contractual right to periodically increase fees we receive for transportation and processing based on certain indexes.


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Other revenue decreased to $18.9 million during 2007 from $25.0 million in 2006. The decrease was primarily due to the sale of various non-energy related assets to our former President and Chief Operating Officer. Revenues related to these assets are included in the 2006 period prior to their sale in August 2006. This decrease was slightly offset by an increase in revenues generated by our CO2 operations.
 
Operating Costs and Expenses.  Total operating costs and expenses increased to $490.6 million during 2007, compared to $351.3 million in 2006, primarily due to increases in our production-related costs as well as an increase in corporate staff. These increases were partially offset by decreases in costs attributable to our drilling and services and midstream and marketing operations as well as increased gains on derivative instruments.
 
                                 
    Year Ended December 31,              
    2007     2006     $ Change     % Change  
          (In thousands)              
 
Operating costs and expenses:
                               
Production
  $ 106,192     $ 35,149     $ 71,043       202.1 %
Production taxes
    19,557       4,654       14,903       320.2 %
Drilling and services
    44,211       98,436       (54,225 )     (55.1 )%
Midstream and marketing
    94,253       115,076       (20,823 )     (18.1 )%
Depreciation, depletion, and amortization — natural gas and crude oil
    173,568       26,321       147,247       559.4 %
Depreciation, depletion and amortization — other
    53,541       29,305       24,236       82.7 %
General and administrative
    61,780       55,634       6,146       11.0 %
Gain on derivative instruments
    (60,732 )     (12,291 )     (48,441 )     (394.1 )%
Gain on sale of assets
    (1,777 )     (1,023 )     (754 )     (73.7 )%
                                 
Total operating costs and expenses
  $ 490,593     $ 351,261     $ 139,332       39.7 %
                                 
 
Production expense includes the costs associated with our exploration and production activities, including, but not limited to, lease operating expense and processing costs. Production expenses increased $71.0 million due to increased production from our 2007 drilling activity and the addition of the NEG properties. The remainder of the increase was due to an increase in lease operating expenses due to an increase in the number of wells we operate. Production taxes increased $14.9 million, or 320%, to $19.6 million primarily due to increased gas production as a result of our 2007 drilling activity and the addition of the NEG properties in 2006.
 
Drilling and services and midstream and marketing expenses decreased 55% and 18% respectively, during 2007 as compared to 2006 primarily because of the increase in the number and working interest ownership of the wells we drilled for our own account.
 
DD&A for our natural gas and crude oil properties increased to $173.6 million during 2007 from $26.3 million in 2006. Our DD&A per Mcfe increased $0.98 to $2.70 from $1.72 in 2006. The increase is primarily attributable to our 2007 capital expenditures and the NEG acquisition, which increased our depreciable properties by the purchase price plus future development costs and increased production. Our production increased 320% to 64.2 Bcfe from 15.3 Bcfe in 2006.
 
DD&A for our other assets consists primarily of depreciation of our drilling rigs, natural gas plants and other equipment. The $24.2 million increase in DD&A — other was due primarily to our increased investments in rigs, other oilfield services equipment and midstream assets. During 2006 and 2007, capital expenditures for drilling rigs, other oilfield services equipment and midstream assets were $293 million on a combined basis. We calculate depreciation of property and equipment using the straight-line method over the estimated useful lives of the assets, which range from three to 25 years. Our drilling rigs and related oil field services equipment are depreciated over an average seven-year useful life.


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General and administrative expenses increased 11% to $61.8 million during 2007 from $55.6 million in 2006. The increase was principally attributable to a $17.3 million increase in corporate salaries and wages which was due to a significant increase in corporate and support staff. As of December 31, 2007 we had 2,227 employees as compared to 1,443 at December 31, 2006. The increase in corporate salaries and wages was partially offset by $4.6 million in capitalized general and administrative expenses, a $5.5 million decrease due to a legal settlement recorded in 2006 and a $1.6 million decrease in stock compensation expense. In accordance with the full-cost method of accounting, we capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. During 2006 we settled a legal dispute resulting in an additional loss on the settlement of $5.5 million. As part of a severance package for certain executive officers, the Board of Directors approved the acceleration of vesting of certain stock awards resulting in increased compensation expense recognized during 2006.
 
For the year ended December 31, 2007, we recorded a gain of $60.7 million ($26.2 million unrealized gain and $34.5 million realized gain) on our derivatives instruments compared to a $12.3 million gain ($1.9 million unrealized loss and $14.2 million realized gain) in 2006. During 2007, we selectively entered into natural gas swaps and basis swaps by capitalizing on what we perceived as spikes in the price of natural gas or favorable basis differences between the NYMEX price and natural gas prices at our principal West Texas pricing point of Waha Hub. Unrealized gains or losses on derivatives contracts represent the change in fair value of open derivatives positions during the period. The change in fair value is principally measured based on period end prices as compared to the contract price. The unrealized gain recorded during 2007 was attributable to a decrease in average natural gas prices at December 31, 2007 as compared to the average natural gas prices at the various contract dates.
 
Other Income (Expense).  Total other expense increased to $107.1 million for the year ended December 31, 2007 from $15.1 million in 2006. The increase is reflected in the table below.
 
                                 
    Year Ended December 31,              
    2007     2006     $ Change     % Change  
          (In thousands)              
 
Other income (expense):
                               
Interest income
  $ 5,423     $ 1,109     $ 4,314       389.0 %
Interest expense
    (117,185 )     (16,904 )     (100,281 )     593.2 %
Minority interest
    276       (296 )     572       193.2 %
Income from equity investments
    4,372       967       3,405       352.1 %
                                 
Total other expense
    (107,114 )     (15,124 )     (91,990 )     (608.2 )%
                                 
Income before income taxes
    79,745       21,857       57,888       264.8 %
Income tax expense
    29,524       6,236       23,288       373.4 %
                                 
Net income
  $ 50,221     $ 15,621     $ 34,600       221.5 %
                                 
 
Interest income increased to $5.4 million in 2007 from $1.1 million in 2006. This increase was due to interest income from investment of excess cash after the repayment of debt.
 
Interest expense increased to $117.2 million during 2007, from $16.9 million in 2006. This increase was attributable to increased average debt balances. To finance the NEG acquisition, we entered into a $750 million senior credit facility, which had an initial borrowing base of $300 million, and an $850 million senior bridge facility. In March 2007, we entered into a $1.0 billion senior term loan and sold 17.8 million shares of common stock in a private placement. A portion of the proceeds from the senior unsecured term loan was used to repay the bridge loan. Please read “— Liquidity and Capital Resources.”
 
The minority interest is derived from Cholla Pipeline, LP, Sagebrush Pipeline, LLC and Integra. We acquired the remaining minority interest in Integra in the fourth quarter of 2007.


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During the year ended December 31, 2007 we reported income from equity investments of $4.4 million as compared to $1.0 million in 2006. Approximately $1.9 million of the increase was attributable to income from our interest in the Grey Ranch processing plant which has experienced increased profitability due to higher levels of utilization in 2007 as compared to 2006. Approximately $1.5 million of the increase was attributable to income from Larclay as all of Larclay’s rigs have now been delivered and all but one rig are operational.
 
We reported an income tax expense of $29.5 million for the year ended December 31, 2007 as compared to an expense of $6.2 million in 2006. The current period income tax expense represents an effective income tax rate of 37.0% as compared to 28.5% in 2006. The lower effective income tax rate in 2006 was attributable to favorable percentage depletion deductions during that period.
 
Year Ended December 31, 2006 Compared to Year Ended December 31, 2005
 
Revenue.  Total revenue increased to $388.2 million in 2006 from $287.7 million in 2005, which is further explained by the categories below.
 
                                 
    Year Ended December 31,              
    2006     2005     $ Change     % Change  
          (In thousands)              
 
Revenue:
                               
Natural gas and crude oil
  $ 101,252     $ 49,987     $ 51,265       102.6 %
Drilling and services
    139,049       80,343       58,706       73.1 %
Midstream and marketing
    122,896       147,133       (24,237 )     (16.5 )%
Other
    25,045       10,230       14,815       144.8 %
                                 
Total revenues
  $ 388,242     $ 287,693     $ 100,549       35.0 %
                                 
 
Natural gas and crude oil revenue increased $51.3 million to $101.3 million in 2006 from $50.0 million in 2005. This was primarily a result of an increase in natural gas production volumes. Total natural gas production almost doubled to 13,410 Mmcf in 2006 compared to 6,873 Mmcf in 2005. Natural gas prices decreased $0.35, or 5%, in the 2006 period to $6.19 per Mcf compared to $6.54 per Mcf in 2005.
 
Drilling and services revenue increased 73% to $139.0 million for the year ended December 31, 2006 compared to $80.3 million in the same period in 2005, primarily due to an increase in the number of drilling rigs we owned and to an increase in the average daily revenue per rig. The number of rigs we owned increased to 25 (21.9 average for the year) as of December 31, 2006 compared to 19 (14.3 average for the year) in 2005, an increase of 32%, and the average daily revenue per rig, after considering the effect of the elimination of intercompany usage, increased 48% to $17,034 in 2006 compared to $11,503 in 2005. Additionally, the revenue from our heavy hauling trucking subsidiary increased $7.8 million during the comparison period due to an expansion of our trucking services. The revenue from our pulling unit operations increased $7.7 million because of an increase in the demand for these oil field services and an increase in the rate we charge.
 
Midstream and marketing revenue decreased $24.2 million from 2005 with revenues of $122.9 million during the year ended December 31, 2006 as compared to $147.1 million in 2005. We do not record midstream and marketing revenues for marketing, transportation, treating and processing of our own gas. The NEG acquisition significantly decreased our midstream gas services revenues as more gas was transported and marketed for our own account. Prior to the NEG acquisition, transportation, treating and processing of gas for NEG was recorded as midstream and marketing revenue. We have the contractual right to periodically increase fees we receive for transportation and processing based on certain indexes.
 
Other revenues increased $14.8 million to $25.0 million in 2006 from $10.2 million in 2005. The increase was primarily attributable to an increase of $12.0 million in CO2 and tertiary oil recovery revenues. In December 2005, we acquired an additional equity interest in PetroSource which increased our ownership interest to 86.5%, resulting in the consolidation of PetroSource commencing in the fourth quarter of 2005. We recorded PetroSource revenues for the full year in 2006. The remainder of the increase was attributable to


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additional administration fees collected from operating natural gas and oil wells and lease acreage income received as a result of an increase in the number of wells, an increase in overhead rates and an increase in leasing activities. Approximately $0.9 million of the increase was related to an increase of revenue from a shopping center that was sold in 2006.
 
Operating Costs and Expenses.  Total operating costs and expenses increased $97.6 million to $351.3 million in 2006 from $253.6 million in 2005, which is further explained by the categories below.
 
                                 
    Year Ended December 31,              
    2006     2005     $ Change     % Change  
          (In thousands)              
 
Operating costs and expenses:
                               
Production
  $ 35,149     $ 16,195     $ 18,954       117.0 %
Production taxes
    4,654       3,158       1,496       47.4 %
Drilling and services
    98,436       52,122       46,314       88.9 %
Midstream and marketing
    115,076       141,372       (26,296 )     (18.6 )%
Depreciation, depletion and amortization-natural gas and oil
    26,321       9,313       17,008       182.6 %
Depreciation, depletion and amortization-other
    29,305       14,893       14,412       96.8 %
General and administrative
    55,634       11,908       43,726       367.2 %
Loss (gain) on derivative instruments
    (12,291 )     4,132       (16,423 )     (397.5 )%
Loss (gain) on sale of assets
    (1,023 )     547       (1,570 )     (287.0 )%
                                 
Total operating costs and expenses
  $ 351,261     $ 253,640     $ 97,621       38.5 %
                                 
 
Production expense increased to $35.1 million in 2006 from $16.2 million in 2005 primarily due to the increase in the number of wells operated in 2006 as compared to 2005, the addition of NEG for the period from November 21, 2006 to December 31, 2006 and the addition of PetroSource for the full year in 2006 as compared to one quarter in 2005. Approximately $7.5 million of the increase was attributable to the NEG acquisition and approximately $3.2 million of the increase was attributable to PetroSource with the remainder of the increase due to an increase in the number of wells we operate.
 
Production taxes increased $1.5 million, or 47%, to $4.7 million due to the increase in natural gas production, which was partially offset by a decline in realized natural gas prices. Production taxes are generally assessed at the wellhead and are based on the volumes produced times the price received.
 
Drilling and services expenses increased 89% to $98.4 million in 2006 from $52.1 million in 2005, primarily due to an increase in oil field services operating expense. Oil field services operating expenses, including fuel, repairs and maintenance, increased $14.2 million due to an increase in the number of drilling rigs we owned as well as work we performed on a turnkey and footage basis rather than a day rate basis.
 
Midstream and marketing expenses decreased $26.3 million, or 19%, to $115.1 million in 2006 as compared to $141.4 million in 2005 due to a decrease in the average price paid for natural gas that we market and a decrease in natural gas purchased from third parties as we focused our marketing efforts more on our own production.
 
DD&A relating to our natural gas and oil properties increased 183% to $26.3 million in 2006 from $9.3 million in 2005. The increase was primarily attributable to a 110% increase in year-over-year production and a 37% increase in DD&A per unit of production. The average DD&A per Mcfe was $1.68 for the year ended December 31, 2006 as compared to $1.23 in 2005. The increase in the DD&A rate was attributable to the NEG acquisition which added significantly higher reserves at a higher cost per Mcfe.
 
DD&A related to other property, plant and equipment increased $14.4 million, or 97%, primarily due to our investment in additional drilling rigs and oil field service equipment.


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General and administrative expense increased $43.7 million to $55.6 million in 2006 from $11.9 million in 2005, due in part to an increase in expense related to salaries and wages as we added a significant amount of staff to accommodate our acquisitions and our increased drilling activities, a $5 million dispute settlement, a $3.6 million increase in property and franchise taxes, higher administrative costs associated with our increase in staff including rent, utilities, insurance and office equipment and supplies, a $2.5 million increase in bad debt expense and an increase in legal and professional expenses. Legal and professional fees increased $4.7 million due primarily to an increase in legal fees relating to two legal issues and increased audit fees.
 
For the year ended December 31, 2006, we recorded a gain on derivative instruments of $12.3 million compared to a loss of $4.1 million in 2005. We enter into collars and fixed-price swaps to mitigate the effect of price fluctuations of natural gas and oil. We use natural gas basis swaps to mitigate the risk of fluctuations in pricing differentials between our natural gas well head prices and benchmark spot prices. We have not designated any of these derivative contracts as hedges for accounting purposes. We record derivatives contracts at fair value on the balance sheet, and gains or losses resulting from changes in the fair value of our derivative contracts (unrealized) are recognized as a component of operating costs and expenses. Unrealized gains or losses are realized upon settlement. During the first eleven months of 2006, we settled or terminated all of our natural gas derivative contracts and realized a net gain of approximately $14.2 million. Offsetting the 2006 net realized gain on the settlement or early termination of our derivative instruments was a net unrealized loss of $1.9 million which represented the change in fair value of our derivatives instruments from the purchase date in early December 2006 to December 31, 2006. Generally, we record unrealized gains on our swaps and fixed-price swaps when natural gas and oil commodity prices decrease and record unrealized losses as natural gas and oil prices increase. We record unrealized gains on our basis swaps if the pricing differential increases and unrealized losses as the pricing differential decreases. Gains or losses on derivatives contracts are realized upon settlement. During 2005 we did not terminate any derivatives positions and realized a loss of $2.8 million due to normal settlements. Future volatility in natural gas and oil prices could have an adverse effect on the operating results of our exploration and production segment.
 
Other Income (Expense).  Total other expense increased to $15.1 million in 2006 from $6.2 million in 2005. The increase is detailed in the table below.
 
                                 
    Year Ended December 31,              
    2006     2005     $ Change     % Change  
          (In thousands)              
 
Other income (expense):
                               
Interest income
  $ 1,109     $ 206     $ 903       438.3 %
Interest expense
    (16,904 )     (5,277 )     (11,627 )     (220.3 )%
Minority interest
    (296 )     (737 )     441       59.8 %
Income (loss) from equity investments
    967       (384 )     1,351       351.8 %
                                 
Total other expense
    (15,124 )     (6,192 )     (8,932 )     (144.3 )%
                                 
Income before income taxes
    21,857       27,861       (6,004 )     (21.5 )%
Income tax expense
    6,236       9,968       (3,732 )     (37.4 )%
Income from discontinued operations, net of tax
          229       (229 )     (100.0 )%
                                 
Net income
  $ 15,621     $ 18,122     $ (2,501 )     (13.8 )%
                                 
 
Interest income increased to $1.1 million in 2006 from $0.2 million in 2005. This increase was due to interest income recognized in 2006 related to excess cash balances with various financial institutions.
 
Interest expense increased to $16.9 million in 2006 from $5.3 million in 2005. This increase was due to the additional debt that we incurred to finance our purchase of NEG.
 
We recorded income from equity investments of $1.0 million in 2006 as compared to a $0.4 million loss in 2005. The 2005 loss was primarily due to PetroSource. We accounted for PetroSource under the equity method during the first nine months of 2005.


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Income tax expense decreased to $6.2 million in 2006 from $10.0 million in 2005 primarily due to a decrease in our effective income tax rate. During 2006, we realized a $3.5 million reduction in tax expense from our percentage depletion deduction, which was partially offset by $1.3 million in additional state income taxes.
 
Liquidity and Capital Resources
 
Summary
 
Our operating cash flow is influenced mainly by the prices 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 rates we receive for these services; and the margins we obtain from our natural gas and CO2 gathering and processing contracts.
 
On November 9, 2007, we completed the initial public offering of our common stock. We sold 32,379,500 shares of our common stock, including 4,170,000 shares sold directly to an entity controlled by our Chairman and Chief Executive Officer, Tom L. Ward. 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  
         
 
As of March 31, 2008, our cash and cash equivalents were $0.7 million, and we had approximately $462.3 million available under our senior credit facility. Amounts outstanding under our senior credit facility at March 31, 2008 totaled $215.0 million. As of March 31, 2008, we had $1.3 billion in total debt outstanding.
 
Capital Expenditures
 
We make and expect to continue to make substantial capital expenditures in the exploration, development, production and acquisition of natural gas and crude oil reserves.
 
Our capital expenditures by segment were:
 
                                         
                      Three Months Ended
 
    Year Ended December 31,     March 31,  
    2007     2006     2005     2008     2007  
                (In thousands)              
 
Capital Expenditures:
                                       
Exploration and production
  $ 1,046,552     $ 170,872     $ 61,227     $ 354,765     $ 127,582  
Drilling and oil field services
    123,232       89,810       43,730       17,921       41,242  
Midstream gas services
    63,828       16,975       25,904       38,721       9,543  
Other
    47,236       28,884       3,735       7,243       2,728  
                                         
Capital expenditures, excluding acquisitions
    1,280,848       306,541       134,596       418,650       181,095  
Acquisitions
    116,650       1,054,075       21,247              
                                         
Total
  $ 1,397,498     $ 1,360,616     $ 155,843     $ 418,650     $ 181,095  
                                         
 
We estimate that our total capital expenditures for 2008, excluding acquisitions, will be approximately $1.5 billion. Our planned 2008 capital expenditures are consistent with 2007 levels. As in 2007, our 2008 capital expenditures for our exploration and production segment will be focused on growing and developing


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our reserves and production on our existing acreage and acquiring additional leasehold interests, primarily in the WTO. Of our total $1.5 billion capital expenditure budget, approximately $1.2 billion is budgeted for exploration and production activities. Included in our 2008 exploration and production capital expenditure budget is $723 million for drilling in the WTO, including the Piñon field, $241 million for drilling in areas other than the WTO, $33 million dedicated to our tertiary oil recovery program and $241 million for land and seismic. Based on encouraging initial results from our 3-D seismic acquisition program that we commenced in 2007, we have budgeted $151 million of our 2008 WTO capital expenditures to explore for new fields within the WTO. We plan to drill approximately 440 gross wells in 2008.
 
During 2008, we completed our rig fleet expansion program that we started in 2005. Final delivery of all of the rigs ordered from Chinese manufacturers occurred in 2007, and all such rigs had been retrofitted and joined our fleet by the second quarter of 2008. We are also continuing to upgrade and modernize our rig fleet. Approximately $67 million of our 2008 capital expenditure budget will be spent on our drilling and oil field services segment.
 
We anticipate spending approximately $195 million in capital expenditures in our midstream gas services and other segments as we expand our network of gas gathering lines and plant and compression capacity.
 
We believe that our cash flows from operations, current cash and investments on hand and availability under our senior credit facility will be sufficient to meet our capital expenditure budget for the next twelve months. The majority of our capital expenditures will be discretionary and could be curtailed if our cash flows decline from expected levels or we are unable to obtain capital on attractive terms; however, we have various sources of capital in the form of our revolving credit facility, potential asset sales or the incurrence of additional long-term debt.
 
Cash Flows from Continuing Operations
 
Our cash flows from continuing operations are as follows:
 
                                         
                      Three Months Ended
 
    Year Ended December 31,     March 31,  
    2007     2006     2005     2008     2007  
                (In thousands)              
 
Cash Flows from Operations:
                                       
Cash flows provided by operating activities
  $ 357,452     $ 67,349     $ 63,297     $ 156,689     $ 43,963  
Cash flows used in investing activities
    (1,385,581 )     (1,340,567 )     (155,826 )     (418,979 )     (182,546 )
Cash flows provided by financing activities
    1,052,316       1,266,435       126,413       199,881       293,094  
                                         
Net increase (decrease) in cash and cash equivalents
  $ 24,187     $ (6,783 )   $ 33,884     $ (62,409 )   $ 154,511  
                                         
 
Operating Activities.  Net cash provided by operating activities for the three months ended March 31, 2008 and 2007 were $156.7 million and $44.0 million, respectively. The increase in cash provided by operating activities from 2007 to 2008 was primarily due to our 78.1% increase in production volumes as a result of our drilling success in the WTO as well as various acquisitions throughout 2007 and the first three months of 2008. Also, contributing to this increase was a 27.8% increase in the combined average prices we received for the natural gas and crude oil produced. These increases were partially offset by increases in general and administrative costs, such as salaries and wages.
 
Net cash provided by operating activities for the years ended December 31, 2007 and 2006 were $357.5 million and $67.3 million, respectively. The increase in cash provided by operating activities from 2006 to 2007 was primarily due to our $34.6 million increase in net income as a result of our 320% increase


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in production volumes as a result of the NEG and various other acquisitions as well as our drilling success. Also, contributing to this increase was $34.5 million in realized gains on our derivative contracts. These increases were partially offset by increases in general and administrative costs such as salaries and wages.
 
Cash flows provided by operating activities increased $4.0 million to $67.3 million in 2006 from $63.3 million in 2005 primarily due to an increase in non-cash DD&A of $31.4 million and an increase in non-cash stock-based compensation expense of $8.3 million as net income decreased approximately $2.5 million in 2006 over 2005. The increases were substantially offset by changes in operating assets and liabilities.
 
Investing Activities.  Cash flows used in investing activities increased to $419.0 million in the three month period ended March 31, 2008 from $182.5 million in the comparable 2007 period as we continued to ramp up our capital expenditure program. For the three month period ended March 31, 2008, our capital expenditures were $354.8 million in our exploration and production segment, $17.9 million for drilling and oil field services, $38.7 million for midstream gas services and $7.2 million for other capital expenditures. During the same period in 2007, capital expenditures were $127.6 million in our exploration and production segment, $41.2 million for drilling and oil field services, $9.5 million for midstream gas services and $2.7 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 continued to ramp up our capital expenditure program. During 2007 our capital expenditures were $1,046.6 million in our exploration and production segment, $123.2 million for drilling and oil field services, $63.8 million for midstream gas services and $47.2 million for other capital expenditures.
 
Cash flows used in investing activities increased to $1,340.6 million for the year ended December 31, 2006 from $155.8 million in 2005. During 2006, our cash flows used in investing activities included acquisitions of $1,054 million, including the NEG acquisition described above. During the comparison period, exploration and production capital expenditures increased to $170.9 million in 2006 from $61.2 million in 2005, primarily because of the additional wells that were drilled in the Piñon Field in 2006 and 2005. Capital expenditures for drilling and oil field services increased to $89.8 million in 2006 from $43.7 million in 2005, due to an increase in the number of drilling rigs. Proceeds from the sale of assets increased to $19.7 million in 2006 from $3.3 million in 2005.
 
Financing Activities.  Since December 2005, we have used equity issuances, borrowings and, to a lesser extent, our cash flows from operations to fund our rapid growth. Proceeds from borrowings decreased to $340.2 million for the three months ended March 31, 2008, and we repaid approximately $128.9 million leaving net borrowings during the period of approximately $211.3 million. Our financing activities provided $199.9 million in cash for the three month period ended March 31, 2008 compared to $293.1 million in the comparable period in 2007.
 
During 2007 we raised $1.1 billion in equity issuances and had net cash repayments of $0.7 million of debt. Our equity issuances included the November 2007 initial public offering of our common stock yielding net proceeds of $794.7 million and a March 2007 private placement of our common stock which provided net proceeds of approximately $318.7 million. Proceeds from borrowings were $1,331.5 million during 2007 and we repaid approximately $1,332.2 million leaving net cash repayments during 2007 of approximately $0.7 million. We used the net proceeds from our term loan and the common stock issuances to repay our senior bridge facility and all of the outstanding borrowings under our senior credit facility as well as to fund a portion of our capital expenditure program. Our financing activities provided $1,052.3 million in cash during 2007 compared to $1,266.4 million in 2006.
 
During the year ended December 31, 2006, we incurred net borrowings of $743.0 million, raised $100.8 million from issuances of common stock and raised $439.5 million from an issuance of redeemable convertible preferred stock. Our net borrowings, common stock issuances and issuance of redeemable preferred stock in 2006 were primarily used to finance the NEG acquisition as well as our 2006 capital expenditure


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program. Most of our borrowings in 2005 funded the acquisition of drilling rigs, our exploration and production activities and the expansion of our gathering and treating assets. In December 2005, we received $173.1 million in net proceeds from a private placement of common stock, which was primarily used to reduce outstanding borrowings and to increase our interest in SandRidge Tertiary and SandRidge CO2.
 
Credit Facilities and Other Indebtedness
 
Senior Credit Facility.  On November 21, 2006, we entered into a new $750.0 million senior secured revolving credit facility (the “senior credit facility”) with Bank of America, N.A., as Administrative Agent. The senior credit facility matures on November 21, 2011 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 initial proceeds of the senior credit facility were used to (i) partially finance the NEG acquisition, (ii) refinance our existing senior secured revolving credit facility and NEG’s existing credit facility, and (iii) pay fees and expenses related to the NEG acquisition and our existing credit facility.
 
The senior credit facility contains various covenants that limit our and certain of our subsidiaries’ ability to grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of our assets. Additionally, the senior credit facility limits our and certain of our subsidiaries’ ability to incur additional indebtedness.
 
The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for (i) the ratio of total funded debt to EBITDAX (as defined in the senior credit facility), which may not exceed 4.5:1.0 calculated using the last fiscal quarter on an annualized basis as of the end of fiscal quarters ending on or before September 30, 2008 and calculated using the last four completed fiscal quarters thereafter, (ii) the ratio of EBITDAX to interest expense plus current maturities of long-term debt, which must be at least 2.5:1.0 calculated using the last four completed fiscal quarters, and (iii) the current ratio, which must be at least 1.0:1.0. As of March 31, 2008, we were in compliance with all of the 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 intercompany debt of us and our subsidiaries; and substantially all of our assets and the assets of our guarantor subsidiaries, including proved natural gas and crude oil reserves representing at least 80% of the present discounted 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.
 
The borrowing base is subject to review semi-annually; however, the lenders reserve the right to have one additional redetermination of the borrowing base per calendar year. Unscheduled redeterminations may be made at our request, but are limited to two requests per year. The borrowing base is determined based on proved developed producing reserves, proved developed non-producing reserves and proved undeveloped reserves and was $700.0 million as of March 31, 2008. As of March 31, 2008, we had outstanding indebtedness of $237.7 million under our senior credit facility, including outstanding letters of credit of $22.7 million. The committed loan amount for the facility was increased to $1.75 billion and the borrowing base was increased to $1.2 billion during April 2008. The $1.2 billion borrowing base contemplated a potential future fixed income transaction not to exceed $400.0 million. As a result of our May 2008 issuance of $750.0 million of senior notes, our borrowing base was reduced to $1.1 billion. As of June 20, 2008, there were no amounts outstanding under our senior credit facility, though, at that time, outstanding letters of credit reduced borrowing capacity under the senior credit facility by $22 million.
 
At our election, interest under the senior credit facility is determined by reference to (i) LIBOR plus an applicable margin between 1.25% and 2.00% per annum or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin between 0.25% and 1.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average interest rate paid on amounts outstanding under our senior credit facility for the three month period ended March 31, 2008 was 4.57%.


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Senior Term Loans.  On March 22, 2007, we issued $1.0 billion principal amount of senior unsecured term loans. The proceeds of the term loans were used to partially repay the senior bridge facility described below. The senior term loans include both a floating rate tranche and fixed rate tranche as described below.
 
We issued $350.0 million at a variable rate with interest payable quarterly and principal due on April 1, 2014 (the “variable rate term loans”). The variable rate term loans 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 bank’s prime rate plus 2.625%. The average interest rates paid on amounts outstanding under our variable rate term loans for the three month period ended March 31, 2008 was 8.36%. In January 2008, we entered into a $350 million notional amount interest rate swap agreement with a financial institution that effectively fixed our interest rate on the variable rate term loans at 6.2625% for the period from April 1, 2008 to April 1, 2011.
 
We also issued $650.0 million at a fixed rate of 8.625% with principal due on April 1, 2015 (the “fixed rate term loans”). Under the terms of the fixed rate term loans, interest was payable quarterly.
 
On March 28, 2008, we commenced an offer to exchange the senior term loans for senior unsecured notes with registration rights, as required under the senior term loan credit agreement. The offer expired on April 28, 2008, and on May 1, 2008, we issued $650.0 million of Senior Notes Due 2015 in exchange for an equal outstanding principal amount of fixed rate term loans and $350.0 million of Senior Floating Rate Notes Due 2014 in exchange for an equal outstanding principal amount of variable rate term loans. The newly issued notes have terms that are substantially identical to those of the exchanged senior term loans, except that the notes have been issued with registration rights.
 
Debt covenants under the senior term loans included financial covenants similar to those of the senior credit facility and included limitations on the incurrence of indebtedness, payment of dividends, asset sales, certain asset purchases, transactions with related parties and consolidation or merger agreements. We incurred $26.1 million of debt issuance costs in connection with the senior term loans. These costs are included in other assets and amortized over the term of the senior term loans.
 
Other Indebtedness.  We have financed a portion of our drilling rig fleet and related oil field services equipment through notes payable. At March 31, 2008, the aggregate outstanding balance of these notes was $44.3 million, with annual fixed interest rates ranging from 7.64% to 8.87%. The notes have a final maturity date of December 1, 2011, require aggregate monthly installments for principal and interest in the amount of $1.2 million and are secured by the equipment. The notes have a prepayment penalty (currently ranging from 1 to 3%) that is triggered if we repay the notes prior to maturity.
 
Building Mortgage.  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 which we purchased 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 expect to make payments of principal and interest on this note totaling $0.8 million and $1.2 million, respectively, over the next twelve months.
 
We have financed the purchase of other equipment used in our business. At March 31, 2007, the aggregate outstanding balance on these financings was $6.8 million. We substantially repaid such borrowings during July 2007 with borrowings under our senior credit facility.
 
Senior Bridge Facility.  On November 21, 2006, we entered into an $850.0 million senior unsecured bridge facility in conjunction with the acquisition of NEG. This facility was repaid in full in March 2007 with proceeds from our senior unsecured term loans.
 
Redeemable Convertible Preferred Stock
 
We had 1,844,464 shares of redeemable convertible preferred stock issued and outstanding at March 31, 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 of its redeemable convertible preferred stock. In May 2008, we


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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. This conversion resulted in a one-time charge to retained earnings of $6.1 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.
 
Contractual Obligations
 
A summary of our contractual obligations as of December 31, 2007 is provided in the following table:
 
                                                         
    Payments Due by Year  
    2008     2009     2010     2011     2012     After 2012     Total  
    (In thousands)  
 
Long-term debt
  $ 15,350     $ 16,580     $ 12,476     $ 7,222     $ 1,052     $ 1,014,969     $ 1,067,649  
Interest on term loans(1)
    92,868       91,580       90,322       89,510       89,219       172,020       625,519  
Firm transportation(2)
    1,597       1,597       1,597       1,597       1,597       6,775       14,760  
Operating leases
    2,139       1,102       110       110       46             3,507  
Third-party drilling rig commitments(3)
    12,803                                     12,803  
Dispute settlement payments(4)
    5,000       5,000       5,000       5,000                   20,000  
Asset retirement obligations
    864       365             7,822       444       49,085       58,580  
                                                         
Total
  $ 130,621     $ 116,224     $ 109,505     $ 111,261     $ 92,358     $ 1,242,849     $ 1,802,818  
                                                         
 
 
(1) Based on interest rates as of December 31, 2007.
 
(2) We entered into a firm transportation agreement with Questar Pipeline Company giving us guaranteed capacity on its pipeline for 10 MmBtu per day at an estimated charge of $0.9 million per year, with a total commitment of $9.1 million. In December 2006, we assigned our rights and obligations to a third-party.
 
(3) Drilling contracts with third-party drilling rig operators at specified day rates. All of our drilling rig contracts contain operator performance conditions that allow for pricing adjustments or early termination for operator nonperformance.
 
(4) In January 2007, we settled a royalty interest dispute and agreed to pay five installments of $5 million each, plus interest commencing April 1, 2007. The remaining installments are due on July 1 of each year commencing July 1, 2008.
 
In connection with the NEG acquisition, we acquired restricted deposits representing bank trust and escrow accounts required by surety bond underwriters and certain former owners of NEG’s offshore properties. In accordance with requirements of the U.S Department of Interior’s Mineral Management Service, NEG was required to put in place surety bonds or escrow agreements to provide satisfaction of its eventual responsibility to plug and abandon wells and remove structures when certain offshore fields are no longer in use. As part of the agreement with the surety bond underwriter or the former owners of the particular fields, bank trust and escrow accounts were set up and funded based on the terms of the escrow agreements. Certain amounts are required to be paid upon receipt of proceeds from production.
 
During 2007, funds totaling $10.3 million were released from escrow accounts and returned to us.


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In connection with one of the escrow accounts, we are required to make quarterly deposits to the escrow accounts of $0.8 million up to a maximum of $14.0 million. Payments to the escrow account are estimated as follows (in thousands):
 
         
2008
  $ 3,200  
2009
    3,200  
2010
    2,586  
         
    $ 8,986  
         
 
Additionally, two of the escrow accounts require us to deposit additional funds in an escrow account equal to 10% of the net proceeds, as defined, from certain of our offshore properties. During 2007 we deposited approximately $5.8 million in the escrow accounts.
 
Critical Accounting Policies and Estimates
 
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make assumptions and prepare estimates that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and revenues and expenses. We base our estimates on historical experience and various other assumptions that we believe are reasonable; however, actual results may differ. See Note 1 to our Consolidated Financial Statements included elsewhere herein for a discussion of our significant accounting policies.
 
Proved Reserves.  Over 97% of our reserves are estimated on an annual basis by independent petroleum engineers. Estimates of proved reserves are based on the quantities of natural gas and oil which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond our control. The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data, and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves to change, as well as causing estimates of future net revenues to change. For the years ended December 31, 2007, 2006 and 2005, we revised our proved reserves upward from prior years’ reports by approximately 351.6 Bcfe, 26.6 Bcfe and 12.3 Bcfe, respectively due to market prices at the end of the applicable period or from production performance indicating more (or less) reserves in place or larger (or smaller) reservoir size than initially estimated. Estimates of proved reserves are key components of our most significant financial estimates involving our rate for recording depreciation, depletion and amortization and our full-cost ceiling limitation. These revisions may be material and could materially affect our future depletion, depreciation and amortization expenses.
 
Method of Accounting for Natural Gas and Oil Properties.  Our natural gas and oil properties are accounted for using the full-cost method of accounting. All direct costs and certain indirect costs associated with the acquisition, exploration and development of natural gas and oil properties are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding natural gas and oil reserves. Amortization of natural gas and oil properties is provided using the unit-of-production method based on estimated proved natural gas and oil reserves. No gains or losses are recognized upon the sale or disposition of natural gas and oil properties unless the sale or disposition represents a significant quantity of natural gas and oil reserves, which would have a significant impact on the depreciation, depletion and amortization rate.
 
In accordance with full-cost accounting rules, capitalized costs are subject to a limitation. The capitalized cost of natural gas and oil properties, net of accumulated depreciation, depletion, and amortization, may not


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exceed the estimated future net cash flows from proved natural gas and oil reserves discounted at 10%, plus the lower of cost or fair market value of unproved properties as adjusted for related tax effects. The full-cost ceiling limitation is calculated using natural gas and oil prices in effect as of the balance sheet date and adjusted for “basis” or location differential, held constant over the life of the reserves. If capitalized costs exceed this limit (the “ceiling limitation”), the excess must be charged to expense. Once incurred, a write-down is not reversible at a later date. We did not have any adjustment to earnings due to the ceiling limitation for the periods presented herein.
 
Unevaluated Properties.  The balance of unevaluated properties is comprised of capital costs incurred for undeveloped acreage, wells and production facilities in progress and wells pending determination, together with capitalized interest costs for these projects. These costs are initially excluded from our amortization base until the outcome of the project has been determined or, generally, until it is known whether proved reserves will or will not be assigned to the property. We assess all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. We assess our properties on an individual basis or as a group if properties are individually insignificant. Our assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full-cost pool and are then subject to amortization. We estimate that substantially all of our costs classified as unproved as of the balance sheet date will be evaluated and transferred within a four-year period.
 
Asset Retirement Obligations.  Asset retirement obligations represent the estimated future abandonment costs of tangible long-lived assets such as platforms, wells, service assets, pipelines and other facilities. We estimate the fair value of an asset’s retirement obligation in the period in which the liability is incurred, if a reasonable estimate can be made. We employ a present value technique to estimate the fair value of an asset retirement obligation, which reflects certain assumptions, including an inflation rate, our credit-adjusted, risk-free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability based on third-party quotes and current actual costs. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.
 
Revenue Recognition and Gas Balancing.  Oil and natural gas revenues are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. We account for oil and natural gas production imbalances using the sales method, whereby we recognize revenue on all oil and natural gas sold to our customers notwithstanding the fact that its ownership may be less than 100% of the oil and natural gas sold. Liabilities are recorded for imbalances greater than our proportionate share of remaining estimated oil and natural gas reserves.
 
We recognize revenues and expenses generated from “daywork” drilling contracts as the services are performed, since we do not bear the risk of completion of the well. Under “footage” and “turnkey” contracts, we bear the risk of completion of the well; therefore, revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The duration of all three types of contracts ranges typically from 20 to 90 days. The entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on “footage” or “turnkey” contracts, which are still in process at the end of the period.
 
We may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one market to another are recognized over the term of the related drilling contract. The contract terms are typically from 20 to 90 days.
 
Revenues of our midstream gas services segment are derived from providing supply, transportation, balancing and sales services for producers and wholesale customers on our natural gas pipelines, as well as other interconnected pipeline systems. Midstream gas services are primarily undertaken to realize incremental margins on gas purchased at the wellhead, and provide value-added services to customers. In general, natural


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gas purchased and sold by our midstream gas business is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Revenues are recognized upon delivery of natural gas to customers and/or when services are rendered, pricing is determinable and collectibility is reasonably assured.
 
Revenue from sales of CO2 is recognized when the product is delivered to the customer. We recognize service fees related to the transportation of CO2 as revenue when the related service is provided.
 
Property, Plant and Equipment, Net.  Other capitalized costs, including drilling equipment, natural gas gathering and processing equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the straight-line method based on estimated useful lives. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 39 years.
 
Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in such estimates could cause us to reduce the carrying value of property and equipment.
 
When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations.
 
Income Taxes.  Deferred income taxes are provided on temporary differences between financial statement and income tax reporting. Temporary differences are differences between the amounts of assets and liabilities reported for financial statement purposes and their tax bases. Deferred tax assets are recognized for temporary differences that will be deductible in future years’ tax returns and for operating loss and tax credit carryforwards. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. Deferred tax liabilities are recognized for temporary differences that will be taxable in future years’ tax returns.
 
Derivative Financial Instruments.  To manage risks related to increases in interest rates and changes in natural gas and oil prices, we enter into interest rate swaps and natural gas and oil futures contracts.
 
We recognize all of our derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship, and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, we designate the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. For derivative instruments not designated as hedging instruments, the gain or loss is recognized in current earnings during the period of change. None of our derivatives were designated as hedging instruments during any of the periods presented.
 
New Accounting Pronouncements
 
For a discussion of recently adopted accounting standards, see Note 1 to our consolidated financial statements as of December 31, 2007 and 2006 and the three years ended December 31, 2007 and Note 2 to our condensed consolidated financial statements as of March 31, 2008 and the three month periods ended March 31, 2008 and 2007 included in elsewhere in this prospectus.
 
Effects of Inflation
 
The effect of inflation in the natural gas and oil industry is primarily driven by the prices for natural gas and oil. Increased commodity prices increase demand for contract drilling rigs and services, which supports


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higher drilling rig activity. This in turn affects the overall demand for our drilling rigs and the dayrates we can obtain for our contract drilling services.
 
Over the last three years, natural gas and oil prices have been volatile, and during periods of higher utilization we have experienced increases in labor cost and the cost of services to support our drilling rigs.
 
During this same period, when commodity prices declined, labor rates did not return to the levels that existed before the increases. If natural gas prices increase substantially for a long period, shortages in support equipment (such as drill pipe, third-party services and qualified labor) may result in additional increases in our material and labor costs. These conditions may limit our ability to realize improvements in operating profits. How inflation will affect us in the future will depend on additional increases, if any, realized in our drilling rig rates and the prices we receive for our natural gas and oil.
 
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 delivery of a physical quantity to satisfy settlement.
 
Commodity Price Risk.  Our most significant market risk is the prices we receive for our natural gas and oil production, which can be highly volatile. In light of this historical volatility, we periodically have entered into, and expect in the future to enter into, derivative arrangements aimed at reducing the variability of natural gas and oil prices we receive for our production. We will from time to time enter into commodities pricing derivative instruments for a portion of our anticipated production volumes depending upon our management’s view of opportunities under the then current market conditions. We do not intend to enter into derivative instruments that would exceed our expected production volumes for the period covered by the derivative arrangement. Our current credit agreement limits our ability to enter into derivatives transactions to 85% of expected production volumes from estimated proved reserves.
 
We use, or may use, a variety of commodity-based derivative instruments, including collars, fixed-price swaps and basis protection swaps. These transactions generally require no cash payment upfront and are settled in cash at maturity. While our derivative strategy may result in lower operating profits than if we were not party to these derivative instruments in times of high natural gas prices, we believe that the stabilization of prices and protection afforded us by providing a revenue floor for our production is very beneficial.
 
For natural gas derivatives, transactions are settled based upon the New York Mercantile Exchange price of natural gas at the Waha hub, a West Texas gas marketing and delivery center, on the final trading day of the month. Settlement for natural gas derivative contracts occurs in the month following the production month. Generally, our trade counterparties are affiliates of the financial institution that is a party to our credit agreement, although we do have transactions with counterparties that are not affiliated with this institution.
 
While we believe that the gas and oil price derivative arrangements we enter into are important to our program to manage price variability for our production, we have not designated any of our derivative contracts as hedges for accounting purposes. We record all derivative contracts on the balance sheet at fair value, which will be significantly affected by changes in gas and oil prices. We establish fair value of our derivative contracts by market price quotations of the derivative contract or, if not available, market price quotations of derivative contracts with similar terms and characteristics. When market quotations are not available, we will estimate the fair value of derivative contracts using option pricing models that management believes represent its best estimate. Changes in fair values of our derivative contracts that are not designated as hedges for accounting purposes are recognized as unrealized gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in fair value of our commodities derivative arrangements. The gain recognized in earnings, included in operating costs and expenses, for the years ended December 31, 2007 and 2006 was $60.7 million and $12.3 million, respectively. For the year ended December 31, 2005, we recognized a loss of $4.1 million.


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At March 31, 2008, our open commodity derivative contracts consisted of the following:
 
                 
    Notional
    Weighted Avg.
 
Period and Type of Contract
 
(in MMBtus)
   
Fixed Price
 
 
Natural Gas
               
April 2008 — June 2008
               
Price swap contracts
    17,900     $ 7.69  
Basis swap contracts
    13,350     $ (0.59 )
July 2008 — September 2008
               
Price swap contracts
    18,100     $ 8.23  
Basis swap contracts
    15,640     $ (0.57 )
October 2008 — December 2008
               
Price swap contracts
    17,480     $ 8.67  
Basis swap contracts
    14,720     $ (0.65 )
January 2009 — March 2009
               
Price swap contracts
    6,300     $ 9.12  
Basis swap contracts
    2,700     $ (0.49 )
April 2009 — June 2009
               
Price swap contracts
    910     $ 8.10  
Basis swap contracts
    2,730     $ (0.49 )
July 2009 — September 2009
               
Basis swap contracts
    2,760     $ (0.49 )
October 2009 — December 2009
               
Basis swap contracts
    2,760     $ (0.49 )
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 )
Crude Oil
               
April 2008 — June 2008
               
Price swap contracts
    270     $ 95.04  
Collar contracts
    21     $ 50.00 — 83.35  
July 2008 — September 2008
               
Price swap contracts
    225     $ 94.33  
Collar contracts
    27     $ 50.00 — 82.60  
October 2008 — December 2008
               
Price swap contracts
    225     $ 93.17  
Collar contracts
    27     $ 50.00 — 82.60  
 
These derivatives have not been designated as hedges and the Company records all derivatives on the balance sheet at fair value. Changes in derivative fair values are recognized in earnings. Cash settlements and


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valuation gains and losses are included in (gain) loss on derivative contracts in the consolidated statements of operations. The following summarizes the cash settlements and valuation gains and losses (in thousands):
 
                                         
          Three Months
 
    Year Ended December 31,     Ended March 31,  
    2005     2006     2007     2007     2008  
 
Realized (gain) loss
  $ 2,836     $ (14,169 )   $ (34,494 )   $ 1,519     $ (7,329 )
Unrealized (gain) loss
    1,296       1,878       (26,238 )     21,622       144,173  
                                         
(Gain) loss on derivative contracts
  $ 4,132     $ (12,291 )   $ (60,732 )   $ 23,181     $ 136,844  
                                         
 
Interest Rate Risk.  We are subject to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us (i) to changes in market interest rates reflected in the fair value of the debt and (ii) to the risk that we may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes us to short-term changes in market interest rates as our interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate.
 
The indebtedness evidenced by notes payable related to our drilling rig fleet and related oil field services equipment, Sagebrush Pipeline, insurance financing, and other equipment and vehicles and a portion of our senior term loans is a fixed-rate debt, which exposes us to cash-flow risk from market interest rate changes on these notes. The fair value of that debt varies as interest rates change.
 
Borrowings under our senior credit facility and a portion of our senior term loans expose us to certain market risks. We use sensitivity analysis to determine the impact that market risk exposures may have on our variable interest rate borrowings. Based on the approximately $350.0 million outstanding balance of the variable rate portion of our senior term loans at December 31, 2007, a one percent change in the applicable rate, with all other variables held constant, would result in a change in our interest expense of approximately $3.5 million for the year ended December 31, 2007 and $1.4 million for the three months ended March 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 agreements. At December 31, 2007, we were not party to any interest rate swap instruments. In January 2008, we entered into a $350 million notional amount interest rate swap agreement with a financial institution that effectively fixed our interest rate on the Variable Rate Term Loans at 6.2625% for the period from April 1, 2008 through April 1, 2011. This swap has not been designated as a hedge.
 
An unrealized gain of $0.8 million was recorded in interest expense in the condensed consolidated statement of operations for the change in fair value of the interest rate swap for the three months ended March 31, 2008.


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BUSINESS
 
General
 
We are a rapidly expanding independent natural gas and crude oil company headquartered in Oklahoma City, Oklahoma 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, Thistle, Big Canyon, and McKay Creek exploration areas. We also own and operate drilling rigs and conduct related oil field services, and we own and operate interests in gas gathering, marketing and processing facilities and CO2 gathering and transportation facilities.
 
We continue to focus on exploration and development of our significant holdings in the WTO, an area in which we are the largest operator and producer. The WTO is a natural gas prone geological region in Pecos County and Terrell County, Texas where we have operated since 1986 and currently have approximately 550,000 net acres under lease. We intend to add to our existing reserve and production base in the WTO by increasing our development drilling activities in the Piñon Field and our exploration program in the other exploration areas that we have identified. We also have significant operations in East Texas, the Gulf Coast, the Mid-Continent, and the Gulf of Mexico. We have assembled an extensive natural gas and oil property base on which we have identified approximately 5,000 potential drilling locations as of March 31, 2008, including approximately 2,600 locations in the WTO. As of December 31, 2007, our proved reserves were 1,516.2 Bcfe, of which 86% were natural gas, based on third party engineering estimates. As of March 31, 2008, our proved reserves were 1,698.9 Bcfe, of which 86% were natural gas. Approximately 97% of our year-end reserves are estimated by third party engineers. As of March 31, 2008, we had 1,869 gross (1,335.5 net) producing wells, substantially all of which we operate, and we had interests in approximately 1,266,376 gross (921,659 net) natural gas and oil leased acres. Additionally, we had 31 rigs drilling in the WTO, 5 rigs drilling in East Texas, 2 rigs drilling in the Mid-Continent, and 2 rigs drilling in other areas.
 
We also operate businesses that are complementary to our primary exploration, development and production activities, which provides us with operational flexibility and an advantageous cost structure. We own related natural gas gathering and treating facilities, a natural gas marketing business and oil field services business, including our Lariat drilling rig business. As of March 31, 2008, our drilling rig fleet consisted of 44 rigs — 32 rigs owned by us and 12 rigs owned by Larclay, L.P., a limited partnership in which we have a 50% interest. Currently, 26 of our owned rigs and eleven of the Larclay rigs are operational. We also capture and transport CO2 to the Permian Basin for equity and third party tertiary oil recovery projects.
 
Our capital expenditures budget for 2008 is approximately $1.5 billion. As of March 31, 2008, approximately $418.7 million of this budget had been expended. Our 2008 capital expenditure budget includes $1,238 million for exploration and production (including land and seismic acquisitions of $241 million), $67 million for oilfield services and $195 million for midstream and other. Our capital expenditures for 2007, including acquisitions, were $1,397.5 million, which included $1,150.6 million for exploration and development (including land and seismic acquisitions and our tertiary recovery operations), $123.2 million for drilling and oil field services, $73.8 million for our midstream operations and $49.8 million for other capital expenditures. Approximately $871.2 million of our 2007 capital expenditures was spent on our Piñon Field development and our exploratory projects in the WTO (including land and seismic acquisitions). We drilled 316 gross (274.7 net) wells in 2007, including approximately 190 gross (177.8 net) wells in the WTO.
 
Recent Developments
 
  •  On April 4, 2008, we amended our revolving credit facility, increasing the borrowing base to $1.2 billion, with aggregate commitments of $1.75 billion. The $1.2 billion borrowing base contemplated a potential future fixed income transaction not to exceed $400.0 million. As a result of our May 2008 issuance of $750.0 million of senior notes, our borrowing base was reduced to $1.1 billion.


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  •  On May 1, 2008, we consummated an exchange offer for both tranches of our senior term loans. Under the terms of the exchange offer, we issued $650 million of 85/8% Senior Notes Due 2015 in exchange for an equal outstanding principal amount of fixed rate senior term loans and $350 million of Senior Floating Rate Notes Due 2014 in exchange for an equal outstanding principal amount of variable rate term loans.
 
  •  Since March 31, 2008, we have converted the remaining 1,844,464 shares of our outstanding redeemable convertible preferred stock to 18,810,260 shares of our common stock. Since December 31, 2007, holders of our preferred stock have received approximately 10.2 shares of our common stock for each share of preferred stock, resulting in the issuance of 19,150,083 shares of our common stock for all previously issued convertible preferred stock, including 339,823 shares of common stock issued upon conversion of convertible preferred stock prior to April 1, 2008. The conversion has increased our shareholder equity by approximately $381.0 million since March 31, 2008.
 
  •  On May 8, 2008, we announced an increase in our 2008 capital expenditures budget to $1.5 billion from the previously announced $1.25 billion.
 
  •  In May 2008, we and other parties entered into an agreement to sell substantially all of our assets located in the Piceance Basin of Colorado to a subsidiary of The Williams Companies, Inc. The total purchase price was $285 million, with net proceeds to us of approximately $140 million, subject to closing adjustments and final allocation of the sales price among multiple sellers. Assets sold included undeveloped acreage, working interests in wells, gathering and compression systems and other facilities related to the wells. This sale was completed on May 20, 2008.
 
  •  On May 20, 2008, we issued $750 million of our 8% Senior Notes due 2018 in a private placement. We received net proceeds of approximately $734 million from the offering. We used approximately $478 million of the net proceeds to repay all of the outstanding balance on our senior credit facility. The remaining proceeds will be used to fund the remaining unfunded portion of our $1.5 billion capital expenditures budget for 2008.
 
Competitive Strengths
 
We have a number of strengths that we believe will help us successfully execute our strategies:
 
  •  Large Asset Base with Substantial Drilling Inventory.  Our producing properties are characterized by long-lived, predominantly natural gas reserves with established production profiles. Our estimated proved reserves of 1,516.2 Bcfe as of December 31, 2007 had a proved reserves to production ratio of approximately 17.7 years. Our core area of operations in the WTO has expanded to 651,426 gross (547,392 net) acres as of March 31, 2008. We have identified approximately 2,600 potential drilling locations in the WTO and believe that we will be able to expand the number of drilling locations in the remainder of the WTO through exploratory drilling and our use of 3-D seismic technology.
 
  •  Geographically Concentrated Exploration and Development Operations.  We intend to focus our drilling and development operations in the WTO to fully exploit this unique geological area. In addition to the WTO, we also are active in East Texas developing the Cotton Valley Trend with a continuous five rig program. Geographic concentration in these areas allows us to establish economies of scale and improve both drilling and production efficiencies resulting in lower development and operating costs and maximizing the value of our producing properties. We believe our concentrated, largely undeveloped acreage position in our core areas will enable us to organically grow our reserves and production for many years.
 
  •  Experienced Management Team.  During 2006, we significantly expanded our management team when Tom L. Ward, co-founder and former president of Chesapeake Energy Corporation, purchased a significant interest in us and became our Chairman and Chief Executive Officer. Mr. Ward leads an experienced management team of 10 executive officers and 40 senior executives.
 
  •  High Degree of Operational Control.  We operate over 98% of our production in the WTO, East Texas, the Gulf Coast and the Mid-Continent, which permits us to manage our operating costs and better control capital expenditures and the timing of development and exploitation activities.


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  •  Large Modern Fleet of Drilling Rigs.  We own a drilling rig fleet consisting of 44 rigs — 32 rigs owned by us and 12 rigs owned by Larclay, L.P., a limited partnership in which we have a 50% interest. By controlling a large, modern and efficient drilling fleet, we can develop our existing reserves and explore for new reserves on a more economical basis.
 
Business Strategy
 
Our primary objective is to achieve long-term growth and maximize stockholder value over multiple business cycles by pursuing the following strategies:
 
  •  Grow Through Exploration and Development of Existing Acreage.  We expect to generate long-term reserve and production growth by exploring and developing our large acreage position. Our primary exploration and development focus will be in the WTO, where we have identified approximately 2,600 potential drilling locations and had 31 rigs operating as of March 31, 2008.
 
  •  Apply Technological Improvements to Our Exploration and Development Program.  We intend to achieve high drilling and exploration success rates with a large scale 3-D seismic acquisition program and the use of enhanced interpretation technologies. 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 under-explored WTO.
 
  •  Seek Opportunistic Acquisitions in Our Core Geographic Area.  Since January 2006, through acquisitions and leasing activities, we have tripled our net acreage position in the WTO. We intend to continue to seek other opportunities to optimize and enhance our exploratory acreage position in the WTO and other strategic areas.
 
  •  Reduce Costs, Enhance Returns and Maintain Operating Flexibility by Controlling Drilling Rigs and Midstream Assets.  By controlling our fleet of drilling rigs and gathering and treating assets, we believe we will be able to better control overall costs and maintain a high degree of operational flexibility.
 
Our Business 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 and the Mid-Continent, as well as other non-core operating areas.


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The following table identifies certain information concerning our exploration and production business as of the dates indicated unless otherwise noted:
 
                                                                 
                            As of March 31, 2008  
    As of December 31, 2007                       Number of
 
    Estimated
                Proved
                      Identified
 
    Net Proved
          Daily
    Reserves/
    Daily
                Potential
 
    Reserves
    PV-10
    Production
    Production
    Production
    Gross
    Net
    Drilling
 
    (Bcfe)(1)     (In millions)(2)     (Mmcfe/d)(3)     (Years)     (Mmcfe/d)(4)     Acreage     Acreage     Locations  
 
Area
                                                               
WTO
    922.2     $ 1,785.5       115.7       21.8       134.4       651,426       547,392       2,567  
East Texas
    202.5       331.1       32.7       17.0       38.4       44,217       30,398       566  
Gulf Coast
    97.8       388.3       42.5       6.3       42.5       49,261       31,965       42  
Mid-Continent
    66.0       131.2       9.0       20.1       12.1       296,874       185,909       806  
Other:
                                                               
Gulf of Mexico
    60.1       240.3       18.3       9.0       15.8       73,614       36,770       67  
Other West Texas
    38.0       192.6       12.1       8.6       13.2       36,660       26,381       77  
Tertiary recovery- West Texas
    119.7       468.3       0.8       410.0       1.5       9,064       8,195       67  
Piceance Basin(5)
    9.0       8.9       0.6       41.0       0.7       40,334       15,686       828  
Other
    0.9       4.3       2.8       0.9       2.6       64,926       38,963        
                                                                 
Total
    1,516.2     $ 3,550.5       234.5       17.7       261.2       1,266,376       921,659       5,020  
                                                                 
 
 
(1) Internally prepared estimates of net proved reserves were 1,698.9 Bcfe as of March 31, 2008.
 
(2) 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. Our Standardized Measure was $2,718.5 million at December 31, 2007.
 
(3) Represents average daily net production for the month of December 2007.
 
(4) Represents average daily net production for the month of March 2008.
 
(5) We sold all of our Piceance Basin assets on May 20, 2008 for estimated net cash consideration to us of approximately $140 million, subject to closing adjustments and final allocation of the sales proceeds among multiple sellers.
 
West Texas Overthrust (WTO)
 
We have drilled and developed natural gas in the WTO since 1986. This area is located in Pecos and Terrell Counties in West Texas and is associated with the Marathon-Ouachita fold and thrust belt that extends east-northeast across the United States into the Appalachian Mountain Region. The WTO was created by the collision of the ancestral North American and South American continents resulting in source rock and reservoir rock, including potential hydrocarbon traps, becoming thrusted upon one another in multiple layers (imbricate stacking) along the leading edge of the WTO. The collision and thrusting resulted in a unique and complex geological setting in which multiple layers of reservoir rock became highly fractured and increased the likelihood for conventional trapping of natural gas and oil accumulations. 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 largely under-explored. The high CO2 content, the lack of infrastructure in the region, historical limitations of conventional subsurface geological and geophysical methods and commodity prices discouraged exploration of the area. We believe our access to and control of the necessary infrastructure combined with application of modern seismic techniques will allow us to identify further exploration and development opportunities in the WTO.
 
In May 2007, we began a three-year seismic program to acquire 1,400 square miles of modern 3-D seismic data in the WTO. We believe this 3-D seismic program may identify structural details of potential


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reservoirs, thus lowering exploratory drilling risk and improving completion efficiency. As of March 31, 2008, we have acquired 575 square miles of 3-D seismic data, of which 393 square miles have been processed and are currently being interpreted.
 
We have acquired leasehold acreage in the WTO, tripling our position since January 2006. As of March 31, 2008 we owned 651,426 gross (547,392 net) acres. In addition, we had identified approximately 2,600 total gross drilling locations in the WTO, and our capital expenditures budget for 2008 with respect to the WTO is $920 million (including land and seismic acquisitions of $198 million).
 
Piñon Field.  The Piñon Field, located in Pecos County, is our most significant producing field, and accounts for 61% of our proved reserve base as of December 31, 2007 (60% as of March 31, 2008, based on our internally prepared reserve report) and approximately 76% of our 2007 exploration and development expenditures (including land and seismic acquisitions). The Piñon Field lies along the leading edge of the WTO. The primary reservoirs are the 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 (depth from 7,000 to 10,000 feet). As of December 31, 2007, our estimated proved natural gas and oil reserves in the Piñon Field were 922.2 Bcfe, 55% of which were proved undeveloped reserves, based on estimates prepared by Netherland, Sewell and Associates, Inc. As of March 31, 2008, they were 1,021.2 Bcfe, 57% of which were proved undeveloped reserves, based on our internally prepared reserve report. Our interests in the Piñon Field include 527 producing wells as of March 31, 2008. We had a 93% average working interest in the producing area of Piñon Field and were running 31 drilling rigs in the Piñon Field as of March 31, 2008. We drilled 190 wells in the field during 2007.
 
West Texas Overthrust Exploration Areas.  Through our regional exploratory efforts, to date we have identified five exploration areas: Allison Ranch, South Sabino, Thistle, Big Canyon and McKay Creek. As a result of our seismic program commenced in 2007, we are starting to drill exploration areas in the WTO:
 
  •  South Sabino Exploration Area.  The South Sabino exploration area is located directly east and adjacent to the Piñon Field. We are currently in the process of drilling two exploratory wells to depths of 10,000 to 13,000 feet in the South Sabino as a result of our recent 3-D seismic interpretation of this area.
 
  •  Big Canyon Exploration Area.  As a result of our 3-D seismic data in this area, we are currently drilling a 17,000 foot exploratory test well structurally offsetting to the original Big Canyon Ranch 106-1 well.
 
West Texas Overthrust Development.  The following table provides information concerning development opportunities in the WTO:
 
                                                     
Estimated
    Estimated
                      2008 Capital
       
Net PUD
    Gross PUD
    Gross PUD
    Total Gross
    Gross 2008
    Expenditures
    2007 Year
 
Reserves
    Reserves
    Drilling
    Drilling
    Drilling
    Budget
    End Rigs
 
(Bcfe)(1)
    (Bcfe)(1)     Locations(1)     Locations(1)     Locations     (In millions)(2)     Working  
 
  509.9       731.6       397       2,594       267       622       30  
                                                     
 
 
(1) As of December 31, 2007.
 
(2) Excludes capital expenditures related to land and seismic acquisitions.
 
East Texas — Cotton Valley Trend
 
We own significant natural gas and oil interests in the Cotton Valley Trend in East Texas. We held interests in 44,217 gross (30,398 net) acres in East Texas as of March 31, 2008. At December 31, 2007, our estimated net proved reserves in East Texas were 202.5 Bcfe, based on estimates of our independent engineer, with net production of approximately 32.7 Mmcfe per day. As of March 31, 2008, these figures had risen to 236.7 Bcfe, based on our internally prepared reserve report, and net production of 38.4 Mmcfe per day. We intend to target the tight sand reservoirs of the Cotton Valley, Pettit and Travis Peak formations at depths of 6,500 to 10,500 feet. These sands are typically distributed over a large area, which has led to a 100% success


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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 as little as 20 acres per well. We drilled 48 (42.0 net) wells in the Cotton Valley Trend in 2007. We currently have 5 rigs running in this region and we expect to drill an additional 56 wells during the remainder of 2008.
 
Gulf Coast
 
We own natural gas and oil interests in 49,261 gross (31,965 net) acres in the Gulf Coast area as of March 31, 2008, which encompasses the large coastal plain from the southernmost tip of Texas through the southern portion of Louisiana. As of December 31, 2007, our estimated net proved reserves in the Gulf Coast area were 97.8 Bcfe, based on estimates of our independent engineer, with net production of approximately 42.5 Mmcfe per day. As of March 31, 2008, based on our internally prepared reserve report, these figures were 98.6 Bcfe and net production of 42.5 Mmcfe per day.
 
Mid-Continent
 
We own interests in properties in Oklahoma and Southern Kansas that make up our Mid-Continent area. As of March 31, 2008, we held interests in 296,874 gross (185,909 net) leasehold and option acres in these areas. As of December 31, 2007, our estimated proved reserves in the Mid-Continent area were 66.0 Bcfe, based on estimates of our independent and internal engineers and 102.3 Bcfe as of March 31, 2008 based on internally prepared reserve estimates. Our average daily net production as of March 2008 was approximately 12.1 Mmcfe per day. As we continue to drill and expand our acreage positions, our Mid-Continent prospects may become increasingly important to our Company.
 
Other Areas
 
Gulf of Mexico.  We own natural gas and oil interests in 73,614 gross (36,770 net) acres in state and federal waters off the coast of Texas and Louisiana as of March 31, 2008. At December 31, 2007, our estimated net proved reserves were 60.1 Bcfe, based on estimates of our independent engineer, with net production of approximately 18.3 Mmcfe per day for the month of December 2007. As of March 31, 2008, these figures were 61.9 Bcfe, based on our internally prepared reserve report, and net production of 15.8 Mmcfe per day. The water depth ranges from 30 feet to 1,100 feet, and activity extends from the coast to more than 100 miles offshore.
 
Other West Texas.  Our other non-tertiary West Texas assets include our Brooklaw Field and the Goldsmith Adobe Unit in the Permian Basin. As of March 31, 2008, we own 36,660 gross (26,381 net) acres in these properties. As of December 31, 2007, our estimated net proved reserves were 38.0 Bcfe, based on estimates of our independent engineer. As of March 31, 2008, this amount had risen to 46.6 Bcfe, based on our internally prepared reserve report. We have identified 77 potential drilling locations in these fields, including 61 proved undeveloped locations.
 
Tertiary Oil Recovery
 
Wellman Unit.  The Wellman Unit is part of our tertiary oil recovery operations. The Wellman Field, located in Terry County, Texas was discovered in 1950 and produces from the Canyon Reef limestone formation of Permian age from an average depth of 9,500 feet. The Wellman Unit is on the western edge of the Horseshoe Atoll, a geologic feature in the northern part of the Midland Basin. There are approximately 110 separate fields that are contained within this feature, including seven existing CO2 floods. The Wellman Unit covers approximately 2,120 acres, 1,200 of which are well-suited for both water and CO2 floods. The Wellman Field has been partially CO2 flooded and water flooded to produce 83.7 Mmboe to date. We recently re-initiated injection of CO2, and our injection rate averaged 10.9 Mmcf per day in 2007 and we expect to reach an average 30.9 Mmcf per day over the next 10 years. As of December 31, 2007, net proved reserves


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attributable to the Wellman Unit were 9.3 Mmboe. We also own a CO2 recycling plant at this unit with a capacity of 28 Mmcf per day. The plant includes 6,000 horsepower of CO2 compression and 4,850 horsepower of processing compression, which is sufficient to handle the recycling of the CO2 that will be produced in association with the production of these reserves.
 
George Allen Unit.  The George Allen Unit, located in Gaines County, Texas covers 800 gross acres in the George Allen Field and produces from the San Andres formation from an average depth of 4,950 feet. We have also leased an additional 320 acres adjacent to the unit to the south. The field is located within the greater Wasson area which contains seven active CO2 floods including the largest in the world, the Denver Unit. The George Allen Unit has produced 1.6 Mmboe to date, but it also contains a significant transition zone which has been proven to be a tertiary oil target at the nearby Denver Unit. We are currently implementing a nine pattern pilot program. CO2 injection began in December 2007 at 2.0 Mmcf per day. Injection is expected to increase to 15 Mmcf per day by mid-year 2008. As of December 31, 2007, net proved reserves attributable to the George Allen Field were 8.0 Mmboe. As of December 31, 2007, the CO2 injection rate was 2.0 Mmcf per day.
 
South Mallet Unit.  The South Mallet Unit, located in Hockley County, Texas covers 3,540 gross acres in the Slaughter/Levelland Field complex and produces from the San Andres formation from an average depth of 5,000 feet. These fields are some of the largest in West Texas and currently have ten active CO2 floods and four more at various stages of readiness. The South Mallet Unit has produced 27.8 Mmboe to date. We are currently evaluating the project for CO2 development with plans to begin injection of CO2 in 2009. We expect to reach an injection rate of approximately 18 Mmcf per day by the beginning of 2010. As of December 31, 2007, net proved reserves attributable to the South Mallet Unit were 2.5 Mmboe.
 
Jones Ranch Area.  Several miles west of the George Allen Unit, in Gaines County, SandRidge Tertiary has acquired various leases in the Jones Ranch Area. These leases produce from various depths and formations from approximately 2,400 gross acres. We are evaluating these leases for both conventional development and tertiary potential.


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Proved Reserves
 
The following historical estimates of net proved natural gas and oil reserves are based on reserve reports as of December 31, 2005, December 31, 2006, and December 31, 2007, substantially all of which were prepared by our independent petroleum engineers and by our internal reserves data. The PV-10 and Standardized Measure shown in the table are not intended to represent the current market value of our estimated natural gas and oil reserves. Based on our current drilling schedule, we estimate that 88% of our current proved undeveloped reserves will be developed by 2011 and all of our current proved undeveloped reserves will be developed by 2012. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus in evaluating the material presented below.
 
Netherland, Sewell & Associates, Inc., independent oil and gas consultants, have prepared the reports of proved reserves of natural gas and crude oil for our net interest in oil and gas properties, which constitute approximately 89% of our total proved reserves as of December 31, 2007, approximately 92% of our total proved reserves as of December 31, 2006 and 1.5% of our total proved reserves as of December 31, 2005. DeGolyer and MacNaughton prepared the reports of proved reserves for SandRidge Tertiary (our tertiary oil reserves located in West Texas), which constitute approximately 8% of our total proved reserves as of December 31, 2007, approximately 7% of our total proved reserves as of December 31, 2006 and approximately 98% of our total proved reserves as of December 31, 2005. The remaining 3%, 1% and 0.5% of our proved reserves as of December 31, 2007, 2006 and 2005 were based on internally prepared estimates.
 
                                 
    At December 31,     At March 31,
 
    2005     2006     2007     2008  
 
Estimated Proved Reserves(1)
                               
Natural Gas (Bcf)(2)
    237.4       850.7       1,297.0       1,464.6  
Oil (MmBbls)
    10.4       25.2       36.5       39.1  
Total (Bcfe)
    300.0       1,001.8       1,516.2       1,698.9  
PV-10 (in millions)(3)
  $ 733.3     $ 1,734.3     $ 3,550.5          
Standardized Measure of Discounted Net Cash Flows (in millions)(4)
  $ 499.2     $ 1,440.2     $ 2,718.5          
 
 
(1) Substantially all of year-end reserves are based upon estimates of our independent petroleum engineers’ reserve data. Reserves at March 31, 2008 are based upon our internal reserves data, and 43% of these reserves are classified as proved developed. Our estimated proved reserves and the future net revenues, PV-10 and Standardized Measure of Discounted Net Cash Flows were determined using end of the period prices for natural gas and oil that we realized as of December 31, 2005, December 31, 2006 and December 31, 2007, which were as follows:
 
                         
    At December 31,  
    2005     2006     2007  
 
End of Period Prices
                       
Natural Gas (per Mcf)
  $ 8.40     $ 5.32     $ 6.46  
Oil (per barrel)
  $ 54.02     $ 54.62     $ 87.47  
 
(2) Given the nature of our natural gas reserves, a significant amount of our production, primarily in the WTO, contains natural gas that is 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 and other items on future net revenues. Neither PV-10 nor Standardized Measure represent an estimate of fair market value of our natural gas and oil properties. PV-10 is used by


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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,  
    2005     2006     2007  
    (In millions)  
 
Standardized Measure of Discounted Net Cash Flows
  $ 499.2     $ 1,440.2     $ 2,718.5  
Present value of future income tax and other discounted at 10%
    234.1       294.1       832.0  
                         
PV-10
  $ 733.3     $ 1,734.3     $ 3,550.5  
                         
 
(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 were used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes and other items.
 
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
 
Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (i) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (ii) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
 
Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
 
Estimates of proved reserves do not include the following:
 
  •  oil that may become available from known reservoirs but is classified separately as indicated additional reserves;
 
  •  crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors;
 
  •  crude oil, natural gas and natural gas liquids that may occur in undrilled prospects; and
 
  •  crude oil, natural gas and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such sources.


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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 from our high CO2 natural gas in the WTO have been taken into account in our lease operating expenses as processing and gathering fees. In all areas, natural gas sales are delivered to sales points with CO2 levels within pipeline specifications and thus are included in sales and reserves volumes.
 
                                         
    Year Ended December 31,     Three Months Ended March 31,  
    2005     2006     2007     2007     2008  
 
Production Data:
                                       
Natural Gas (Mmcf)
    6,873       13,410       51,958       10,449       19,173  
Crude oil (MBbls)(1)
    72       322       2,042       393       611  
Combined Equivalent Volumes (Mmcfe)
    7,305       15,342       64,211       12,807       22,839  
Average Daily Combined Equivalent Volumes (Mmcfe/d)
    20.0       42.0       175.9       142.3       251.0  
Average Sales Prices(2):
                                       
Natural Gas (per Mcf)
  $ 6.54     $ 6.19     $ 6.51     $ 6.60     $ 7.86  
Crude oil (per Bbl)(1)
  $ 48.19     $ 56.61     $ 68.12     $ 54.06     $ 89.81  
Combined Equivalent (per Mcfe)
  $ 6.63     $ 6.60     $ 7.45     $ 7.04     $ 9.00  
Expenses per Mcfe:
                                       
Lease operating expenses:
                                       
Transportation
  $ 0.16     $ 0.22     $ 0.12     $ 0.17     $ 0.11  
Processing and gathering(3)
    0.42       0.37       0.28       0.23       0.34  
Other lease operating expenses
    1.64       1.70       1.25       1.32       1.05  
                                         
Total lease operating expenses
  $ 2.22     $ 2.29     $ 1.65     $ 1.72     $ 1.50  
                                         
Production taxes
  $ 0.43     $ 0.30     $ 0.30     $ 0.23     $ 0.40  
 
 
(1) Includes natural gas liquids.
 
(2) Reported prices represent actual prices for the periods presented and do not give effect to hedging transactions.
 
(3) Includes costs attributable to gas treatment to remove CO2 and other impurities from our high CO2 natural gas.


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Productive Wells
 
The following table sets forth the number of productive wells in which we owned a working interest at December 31, 2007. Productive wells consist of producing wells and wells capable of producing, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
 
                 
Area
  Gross     Net  
 
WTO
    471       435  
East Texas
    177       163  
Gulf Coast
    214       133  
Other:
               
Gulf of Mexico
    67       43  
Other West Texas
    264       251  
Tertiary recovery — West Texas (SandRidge Tertiary)
    46       43  
Piceance Basin(1)
    52       20  
Other, including Oklahoma
    363       146  
                 
Total
    1,654       1,234  
                 
 
 
(1) We sold all of our Piceance Basin assets on May 20, 2008 for estimated net cash consideration to us of approximately $140 million, subject to closing adjustments and final allocation of the sales proceeds among multiple sellers.
 
Developed and Undeveloped Acreage
 
The following table sets forth information at December 31, 2007:
 
                                 
    Developed Acreage(1)     Undeveloped Acreage(2)  
Area
  Gross(3)     Net(4)     Gross(3)     Net(4)  
 
WTO
    13,157       10,824       587,389       497,921  
East Texas
    28,084       25,891       25,304       6,848  
Gulf Coast
    39,438       24,678       11,330       8,639  
Other:
                               
Gulf of Mexico
    73,614       36,770              
Other West Texas
    24,272       16,030       7,575       6,911  
Tertiary recovery — West Texas (SandRidge Tertiary)
    9,064       8,195              
Piceance Basin(5)
    1,800       451       38,534       15,235  
Other, including Oklahoma
    86,498       43,255       357,048       120,639  
                                 
Total
    275,927       166,094       1,027,180       656,193  
                                 
 
 
(1) Developed acres are acres spaced or assigned to productive wells.
 
(2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
 
(3) A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
 
(4) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.


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(5) We sold all of our Piceance Basin assets on May 20, 2008 for estimated net cash consideration to us of approximately $140 million, subject to closing adjustments and final allocation of the sales proceeds among multiple sellers.
 
Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. We generally have been able to obtain extensions of the primary terms of our federal leases when we have been unable to obtain drilling permits due to a pending Environmental Assessment, Environmental Impact Statement or related legal challenge. The following table sets forth as of December 31, 2007 the expiration periods of the gross and net acres that are subject to leases in the acreage summarized in the above table.
 
                 
    Acres Expiring  
Twelve Months Ending
  Gross     Net  
 
December 31, 2008
    46,635       36,198  
December 31, 2009
    135,669       121,134  
December 31, 2010
    356,993       162,761  
December 31, 2011 and later
    390,181       279,038  
Other(1)
    373,629       223,156  
                 
Total
    1,303,107       822,287  
                 
 
 
(1) Leases remaining in effect until the cessation of development efforts or cessation of production on the developed portion of the particular lease.
 
Drilling Activity
 
The following table sets forth information with respect to wells we completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. “Gross” refers to the total wells in which we had a working interest and “net” refers to gross wells multiplied by our working interest.
 
                                                                                                 
    2007     2006     2005  
    Gross     Percent     Net     Percent     Gross     Percent     Net     Percent     Gross     Percent     Net     Percent  
 
Development:
                                                                                               
Productive
    281       99.3 %     244.4       99.5 %     82       94 %     50.8       95 %     31       100 %     13.0       100 %
Dry
    2       0.7 %     1.3       0.5 %     5       6 %     2.5       5 %                        
                                                                                                 
Total
    283       100 %     245.7       100 %     87       100 %     53.3       100 %     31       100 %     13.0       100 %
                                                                                                 
Exploratory:
                                                                                               
Productive
    27       82 %     24.3       84 %     19       76 %     13.0       72 %     2       22 %     0.8       22 %
Dry
    6       18 %     4.7       16 %     6       24 %     5.0       28 %     7       78 %     2.9       78 %
                                                                                                 
Total
    33       100 %     29.0       100 %     25       100 %     18.0       100 %     9       100 %     3.7       100 %
                                                                                                 
Total:
                                                                                               
Productive
    308       98 %     268.7       98 %     101       90 %     63.8       89 %     33       83 %     13.8       83 %
Dry
    8       2 %     6.0       2 %     11       10 %     7.5       11 %     7       17 %     2.9       17 %
                                                                                                 
      316       100 %     274.7       100 %     112       100 %     71.3       100 %     40       100 %     16.7       100 %
                                                                                                 
 
At December 31, 2007, we had 40 wells in process.


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Drilling Rigs
 
The following table sets forth information with respect to the drilling on our acreage as of December 31, 2007.
 
                 
Area
  Owned(1)     Third-Party  
 
WTO
    28       2  
East Texas
          6  
Gulf Coast
          1  
Other, including Oklahoma
    1       2  
                 
Total
    29       11  
                 
 
 
(1) Includes rigs owned by Lariat, our wholly owned subsidiary, and by Larclay, a limited partnership in which we have a 50% interest.
 
Marketing and Customers
 
Through Integra Energy, our subsidiary, we market our natural gas production in accordance with standard industry practices. Each month we develop a portfolio of natural gas sales by arranging for a percentage of Integra Energy’s natural gas to be sold on a first of the month index price basis with the remaining volume sold on a daily swing basis at current market rates. Most of the natural gas is sold on a month-to-month basis, and any longer term or evergreen agreements that we are subject to provide pricing provisions that allow us to receive monthly market area based prices. During the year ended December 31, 2007, we sold natural gas to 24 different purchasers.
 
The top five natural gas purchasers of our WTO production for the year ended December 31, 2007 and each company’s approximate percentage of total sales during that period are listed below:
 
         
Gas Purchasers
  %  
 
Magnus Energy Marketing, Ltd. 
    25.0 %
ANP Funding I, LLC
    21.4 %
Atmos Energy Corporation
    12.9 %
City of Austin, Texas
    10.9 %
El Paso Industrial Energy, LP
    10.5 %
 
In light of access to numerous other purchasers through existing pipeline interconnections, we do not believe the loss of any of our major gas purchasers would have a material effect on our business.
 
Title to Properties
 
As is customary in the natural gas and oil industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. In addition, prior to completing an acquisition of producing natural gas and oil leases, we perform title reviews on the most significant leases, and depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. To date, we have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the natural gas and oil industry. Our natural gas and oil properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.


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Drilling and Oil Field Services
 
We provide drilling and related oil field services to our exploration and production business and to third parties in West Texas.
 
Drilling Operations
 
We drill for our own account in the WTO through our drilling and oil field services subsidiary, Lariat Services, Inc. In addition, we also drill wells for other natural gas and oil companies, primarily located in the West Texas region. We believe that drilling with our own rigs allows us to control costs and maintain operating flexibility. We have a 50% interest in a limited partnership, Larclay, that owns and operates drilling rigs. We believe that our ownership of drilling rigs and our related oil field services will continue to be a catalyst of our growth. As of December 31, 2007, 22 of our rigs and seven Larclay rigs were working on properties operated by us, and we operated 43 rigs, including eleven of the twelve rigs owned by Larclay. Our rig fleet is designed to drill in our specific areas of operation and have an average horsepower of over 800 and an average depth capacity of greater than 10,500 feet.
 
In 2005, we ordered 22 rigs from Chinese manufacturers for an aggregate purchase price of $126.4 million, which included the cost of assembling and equipping the rigs in the U.S. Due in part to the shortage of experienced drilling employees and various operational challenges, we have deemed it prudent to retrofit five Chinese rigs to a conventional operation. Of the five rigs to be retrofit, four had become operational at March 31, 2008 and the fifth became operational during the second quarter of 2008.
 
The table below identifies certain information concerning our contract drilling operations:
 
                         
    Year Ended December 31,  
    2007     2006     2005  
 
Number of operational rigs owned at end of period
    25       25       19  
Average number of operational rigs owned during the period
    26.0       21.9       14.3  
Average number of rigs utilized
    23.8       21.9       14.3  
Average drilling revenue per rig per day(1)(2)
  $ 17,177     $ 17,034     $ 11,503  
 
 
(1) Represents the total revenues from our contract drilling operations divided by the total number of days our drilling rigs were used during the period.
 
(2) Does not include revenues for related rental equipment.
 
The table below identifies certain information concerning our drilling rigs as of December 31, 2007:
 
                                         
                      Operating for
    Operating for
 
    Owned     Operational     Idle     SandRidge     Third Parties  
 
Lariat
    32 (1)     25       0       22       3  
Larclay
    12 (2)     11       1       7       3  
                                         
Total
    44       36       1       29       6  
                                         
 
 
(1) Includes three rigs that were being retrofitted and four rigs that are non-operational.
 
(2) Includes one rig that has not been assembled.
 
Oil Field Services
 
Our oil field services business began in 1986 and conducts operations that complement our exploration and production operation. These services include providing pulling units, coiled-tubing units, trucking, location and road construction roustabout services and rental tools to ourselves and to third parties. Less than 28% of our oil field services in 2007 were performed for third parties. We also provide underbalanced drilling systems for our own wells. Our capital expenditures for 2007 related to our oil field services were $123.2 million and we have budgeted approximately $50 million in capital expenditures in 2008 for oil field services.


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Types of Drilling Contracts
 
We obtain our contracts for drilling natural gas and oil wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on a daywork, footage or turnkey basis. The contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, the anticipated duration of the work to be performed and prevailing market rates. For a discussion of these contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Segment Overview — Drilling and Oil Field Services Segment.”
 
Our Customers
 
We perform approximately two-thirds of our drilling services in support of our exploration and production business and approximately one-third with the other operators in West Texas. For the year ended December 31, 2007, we generated revenues of $38.1 million for drilling services performed for third parties, with Mariner Energy, Inc. accounting for $19.0 million of those revenues.
 
Midstream Gas Services
 
We provide gathering, compression, processing and treating services of natural gas in the TransPecos region of 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 our primary midstream assets as of December 31, 2007:
 
                         
    Plant Capacity
    Average
    Third-Party
 
Gas Plants
  (Mmcf/d)     Utilization(1)     Usage  
 
Pike’s Peak(2) — West Texas
    70       90 %     1 %
Grey Ranch(3) — West Texas
    92       89 %     31 %
Sagebrush(4) — Piceance Basin
    50       24 %     21 %
 
 
(1) Average utilization for the year ended December 31, 2007.
 
(2) A project to expand Pike’s Peak capacity to 70 Mmcf per day was completed in the fourth quarter of 2007.
 
(3) A project to expand the plant to 92 Mmcf/per day was completed during the fourth quarter of 2007. The plant capacity is expected to be further increased to 170 Mmcf/per day by the third quarter of 2008.
 
(4) Sagebrush commenced processing operations on May 1, 2007. Current throughput is 22 Mmcf per day, increasing utilization to 44%. See “— Recent Developments” for information about the sale of our Piceance assets.
 
                 
    CO2 Compression
    Average
 
SandRidge Tertiary Facilities (West Texas)
  Capacity (Mmcf/d)     Utilization(1)  
 
Pike’s Peak
    38       63 %
Mitchell
    26       41 %
Grey Ranch
    40       59 %
Terrell
    38       66 %
 
 
(1) Average utilization for year ended December 31, 2007.
 
West Texas
 
In Pecos County, we operate and own the Pike’s Peak gas treating plant, which has the capacity to treat 70 Mmcf per day of gas for the removal of CO2 from natural gas produced in the Piñon Field and nearby areas. We also own the Grey Ranch CO2 treatment plant located in Pecos County and have a 50% interest in the partnership that leases the plant from us under a lease expiring in 2010. Our 50% partner, Southern Union, operates the plant. The treating capacities for both the Pike’s Peak and Grey Ranch plants are dependent upon


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the quality of natural gas being treated. The above numbers for the Pike’s Peak and Grey Ranch plants are based on a natural gas stream that averages 65% CO2.
 
Our two West Texas plants remove CO2 from natural gas production and deliver residue gas into the Atmos Lone Star and Enterprise Energy Services pipelines. These assets are operated on fixed fees based upon throughput of natural gas. We have access for up to 60 Mmcf per day of treating capacity at Anadarko Petroleum Corporation’s Mitchell Plant under a long term fixed fee arrangement.
 
We also operate or own approximately 367 miles of natural gas gathering pipelines and numerous dehydration units. Within the Piñon Field, we operate separate gathering systems for sweet natural gas and produced natural gas containing high percentages of CO2. In addition to servicing our exploration and production business, these assets also service other natural gas and oil companies.
 
The majority of the produced natural gas gathered by our midstream assets in West Texas requires compression from the wellhead to the final sales meter. As of December 31, 2007, we currently own and operate approximately 45,000 horsepower of gas compression and anticipate installing an additional 40,000 horsepower in 2008.
 
Other Areas
 
In May 2008, we and other parties entered into an agreement to sell substantially all of our assets located in the Piceance Basin of Colorado to a subsidiary of The Williams Companies, Inc. The total purchase price was $285 million, with net proceeds to us of approximately $140 million, subject to closing adjustments and final allocation of the sales price among multiple sellers. Assets sold included undeveloped acreage, working interests in wells, gathering and compression systems and other facilities related to the wells. This sale was completed on May 20, 2008.
 
We own approximately 70 miles of pipeline gathering systems and operate more than 10,000 horsepower of natural gas compression in East Texas and approximately 44 miles of pipeline gathering systems in the Gulf Coast area.
 
Capital Expenditures
 
The growth of our midstream assets is driven by our exploration and development operations. Historically, pipeline and facility expansions are made when warranted by the increase in production or the development of additional acreage. During 2007, we spent approximately $73.8 million in capital expenditures to install pipeline and compression infrastructure to accommodate our growth in production and for increased treating capacity for high CO2 gas, adding approximately 75 Mmcf per day in additional treating capacity. We anticipate adding approximately 80 Mmcf per day in additional treating capacity in 2008. We have budgeted approximately $107 million in 2008 capital expenditures for our midstream and other segments.
 
Marketing
 
Through Integra Energy, our subsidiary, we buy and sell the natural gas and oil production from SandRidge-operated wells and third-party operated wells within our West Texas operations. Through Integra Energy, we purchase and sell residue gas from the Sagebrush plant into Questar Corporation and Colorado Interstate Gas pipelines. We generally buy and sell natural gas on “back-to-back” contracts using a portfolio of baseload and spot sales agreements. Identical volumes are bought and sold on monthly and daily contracts using a combination of Inside FERC and Gas Daily pricing indices to eliminate price exposure. We market our oil and condensate production in both Texas and Colorado to Shell Trading U.S. Company at current market rates.
 
We do not actively seek to buy and sell third-party natural gas due to onerous credit requirements and minimal margin expectations. We conduct thorough credit checks with all potential purchasers and minimize our exposure by contracting with multiple parties each month. We do not engage in any hedging activities with respect to these contracts. We manage several interruptible natural gas transportation agreements in order to take advantage of price differentials or to secure available markets when necessary. We currently have


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75,000 MmBtu per day of firm transportation service subscribed on the Oasis Pipeline for a portion of our Piñon Field production for 2008.
 
Other Operations
 
Our CO2 gathering, merchant sales and tertiary oil recovery operations are conducted through SandRidge CO2. SandRidge CO2 owns 231 miles of CO2 pipelines in West Texas with approximately 88,000 horsepower of owned and leased CO2 compression available with approximately 54,000 horsepower currently operational. In addition, SandRidge CO2 has exclusive long-term supply contracts to gather CO2 from natural gas treatment plants in West Texas and is the sole gatherer of CO2 from the four natural gas treatment plants located in the Delaware and Val Verde Basins of West Texas. Our CO2 supply is primarily used in our and third parties’ tertiary oil recovery operations. We have assembled an experienced CO2 management team, including engineers and geologists with extensive experience in CO2 flooding with industry leaders.
 
Production from most oil reservoirs includes three distinct phases: primary, secondary and tertiary or enhanced recovery. During primary recovery, the natural pressure of the reservoir or gravity drives oil into the wellbore and artificial lift techniques (such as pumps) produce the oil to the surface. However, only about 10% to 15% of a reservoir’s original oil in place is typically produced during primary recovery. Secondary recovery techniques, most commonly water flooding, often increase ultimate recovery to more than 20% to 45% of the original oil in place. This technique involves injecting water to displace oil and drive it to the wellbore. Even after a water flood, the majority of the original oil in place is still un-recovered. Tertiary or enhanced recovery techniques, such as CO2 flooding, can recover additional oil. In CO2 flooding, the CO2 is injected into the reservoir. At high pressures (approximately 2,000 psi), the CO2 is in a liquid phase and can become miscible with the oil, which means the CO2 and oil mix together and form one fluid. This mixing changes the fluid properties of the oil and enables this trapped oil to begin to move in the reservoir again. The result is a potentially significant increase in production. CO2 injection can recover, on average, an additional 10% to 16% of the original oil in place in a field over a period of 20 to 30 years. Mature fields that have been abandoned may still be viable candidates for CO2 floods. CO2 flooding typically extends the life of oil fields by 20 years.
 
In 2004 and 2005, we acquired West Texas waterfloods, the Wellman and South Mallet Units and the George Allen Unit, for the purpose of evaluating for potential implementation of tertiary oil recovery operations utilizing our equity CO2 supply. For a discussion of our tertiary reserves and production at the units, please read “— Exploration and Production Operations — Tertiary Oil Recovery.” We have also identified numerous other properties that are attractive candidates for implementing CO2 projects. We believe we have a competitive advantage in identifying, acquiring and developing these properties because of our expertise and large available CO2 supply.
 
SandRidge CO2 currently has approximately 95 Mmcf per day of CO2 in available supply. We currently deliver the majority of this supply to Occidental Permian Ltd. and Pure Resources L.P. In December 2007, we captured and sold 92 Mmcf per day. Our long term contracts in place with Occidental provide for the exchange of up to 60% of the delivered volumes. We believe our current tertiary oil recovery properties will require an average of 65 to 75 Mmcf of CO2 per day over the next five years. We intend to increase our supply of CO2 in order to provide sufficient capacity for our tertiary oil recovery operations. We expect the supply of CO2 to increase as additional natural gas reserves with a high CO2 content are developed in the Piñon and surrounding fields. In addition, we intend to increase the capacity of our CO2 treating, gathering and transportation assets which will continue to provide for our CO2 needs, as well as the expansion of our merchant sales business. Currently, two additional compressors are being refurbished at the Grey Ranch and Mitchell Plant. These units will add over 11,000 horsepower and over 30 Mmcf per day of capacity.
 
Future regulation of greenhouse gas emissions may provide the Company an opportunity to create economic benefits in the form of Emissions Reduction Credits (“ERCs”), but such regulation may also impose burdens on the conduct and cost of our operations. Recently, a number of states and regions of the U.S. have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of “greenhouse gases,” such as CO2 and methane. In addition, the U.S. Congress is actively considering legislation to reduce


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emissions of greenhouse gases, and in light of the U.S. Supreme Court’s recent decision in Massachusetts, et al. v. EPA, the U.S. Environmental Protection Agency may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Other nations (not including the United States) have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” These legislative and regulatory efforts may result in legal requirements that create a more active and more valuable market in which to trade ERCs, although the timing and scope of future legal requirements governing greenhouse gases remain uncertain. We currently capture approximately 1.5 million metric tons of CO2 per year. We may benefit from such capture to the extent it results in ERCs that can be traded or can be used by us to meet future compliance obligations that may otherwise be costly to satisfy. ERCs of just over 170,000 tonnes were sold on the voluntary market during 2007.
 
Competition
 
We believe that our leasehold acreage position, oil field service businesses, midstream assets, CO2 supply and technical and operational capabilities generally enable us to compete effectively. However, the natural gas and oil industry is intensely competitive, and we face competition in each of our business segments.
 
We believe our geographic concentration of operations and vertical integration enable us to compete effectively with our exploration and production operations. However, we compete with companies that have greater financial and personnel resources than we do. These companies may be able to pay more for producing properties and undeveloped acreage. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas and oil market prices. Our larger or integrated competitors may be able to absorb the burden of any existing and future federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas and oil properties.
 
We believe the type, age and condition of our drilling rigs, the quality of our crew and the responsiveness of our management generally enable us to compete effectively. However, to the extent we drill for third parties, we encounter substantial competition from other drilling contractors. Our primary market area is highly competitive. The drilling contracts we compete for are sometimes awarded on the basis of competitive bids.
 
We believe pricing and rig availability are the primary factors our potential customers consider in determining which drilling contractor to select. While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, the experience of our rig crews and our willingness to drill on a turnkey basis, to differentiate us from our competitors. This strategy is less effective when demand for drilling services is weak or there is an oversupply of rigs, as these conditions usually result in increased price competition, which makes it more difficult for us to compete on the basis of factors other than price. Many of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to better withstand industry downturns and better retain skilled rig personnel.
 
We believe our geographic concentration of operations enables us to compete effectively in our midstream business segment. Most of our midstream assets are integrated with our production. However, with respect to third-party gas and acquisitions, we compete with companies that have greater financial and personnel resources than we do. These companies may be able to pay more for acquisitions. In addition, these companies may have a greater ability to price their services below our prices for similar services. Our larger or integrated competitors may be able to absorb the burden of any existing and future federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position.


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We believe our supply of CO2, focus on small to mid-sized acquisitions and technical expertise enable us to compete effectively in our tertiary oil recovery business. However, we face the same competitive pressures in this business that we do in our traditional exploration and production segment.
 
Seasonal Nature of Business
 
Generally, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or cool summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other natural gas and oil operations in a portion of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.
 
Environmental Matters and Regulation
 
General
 
We are subject to extensive and complex federal, state and local laws and regulations governing the protection of the environment and of the health and safety of our employees. These laws and regulations may, among other things:
 
  •  require the acquisition of various permits before drilling commences;
 
  •  require the installation of expensive pollution control equipment;
 
  •  require safety-related procedures and personal protective equipment to be used during operations;
 
  •  restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with the natural gas and oil drilling, production, transportation and processing activities;
 
  •  suspend, limit, prohibit or require approval before construction, drilling or other activities; and
 
  •  require remedial measures to mitigate pollution from historical and ongoing operations, such as the closure of pits and plugging of abandoned wells.
 
These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability.
 
Governmental authorities have the power to enforce compliance with environmental laws, regulations and permits, and violations are subject to injunction, as well as administrative, civil and potentially criminal penalties. The effects of these laws and regulations, as well as other laws or regulations that may be adopted in the future, could have a material adverse impact on our business, financial condition and results of operations. Below is a discussion of the environmental laws and regulations that could have a material impact on the oil and gas industry.
 
Comprehensive Environmental Response, Compensation and Liability Act
 
The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, and analogous state laws impose joint and several liability, without regard to fault or legality of conduct, on specific classes of persons for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to strict joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of related environmental and health studies. In addition, it is not uncommon for neighboring landowners and other third


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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 CERCLA’s definition of hazardous substances. Further, natural gas and oil exploration, production, processing and other activities have been conducted at some of our properties by previous owners and operators, and materials from these operations remain at and could migrate from some of our properties and may warrant or require investigation or remediation or other response action. Therefore, governmental agencies or third parties could seek to hold us responsible under CERCLA or similar state laws for all or part of the costs to clean up a site at or to which hazardous substances may have been released or deposited.
 
Waste Handling
 
The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the U.S. Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are currently excluded from regulation as RCRA hazardous wastes but instead are regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain natural gas and oil exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change would likely increase our operating expenses, which could have a material adverse effect on our business, financial condition or results of operations as well as on the industry in general.
 
Air Emissions
 
The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. These regulatory programs may require us to obtain permits before commencing construction on a new source of air emissions, and they may require us to reduce emissions or to install expensive emission control technologies at existing facilities and new facilities. As a result, we may be required to incur increased capital and operating costs at existing and new facilities. For instance, the Grey Ranch natural gas treatment plant operates under a permit granted by the Texas Commission on Environmental Quality, or TCEQ that currently allows us to vent CO2 emissions. Effective March 2009, we will be required to install control devices that limit the quantity of organic compounds vented by the plant. We are in the process of refurbishing existing compressors at an estimated cost of $4.0 million, which will enable us to capture the CO2 for ultimate delivery to the marketplace. Additional expenses and capital costs may be required for us to maintain or achieve compliance with current and future laws governing air emissions.
 
We are subject to air quality compliance reviews by federal and state agencies, and the failure to meet applicable requirements may result in enforcement action, including fines and penalties. In February 2008, we received a notice of alleged violations from TCEQ for certain monitoring and recordkeeping deficiencies and emissions in excess of allowable limits at our Pike’s Peak processing plant in 2007. We are preparing a response regarding corrective action taken with regard to the alleged violations.
 
Water Discharges
 
The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances into waters of the United States, including wetlands, as well as state waters. These laws prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and other substances related to the oil and natural gas industry into onshore, coastal and offshore waters without appropriate permits. Some of the pollutant limitations have become more restrictive over the years, and additional restrictions and limitations including technology requirements and receiving water limits, may be imposed in the future. The Clean Water Act also regulates storm water discharges from industrial and construction activities. Regulations


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promulgated by the EPA and state regulatory agencies require industries engaged in certain industrial or construction activities to acquire permits and implement storm water management plans and best management practices, to conduct periodic monitoring and reporting of discharges, and to train employees. Further, federal and state regulations require certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. There are costs associated with each of these regulatory requirements. In addition, federal and state regulatory agencies can impose administrative, civil and potentially criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
 
The Oil Pollution Act of 1990, or OPA, which amends and augments the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. In addition, OPA and regulations that implement OPA impose a variety of regulations on responsible parties related to the prevention of oil spills and liability for clean up and natural resource damages resulting from such spills. For example, some of our facilities in the Gulf Coast region must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance.
 
National Environmental Policy Act
 
Natural gas and oil exploration and production activities on federal lands or otherwise requiring federal approval are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency may prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that is made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans on federal lands, require governmental permits that are subject to the requirements of NEPA. The NEPA process has the potential to delay or even prohibit our development of natural gas and oil projects in covered areas.
 
Future Laws and Regulations
 
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to restrict or regulate emissions of greenhouse gases. At least 17 states, as well as other regions, have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and regional greenhouse gas cap-and-trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources, e.g., cars and trucks, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The court’s holding in Massachusetts, et al. v. EPA, that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant,” may lead to future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the Kyoto Protocol, an international treaty pursuant to which participating countries, not including the United States, have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Passage of climate-related legislation or other regulatory initiatives by Congress or various states of the U.S., or the adoption of regulations by the EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business, may have an adverse effect on demand for our services or products and may result in compliance obligations with respect to the release, capture and use of carbon dioxide that could have an adverse effect on our operations.


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Anti-Terrorism Measures
 
The federal Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to the act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. We have not yet determined the extent to which our facilities are subject to the interim rules or the associated costs to comply, but it is possible that such costs could be substantial.
 
Other Regulation of the Natural Gas and Oil Industry
 
The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities, including Native American tribes. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
 
Drilling and Production
 
Our operations are subject to various types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribes, in which we operate also regulate one or more of the following:
 
  •  the location of the wells;
 
  •  the method of drilling and casing wells;
 
  •  the rate of production or “allowables;”
 
  •  the surface use and restoration of properties upon which wells are drilled;
 
  •  the plugging and abandoning of wells; and
 
  •  notice to surface owners and other third parties.
 
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
 
Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines, and for site restoration, in areas where we operate. Minerals Management Service of the U.S. Department of the Interior, or MMS, Regulations require that owners and operators plug and abandon wells and decommission and remove offshore facilities located in federal offshore lease areas in a prescribed manner. The MMS requires federal leaseholders to post


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performance bonds or otherwise provide necessary financial assurances to provide for such abandonment, decommissioning and removal. The Railroad Commission of Texas has financial responsibility requirements for owners and operators of facilities in state waters to provide for similar assurances. The U.S. Army Corps of Engineers, or ACOE, and many other state and local municipalities have regulations for plugging and abandonment, decommissioning and site restoration. Although the ACOE does not require bonds or other financial assurances, some other state agencies and municipalities do have such requirements.
 
Natural Gas Sales Transportation
 
Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission, or FERC, has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production.
 
FERC also regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
 
Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point-of-sale locations.
 
Employees
 
As of December 31, 2007, we had 2,219 full-time employees and 8 part-time employees, including more than 150 geologists, geophysicists, petroleum engineers, technicians, land and regulatory professionals. Of our 2,227 employees, 335 were located at our headquarters in Oklahoma City, Oklahoma, eight in Amarillo, Texas and the remaining 1,884 employees were working in our various field offices and at our drilling sites.
 
Offices
 
As of December 31, 2007 we leased 80,861 square feet of office space in Oklahoma City, Oklahoma at 1601 N.W. Expressway, where our principal offices are located. The term of the lease expires on August 31, 2009. In July 2007, we purchased property to serve as our future corporate headquarters. The 3.51-acre site contains five buildings and is located in downtown Oklahoma City, Oklahoma.
 
We also lease or sublease 28,887 square feet of office space in Amarillo, Texas at 701 S. Taylor Street, where our principal offices were previously located. The leases expire in April 2009. We lease 6,725 square feet of office space at 16801 Greenspoint Park Drive in Houston, Texas under a lease expiring in January 2014. SandRidge Tertiary currently leases approximately 7,848 square feet in Midland, Texas under a lease expiring in December 2008. We own two buildings in Fort Stockton, Texas that combined total 9,292 square


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feet. Adjacent to these buildings, we own approximately 31,620 square feet of office and shop space. We also own an approximate 10,000 square foot office building in Midland, Texas and own 4,358 square feet of office space and 6,240 square feet of shop space in Odessa, Texas. In addition, we lease a field office located in Longview and Odessa, Texas, Yukon, Oklahoma, Shreveport, Louisiana and Rifle, Colorado.


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DESCRIPTION OF THE NOTES
 
You can find the definitions of certain terms used in this description under the subheading “— Certain Definitions.” In this Description of the Notes, the term “Company” refers only to SandRidge Energy, Inc., and any successor obligor on the notes, and not to any of its subsidiaries. You can find the definitions of certain terms used in this description under “— Certain Definitions.” References herein to the “Guarantors” refer to the Subsidiary Guarantors described below.
 
The Company issued the 85/8% Senior Notes Due 2015 and the Senior Floating Rate Notes Due 2014 (collectively, the “outstanding notes”) under an indenture among the Company, certain subsidiaries of the Company, as Guarantors, and Wells Fargo Bank, National Association, as trustee, and it will issue the exchange notes (together with the outstanding notes, the “notes”) under the same indenture. Both the outstanding notes and the exchange notes of the 85/8 Senior Notes Due 2015 series of notes are referred to collectively in this description as the “Senior Notes,” and both the outstanding notes and the exchange notes of the Senior Floating Rate Notes Due 2014 series of notes are referred to collectively in this description as the “Senior Floating Rate Notes”. The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939.
 
The following description is a summary of the material provisions of the indenture. It does not restate that agreement in its entirety. We urge you to read the indenture because it, and not this description, defines your rights as holders of the exchange notes. Certain defined terms used in this description but not defined below under “— Certain Definitions” have the meanings assigned to them in the indenture.
 
The registered Holder of a note will be treated as the owner of it for all purposes. Only registered Holders will have rights under the indenture.
 
We are conducting the exchange offers to enable holders of outstanding notes to exchange their notes for publicly registered notes having substantially identical terms, except for provisions relating to transfer restrictions and additional interest. Any outstanding notes, the exchange notes issued in the exchange offer and any additional notes subsequently issued under the indenture will constitute a single series of securities under the indenture (except in the limited circumstances provided in the indenture) and therefore will vote together as a single class for purposes of determining whether holders of the requisite percentage in aggregate principal amount thereof have taken actions or exercised rights they are entitled to take or exercise under the indenture.
 
Basic Terms of the Senior Notes
 
The Senior Notes
 
  •  are unsecured unsubordinated obligations of the Company, ranking equally in right of payment with all existing and future unsubordinated obligations of the Company;
 
  •  were issued in an original aggregate principal amount of up to $650,000,000; provided, that the Company is entitled to, without the consent of the holders (and without regard to any restrictions or limitations set forth under “— Certain Covenants — Limitation on Indebtedness and Issuance of Disqualified Stock”), increase the outstanding principal amount of the Senior Notes or issue additional Senior Notes (the “PIK Notes”) under the indenture on the same terms and conditions as the applicable Senior Notes issued under the indenture (in each case, a “PIK Payment”).
 
  •  mature on April 1, 2015;
 
  •  permit the Company, with respect to interest periods ending on or before April 1, 2011, to elect to pay interest in cash (“Cash Interest”) or by increasing the outstanding principal amount of the Senior Notes or issuing additional Senior Notes (“PIK Interest”);
 
  •  bear interest commencing the date of issue (or, the case of the first interest payment, commencing April 1, 2008) at (i) 8.625% during periods when Cash Interest is accruing and (ii) 9.375% during periods when PIK Interest is accruing, payable semiannually on each April 1 and October 1, payable


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  commencing October 1, 2008, to holders of record on the March 15 or September 15 immediately preceding the interest payment date;
 
  •  bear interest on overdue principal, and, in certain circumstances, to the extent lawful, overdue interest, at 2% per annum higher than the rates described in the preceding bullet point.
 
Interest on the Senior Notes will accrue from April 1, 2008 and will be computed on the basis of a 360-day year of twelve 30-day months; provided, that the interest for the period from April 1, 2008 through May 1, 2008 will be computed on the basis of a 360-day year and actual days elapsed. Interest on the exchange notes of this series will accrue from April 1, 2008.
 
The Company must elect whether the interest payment with respect to each interest period is to be in the form of Cash Interest or PIK Interest by delivering a notice to the trustee at least 5 Business Days prior to the beginning of such interest period. The trustee shall promptly deliver a corresponding notice to the holders. In the absence of such an election for any interest period, interest on the Senior Notes will be payable in the form of the interest payment for the prior interest period. Interest for the first period commencing on the Issue Date shall be payable in the form of Cash Interest. All interest payments on the Senior Notes made after April 1, 2011 shall be made in the form of Cash Interest.
 
Interest that is paid in the form of PIK Interest on the Senior Notes will be payable (a) with respect to the Senior Notes represented by one or more global notes registered in the name of, or held by, DTC or its nominee on the relevant record date, by increasing the principal amount of the outstanding Senior Notes represented by such global notes by an amount equal to the amount of PIK Interest for the applicable interest period (rounded up to the nearest $1,000) and (b) with respect to Senior Notes represented by certificated notes, by issuing PIK Notes in certificated form in an aggregate principal amount equal to the amount of PIK Interest for the applicable interest period (rounded up to the nearest whole dollar), and the trustee will, at the request of the Company, authenticate and deliver such PIK Notes in certificated form for original issuance to the holders on the relevant record date. Interest on the Senior Notes that is paid in the form of PIK Interest shall be considered paid or duly provided for, for all purposes under the indenture, and shall not be considered overdue. Following an increase in the principal amount of the outstanding Senior Notes represented by global notes as a result of a PIK Payment, such Senior Notes will bear interest on such increased principal amount from and after the date of such PIK Payment. Any PIK Notes issued in certificated form will be dated as of the applicable interest payment date and will bear interest from and after such date. All PIK Notes issued pursuant to a PIK Payment will mature on April 1, 2015, and will be governed by, and subject to the terms, provisions and conditions of, the indenture and shall have the same rights and benefits as the Senior Notes not issued pursuant to a PIK Payment. Any certificated PIK Notes will be issued with the description “PIK” on the face of such PIK Note.
 
Basic Terms of the Senior Floating Rate Notes
 
The Senior Floating Rate Notes
 
  •  are unsecured unsubordinated obligations of the Company, ranking equally in right of payment with all existing and future unsubordinated obligations of the Company;
 
  •  were issued in an original aggregate principal amount of up to $350,000,000;
 
  •  mature on April 1, 2014;
 
  •  bear interest, payable in cash, commencing the date of issue (or, the case of the first interest payment, commencing April 1, 2008) at the LIBOR Rate (which will be adjusted quarterly) plus 3.625%, payable quarterly on each January 1, April 1, July 1 and October 1, payable commencing July 1, 2008, to holders of record on the March 15, June 15, September 15 or December 15 immediately preceding the interest payment date, except that the interest rate for the period beginning on the Issue Date and ending June 30, 2008 will be 6.3225%; and
 
  •  bear interest on overdue principal, and, in certain circumstances, to the extent lawful, on overdue interest, at 2% per annum higher than the rates described in the preceding bullet point.


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Interest on the Senior Floating Rate Notes will be computed on the basis of a 360-day year and actual days elapsed. Interest on the exchange notes of this series will accrue from July 1, 2008.
 
Additional Notes
 
Subject to the covenants described below, the Company may issue additional Senior Notes and additional Senior Floating Rate Notes under the indenture having the same terms in all respects as the Senior Notes and the Senior Floating Rate Notes, respectively, except that interest will accrue on such additional notes from their date of issuance. The outstanding notes, the exchange notes, any Additional Notes and any PIK Notes would be treated as a single class for all purposes under the indenture and will vote together as one class on all matters with respect to the notes, except as expressly set forth in the indenture.
 
Optional Redemption
 
Except as set forth in this section, the notes are not redeemable at the option of the Company.
 
At any time and from time to time on or after April 1, 2011, the Company may redeem the Senior Notes, in whole or in part, at a redemption price equal to the percentage of principal amount set forth below plus accrued and unpaid interest to the redemption date, if redeemed during the twelve-month period indicated below.
 
         
12-Month Period Commencing
  Percentage  
 
April 1, 2011
    104.313 %
April 1, 2012
    102.156 %
April 1, 2013 and thereafter
    100.000 %
 
At any time and from time to time on or after April 1, 2009, the Company may redeem the Senior Floating Rate Notes, in whole or in part, at a redemption price equal to the percentage of principal amount set forth below plus accrued and unpaid interest to the redemption date, if redeemed during the twelve-month period indicated below.
 
         
12-Month Period Commencing
  Percentage  
 
April 1, 2009
    103.00 %
April 1, 2010
    102.00 %
April 1, 2011
    101.00 %
April 1, 2012 and thereafter
    100.00 %
 
If fewer than all of the notes are being redeemed, the trustee will select the notes to be redeemed pro rata, by lot or by any other method the trustee in its sole discretion deems fair and appropriate, in denominations of $1,000 principal amount and multiples thereof. Upon surrender of any note redeemed in part, the holder will receive a new note equal in principal amount to the unredeemed portion of the surrendered note. Once notice of redemption is sent to the holders, notes called for redemption become due and payable at the redemption price on the redemption date, and, commencing on the redemption date, notes redeemed will cease to accrue interest.
 
No Mandatory Redemption or Sinking Fund
 
There will be no mandatory redemption or sinking fund payments for the notes.
 
Guaranties
 
The obligations of the Company pursuant to the notes, including any repurchase obligation resulting from a Change of Control, are unconditionally guaranteed, jointly and severally, on an unsecured basis, by the Guarantors. If the Company or any of its Restricted Subsidiaries acquires or creates a Restricted Subsidiary (other than a Foreign Subsidiary or an Immaterial Subsidiary) after the date of the indenture, the new Restricted Subsidiary must provide a guaranty of the notes (a “Note Guaranty”).


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Each Note Guaranty is limited to the maximum amount that would not render the Guarantors obligations subject to avoidance under applicable fraudulent conveyance provisions of the United States Bankruptcy Code or any comparable provision of state law. By virtue of this limitation, a Guarantor’s obligation under its Note Guaranty could be significantly less than amounts payable with respect to the notes, or a Guarantor may have effectively no obligation under its Note Guaranty. See “Risk Factors — Risks Relating to the Notes and the Exchange Offers — Insolvency and fraudulent transfer laws and other limitations may preclude the recovery of payment under the Notes and the guarantees.”
 
The Note Guaranty of a Guarantor will terminate upon
 
(1) a sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of consolidation or merger) to a Person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary, if the sale or other disposition is permitted by the indenture,
 
(2) a sale or other disposition of all or substantially all of the Capital Stock of that Guarantor to a Person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary, if the sale or other disposition is permitted by the indenture,
 
(3) if the Note Guaranty was required pursuant to the terms of the indenture, the cessation of the circumstances requiring the Note Guaranty,
 
(4) the designation in accordance with the indenture of the Guarantor as an Unrestricted Subsidiary, or
 
(5) defeasance or discharge of the notes, as provided in “— Defeasance and Discharge.”
 
Ranking
 
The payment of the principal of, premium, if any, and interest on the notes and the payment of any Note Guaranty rank equally in right of payment to all existing and future senior indebtedness of the Company or the relevant Guarantor, as the case may be, including the obligations of the Company and such Guarantor under the Senior Credit Facilities.
 
The notes and the Note Guaranties are effectively subordinated in right of payment to all of the Company’s and each Guarantor’s existing and future secured Indebtedness to the extent of the value of the collateral securing such secured indebtedness. Although the indenture contains limitations on the amount of additional Indebtedness that the Company, the Guarantors and the Company’s Restricted Subsidiaries may incur, under certain circumstances the amount of such Indebtedness could be substantial and, in any case, such Indebtedness may be senior indebtedness. See “— Certain Covenants — Limitation on Indebtedness and Disqualified Stock.”
 
The Company conducts some of its operations through its subsidiaries, and certain of its immaterial domestic subsidiaries have not guaranteed the notes. Claims of creditors of such non-guarantor subsidiaries, including trade creditors, secured creditors and creditors holding debt and guarantees issued by those subsidiaries, and claims of preferred and minority stockholders (if any) of those subsidiaries generally will have priority with respect to the assets and earnings of those subsidiaries over the claims of creditors of the Company, including holders of the notes. The notes and each Note Guaranty therefore are effectively subordinated to creditors (including trade creditors) and preferred and minority stockholders (if any) of subsidiaries of the Company (other than the Guarantors). As of December 31, 2007, the total liabilities of the Company’s subsidiaries (other than the Guarantors) were approximately $11.2 million, including trade payables. Although the indenture limits the incurrence of Indebtedness and Disqualified Stock of Restricted Subsidiaries, the limitation is subject to a number of significant exceptions. Moreover, the indenture does not impose any limitation on the incurrence by Restricted Subsidiaries of liabilities that are not considered Indebtedness or Disqualified Stock under the indenture. See “— Certain Covenants — Limitation on Indebtedness and Disqualified Stock.”


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Certain Covenants
 
The indenture contains covenants including, among others, the following:
 
Limitation on Indebtedness and Disqualified Stock.  (a) The Company will not, and will not cause or permit any of its Restricted Subsidiaries to, create, issue, incur, assume, guarantee or otherwise in any manner become directly or indirectly liable for the payment of or otherwise incur, contingently or otherwise (collectively, “incur”), any Indebtedness (including any Acquired Debt and the issuance of Disqualified Stock), unless such Indebtedness is incurred by the Company or any Guarantor and, in each case, the Company’s Consolidated Fixed Charge Coverage Ratio for the most recent four full fiscal quarters for which financial statements are available immediately preceding the incurrence of such Indebtedness taken as one period is at least equal to or greater than 2.50:1.
 
(b) Notwithstanding the foregoing, the Company and, to the extent specifically set forth below, the Restricted Subsidiaries may incur each and all of the following (collectively, the “Permitted Debt”):
 
(1) Indebtedness of the Company or any Guarantor (whether as borrowers or guarantors) under one or more Credit Facilities (other than the Unsecured Credit Agreement) in an aggregate principal amount at any one time outstanding under this clause (i) not to exceed the greater of (x) $750,000,000 and (y) 30.0% of Adjusted Consolidated Net Tangible Assets;
 
(2) Indebtedness of (i) the Company pursuant to the Unsecured Credit Agreement and the notes (other than Additional Notes) and (ii) any Guarantor (x) in respect of its Guarantee of the Company’s obligations under the Unsecured Credit Agreement and (y) pursuant to a Note Guaranty of the notes (including Additional Notes);
 
(3) Indebtedness of the Company or any Guarantor outstanding on March 22, 2007, and not otherwise referred to in this definition of “Permitted Debt;”
 
(4) intercompany Indebtedness between or among the Company and any of its Restricted Subsidiaries; provided, however, that:
 
(A) if the Company or any Guarantor is the obligor on such Indebtedness, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all obligations with respect to the notes, in the case of the Company, or the Note Guaranty, in the case of a Guarantor; and
 
(B) (i) any subsequent issuance or transfer of Capital Stock that results in any such Indebtedness being held by a Person other than the Company or a Restricted Subsidiary thereof (other than pursuant to a Credit Facility) and (ii) any sale or other transfer of any such Indebtedness to a Person that is not either the Company or a Restricted Subsidiary thereof, shall be deemed, in each case, to constitute an incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (4);
 
(5) Guarantees by the Company or any Guarantor of any Indebtedness of the Company or any of the Guarantors which is permitted to be incurred under the indenture;
 
(6)
 
(A) obligations pursuant to Interest Rate Agreements entered into in the ordinary course of business with respect to Indebtedness permitted by the indenture;
 
(B) obligations under currency exchange contracts entered into in the ordinary course of business; and
 
(C) obligations pursuant to hedging arrangements (including, without limitation, swaps, caps, floors, collars, options and similar agreements) entered into in the ordinary course of business for the purpose of protecting, on a net basis, against price risks, basis risks, or other risks encountered in the Oil and Gas Business;


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(7) Indebtedness of the Company or any Restricted Subsidiary represented by Capital Lease Obligations (whether or not incurred pursuant to Sale Leaseback Transactions) or Purchase Money Obligations or other Indebtedness incurred or assumed in connection with the acquisition or development of real or personal, movable or immovable, property in each case incurred for the purpose of financing or refinancing all or any part of the purchase price or cost of construction or improvement of property used in the business of the Company, in an aggregate principal amount pursuant to this clause (7) (together with the aggregate principal amount of any Permitted Refinancing Indebtedness in respect of Indebtedness originally incurred pursuant to this clause (7)) not to exceed $50,000,000 outstanding at any time; provided that the principal amount of any Indebtedness permitted under this clause (7) did not in each case at the time of incurrence exceed the Fair Market Value, as determined by the Company in good faith, of the acquired or constructed asset or improvement so financed;
 
(8) Indebtedness of the Company or any Guarantor in connection with
 
(A) one or more standby letters of credit issued for the account of the Company or a Guarantor in the ordinary course of business and
 
(B) other letters of credit, surety, bid, performance, appeal or similar bonds, bankers’ acceptances, completion guarantees or similar instruments; provided that, in each case contemplated by this clause (8), upon the drawing of such letters of credit or other instrument, such obligations are reimbursed within 30 days following such drawing; provided, further, that with respect to clauses (A) and (B), such Indebtedness is not in connection with the borrowing of money or the obtaining of advances or credit;
 
(9) obligations relating to oil or gas balancing positions arising in the ordinary course of business;
 
(10) Indebtedness of the Company or any Restricted Subsidiary arising from agreements for indemnification or purchase price adjustment obligations or similar obligations, earn-outs or other similar obligations or from Guarantees or letters of credit, surety bonds or performance bonds securing any obligation of the Company or a Restricted Subsidiary pursuant to such an agreement, in each case incurred or assumed in connection with the acquisition or disposition of any business, assets or Capital Stock of a Restricted Subsidiary;
 
(11) Permitted Refinancing Indebtedness of the Company or any Restricted Subsidiary issued in exchange for, or the net proceeds of which are used to renew, extend, substitute, defease, refund, refinance or replace, any Indebtedness, including any Disqualified Stock, incurred pursuant to paragraph (a) and clauses (2), (3) and (7) of paragraph (b) of this covenant;
 
(12) the incurrence by the Company or any of its Restricted Subsidiaries of Acquired Debt in connection with a transaction meeting either one of the financial tests set forth in clause (3) of “— Consolidation, Merger or Sale of Assets — Consolidation, Merger or Sale of Assets by the Company;”
 
(13) any obligation arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business, provided, however, that such Indebtedness is extinguished within five business days of incurrence; and
 
(14) Indebtedness of the Company or any Restricted Subsidiary in addition to that described in clauses (1) through (13) above, and any renewals, extensions, substitutions, refinancings or replacements of such Indebtedness, so long as the aggregate principal amount of all such Indebtedness shall not exceed $40,000,000 outstanding at any one time in the aggregate.
 
(c) For purposes of determining compliance with this covenant, in the event that an item of Indebtedness meets the criteria of more than one of the types of Indebtedness permitted by this covenant, the Company in its sole discretion may classify or reclassify such item of Indebtedness and only be required to include the amount of such Indebtedness as one of such types (or to divide such Indebtedness between two or more of such types); provided that any Indebtedness under the Senior Credit Facility which is in existence on the Issue


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Date shall be deemed to have been incurred pursuant to clause (1) of paragraph (b) of this covenant rather than paragraph (a) of this covenant.
 
(d) Indebtedness permitted by this covenant need not be permitted solely by reference to one provision permitting such Indebtedness but may be permitted in part by one such provision and in part by one or more other provisions of this covenant permitting such Indebtedness.
 
(e) Accrual of interest, accretion of principal or liquidation preference (or similar amount) in respect of Preferred Stock or amortization of original issue discount, and the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, and the accretion or payment of dividends on any Disqualified Stock or Preferred Stock (including without limitation the Series A Preferred Stock) in the form of additional shares of the same class of Disqualified Stock or Preferred Stock and the issuance of additional shares of Series A Preferred Stock pursuant to warrants issued and outstanding on the Issue Date will not be deemed to be an incurrence of Indebtedness for purposes of this covenant; provided, in each such case, that the amount thereof as accrued shall be included as required in the calculation of the Consolidated Fixed Charge Coverage Ratio of the Company.
 
(f) For purposes of determining compliance with any dollar-denominated restriction on the incurrence of Indebtedness denominated in a foreign currency, the dollar-equivalent principal amount of such Indebtedness incurred pursuant thereto shall be calculated based on the relevant currency exchange rate in effect on the date that such Indebtedness was incurred.
 
(g) If Indebtedness is secured by a letter of credit that serves only to secure such Indebtedness, then the total amount deemed incurred shall be equal to the greater of (x) the principal of such Indebtedness and (y) the amount that may be drawn under such letter of credit.
 
(h) The amount of Indebtedness issued at a price less than the amount of the liability thereof shall be determined in accordance with GAAP.
 
Limitation on Restricted Payments.  (a) The Company will not, and will not cause or permit any Restricted Subsidiary to, directly or indirectly:
 
(1) pay any dividend on, or make any distribution to holders of, any shares of the Company’s Capital Stock (other than dividends or distributions payable solely in shares of the Company’s Qualified Capital Stock);
 
(2) purchase, redeem, defease or otherwise acquire or retire for value, directly or indirectly, the Company’s Capital Stock;
 
(3) make any principal payment on, or purchase, redeem, defease, retire or otherwise acquire for value, prior to any scheduled principal payment, sinking fund payment or maturity, any Subordinated Indebtedness, except a payment on, or a purchase, redemption, defeasance, retirement or other acquisition of such Subordinated Indebtedness within one year of its final maturity;
 
(4) pay any dividend or distribution on any Capital Stock of any Restricted Subsidiary to any Person (other than (A) to the Company or any of its Wholly Owned Restricted Subsidiaries or any Guarantor or (B) dividends or distributions made by a Restricted Subsidiary on a pro rata basis to all holders of the Capital Stock of such Restricted Subsidiary); or
 
(5) make any Investment in any Person (other than any Permitted Investments);
 
(any of the foregoing actions described in clauses (1) through (5) above, other than any such action that is a Permitted Payment (as defined in paragraph (b) of this covenant), collectively, “Restricted Payments”) (the amount of any such Restricted Payment, if other than cash, shall be the Fair Market Value of the assets proposed to be transferred, as determined by the Board of Directors of the Company, whose determination shall be conclusive and evidenced by a board resolution), unless
 
(A) immediately after giving effect to such proposed Restricted Payment on a pro forma basis, no Default or Event of Default shall have occurred and be continuing;


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(B) immediately after giving effect to such Restricted Payment on a pro forma basis, the Company could incur $1.00 of additional Indebtedness (other than Permitted Debt) under paragraph (a) of the covenant described under “— Limitation on Debt and Disqualified Stock; and
 
(C) after giving effect to the proposed Restricted Payment, the aggregate amount of all such Restricted Payments declared or made after March 22, 2007 (including all Designation Amounts) does not exceed the sum of:
 
(i) 50% of the aggregate Consolidated Net Income of the Company accrued on a cumulative basis during the period beginning April 1, 2007 and ending on the last day of the Company’s last fiscal quarter ending prior to the date of the Restricted Payment (or, if such aggregate cumulative Consolidated Net Income shall be a loss, minus 100% of such loss);
 
(ii) the aggregate Net Cash Proceeds, or the Fair Market Value of property other than cash, received after March 22, 2007 by the Company either (1) as capital contributions in the form of common equity to the Company or (2) from the issuance or sale (other than to any of its Subsidiaries) of Qualified Capital Stock of the Company (except, in each case, to the extent such proceeds are used to purchase, redeem or otherwise retire Capital Stock or Subordinated Indebtedness as set forth below in clauses (2) and (3) of paragraph (b) of this covenant (and excluding the Net Cash Proceeds from the issuance of Qualified Capital Stock financed, directly or indirectly, using funds borrowed from the Company or any Subsidiary until and to the extent such borrowing is repaid);
 
(iii) the aggregate Net Cash Proceeds received after March 22, 2007 by the Company (other than from any of its Subsidiaries) upon the exercise of any options, warrants or rights to purchase Qualified Capital Stock of the Company (and excluding the Net Cash Proceeds from the exercise of any options, warrants or rights to purchase Qualified Capital Stock financed, directly or indirectly, using funds borrowed from the Company or any Subsidiary until and to the extent such borrowing is repaid);
 
(iv) the aggregate Net Cash Proceeds received after March 22, 2007 by the Company from the conversion or exchange, if any, of debt securities or Disqualified Stock of the Company or its Restricted Subsidiaries into or for Qualified Capital Stock of the Company plus, to the extent such debt securities or Disqualified Stock were issued after March 22, 2007, the aggregate of Net Cash Proceeds from their original issuance (and excluding the Net Cash Proceeds from the conversion or exchange of debt securities or Disqualified Stock financed, directly or indirectly, using funds borrowed from the Company or any Subsidiary until and to the extent such borrowing is repaid);
 
(v)
 
(a) in the case of the disposition or repayment of any Investment constituting a Restricted Payment (including any Investment in an Unrestricted Subsidiary) made after March 22, 2007, an amount (to the extent not included in Consolidated Net Income) equal to the amount received with respect to such Investment, less the cost of the disposition of such Investment and net of taxes, and
 
(b) in the case of the redesignation of an Unrestricted Subsidiary as a Restricted Subsidiary (as long as the designation of such Subsidiary as an Unrestricted Subsidiary was deemed a Restricted Payment), the Fair Market Value of the Company’s interest in such Subsidiary at the time of such redesignation; and
 
(vi) any amount which previously qualified as a Restricted Payment on account of any Guarantee entered into by the Company or any Restricted Subsidiary; provided that such Guarantee has not been called upon and the obligation arising under such Guarantee no longer exists.


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(b) Notwithstanding the foregoing, and in the case of clauses (2) through (9) below, so long as no Default or Event of Default is continuing or would arise therefrom, the foregoing provisions shall not prohibit the following actions (each of clauses (1) through (9) being referred to as a “Permitted Payment”):
 
(1) the payment of any dividend within 60 days after the date of declaration thereof, if at such date of declaration such payment was permitted by the provisions of paragraph (a) of this covenant, and such payment shall be deemed to have been paid on such date of declaration;
 
(2) the purchase, defeasance, redemption, or other acquisition or retirement for value of any Capital Stock of the Company in exchange for (including any such exchange pursuant to the exercise of a conversion right or privilege in connection with which cash is paid in lieu of the issuance of fractional shares or scrip), or out of the Net Cash Proceeds of a substantially concurrent issuance and sale for cash (other than to a Subsidiary) of, any Qualified Capital Stock of the Company; provided that the Net Cash Proceeds from the issuance of such Qualified Capital Stock shall be excluded from clause (C)(ii) above;
 
(3) the purchase, redemption, defeasance, retirement or other acquisition for value or payment of principal of any Subordinated Indebtedness in exchange for, or in an amount not in excess of the Net Cash Proceeds of, a substantially concurrent issuance and sale for cash (other than to any Subsidiary of the Company) of any Qualified Capital Stock of the Company, provided that the Net Cash Proceeds from the issuance of such shares of Qualified Capital Stock shall be excluded from clause (C)(ii) above;
 
(4) the purchase, redemption, defeasance, retirement or other acquisition for value or payment of principal of any Subordinated Indebtedness (other than Disqualified Stock) through the substantially concurrent issuance of Permitted Refinancing Indebtedness;
 
(5) any purchase, redemption, retirement, defeasance or other acquisition for value of any Subordinated Indebtedness pursuant to the provisions of such Subordinated Indebtedness upon a Change of Control or an Asset Sale after the Company shall have complied with the provisions of the covenants set forth in “— Repurchase of Notes upon a Change of Control” or “— Limitation on Asset Sales,” as the case may be and repurchased all notes tendered for purchase in connection with the Offer to Purchase;
 
(6) the purchase, redemption, defeasance or other acquisition or retirement for value of any Capital Stock of the Company held by any current or former officers, directors or employees of the Company or any of its Subsidiaries (or permitted transferees of such current or former officers, directors or employees) pursuant to the terms of agreements (including employment agreements) or plans approved by the Company’s board of directors, including any such purchase, redemption, defeasance or other acquisition or retirement of such Capital Stock that is deemed to occur upon the exercise of stock options or similar rights if such shares represent all or a portion of the exercise price or are surrendered in connection with satisfying Federal income tax obligations; provided, however, that the aggregate amount of such purchases, redemptions, defeasances or other retirements and acquisitions pursuant to this clause (6) will not, in the aggregate, exceed $2,000,000 per fiscal year;
 
(7) loans made to officers, directors or employees of the Company or any Restricted Subsidiary approved by the board of directors of the Company in an aggregate amount not to exceed $2,000,000 outstanding at any one time, the proceeds of which are used solely (A) to purchase Capital Stock of the Company in connection with a restricted stock or employee stock purchase plan, or to exercise stock options received pursuant to an employee or director stock option plan or other incentive plan, in a principal amount not to exceed the exercise price of such stock options or (B) to refinance loans, together with accrued interest thereon, made pursuant to item (A) of this clause (7);
 
(8) payments of dividends on the Series A Preferred Stock outstanding on March 22, 2007, together with any additional Series A Preferred Stock issued after March 22, 2007 pursuant to warrants issued and outstanding on March 22, 2007, in an amount in any fiscal year not to exceed the dividend rate required under the terms thereof as set forth in the Certificate of Designations with respect to such Series A Preferred Stock on March 22, 2007;


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(9) payments to dissenting stockholders of the Company (A) pursuant to applicable law or (B) in connection with the settlement or other satisfaction of legal claims made pursuant to or in connection with a consolidation, merger or transfer of assets in connection with a transaction that is not prohibited by the indenture; or
 
(10) payments made by any Person other than the Company or any Restricted Subsidiary to the stockholders of the Company in connection with or as part of (A) a merger or consolidation of the Company with or into such Person or a Subsidiary of such Person, or (B) a merger of a Subsidiary of such Person into the Company; and
 
(11) Restricted Payments not exceeding $25,000,000 in the aggregate since March 22, 2007.
 
(c) Not later than the date of making any Restricted Payment (other than any Restricted Payment permitted pursuant to clauses (2) through (11) of paragraph (b) of this covenant), the Company will deliver to the trustee an Officers’ Certificate stating that the Restricted Payment is permitted and setting forth the basis upon which the calculations required by the covenant were calculated.
 
Limitation on Liens.  (a) The Company will not, and will not cause or permit any Restricted Subsidiary to, directly or indirectly, create or incur, in order to secure any Indebtedness, any Lien of any kind, other than Permitted Liens, upon any property or assets (including any intercompany notes) of the Company or any Restricted Subsidiary owned on the date hereof or acquired after the date hereof, or assign or convey, in order to secure any Indebtedness, any right to receive any income or profits therefrom, unless the notes (or a Note Guaranty in the case of Liens of a Guarantor) are directly secured equally and ratably with (or, in the case of Subordinated Indebtedness, prior or senior thereto, with the same relative priority as the notes shall have with respect to such Subordinated Indebtedness) the Indebtedness secured by such Lien.
 
(b) Notwithstanding the foregoing, any Lien securing the notes or a Note Guaranty granted pursuant to clause (a) above shall be automatically and unconditionally released and discharged upon:
 
(1) any sale, exchange or transfer to any Person not an Affiliate of the Company of the property or assets secured by such Lien,
 
(2) any sale, exchange or transfer to any Person not an Affiliate of the Company of all of the Capital Stock held by the Company or any Restricted Subsidiary in, or all or substantially all the assets of, any Restricted Subsidiary creating such Lien, or
 
(3) with respect to any Lien securing a Note Guaranty, the release of such Note Guaranty in accordance with the terms of the indenture.
 
Limitation on Sale and Leaseback Transactions.  The Company will not, and will not permit any of its Restricted Subsidiaries to, enter into any Sale Leaseback Transaction; provided, that the Company or any of its Restricted Subsidiaries may enter into a Sale Leaseback Transaction if:
 
(a) the Company or such Subsidiary could have incurred Indebtedness in an amount equal to the Attributable Indebtedness relating to such Sale Leaseback Transaction pursuant to the Consolidated Fixed Charge Coverage Ratio test set forth in paragraph (a) of the covenant described under “— Limitation on Debt and Disqualified Stock;”
 
(b) the gross cash proceeds of such Sale Leaseback Transaction are at least equal to the Fair Market Value of the property that is the subject of such Sale Leaseback Transaction; and
 
(c) the transfer of assets in such Sale Leaseback Transaction is permitted by, and the Company applies the proceeds of such transaction in the same manner and to the same extent as Net Available Cash and Excess Proceeds from an Asset Sale in compliance with the covenant described under “— Limitation on Asset Sales.”
 
Limitation on Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries.  (a) The Company will not, and will not cause or permit any of its Restricted Subsidiaries to, directly or indirectly,


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create or otherwise cause to come into existence or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:
 
(1) pay dividends or make any other distribution on its Capital Stock to the Company or any other Restricted Subsidiary,
 
(2) pay any Indebtedness owed to the Company or any other Restricted Subsidiary,
 
(3) make loans or advances to the Company or any other Restricted Subsidiary or
 
(4) transfer any of its properties or assets to the Company or any other Restricted Subsidiary.
 
(b) However, clause (a) above will not prohibit any encumbrance or restriction created, existing or becoming effective under or by reason of:
 
(1) any agreement (including the Senior Credit Facility and the Senior Unsecured Credit Agreement) in effect on March 22, 2007;
 
(2) any agreement or instrument with respect to a Restricted Subsidiary that was not a “Restricted Subsidiary” (as defined in the Senior Unsecured Credit Agreement) of the Company on March 22, 2007, in existence at the time such Person becomes (or became) a Restricted Subsidiary of the Company and not incurred in connection with, or in contemplation of, such Person becoming a Restricted Subsidiary, provided that such encumbrances and restrictions are not applicable to the Company or any Restricted Subsidiary or the properties or assets of the Company or any Restricted Subsidiary other than such Subsidiary which is becoming a Restricted Subsidiary;
 
(3) any agreement or instrument governing any Acquired Debt or other agreement of any Person or related to assets acquired by or merged into or consolidated with the Company or any Restricted Subsidiaries, so long as such encumbrance or restriction (A) was not entered into in contemplation of the acquisition, merger or consolidation transaction, and (B) is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets or subsidiaries of the Person, so acquired, so long as the agreement containing such restriction does not violate any other provision of the indenture;
 
(4) any applicable law or any requirement of any regulatory body;
 
(5) the security documents evidencing any Liens securing obligations or Indebtedness that limit the right of the debtor to dispose of the assets subject to such Liens; provided that such Liens are permitted to be incurred under the covenant described under “— Limitation on Liens;”
 
(6) provisions restricting subletting or assignment of any lease governing a leasehold interest of the Company or any Restricted Subsidiary, or restrictions in licenses relating to the property covered thereby, or other encumbrances or restrictions in agreements or instruments relating to specific assets or property that restrict generally the transfers of such assets or property, provided, however, that such encumbrances or restrictions do not materially impact the ability of the Company to make payments on the notes when due as required by the terms of the indenture;
 
(7) asset sale agreements with respect to asset sales permitted to be made under the covenant described under “— Limitation on Asset Sales” that limit the transfer of such assets pending the closing of such sale;
 
(8) shareholders’, partnership, joint venture and similar agreements entered into in the ordinary course of business; provided, however, that such encumbrances or restrictions do not apply to any Restricted Subsidiaries other than the applicable company, partnership, joint venture or other entity; and provided, further, however, that such encumbrances and restrictions do not materially impact the ability of the Company to make payments on the notes when due as required by the terms of the indenture;
 
(9) cash or other deposits, or net worth requirements or similar requirements, imposed by suppliers or landlords under contracts entered into in the ordinary course of business;


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(10) any other Credit Facility governing debt of the Company or any Guarantor, permitted to be incurred by the covenant described under “— Limitation on Indebtedness and Disqualified Stock;” provided, however, that such encumbrances or restrictions are not (in the view of the board of directors of the Company as expressed in a board resolution thereof) materially more restrictive, taken as a whole, than those contained in the Senior Credit Facility;
 
(11) customary restrictions on the disposition or distribution of assets or property in agreements entered into in the ordinary course of the Oil and Gas Business of the types described in the definition of Permitted Business Investments; and
 
(12) the indenture, or any agreement, amendment, modification, restatement, renewal, supplement, refunding, replacement or refinancing that extends, renews, refinances or replaces the agreements containing the encumbrances or restrictions in the foregoing clauses (1) through (11), or in this clause (12); provided that the terms and conditions of any such encumbrances or restrictions are no more restrictive in any material respect taken as a whole than those under or pursuant to the agreement so extended, renewed, refinanced or replaced.
 
Guaranties by Restricted Subsidiaries.  (a) Upon the formation or acquisition of any new direct or indirect Restricted Subsidiary (excluding (i) any Foreign Subsidiary and (ii) any Immaterial Subsidiary) by the Company or any Restricted Subsidiary, then such new Restricted Subsidiary will provide a Note Guaranty within 20 days after its formation or acquisition.
 
(b) A Restricted Subsidiary required to provide a Note Guaranty shall execute a supplemental indenture, and deliver an Opinion of Counsel to the trustee to the effect that such supplemental indenture has been duly authorized, executed and delivered by the Restricted Subsidiary and constitutes a valid and binding obligation of the Restricted Subsidiary, enforceable against the Restricted Subsidiary in accordance with its terms (subject to customary exceptions).
 
Each Note Guaranty will be limited to the maximum amount that would not render the Guarantor’s obligations subject to avoidance under applicable fraudulent conveyance provisions of the United States Bankruptcy Code or any comparable provision of state law. By virtue of this limitation, a Guarantor’s obligation under its Note Guaranty could be significantly less than amounts payable with respect to the notes, or a Guarantor may have effectively no obligation under its Note Guaranty.
 
Repurchase of Notes upon a Change of Control.  (a) Not later than 30 days following a Change of Control, the Company will make an Offer to Purchase all outstanding notes at a purchase price equal to 101% of the principal amount plus accrued interest to the date of purchase.
 
(b) The Company will not be required to make an Offer to Purchase pursuant to paragraph (a) of this covenant if a third party makes an Offer to Purchase in the manner, at the times and otherwise in compliance with the requirements set forth in paragraph (a) of this covenant and the other requirements contained in the indenture (including those described in the following paragraphs) applicable to an Offer to Purchase made by the Company and purchases all notes validly tendered and not withdrawn pursuant to such Offer to Purchase.
 
An “Offer to Purchase” must be made by written offer, which will specify the principal amount of notes subject to the offer and the purchase price. The offer must specify an expiration date (the “expiration date”) not less than 30 days or more than 60 days after the date of the offer and a settlement date for purchase (the “purchase date”) not more than five Business Days after the expiration date. The offer must include information concerning the business of the Company and its Subsidiaries which the Company in good faith believes will enable the holders to make an informed decision with respect to the Offer to Purchase. The offer will also contain instructions and materials necessary to enable holders to tender notes pursuant to the offer.
 
A holder may tender all or any portion of its notes pursuant to an Offer to Purchase, subject to the requirement that any portion of a note tendered must be in a multiple of $1,000 principal amount. Holders are entitled to withdraw notes tendered up to the close of business on the expiration date. On the purchase date the purchase price will become due and payable on each note accepted for purchase pursuant to the Offer to Purchase, and interest on notes purchased will cease to accrue on and after the purchase date.


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The Company will comply with Rule 14e-1 under the Exchange Act and all other applicable laws in making any Offer to Purchase, and the above procedures will be deemed modified as necessary to permit such compliance.
 
The Company has agreed in the indenture that it will timely repay Debt or obtain consents as necessary under, or terminate, agreements or instruments that would otherwise prohibit an Offer to Purchase required to be made pursuant to the indenture. Notwithstanding this agreement of the Company, it is important to note the following:
 
Future debt of the Company may prohibit the Company from purchasing notes in the event of a Change of Control, provide that a Change of Control is a default or require repurchase upon a Change of Control. Moreover, the exercise by the noteholders of their right to require the Company to purchase the notes could cause a default under other debt, even if the Change of Control itself does not, due to the financial effect of the purchase on the Company.
 
Further, the Company’s ability to pay cash to the noteholders following the occurrence of a Change of Control may be limited by the Company’s then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make the required purchase of the notes. See “Risk Factors — Risks Relating to the Notes and the Exchange Offers — We may not be able to purchase the notes upon a change of control.”
 
The phrase “all or substantially all,” as used with respect to the assets of the Company in the definition of “Change of Control,” is subject to interpretation under applicable state law, and its applicability in a given instance would depend upon the facts and circumstances. As a result, there may be a degree of uncertainty in ascertaining whether a sale or transfer of “all or substantially all” the assets of the Company has occurred in a particular instance, in which case a holder’s ability to obtain the benefit of these provisions could be unclear.
 
Except as described above with respect to a Change of Control, the indenture does not contain provisions that permit the holder of the notes to require that the Company purchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.
 
The provisions under the indenture relating to the Company’s obligation to make an offer to repurchase the notes as a result of a Change of Control may be waived or amended as described in “— Amendments and Waivers.”
 
Limitation on Asset Sales.  (a) The Company will not, and will not permit any Restricted Subsidiary to, consummate any Asset Sale unless (i) the Company or such Restricted Subsidiary, as the case may be, receives consideration at the time of such Asset Sale at least equal to the Fair Market Value of the assets and property subject to such Asset Sale and (ii) at least 75% of the aggregate consideration paid to the Company or such Restricted Subsidiary in connection with such Asset Sale and all other Asset Sales since March 22, 2007, on a cumulative basis, is in the form of cash, Cash Equivalents, Liquid Securities, Exchanged Properties (including pursuant to asset swaps), the assumption by the purchaser of liabilities of the Company (other than liabilities of the Company that are by their terms subordinated to the notes) or liabilities of any Guarantor that made such Asset Sale (other than liabilities of a Guarantor that are by their terms subordinated to such Guarantor’s Guarantee), in each case as a result of which the Company and its remaining Restricted Subsidiaries are no longer liable for such liabilities, or, solely in the case of any Asset Sale of Midstream Assets, Permitted MLP Securities.
 
(b) The Net Available Cash from Asset Sales by the Company or a Restricted Subsidiary may be applied by the Company or such Restricted Subsidiary, to the extent the Company or such Restricted Subsidiary elects (or is required by the terms of any Pari Passu Indebtedness of the Company or a Restricted Subsidiary), to
 
(1) repay any Indebtedness of the Company other than Subordinated Indebtedness; or
 
(2) reinvest in Additional Assets (including by means of an Investment in Additional Assets by a Restricted Subsidiary with Net Available Cash received by the Company or another Restricted Subsidiary) or make capital expenditures in the Oil and Gas Business.


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(c) Excess Proceeds of less than $20,000,000 will be carried forward and accumulated. When accumulated Excess Proceeds equals or exceeds $20,000,000, the Company must, within 7 Business Days, make an Offer to Purchase notes having a principal amount equal to
 
(1) accumulated Excess Proceeds, multiplied by
 
(2) a fraction (x) the numerator of which is equal to the outstanding principal amount of the notes and (y) the denominator of which is equal to the outstanding principal amount of the notes and all Pari Passu Indebtedness similarly required to be repaid, redeemed or tendered for in connection with the Asset Sale,
 
rounded down to the nearest $1,000. Any Offer to Purchase notes pursuant to this paragraph (c) shall be made ratably to the holders of the Senior Notes and to the holders of the Senior Floating Rate Notes on the basis of the principal amount of Senior Notes and Senior Floating Rate Notes then outstanding. The purchase price for the notes will be 100% of the principal amount plus accrued interest to the date of purchase. Upon completion of the Offer to Purchase, Excess Proceeds will be reset at zero.
 
Limitation on Transactions with Shareholders and Affiliates.  The Company will not, and will not cause or permit any of its Restricted Subsidiaries to, directly or indirectly, enter into any transaction or series of related transactions (including, without limitation, the sale, purchase, exchange or lease of assets, property or services) with or for the benefit of any Affiliate of the Company (other than the Company or a Restricted Subsidiary) unless such transaction or series of related transactions is entered into in good faith and in writing and
 
(1) such transaction or series of related transactions is on terms that are no less favorable to the Company or such Restricted Subsidiary, as the case may be, than those that would be available in a comparable transaction in arm’s-length dealings with a party who is not an Affiliate of the Company,
 
(2) with respect to any transaction or series of related transactions involving aggregate value in excess of $10,000,000,
 
(A) the Company delivers an Officers’ Certificate to the trustee certifying that such transaction or series of related transactions complies with clause (1) above, and
 
(B) such transaction or series of related transactions has been approved by a majority of the Disinterested Directors of the Board of Directors of the Company, or in the event there is only one Disinterested Director, by such Disinterested Director, or
 
(3) with respect to any transaction or series of related transactions involving aggregate value in excess of $30,000,000, the Company delivers to the trustee a written opinion of an investment banking firm of national standing or other recognized independent expert with experience appraising the terms and conditions of the type of transaction or series of related transactions for which an opinion is required stating that the transaction or series of related transactions is fair to the Company or such Restricted Subsidiary from a financial point of view;
 
provided, however, that this covenant shall not apply to:
 
(1) employee benefit arrangements with any officer or director of the Company, including under any employment agreement, stock option or stock incentive plans, and customary indemnification arrangements with officers or directors of the Company, in each case entered into in the ordinary course of business,
 
(2) the payment of reasonable and customary fees to directors of the Company or any of its Restricted Subsidiaries who are not employees of the Company or any Affiliate,
 
(3) any Restricted Payments or Permitted Payments made in compliance with the covenant described under “— Limitation on Restricted Payments,”
 
(4) sales of Capital Stock (other than Disqualified Stock) of the Company to Affiliates of the Company,


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(5) in the case of contracts for purchase of drilling equipment or sale of oil field service supplies or natural gas or other operational contracts, any such contracts are entered into in the ordinary course of business on terms substantially similar to those contained in similar contracts entered into by the Company or any Restricted Subsidiary and third parties, or if neither the Company nor any Restricted Subsidiary has entered into a similar contract with a third party, that the terms are no less favorable than those available from third parties on an arm’s length basis, as determined by the board of directors of the Company,
 
(6) any customary agreements with stockholders of the Company providing for preemptive, voting, tag-along and similar rights to certain stockholders of the Company, provided that such agreements are approved in advance by a majority of the Disinterested Directors, and
 
(7) any transactions undertaken pursuant to any contracts in existence on March 22, 2007 (as in effect on such date) and any renewals, replacements or modifications of such contracts (pursuant to new transactions or otherwise) on terms no less favorable to the holders of the notes than those in effect on March 22, 2007.
 
Line of Business.  Neither the Company nor any of its Restricted Subsidiaries will directly or indirectly engage in any line or lines of business activity other than that which is an Oil and Gas Business, except to such extent as would not be material to the Company and its Restricted Subsidiaries, taken as a whole.
 
Designation of Restricted and Unrestricted Subsidiaries.  (a) The Board of Directors of the Company may designate after the Issue Date any Subsidiary as an “Unrestricted Subsidiary” (a “Designation”) only if:
 
(1) no Default or Event of Default shall have occurred and be continuing at the time of or after giving effect to such Designation;
 
(2)
 
(A) the Company would be permitted to make an Investment (other than a Permitted Investment) at the time of Designation (assuming the effectiveness of such Designation) pursuant to paragraph (a) of the covenant described under “— Limitation on Restricted Payments” in an amount (the “Designation Amount”) equal to the greater of (1) the net book value of the Company’s interest in such Subsidiary calculated in accordance with GAAP or (2) the Fair Market Value of the Company’s interest in such Subsidiary, or
 
(B) the Designation Amount is less than $1,000;
 
(3) the Company would be permitted to incur $1.00 of additional Indebtedness (other than Permitted Debt) pursuant to the covenant described under “— Limitation on Indebtedness and Disqualified Stock” at the time of such Designation (assuming the effectiveness of such Designation);
 
(4) such Unrestricted Subsidiary does not own any Capital Stock in any Restricted Subsidiary of the Company which is not simultaneously being designated an Unrestricted Subsidiary;
 
(5) such Unrestricted Subsidiary is not liable, directly or indirectly, with respect to any Indebtedness other than Unrestricted Subsidiary Indebtedness, provided that an Unrestricted Subsidiary may provide a Note Guaranty; and
 
(6) such Unrestricted Subsidiary is not a party to any agreement, contract, arrangement or understanding at such time with the Company or any Restricted Subsidiary unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to the Company or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Company or, in the event such condition is not satisfied, the value of such agreement, contract, arrangement or understanding to such Unrestricted Subsidiary shall be deemed a Restricted Payment.
 
In the event of any such Designation, the Company shall be deemed, for all purposes of the indenture, to have made an Investment equal to the Designation Amount that constitutes a Restricted Payment pursuant to the covenant described under “— Limitation on Restricted Payments.”
 
(b) The Company shall not and shall not cause or permit any Restricted Subsidiary to at any time


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(1) provide credit support for, Guarantee or subject any of its property or assets (other than the Capital Stock of any Unrestricted Subsidiary) to the satisfaction of, any Indebtedness of any Unrestricted Subsidiary (including any undertaking, agreement or instrument evidencing such Indebtedness), provided, however, that the provisions of this clause (1) of this paragraph (b) shall not be deemed to prevent Permitted Investments in Unrestricted Subsidiaries that are otherwise allowed under the indenture, or
 
(2) be directly or indirectly liable for any Indebtedness of any Unrestricted Subsidiary.
 
(c) For purposes of the foregoing, the Designation of a Subsidiary of the Company as an Unrestricted Subsidiary shall be deemed to be the Designation of all of the Subsidiaries of such Subsidiary as Unrestricted Subsidiaries. Unless so designated as an Unrestricted Subsidiary, any Person that becomes a Subsidiary of the Company will be classified as a Restricted Subsidiary.
 
(d) The Company may revoke any Designation of a Subsidiary as an Unrestricted Subsidiary (a “Revocation”) if:
 
(1) no Default or Event of Default shall have occurred and be continuing at the time of and after giving effect to such Revocation;
 
(2) all Liens and Indebtedness of such Unrestricted Subsidiary outstanding immediately following such Revocation would, if incurred at such time, have been permitted to be incurred for all purposes of the indenture; and
 
(3) unless such redesignated Subsidiary shall not have any Indebtedness outstanding (other than Indebtedness that would be Permitted Debt), immediately after giving effect to such proposed Revocation, and after giving pro forma effect to the incurrence of any such Indebtedness of such redesignated Subsidiary as if such Indebtedness was incurred on the date of the Revocation, the Company could incur $1.00 of additional Indebtedness (other than Permitted Debt) pursuant to the covenant described under “— Limitation on Indebtedness and Disqualified Stock.”
 
(e) All Designations and Revocations must be evidenced by a resolution of the Board of Directors of the Company delivered to the trustee certifying compliance with the foregoing provisions of this covenant.
 
Financial Reports.  (a) Whether or not the Company is subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, the Company must provide the trustee and holders of notes within the time periods specified in those sections with
 
(1) all quarterly and annual financial information that would be required to be contained in a filing with the SEC on Forms 10-Q and 10-K if the Company were required to file such forms, including a “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and, with respect to annual information only, a report thereon by the Company’s certified independent accountants, and
 
(2) all current reports that would be required to be filed with the SEC on Form 8-K if the Company were required to file such reports.
 
(b) Whether or not required by the SEC, the Company will, if the SEC will accept the filing, file a copy of all of the information and reports referred to in clauses (1) and (2) above with the SEC for public availability within the time periods specified in the SEC’s rules and regulations, and any such information and reports so filed with the SEC shall be deemed to have been provided to holders pursuant to paragraph (a) of this covenant. The Company will make the information and reports referred to in clauses (1) and (2) above available to securities analysts and prospective investors upon request, to the extent such information and reports have not been filed with the SEC.
 
(c) If the Company had any Unrestricted Subsidiaries during the relevant period, the Company will provide to the trustee and the holders of notes information sufficient to ascertain the financial condition and results of operations of the Company and its Restricted Subsidiaries, excluding in all respects the Unrestricted Subsidiaries, to the extent such information has not been filed with the SEC.


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(d) For so long as any of the notes remain outstanding and constitute “restricted securities” under Rule 144, the Company will furnish to the Holders of the notes and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.
 
Reports to Trustee.  (a) The Company will deliver to the trustee within 120 days after the end of each fiscal year a certificate from the principal executive, financial or accounting officer of the Company stating that the officer has conducted or supervised a review of the activities of the Company and its Restricted Subsidiaries and their performance under the indenture and that, based upon such review, the Company has fulfilled its obligations hereunder or, if there has been a Default, specifying the Default and its nature and status.
 
(b) The Company will deliver to the trustee, as soon as possible and in any event within 30 days after the Company becomes aware or should reasonably become aware of the occurrence of a Default, an Officers’ Certificate setting forth the details of the Default, and the action which the Company proposes to take with respect thereto.
 
Consolidation, Merger or Sale of Assets
 
The indenture further provides as follows regarding consolidation, merger or sale of all or substantially all of the assets of the Company or a Guarantor:
 
Consolidation, Merger or Sale of Assets by the Company.  (a) The Company will not, in a single transaction or through a series of related transactions, consolidate with or merge with or into any other Person or sell, assign, convey, transfer, lease or otherwise dispose of all or substantially all of its properties and assets to any Person or group of Persons, or permit any of its Restricted Subsidiaries to enter into any such transaction or series of transactions, if such transaction or series of transactions, in the aggregate, would result in a sale, assignment, conveyance, transfer, lease or disposition of all or substantially all of the properties and assets of the Company and its Restricted Subsidiaries on a Consolidated basis to any other Person or group of Persons (other than the Company or a Guarantor), unless at the time and after giving effect thereto:
 
(1) either (A) the Company will be the continuing corporation or (B) the Person (if other than the Company) formed by such consolidation or into which the Company is merged or the Person which acquires by sale, assignment, conveyance, transfer, lease or disposition all or substantially all of the properties and assets of the Company and its Restricted Subsidiaries on a Consolidated basis (the “Surviving Entity”) will be a corporation, limited liability company or limited partnership (provided that in the event the Surviving Entity is a limited partnership, then a Subsidiary of the Surviving Entity that is a corporation or limited liability company shall execute a supplement to the indenture pursuant to which it shall become a co-obligor of the Surviving Entity’s obligations under the indenture and the notes) duly organized and validly existing under the laws of the United States of America, any state thereof or the District of Columbia and the Surviving Entity expressly assumes, by executing a supplement to the indenture, all the obligations of the Company under the indenture and the notes and any Registration Rights Agreement then in effect;
 
(2) immediately after giving effect to such transaction on a pro forma basis (and treating any Indebtedness not previously an obligation of the Company or any of its Restricted Subsidiaries which becomes the obligation of the Company or any of its Restricted Subsidiaries as a result of such transaction as having been incurred at the time of such transaction), no Default or Event of Default will have occurred and be continuing;
 
(3) immediately after giving effect to such transaction on a pro forma basis (on the assumption that the transaction occurred on the first day of the four-quarter period for which financial statements are available ending immediately prior to the consummation of such transaction with the appropriate adjustments with respect to the transaction being included in such pro forma calculation), the Company (or the Surviving Entity if the Company is not the continuing obligor under the indenture) (A) could incur $1.00 of additional Indebtedness (other than Permitted Debt) under the covenant


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described under “— Limitation on Indebtedness and Disqualified Stock” or (B) would have a Consolidated Fixed Charge Coverage Ratio not less than the Consolidated Fixed Charge Coverage Ratio of the Company immediately prior to such transaction;
 
(4) unless the Company is the continuing obligor under the indenture, at the time of the transaction, each Guarantor, if any, unless it is the other party to the transactions described above, will have confirmed, by executing a supplement to the indenture, that its Note Guaranty shall apply to the Surviving Entity’s obligations under the indenture and the notes and any Registration Rights Agreement then in effect;
 
(5) at the time of the transaction, if any of the property or assets of the Company or any of its Restricted Subsidiaries would thereupon become subject to any Lien, the provisions of the covenant described under “— Limitation on Liens” are complied with; and
 
(6) at the time of the transaction, the Company or the Surviving Entity will have delivered, or caused to be delivered, to the trustee, an Officers’ Certificate and an Opinion of Counsel, each to the effect that such consolidation, merger, transfer, sale, assignment, conveyance, transfer, lease or other transaction and any supplement to the indenture executed and delivered in connection therewith comply with the terms of the indenture.
 
(b) In the event of any transaction (other than a lease) described in and complying with the conditions listed in paragraph (a) of this covenant in which the Company is not the Surviving Entity, the Surviving Entity shall succeed to, and be substituted for, and may exercise every right and power of, the Company under the indenture and the notes, and the Company shall be discharged from all obligations and covenants under the indenture and the notes.
 
(c) Notwithstanding the foregoing, the Company may merge with an Affiliate incorporated or organized solely for the purpose of reincorporating or reorganizing the Company in another jurisdiction to realize tax or other benefits.
 
Consolidation, Merger or Sale of Assets by a Guarantor.  (a) Each Guarantor will not, and the Company will not permit a Guarantor to, in a single transaction or through a series of related transactions, (x) consolidate with or merge with or into any other Person (other than the Company or any other Guarantor) or (y) sell, assign, convey, transfer, lease or otherwise dispose of all or substantially all of its properties and assets to any Person or group of Persons (other than the Company or any other Guarantor) or permit any of its Restricted Subsidiaries to enter into any such transaction or series of transactions if such transaction or series of transactions, in the aggregate, in the case of clause (y) would result in a sale, assignment, conveyance, transfer, lease or disposition of all or substantially all of the properties and assets of the Guarantor and its Restricted Subsidiaries on a Consolidated basis to any other Person or group of Persons (other than the Company or any Guarantor), unless at the time and after giving effect thereto:
 
(1) either (A) the Guarantor or the Company will be the continuing Person in the case of a merger involving the Guarantor or (B) the Person (if other than the Guarantor) formed by such consolidation or into which the Guarantor is merged or the Person which acquires by sale, assignment, conveyance, transfer, lease or disposition all or substantially all of the properties and assets of the Guarantor and its Restricted Subsidiaries on a Consolidated basis (the “Surviving Guarantor Entity”) expressly assumes, by executing a supplement to the indenture, all the obligations of such Guarantor under its Note Guaranty;
 
(2) immediately before and immediately after giving effect to such transaction on a pro forma basis, no Default or Event of Default will have occurred and be continuing; and
 
(3) at the time of the transaction such Guarantor or the Surviving Guarantor Entity will have delivered, or caused to be delivered, to the trustee, an Officers’ Certificate and an Opinion of Counsel, each to the effect that such consolidation, merger, transfer, sale, assignment, conveyance, lease or other transaction and any supplement to the indenture executed and delivered in connection therewith comply with the indenture;


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provided, however, that paragraph (a) of this covenant shall not apply to any Guarantor whose Note Guaranty is unconditionally released and discharged in accordance with the indenture.
 
(b) In the event of any transaction (other than a lease) described in and complying with the conditions listed in paragraph (a) of this covenant in which the Guarantor is not the Surviving Guarantor Entity, the Surviving Guarantor Entity shall succeed to, and be substituted for, and may exercise every right and power of, such Guarantor under the indenture, and such Guarantor shall be discharged from all obligations and covenants under the indenture and the Note Guaranty.
 
(c) Notwithstanding the foregoing, any Guarantor may merge with an Affiliate incorporated or organized solely for the purpose of reincorporating or reorganizing such Guarantor in another jurisdiction to realize tax or other benefits.
 
Default and Remedies
 
Events of Default.  An “Event of Default” occurs if
 
(1) the Company defaults in the payment of the principal of any note when the same becomes due and payable at Stated Maturity, upon acceleration or redemption, or otherwise (other than pursuant to an Offer to Purchase);
 
(2) the Company defaults in the payment of interest (including any Additional Interest) on any note when the same becomes due and payable, and the default continues for a period of 30 days;
 
(3) the Company fails to make an Offer to Purchase and thereafter accept and pay for notes tendered when and as required pursuant to the covenants described under “— Certain Covenants — Repurchase of Notes Upon a Change of Control” or “— Certain Covenants — Limitation on Asset Sales,” or the Company or any Guarantor fails to comply with “— Consolidation, Merger or Sale of Assets;”
 
(4) the Company defaults in the performance of or breaches any other covenant or agreement of the Company in the indenture or under the notes and the default or breach continues for a period of 60 consecutive days after written notice to the Company by the trustee or to the Company and the trustee by the holders of 25% or more in aggregate principal amount of the notes;
 
(5) there occurs with respect to any Indebtedness of the Company, any Guarantor or any other Significant Subsidiary having an outstanding principal amount of $30,000,000 or more in the aggregate for all such Indebtedness of all such Persons (i) an event of default that results in such Indebtedness (including any scheduled installment of principal with respect to such Indebtedness) being due and payable prior to its Stated Maturity or (ii) failure to make a principal, premium (if any) or interest payment when due and such defaulted payment is not made, waived or extended within the applicable grace period, the result of which is to give the holder of such Indebtedness the right to accelerate such Indebtedness;
 
(6) one or more judgments, orders or decrees of any court or regulatory or administrative agency for the payment of money in excess of $30,000,000 (determined net of any amounts covered by insurance policies by insurers believed by the Company in good faith to be credit-worthy), either individually or in the aggregate, shall be rendered against the Company, any Guarantor or any other Significant Subsidiary or any of their respective properties and shall not be discharged and either (i) any creditor shall have commenced an enforcement proceeding upon such judgment, order or decree or (ii) there shall have been a period of 60 consecutive days during which a stay of enforcement of such judgment or order, by reason of an appeal or otherwise, shall not be in effect;
 
(7) the Company or any Restricted Subsidiary institutes or consents to the institution of any proceeding under any Debtor Relief Law, or makes an assignment for the benefit of creditors; or applies for or consents to the appointment of any receiver, trustee, custodian, conservator, liquidator, rehabilitator or similar officer for it or for all or any material part of its property; or any receiver, trustee, custodian, conservator, liquidator, rehabilitator or similar officer is appointed without the application or consent of


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such Person and the appointment continues undischarged or unstayed for 60 calendar days; or any proceeding under any Debtor Relief Law relating to any such Person or to all or any material part of its property is instituted without the consent of such Person and continues undismissed or unstayed for 60 calendar days, or an order for relief is entered in any such proceeding;
 
(8) the Company or any Restricted Subsidiary becomes unable or admits in writing its inability or fails generally to pay its debts as they become due, or any writ or warrant of attachment or execution or similar process is issued or levied against all or any material part of the property of any such Person and is not released, vacated or fully bonded within 30 days after its issue or levy; or
 
(9) any Note Guaranty ceases to be in full force and effect, other than in accordance the terms of the indenture, or a Guarantor denies or disaffirms its obligations under its Note Guaranty.
 
Consequences of an Event of Default.  (a) If an Event of Default occurs and is continuing under the indenture, the trustee or the holders of at least 25% in aggregate principal amount of the notes then outstanding, by written notice to the Company (and to the trustee if the notice is given by such holders), may, and the trustee at the request of such holders shall, declare the principal of and accrued interest on the notes to be immediately due and payable. Upon a declaration of acceleration, such principal and interest will become immediately due and payable;
 
provided, however, that upon the occurrence of an actual or deemed entry of an order for relief with respect to the Company under the Bankruptcy Code of the United States, the principal of and accrued interest on the notes then outstanding will become immediately due and payable without any declaration or other act on the part of the trustee or any holder of notes.
 
(b) The holders of a majority in aggregate principal amount of the outstanding notes by written notice to the Company and to the trustee may waive all past defaults and rescind and annul a declaration of acceleration and its consequences if
 
(1) all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the notes that have become due solely by the declaration of acceleration, have been cured or waived, and
 
(2) the rescission would not conflict with any judgment or decree of a court of competent jurisdiction.
 
Except as otherwise provided in “— Consequences of an Event of Default” or “— Amendments and Waivers — Amendments with Consent of Holders,” the holders of a majority in aggregate principal amount of the outstanding notes may, by notice to the trustee, waive an existing Default and its consequences. Upon such waiver, the Default will cease to exist, and any Event of Default arising therefrom will be deemed to have been cured, but no such waiver will extend to any subsequent or other Default or impair any right consequent thereon.
 
The holders of a majority in aggregate principal amount of the outstanding notes may direct the time, method and place of conducting any proceeding for any remedy available to the trustee or exercising any trust or power conferred on the trustee. However, the trustee may refuse to follow any direction that conflicts with law or the indenture, that may involve the trustee in personal liability, or that the trustee determines in good faith may be unduly prejudicial to the rights of holders of notes not joining in the giving of such direction, and may take any other action it deems proper that is not inconsistent with any such direction received from holders of notes.
 
A holder may not institute any proceeding, judicial or otherwise, with respect to the indenture or the notes, or for the appointment of a receiver or trustee, or for any other remedy under the indenture or the notes, unless:
 
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(2) holders of at least 25% in aggregate principal amount of outstanding notes have made written request to the trustee to institute proceedings in respect of the Event of Default in its own name as trustee under the indenture;
 
(3) holders have offered to the trustee security or indemnity reasonably satisfactory to the trustee against any costs, liabilities or expenses to be incurred in compliance with such request;
 
(4) the trustee for 60 days after its receipt of such notice, request and offer of security or indemnity has failed to institute any such proceeding; and
 
(5) during such 60-day period, the holders of a majority in aggregate principal amount of the outstanding notes have not given the trustee a direction that is inconsistent with such written request.
 
Notwithstanding anything to the contrary, the right of a holder of a note to receive payment of principal of or interest on its note on or after the Stated Maturities thereof, or to bring suit for the enforcement of any such payment on or after such dates, may not be impaired or affected without the consent of that holder.
 
If any Default occurs and is continuing and is known to the trustee, the trustee will send notice of the Default to each holder within 90 days after it occurs, unless the Default has been cured; provided that, except in the case of a default in the payment of the principal of or interest on any note, the trustee may withhold the notice if and so long as the board of directors, the executive committee or a trust committee of directors of the trustee in good faith determine that withholding the notice is in the interest of the holders.
 
No Liability of Directors, Officers, Employees, Incorporators, Members, Partners and Stockholders
 
No director, officer, employee, incorporator, member, partner or stockholder of the Company or any Guarantor, as such, will have any liability for any obligations of the Company or such Guarantor under the notes, any Note Guaranty or the indenture or for any claim based on, in respect of, or by reason of, such obligations. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. This waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.
 
Amendments and Waivers
 
Amendments Without Consent of Holder.  The Company, the Guarantors and the trustee may amend or supplement the indenture or the notes without notice to or the consent of any noteholder
 
(1) to cure any ambiguity, defect or inconsistency in the indenture or the notes;
 
(2) to comply with the covenants described in “— Certain Covenants — Consolidation, Merger or Sale of Assets;”
 
(3) to comply with any requirements of the SEC in connection with the qualification of the indenture under the Trust Indenture Act;
 
(4) to evidence and provide for the acceptance of an appointment by a successor trustee;
 
(5) to provide for uncertificated notes in addition to or in place of certificated notes, provided that the uncertificated notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated notes are described in Section 163(f)(2)(B) of the Code;
 
(6) to provide for any Guarantee of the notes, to secure the notes or to confirm and evidence the release, termination or discharge of any Guarantee of or Lien securing the notes when such release, termination or discharge is permitted by the indenture;
 
(7) to provide for or confirm the issuance of additional notes;


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(8) to conform the text of the indenture or the notes to any provision set forth in the “Description of Notes” section of this exchange offer memorandum to the extent that such provision in such “Description of Notes” section was intended to be a verbatim recitation of a provision of the indenture or the notes;
 
(9) to make any other change that does not materially and adversely affect the rights of any holder.
 
Amendments With Consent of Holders.  (a) Except as otherwise provided in “— Default and Remedies — Consequences of a Default” or paragraph (b), the Company, the Guarantors and the trustee may amend, modify or supplement the indenture and the notes with the consent of the holders of a majority in aggregate principal amount of the outstanding notes and the holders of a majority in aggregate principal amount of the outstanding notes may waive future compliance by the Company with any provision of the indenture or the notes; provided that if any amendment, modification, supplement or waiver would only affect the Senior Notes or the Senior Floating Rate Notes, only the consent of the holders of a majority in aggregate principal amount of the outstanding Senior Notes or Senior Floating Rate Notes (and not the consent of at least a majority in aggregate principal amount of all of the then outstanding notes), as the case may be, shall be required.
 
(b) Notwithstanding the provisions of paragraph (a), without the consent of each holder affected, an amendment, modification, supplement or waiver may not
 
(1) reduce the principal amount of or change the Stated Maturity of any installment of principal of any note,
 
(2) reduce the rate of or change the Stated Maturity of any interest payment on any note,
 
(3) reduce the amount payable upon the optional redemption of any note or change the times at which any note may be redeemed or, once notice of redemption has been given, the time at which it must thereupon be redeemed,
 
(4) after the time an Offer to Purchase is required to have been made, reduce the purchase amount or purchase price, or extend the latest expiration date or purchase date thereunder,
 
(5) make any note payable in money other than that stated in the note,
 
(6) impair the right of any holder of notes to receive any principal payment or interest payment on such holder’s notes, on or after the Stated Maturity thereof, or to institute suit for the enforcement of any such payment,
 
(7) make any change in the percentage of the principal amount of the notes required for amendments or waivers,
 
(8) modify or change any provision of the indenture affecting the ranking of the notes or any Note Guaranty in a manner adverse to the holders of the notes or
 
(9) make any change in any Note Guaranty that would adversely affect the noteholders
 
It is not necessary for noteholders to approve the particular form of any proposed amendment, modification, supplement or waiver, but is sufficient if their consent approves the substance thereof.
 
Neither the Company nor any of its Restricted Subsidiaries may, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fee or otherwise, to any holder for or as an inducement to any consent, waiver, amendment or modification of any of the terms or provisions of the indenture or the notes unless such consideration is offered to be paid or agreed to be paid to all holders of the notes that consent, waive or agree to amend or modify such term or provision within the time period set forth in the solicitation documents relating to the consent, waiver, amendment or modification.


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Defeasance and Discharge
 
The Company may discharge its obligations under the notes and the indenture by irrevocably depositing in trust with the trustee money or U.S. Government Obligations sufficient to pay principal of and interest on the notes to maturity or redemption within sixty days, subject to meeting certain other conditions.
 
The Company may also elect to
 
(1) discharge most of its obligations in respect of the notes and the indenture, not including obligations related to the defeasance trust or to the replacement of notes or its obligations to the trustee (“legal defeasance”) or
 
(2) discharge its obligations under most of the covenants and under clauses (3) and (5) of paragraph (a) of “— Consolidation, Merger or Sale of Assets — Consolidation, Merger or Sale of Assets by the Company” (and the events listed in clauses (3), (4), (5), (6) and (9) under “— Default and Remedies — Events of Default” will no longer constitute Events of Default) (“covenant defeasance”)
 
by irrevocably depositing in trust with the trustee money or U.S. Government Obligations sufficient to pay principal of and interest on the notes to final Stated Maturity or redemption and by meeting certain other conditions, including delivery to the trustee of either a ruling received from the Internal Revenue Service or an Opinion of Counsel to the effect that the holders will not recognize income, gain or loss for federal income tax purposes as a result of the defeasance and will be subject to federal income tax on the same amount and in the same manner and at the same times as would otherwise have been the case. The defeasance would in each case be effective when 91 days have passed since the date of the deposit in trust.
 
In the case of either discharge or defeasance, the Note Guaranties, if any, will terminate.
 
Concerning the Trustee
 
Wells Fargo Bank, National Association is the trustee under the indenture and a lender under the Company’s revolving credit facility.
 
Except during the continuance of an Event of Default, the trustee need perform only those duties that are specifically set forth in the indenture and no others, and no implied covenants or obligations will be read into the indenture against the trustee. In case an Event of Default has occurred and is continuing, the trustee shall exercise those rights and powers vested in it by the indenture, and use the same degree of care and skill in their exercise, as a prudent man would exercise or use under the circumstances in the conduct of his own affairs. No provision of the indenture requires the trustee to expend or risk its own funds or otherwise incur any financial liability in the performance of its duties thereunder, or in the exercise of its rights or powers, unless it is offered reasonable security or indemnity against any loss, liability or expense.
 
The indenture and provisions of the Trust Indenture Act incorporated by reference therein contain limitations on the rights of the trustee, should it become a creditor of any obligor on the notes, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee is permitted to engage in other transactions with the Company and its Affiliates; provided that if it acquires any conflicting interest it must either eliminate the conflict within 90 days, apply to the Commission for permission to continue or resign.
 
Form, Denomination and Registration of Notes
 
The notes will be issued in registered form, without interest coupons, in denominations of $1,000 and integral multiples thereof, in the form of both global notes and certificated notes, as further provided below.
 
The trustee is not required (i) to issue, register the transfer of or exchange any note for a period of 15 days before a selection of notes to be redeemed or purchased pursuant to an Offer to Purchase, (ii) to register the transfer of or exchange any note so selected for redemption or purchase in whole or in part, except, in the case of a partial redemption or purchase, that portion of any note not being redeemed or purchased, or (iii) if a redemption or a purchase pursuant to an Offer to Purchase is to occur after a regular record date but on or


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before the corresponding interest payment date, to register the transfer or exchange of any note on or after the regular record date and before the date of redemption or purchase.
 
No service charge will be imposed in connection with any transfer or exchange of any note, but the Company may in general require payment of a sum sufficient to cover any transfer tax or similar governmental charge payable in connection therewith.
 
Global Notes
 
One or more global notes representing each series of the exchange notes will be deposited with a custodian for DTC, and registered in the name of a nominee of DTC. Beneficial interests in the global notes will be shown on records maintained by DTC and its direct and indirect participants. So long as DTC or its nominee is the registered owner or holder of a global note, DTC or such nominee will be considered the sole owner or holder of the notes represented by such global note for all purposes under the indenture and the notes. No owner of a beneficial interest in a global note will be able to transfer such interest except in accordance with DTC’s applicable procedures and the applicable procedures of its direct and indirect participants. Investors may hold their beneficial interests in the global notes directly through DTC if they are participants in DTC, or indirectly through organizations that are participants in DTC.
 
Payments of principal and interest under each global note will be made to DTC’s nominee as the registered owner of such global note. The Company expects that the nominee, upon receipt of any such payment, will immediately credit DTC participants’ accounts with payments proportional to their respective beneficial interests in the principal amount of the relevant global note as shown on the records of DTC. The Company also expects that payments by DTC participants to owners of beneficial interests will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers registered in the names of nominees for such customers. Such payments will be the responsibility of such participants, and none of the Company, the trustee, the custodian or any paying agent or registrar will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial interests in any global note or for maintaining or reviewing any records relating to such beneficial interests.
 
Certificated Notes
 
If DTC notifies the Company that it is unwilling or unable to continue as depositary for a global note and a successor depositary is not appointed by the Company within 90 days of such notice, or an Event of Default has occurred and the trustee has received a request from DTC, the trustee will exchange each beneficial interest in that global note for one or more certificated notes registered in the name of the owner of such beneficial interest, as identified by DTC.
 
Same Day Settlement and Payment
 
The indenture requires that payments in respect of the notes represented by the global notes be made by wire transfer of immediately available funds to the accounts specified by holders of the global notes. With respect to notes in certificated form, the Company will make all payments by wire transfer of immediately available funds to the accounts specified by the holders thereof or, if no such account is specified, by mailing a check to each holder’s registered address.
 
The notes represented by the global notes are expected to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity in such notes will, therefore, be required by DTC to be settled in immediately available funds. The Company expects that secondary trading in any certificated notes will also be settled in immediately available funds.
 
Governing Law
 
The indenture, including the Note Guaranties, and the notes will be governed by, and construed in accordance with, the laws of the State of New York.


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Certain Definitions
 
“Acquired Debt” means Indebtedness of a Person (1) existing at the time such Person becomes a Restricted Subsidiary or (2) assumed in connection with the acquisition of assets from such Person, in each case, other than Indebtedness incurred in connection with, or in contemplation of, such Person becoming a Restricted Subsidiary or such acquisition, as the case may be. Acquired Debt shall be deemed to be incurred on the date of the related acquisition of assets from any Person or the date the acquired Person becomes a Restricted Subsidiary, as the case may be.
 
“Additional Assets” means (i) any assets or property (other than cash, Cash Equivalents or securities) used in the Oil and Gas Business or any business ancillary thereto, (ii) Investments in any other Person engaged in the Oil and Gas Business or any business ancillary thereto (including the acquisition from third parties of Capital Stock of such Person) as a result of which such other Person becomes a Restricted Subsidiary, (iii) the acquisition from third parties of Capital Stock of a Restricted Subsidiary or (iv) Permitted Business Investments.
 
“Additional Interest” means additional interest owed to the Holders pursuant to a Registration Rights Agreement.
 
“Additional Notes” means the Additional Senior Floating Rate Notes and the Additional Senior Notes.
 
“Additional Senior Floating Rate Notes” means any Senior Floating Rate Notes issued under the indenture in addition to the Original Senior Floating Rate Notes, including any Exchange Notes issued in exchange for such Additional Senior Floating Rate Notes, having the same terms in all respects as the Original Senior Floating Rate Notes except that interest will accrue on the Additional Senior Floating Rate Notes from their date of issuance.
 
“Additional Senior Notes” means any Senior Notes issued under the indenture in addition to the Original Senior Notes, including any Exchange Notes issued in exchange for such Additional Senior Notes, having the same terms in all respects as the Original Senior Notes except that interest will accrue on the Additional Senior Notes from their date of issuance.
 
“Adjusted Consolidated Net Tangible Assets” means (without duplication), as of the date of determination, the remainder of:
 
(i) the sum of
 
(a) discounted future net revenues from proved oil and gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state, federal or foreign income taxes, as estimated in a reserve report prepared as of the end of the Company’s most recently completed fiscal year, which reserve report is prepared or reviewed by independent petroleum engineers as to reserves accounting for at least 80% of all such discounted future net revenues and by the Company’s petroleum engineers with respect to any other reserves covered by such report, as increased by, as of the date of determination, the estimated discounted future net revenues from (1) estimated proved oil and gas reserves acquired since such year-end, which reserves were not reflected in such year-end reserve report, and (2) estimated increases in proved oil and gas reserves since such year-end due to exploration, development or exploitation activities or due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report), and decreased by, as of the date of determination, the estimated discounted future net revenues from (3) estimated proved oil and gas reserves reflected in such year-end report produced or disposed of since such year-end and (4) estimated oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since such year-end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report); provided that, in the case of each of the determinations made pursuant to clauses (1) through (4), such increases and decreases shall be as estimated by the Company’s petroleum engineers, unless there is


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a Material Change as a result of such acquisitions, dispositions or revisions, in which event the discounted future net revenues utilized for purposes of this clause (i)(a) shall be confirmed in writing an independent petroleum engineer, plus
 
(b) the capitalized costs that are attributable to oil and gas properties of the Company and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on the Company’s books and records as of a date no earlier than the date of the Company’s latest annual or quarterly financial statements, plus
 
(c) the Net Working Capital on a date no earlier than the date of the Company’s latest annual or quarterly financial statements, plus
 
(d) the greater of (1) the net book value on a date no earlier than the date of the Company’s latest annual or quarterly financial statements and (2) the appraised value, as estimated by independent appraisers, of other tangible assets (including, without duplication, Investments in unconsolidated Restricted Subsidiaries) of the Company and its Restricted Subsidiaries, as of the date no earlier than the date of the Company’s latest audited financial statements (provided that the Company shall not be required to obtain such appraisal of such assets if no such appraisal has been performed),
 
minus (ii) the sum of
 
(a) minority interests, plus
 
(b) any net gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company’s latest audited Consolidated financial statements, plus
 
(c) to the extent included in (i)(a) above, the discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in the Company’s year-end reserve report), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto) plus
 
(d) the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (i)(a) above, would be necessary to fully satisfy the payment obligations of the Company and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).
 
If the Company changes its method of accounting from the full cost method to the successful efforts method or a similar method of accounting, “Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if the Company were still using the full cost method of accounting.
 
“Affiliate” means, with respect to any specified Person: (1) any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person; (2) any other Person that owns, directly or indirectly, 10% or more of the Voting Stock of such specified Person (or any of such specified Person’s direct or indirect parent’s Voting Stock); or (3) any other Person 10% or more of the Voting Stock of which is beneficially owned or held directly or indirectly by such specified Person. For the purposes of this definition, “control” when used with respect to any specified Person means the power to direct the management and policies of such Person, directly or indirectly, whether through ownership of voting securities, by contract or otherwise; and the terms “controlling” and “controlled” have meanings correlative to the foregoing.


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“Asset Sale” means any sale, issuance, conveyance, transfer, lease or other disposition (including, without limitation, by way of merger or consolidation, Production Payments and Reserve Sales or a Sale Leaseback Transaction) (collectively, a “transfer”), directly or indirectly, in one or a series of related transactions, of:
 
(1) any Capital Stock of any Restricted Subsidiary;
 
(2) all or substantially all of the properties and assets of any division or line of business of the Company or any Restricted Subsidiary; or
 
(3) any other properties, assets or rights of the Company or any Restricted Subsidiary other than in the ordinary course of business.
 
For the purposes of this definition, the term “Asset Sale” shall not include:
 
(A) any transfer of properties and assets (including any Capital Stock of a Restricted Subsidiary) that is governed by “— Consolidation, Merger or Sale of Assets,”
 
(B) any transfer of properties and assets that is by the Company to any Restricted Subsidiary, or by any Restricted Subsidiary to the Company or any other Restricted Subsidiary in accordance with the terms of the indenture,
 
(C) any transfer of properties and assets that would be within the definition of a “Permitted Investment” or a “Restricted Payment” and, in the latter case, would be permitted to be made as a Restricted Payment (and shall be deemed a Restricted Payment) under the covenant described in “— Certain Covenants — Limitation on Restricted Payments,”
 
(D) the transfer of Cash Equivalents, inventory, accounts receivable, surplus or obsolete equipment or other property (excluding the disposition of oil and gas in place and other interests in real property unless made in connection with a Permitted Business Investment),
 
(E) the abandonment, assignment (including any assignments made pursuant to the Well Participation Program), lease, sublease or farm-out of oil and gas properties, or the forfeiture or other disposition of such properties, pursuant to operating agreements or other instruments or agreements that, in each case, are entered into in the ordinary course of business in a manner that is customary in the Oil and Gas Business,
 
(F) the transfer of Property received in settlement of debts owing to such Person as a result of foreclosure, perfection or enforcement of any Lien or debt, which debts were owing to such Person in the ordinary course of its business,
 
(G) any Production Payments and Reserve Sales, provided that any such Production Payments and Reserve Sales (other than incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to the Company or a Restricted Subsidiary), shall have been created, incurred, issued, assumed or guaranteed in connection with the acquisition or financing of, and within 90 days after the acquisition of, the Property that is subject thereto,
 
(H) the licensing or sublicensing of intellectual property or other general intangibles to the extent that such license does not prohibit the licensor from using the intellectual property and licenses, leases or subleases of other property,
 
(I) the creation or incurrence of any Lien,
 
(J) the surrender or waiver of contract rights or the settlement, release or surrender of contract, tort or other claims of any kind,
 
(K) the sale or other disposition (whether or not in the ordinary course of business) of oil and gas properties, provided at the time of such sale or other disposition such properties do not have associated with them any proved reserves or


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(L) any transfer of assets the Fair Market Value of which in the aggregate does not exceed $5,000,000 in any transaction or series of related transactions.
 
“Attributable Indebtedness” in respect of a Sale Leaseback Transaction means, at the time of determination, the present value (discounted at the rate of interest implicit in such transaction, determined in accordance with GAAP) of the obligation of the lessee for net rental payments during the remaining term of the lease included in such Sale Leaseback Transaction (including any period for which such lease has been extended or may, at the option of the lessor, be extended).
 
“Board of Directors” means the board of directors or comparable governing body of the Company, or any committee thereof duly authorized to act on its behalf.
 
“Business Day” means any day other than a Saturday, Sunday or other day on which commercial banks are authorized by law to close, or are in fact closed, in New York City or in the city where the Corporate Trust Office of the trustee is located and, if such day relates to any determination of LIBOR or date for payment with respect to any Senior Floating Rate Note, means any such day on which dealings in Dollar deposits are conducted by and between banks in the London interbank eurodollar market.
 
“Capital Lease Obligation” of any Person means any obligation of such Person and its Restricted Subsidiaries on a Consolidated basis under any capital lease of (or other agreement conveying the right to use) real or personal property which, in accordance with GAAP, is required to be recorded as a capitalized lease obligation.
 
“Capital Stock” of any Person means any and all shares, units, interests, participations, rights in or other equivalents (however designated) of such Person’s capital stock, other equity interests whether now outstanding or issued after the date hereof, partnership interests (whether general or limited), limited liability company interests, any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person, including any Preferred Stock, and any rights (other than debt securities convertible into Capital Stock), warrants or options exchangeable for or convertible into such Capital Stock.
 
“Cash Equivalents” means
 
(1) any evidence of Indebtedness issued or directly and fully guaranteed or insured by the United States or any agency or instrumentality thereof,
 
(2) deposits, time deposit accounts, certificates of deposit, money market deposits or acceptances of any financial institution having capital and surplus in excess of $500,000,000 that is a member of the Federal Reserve System and whose senior unsecured debt is rated at least “A-1” by S&P or at least “P-1” by Moody’s,
 
(3) commercial paper with a maturity of 365 days or less issued by a corporation (other than an Affiliate or Subsidiary of the Company) organized and existing under the laws of the United States of America, any state thereof or the District of Columbia and rated at least “A-1” by S&P and at least “P-1” by Moody’s,
 
(4) repurchase agreements and reverse repurchase agreements relating to Indebtedness of a type described in clause (1) above that are entered into with a financial institution described in clause (2) above and mature within 365 days from the date of acquisition,
 
(5) deposits and certificates of deposit with any commercial bank not meeting the qualifications specified in clause (2) above, provided all such deposits do not exceed $1,000,000 in the aggregate at any one time and
 
(6) money market funds which invest substantially all of their assets in securities described in the preceding clauses (1) through (4).
 
“Change of Control” means the occurrence of any of the following events:
 
(1) any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act) other than the Ward Group is or becomes the “beneficial owner” (as defined in Rules 13d-3 and


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13d-5 under the Exchange Act, except that a Person shall be deemed to have beneficial ownership of all shares that such Person has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of more than 50% of the total outstanding Voting Stock of the Company (measured by voting power rather than the number of shares);
 
(2) during any period of two consecutive years, individuals who at the beginning of such period constituted the board of directors of the Company (together with any new directors whose election to such board or whose nomination for election by the stockholders of the Company was approved by a vote of 662/3% of the directors then still in office who were either directors at the beginning of such period or whose election or nomination for election was previously so approved), cease for any reason to constitute a majority of such board of directors then in office;
 
(3) the Company consolidates with or merges with or into any Person, or sells, assigns, conveys, transfers, leases or otherwise disposes of all or substantially all of its assets to any such Person, or any such Person consolidates with or merges into or with the Company, in any such event pursuant to a transaction in which the outstanding Voting Stock of the Company is converted into or exchanged for cash, securities or other property, other than any such transaction where
 
(A) the outstanding Voting Stock of the Company is changed into or exchanged for Voting Stock of the surviving Person which is not Disqualified Stock and
 
(B) immediately after such transaction, no “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act) is the beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that a person shall be deemed to have beneficial ownership of all securities that such person has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of more than 50% of the total outstanding Voting Stock (measured by voting power rather than the number of shares) of the surviving Person; or
 
(4) the Company is liquidated or dissolved or adopts a plan of liquidation or dissolution other than in a transaction which complies with the provisions of “— Consolidation, Merger or Sale of Assets.”
 
For purposes of this definition, any transfer of an equity interest of an entity that was formed for the purpose of acquiring Voting Stock of the Company will be deemed to be a transfer of such portion of such Voting Stock as corresponds to the portion of the equity of such entity that has been so transferred.
 
“Code” means the Internal Revenue Code of 1986.
 
“Consolidated Fixed Charge Coverage Ratio” of any Person means, for any period, the ratio of
 
(a) without duplication, the sum of Consolidated Net Income, and in each case to the extent deducted in computing such Consolidated Net Income for such period, Consolidated Interest Expense, Consolidated Income Tax Expense and Consolidated Non-cash Charges for such period, of such Person and its Restricted Subsidiaries on a Consolidated basis, all determined in accordance with GAAP, less all non-cash items increasing Consolidated Net Income for such period, less (to the extent included in determining Consolidated Net Income) the sum of (a) the amount of deferred revenues that are amortized during the period and are attributable to reserves that are subject to Volumetric Production Payments and (b) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments, and less all cash payments during such period relating to non-cash charges that were added back to Consolidated Net Income in determining the Consolidated Fixed Charge Coverage Ratio in any prior period to
 
(b) without duplication, the sum of Consolidated Interest Expense for such period,
 
in each case after giving pro forma effect to, without duplication,
 
(1) the incurrence of the Indebtedness giving rise to the need to make such calculation and (if applicable) the application of the net proceeds therefrom, including to refinance other Indebtedness,


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as if such Indebtedness was incurred, and the application of such proceeds occurred, on the first day of such period;
 
(2) the incurrence, repayment or retirement of any other Indebtedness by the Person and its Restricted Subsidiaries since the first day of such period as if such Indebtedness was incurred, repaid or retired at the beginning of such period (except that, in making such computation, the amount of Indebtedness under any revolving credit facility shall be computed based upon the average daily balance of such Indebtedness during such period);
 
(3) in the case of Acquired Debt or any acquisition occurring at the time of the incurrence of such Indebtedness, the related acquisition, assuming such acquisition had been consummated on the first day of such period; and
 
(4) any acquisition or disposition by such Person and its Restricted Subsidiaries of any company or any business or any assets out of the ordinary course of business, whether by merger, stock purchase or sale or asset purchase or sale, or any related repayment of Indebtedness, in each case since the first day of such period, assuming such acquisition or disposition had been consummated on the first day of such period;
 
provided that
 
(1) in making such computation, the Consolidated Interest Expense attributable to interest on any Indebtedness computed on a pro forma basis and (A) bearing a floating interest rate shall be computed as if the rate in effect on the date of computation had been the applicable rate for the entire period and (B) which was not outstanding for any part of the period for which the computation is being made but which bears, at the option of such Person, a fixed or floating rate of interest, shall be computed by applying at the option of such Person either the fixed or floating rate, and
 
(2) in making such computation, the Consolidated Interest Expense of such Person attributable to interest on any Indebtedness under a revolving credit facility computed on a pro forma basis shall be computed based upon the average daily balance of such Indebtedness during the applicable period.
 
“Consolidated Income Tax Expense” of any Person means, for any period, the provision for federal, state, local and foreign income taxes (including state franchise taxes accounted for as income taxes in accordance with GAAP) of such Person and its Restricted Subsidiaries for such period as determined, on a Consolidated basis, in accordance with GAAP.
 
“Consolidated Interest Expense” of any Person means, without duplication, for any period, the sum of
 
(a) the interest expense, less interest income, of such Person and its Restricted Subsidiaries for such period, on a Consolidated basis, excluding any interest attributable to Dollar-Denominated Production Payments but including, without limitation,
 
(1) amortization of debt discount (excluding amortization of capitalized debt issuance costs),
 
(2) the net cash costs associated with Interest Rate Agreements (including amortization of discounts),
 
(3) the interest portion of any deferred payment obligation,
 
(4) all commissions, discounts and other fees and charges owed with respect to letters of credit and bankers acceptance financing and
 
(5) accrued interest, minus
 
(b) to the extent included in (a) above, write-offs of deferred financing costs of such Person and its Restricted Subsidiaries during such period and any charge related to, or any premium paid in connection with, paying any such Indebtedness of such Person and its Restricted Subsidiaries prior to its Stated Maturity, plus


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(c) (1) the interest component of the Capital Lease Obligations paid, accrued and/or scheduled to be paid or accrued by such Person and its Restricted Subsidiaries during such period and
 
(2) all capitalized interest of such Person and its Restricted Subsidiaries plus
 
(d) the interest expense under any Guaranteed Debt of such Person and any Restricted Subsidiary to the extent not included under any other clause hereof, whether or not paid by such Person or its Restricted Subsidiaries, plus
 
(e) dividend payments by the Person with respect to Disqualified Stock and of any Restricted Subsidiary with respect to Preferred Stock (except, in either case, dividends paid solely in Qualified Capital Stock of such Person or such Restricted Subsidiary, as the case may be).
 
“Consolidated Net Income” of any Person means, for any period, the Consolidated net income (or loss) of such Person and its Restricted Subsidiaries for such period on a Consolidated basis as determined in accordance with GAAP, adjusted, to the extent included in calculating such net income (or loss), by excluding, without duplication,
 
(1) all extraordinary gains or losses net of taxes (less all fees and expenses relating thereto),
 
(2) the portion of net income (or loss) of such Person and its Restricted Subsidiaries on a Consolidated basis allocable to minority interests in unconsolidated Persons or Unrestricted Subsidiaries to the extent that cash dividends or distributions have not actually been received by such Person or one of its Consolidated Restricted Subsidiaries,
 
(3) any gain or loss, net of taxes, realized upon the termination of any employee pension benefit plan,
 
(4) gains or losses, net of taxes (less all fees and expenses relating thereto), in respect of dispositions of assets other than in the ordinary course of the Oil and Gas Business (including, without limitation, dispositions pursuant to Sale Leaseback Transactions, but excluding transactions such as farmouts, sales of leasehold inventory and sales of undivided interests in drilling prospects),
 
(5) the net income of any Restricted Subsidiary to the extent that the declaration of dividends or similar distributions by that Restricted Subsidiary of that income is not at the time permitted, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders,
 
(6) any write-downs of non-current assets, provided that any ceiling limitation write-downs under SEC guidelines shall be treated as capitalized costs, as if such write-downs had not occurred,
 
(7) any cumulative effect of a change in accounting principles, and
 
(8) all deferred financing costs written off, and premiums paid, in connection with any early extinguishment of Indebtedness.
 
“Consolidated Non-cash Charges” of any Person means, for any period, the aggregate depreciation, depletion, amortization and exploration expense and other non-cash charges of such Person and its Restricted Subsidiaries on a Consolidated basis for such period, as determined in accordance with GAAP (excluding any non-cash charge which requires an accrual or reserve for cash charges for any future period but including, without limitation, any non-cash charge arising from any grant of Capital Stock, options to acquire Capital Stock, or other equity based awards).
 
“Consolidation” and “Consolidated” mean, with respect to any Person, the consolidation of the accounts of such Person and each of its Subsidiaries if and to the extent the accounts of such Person and each of its Subsidiaries would normally be consolidated with those of such Person, all in accordance with GAAP.
 
“Corporate Trust Office” means the office of the trustee at which at any time the corporate trust business in relation to the indenture and the notes is administered, which office at the date of this exchange offer


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memorandum is located at 201 Main Street, 3rd Floor, Fort Worth, Texas 76102-5489, Attention: Corporate Trust Services.
 
“Credit Facility” means one or more debt facilities (including, without limitation, the Senior Credit Facility and the Unsecured Credit Agreement), commercial paper facilities or other debt instruments, indentures or agreements providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to the lenders or to special purpose entities formed to borrow from the lenders against such receivables), letters of credit or other debt obligations, in each case, as amended, restated, modified, renewed, refunded, restructured, supplemented, replaced or refinanced from time to time in whole or in part from time to time, including without limitation any amendment increasing the amount of Indebtedness incurred or available to be borrowed thereunder, extending the maturity of any Indebtedness incurred thereunder or contemplated thereby or deleting, adding or substituting one or more parties thereto (whether or not such added or substituted parties are banks or other institutional lenders).
 
“Debtor Relief Laws” means the Bankruptcy Code of the United States, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization, or similar debtor relief laws of the United States or other applicable jurisdictions from time to time in effect and affecting the rights of creditors generally.
 
“Default” means any event or condition that constitutes an Event of Default or that, with the giving of any notice, the passage of time, or both, would be an Event of Default.
 
“Designation” has the meaning assigned to such term in the covenant described under “— Certain Covenants — Designation of Restricted and Unrestricted Subsidiaries.”
 
“Designation Amount” has the meaning assigned to such term in the covenant described under “— Certain Covenants — Designation of Restricted and Unrestricted Subsidiaries.”
 
“Disinterested Director” means, with respect to any transaction or series of related transactions, a member of the Board of Directors of the Company who does not have any material direct or indirect financial interest (other than as a shareholder or employee of the Company or any Subsidiary) in or with respect to such transaction or series of related transactions.
 
“Disqualified Stock” means (i) the Series A Preferred Stock and (ii) any other Capital Stock that, either by its terms or by the terms of any security into which it is convertible or exchangeable or otherwise, is or upon the happening of an event or passage of time would be, required to be redeemed prior to the final Stated Maturity of the Senior Notes or is redeemable at the option of the holder thereof at any time prior to such final Stated Maturity (other than upon a change of control of or sale of assets by the Company in circumstances where the Holders would have similar rights), or is convertible into or exchangeable for debt securities at any time prior to such final Stated Maturity at the option of the holder thereof.
 
“Dollar” and “$” mean lawful money of the United States.
 
“Dollar-Denominated Production Payment” means a production payment required to be recorded as a borrowing in accordance with GAAP, together with all undertakings and obligations in connection therewith.
 
“DTC” means The Depository Trust Company, a New York corporation, and its successors.
 
“Equity Interests” means, with respect to any Person, all of the shares of capital stock of (or other ownership or profit interests in) such Person, all of the warrants, options or other rights for the purchase or acquisition from such Person of shares of capital stock of (or other ownership or profit interests in) such Person, all of the securities convertible into or exchangeable for shares of capital stock of (or other ownership or profit interests in) such Person or warrants, rights or options for the purchase or acquisition from such Person of such shares (or such other interests), and all of the other ownership or profit interests in such Person (including partnership, member or trust interests therein), whether voting or nonvoting, and whether or not such shares, warrants, options, rights or other interests are outstanding on any date of determination.
 
“Event of Default” has the meaning assigned to such term in “— Default and Remedies.”


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“Excess Proceeds” means any Net Available Cash from an Asset Sale not applied in accordance with paragraph (b) of the covenant described under ‘‘— Certain Covenants — Limitation on Asset Sales” within 365 days from the date of such Asset Sale.
 
“Exchange Act” means the Securities Exchange Act of 1934.
 
“Exchange Notes” means the notes of the Company issued pursuant to the indenture in exchange for, and in an aggregate principal amount equal to, the Initial Notes or any Initial Additional Notes (and any PIK Notes issued pursuant to the indenture), in compliance with the terms of a Registration Rights Agreement and containing terms substantially identical to the Initial Notes or any Initial Additional Notes exchanged (except that (i) such Exchange Notes will be registered under the Securities Act and will not be subject to transfer restrictions or bear a restricted legend, and (ii) the provisions relating to Additional Interest will be eliminated).
 
“Exchange Offer” means an offer by the Company to the holders of the Initial Notes or any Initial Additional Notes (and any PIK Notes issued pursuant to the indenture) to exchange outstanding notes for Exchange Notes, as provided for in a Registration Rights Agreement.
 
“Exchanged Properties” means properties or assets or Capital Stock representing an equity interest in or assets used or useful in the Oil and Gas Business, received by the Company or a Restricted Subsidiary in a substantially concurrent purchase and sale, trade or exchange as a portion of the total consideration for other such properties or assets.
 
“Fair Market Value” means, with respect to any asset or property, the sale value that would be obtained in an arm’s-length free market transaction between an informed and willing seller under no compulsion to sell and an informed and willing buyer under no compulsion to buy. Fair Market Value of an asset or property in excess of $10,000,000 shall be determined by the board of directors of the Company acting in good faith, in which event it shall be evidenced by a resolution of the board of directors.
 
“Foreign Subsidiary” means any Restricted Subsidiary of the Company that (x) is not organized under the laws of the United States of America or any State thereof or the District of Columbia, or (y) was organized under the laws of the United States of America or any State thereof or the District of Columbia that has no material assets other than Capital Stock of one or more foreign entities of the type described in clause (x) above and is not a guarantor of Indebtedness under a Credit Facility.
 
“GAAP” means generally accepted accounting principles in the United States of America as in effect from time to time.
 
“Guarantee” means any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness or other obligation of any other Person and, without limiting the generality of the foregoing, any obligation, direct or indirect, contingent or otherwise, of such Person (i) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness or other obligation of such other Person (whether arising by virtue of partnership arrangements, or by agreement to keep-well, to purchase assets, goods, securities or services, to take-or-pay, or to maintain financial statement conditions or otherwise) or (ii) entered into for purposes of assuring in any other manner the obligee of such Indebtedness or other obligation of the payment thereof or to protect such obligee against loss in respect thereof, in whole or in part; provided that the term “Guarantee” does not include endorsements for collection or deposit in the ordinary course of business. The term “Guarantee” used as a verb has a corresponding meaning.
 
“Guaranteed Debt” of any Person means, without duplication, all Indebtedness of any other Person referred to in the definition of Indebtedness below guaranteed directly or indirectly in any manner by such Person, or in effect guaranteed directly or indirectly by such Person through an agreement, made primarily for the purpose of enabling the debtor to make payment of such Indebtedness or to assure the holder of such Indebtedness against loss,
 
(1) to pay or purchase such Indebtedness or to advance or supply funds for the payment or purchase of such Indebtedness,


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(2) to purchase, sell or lease (as lessee or lessor) property, or to purchase or sell services,
 
(3) to supply funds to, or in any other manner invest in, the debtor (including any agreement to pay for property or services without requiring that such property be received or such services be rendered),
 
(4) to maintain working capital or equity capital of the debtor, or otherwise to maintain the net worth, solvency or other financial condition of the debtor or to cause such debtor to achieve certain levels of financial performance or
 
(5) otherwise to assure a creditor against loss;
 
provided that the term “guarantee” shall not include endorsements for collection or deposit, in either case in the ordinary course of business.
 
“Guarantors” means, collectively, (i) SandRidge Onshore, LLC, Lariat Services, Inc., SandRidge Operating Company, Integra Energy, LLC, SandRidge Exploration and Production, LLC, SandRidge Tertiary, LLC, SandRidge Midstream, Inc, SandRidge Offshore, LLC and SandRidge Holdings, Inc. and (ii) each Restricted Subsidiary that executes a supplemental indenture providing for the guaranty of the payment of the notes, or any successor obligor under its Note Guaranty pursuant to the indenture, in each case unless and until such Guarantor is released from its Note Guaranty pursuant to the indenture.
 
“Immaterial Subsidiary” means any Subsidiary with total assets of less than $500,000, as determined in accordance with its latest financial statements.
 
“Indebtedness” means, with respect to any Person, without duplication,
 
(1) all indebtedness of such Person for borrowed money or for the deferred purchase price of property or services, excluding any Trade Accounts Payable and other accrued current liabilities arising in the ordinary course of business, but including, without limitation, all obligations, contingent or otherwise, of such Person in connection with any letters of credit issued under letter of credit facilities, acceptance facilities or other similar facilities,
 
(2) all obligations of such Person evidenced by bonds, notes, debentures or other similar instruments,
 
(3) all indebtedness created or arising under any conditional sale or other title retention agreement with respect to property acquired by such Person (even if the rights and remedies of the seller or lender under such agreement in the event of default are limited to repossession or sale of such property), but excluding Trade Accounts Payable,
 
(4) all obligations under or in respect of currency exchange contracts, oil, gas or other hydrocarbon price hedging arrangements and Interest Rate Agreements of such Person (the amount of any such obligations to be equal at any time to the termination value of such agreement or arrangement giving rise to such obligation that would be payable by such Person at such time),
 
(5) all Capital Lease Obligations of such Person,
 
(6) the Attributable Indebtedness of such Person related to any Sale Leaseback Transaction,
 
(7) all Indebtedness referred to in clauses (1) through (6) above of other Persons and all dividends of other Persons, to the extent the payment of such Indebtedness or dividends is secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any Lien, upon or with respect to property (including, without limitation, accounts and contract rights) owned by such Person, even though such Person has not assumed or become liable for the payment of such Indebtedness,
 
(8) all Guaranteed Debt of such Person,
 
(9) all Disqualified Stock issued by such Person, valued at the greater of its voluntary or involuntary maximum fixed repurchase price plus accrued and unpaid dividends,


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(10) all Preferred Stock of any Restricted Subsidiary of the Person, valued at the greater of its voluntary or involuntary maximum fixed repurchase price plus accrued and unpaid dividends,
 
(11) with respect to any Production Payment and Reserve Sale, any warranties or guaranties of production or payment by such Person with respect to such Production Payment and Reserve Sale but excluding other contractual obligations of such Person with respect to such Production Payment and Reserve Sale and
 
(12) any amendment, supplement, modification, deferral, renewal, extension, refunding or refinancing of any liability of the types referred to in clauses (1) through (11) above.
 
For purposes hereof, the “maximum fixed repurchase price” of any Disqualified Stock or Preferred Stock which does not have a fixed repurchase price shall be calculated in accordance with the terms of such Disqualified Stock or Preferred Stock as if it were purchased on any date on which Indebtedness shall be required to be determined pursuant to the indenture, and if such price is based upon, or measured by, the Fair Market Value of such Disqualified Stock or Preferred Stock, such Fair Market Value to be determined in good faith by the board of directors of the issuer of such Disqualified Stock or Preferred Stock. Subject to clause (11) of the preceding sentence, Production Payments and Reserve Sales shall not be deemed to be Indebtedness.
 
“Initial Additional Notes” means Additional Notes issued in an offering not registered under the Securities Act and any notes issued in replacement thereof, but not including any Exchange Notes issued in exchange therefor.
 
“Initial Senior Notes” means the Senior Notes issued on the Issue Date and any Senior Notes issued in replacement thereof, but not including any Exchange Notes issued in exchange therefor.
 
“Initial Senior Floating Rate Notes” means the Senior Floating Rate Notes issued on the Issue Date and any Senior Floating Rate Notes issued in replacement thereof, but not including any Exchange Notes issued in exchange therefor.
 
“Initial Notes” means the Initial Senior Notes and the Initial Senior Floating Rate Notes.
 
“interest,” in respect of the notes, unless the context otherwise requires, refers to interest and Additional Interest, if any.
 
“Interest Rate Agreements” means one or more of the following agreements which shall be entered into from time to time by one or more financial institutions: interest rate protection agreements (including, without limitation, interest rate swaps, caps, floors, collars and similar agreements) and/or other types of interest rate hedging agreements.
 
“Investment” means, with respect to any Person, directly or indirectly, any advance, loan (including Guarantees), or other extension of credit or capital contribution to any other Person (by means of any transfer of cash or other property to others or any payment for property or services for the account or use of others), or any purchase, acquisition or ownership by such Person of any Capital Stock, bonds, notes, debentures or other securities issued or owned by any other Person and all other items that would be classified as investments on a balance sheet prepared in accordance with GAAP. “Investment” shall exclude direct or indirect advances to customers or suppliers in the ordinary course of business that are, in conformity with GAAP, recorded as accounts receivable, prepaid expenses or deposits on the Company’s or any Restricted Subsidiary’s balance sheet, endorsements for collection or deposit arising in the ordinary course of business and extensions of trade credit on commercially reasonable terms in accordance with normal trade practices. If the Company or any Restricted Subsidiary of the Company sells or otherwise disposes of any Capital Stock of any direct or indirect Subsidiary of the Company such that, after giving effect to any such sale or disposition, such Person is no longer a Subsidiary of the Company (other than the sale of all of the outstanding Capital Stock of such Subsidiary), the Company will be deemed to have made an Investment on the date of such sale or disposition equal to the Fair Market Value of the Company’s Investments in such Subsidiary that were not sold or disposed of in an amount determined as provided in the covenant described under “— Certain Covenants — Limitation on Restricted Payments.”
 
“Issue Date” means the earliest date on which any notes are originally issued under the indenture, May 1, 2008.


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“Lien” means any mortgage or deed of trust, charge, pledge, lien (statutory or otherwise), privilege, security interest, assignment, deposit, arrangement, hypothecation, claim, preference, priority or other encumbrance for security purposes upon or with respect to any property of any kind (including any conditional sale, capital lease or other title retention agreement, any leases in the nature thereof, and any agreement to give any security interest), real or personal, movable or immovable, now owned or hereafter acquired. A Person will be deemed to own subject to a Lien any property which it has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, Capital Lease Obligation or other title retention agreement. References herein to Liens allowed to exist upon any particular item of Property shall also be deemed (whether or not stated specifically) to allow Liens to exist upon any accessions, improvements or additions to such property, upon any contractual rights relating primarily to such Property, and upon any proceeds of such Property or of such accessions, improvements, additions or contractual rights.
 
“Liquid Securities” means securities (i) of an issuer that is not an Affiliate of the Company, (ii) that are publicly traded on the New York Stock Exchange, the American Stock Exchange or the Nasdaq Stock Market and (iii) as to which the Company is not subject to any restrictions on sale or transfer (including any volume restrictions under Rule 144 under the Securities Act or any other restrictions imposed by the Securities Act) or as to which a registration statement under the Securities Act covering the resale thereof is in effect for as long as the securities are held; provided that securities meeting the requirements of clauses (i), (ii) and (iii) above shall be treated as Liquid Securities from the date of receipt thereof until and only until the earlier of (a) the date on which such securities are sold or exchanged for cash or Cash Equivalents and (b) 360 days following the date of receipt of such securities. If such securities are not sold or exchanged for cash or Cash Equivalents within 360 days of receipt thereof, for purposes of determining whether the transaction pursuant to which the Company or a Restricted Subsidiary received the securities was in compliance with the provisions of the covenant described under “— Certain Covenants — Limitation on Asset Sales,” such securities shall be deemed not to have been Liquid Securities at any time.
 
“Material Change” means an increase or decrease (except to the extent resulting from changes in prices) of more than 30% during a fiscal quarter in the estimated discounted future net revenues from proved oil and gas reserves of the Company and its Restricted Subsidiaries, calculated in accordance with clause (i)(a) of the definition of Adjusted Consolidated Net Tangible Assets; provided, however, that the following will be excluded from the calculation of Material Change: (i) any acquisitions during the quarter of oil and gas reserves with respect to which the discounted future net revenues from proved oil and gas reserves have been estimated or confirmed by independent petroleum engineers and (ii) any dispositions of properties and assets during such quarter that were disposed of in compliance with the covenant described under “— Certain Covenants — Limitation on Asset Sales.”
 
“Midstream Assets” means (i) assets used primarily for gathering, transmission, storage, processing or treatment of natural gas, natural gas liquids or other hydrocarbons or carbon dioxide and (ii) equity interests of any Person that has no substantial assets other than assets referred to in clause (i).
 
“Moody’s” means Moody’s Investors Service, Inc. and any successor thereto.
 
“Net Available Cash” from an Asset Sale or Sale Leaseback Transaction means cash proceeds received therefrom (including (i) any cash proceeds received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise, but only as and when received and (ii) the Fair Market Value of Liquid Securities and Cash Equivalents, and excluding (iii) any other consideration received in the form of assumption by the acquiring Person of Indebtedness or other obligations relating to the assets or property that is the subject of such Asset Sale or Sale Leaseback Transaction and (iv) except to the extent subsequently converted to cash, within 360 days after such Asset Sale or Sale Leaseback Transaction, Cash Equivalents or Liquid Securities; consideration constituting Exchanged Properties or consideration other than as identified in the immediately preceding clauses (i) and (ii)), in each case net of:
 
(a) all legal, title and recording expenses, commissions and other fees and expenses incurred, and all federal, state, foreign and local taxes required to be paid or accrued as a liability under GAAP as a consequence of such Asset Sale or Sale Leaseback Transaction,


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(b) all payments made on any Indebtedness (but specifically excluding Indebtedness of the Company and its Restricted Subsidiaries assumed in connection with or in anticipation of such Asset Sale or Sale Leaseback Transaction) which is secured by any assets subject to such Asset Sale or Sale Leaseback Transaction, in accordance with the terms of any Lien upon such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Sale or Sale Leaseback Transaction or by applicable law, be repaid out of the proceeds from such Asset Sale or Sale Leaseback Transaction, provided that such payments are made in a manner that results in the permanent reduction in the balance of such Indebtedness and, if applicable, a permanent reduction in any outstanding commitment for future incurrences of Indebtedness thereunder,
 
(c) all distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures as a result of such Asset Sale or Sale Leaseback Transaction and
 
(d) the deduction of appropriate amounts to be provided by the seller as a reserve, in accordance with GAAP, against any liabilities associated with the assets disposed of in such Asset Sale or Sale Leaseback Transaction and retained by the Company or any Restricted Subsidiary after such Asset Sale or Sale Leaseback Transaction;
 
provided, however, that if any consideration for an Asset Sale or Sale Leaseback Transaction (which would otherwise constitute Net Available Cash) is required to be held in escrow pending determination of whether a purchase price adjustment will be made, such consideration (or any portion thereof) shall become Net Available Cash only at such time as it is released to the Company or its Restricted Subsidiaries from escrow.
 
“Net Cash Proceeds” means with respect to any issuance or sale of Capital Stock or debt securities or Capital Stock that has been converted into or exchanged for Capital Stock as referred to in “— Certain Covenants — Limitation on Restricted Payments,” the proceeds of such issuance or sale in the form of cash or Cash Equivalents including payments in respect of deferred payment obligations when received in the form of, or stock or other assets when disposed of for, cash or Cash Equivalents (except to the extent that such obligations are financed or sold with recourse to the Company or any Restricted Subsidiary), net of attorney’s fees, accountant’s fees and brokerage, consultation, underwriting and other fees and expenses actually incurred in connection with such issuance or sale and net of taxes paid or payable as a result thereof.
 
“Net Working Capital” means (i) all current assets of the Company and its Restricted Subsidiaries, less (ii) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness, in each case as set forth in Consolidated financial statements of the Company prepared in accordance with GAAP, provided, however, that all of the following shall be excluded in the calculation of Net Working Capital: (a) current assets or liabilities relating to the mark-to-market value of Interest Rate Agreements and hedging arrangements constituting Permitted Debt, (b) any current assets or liabilities relating to non-cash charges arising from any grant of Capital Stock, options to acquire Capital Stock, or other equity based awards, and (c) any current assets or liabilities relating to non-cash charges or accruals for future abandonment liabilities.
 
“Officers’ Certificate” means a certificate signed in the name of the Company (i) by the chairman of the Board of Directors, the president or chief executive officer or a vice president and (ii) by the chief financial officer, the treasurer or any assistant treasurer or the secretary or any assistant secretary.
 
“Oil and Gas Business” means the business of exploiting, exploring for, developing, acquiring, operating, producing, processing, gathering, marketing, storing, selling, hedging, treating, swapping, refining and transporting hydrocarbons and carbon dioxide and other related energy businesses, including contract drilling and other oilfield services.
 
“Oil and Gas Liens” means (i) Liens on any specific property or any interest therein, construction thereon or improvement thereto to secure all or any part of the costs incurred for surveying, exploration, drilling, extraction, development, operation, production, construction, alteration, repair or improvement of, in, under or on such property and the plugging and abandonment of wells located thereon (it being understood that, in the case of oil and gas producing properties, or any interest therein, costs incurred for “development” shall include costs incurred for all facilities relating to such properties or to projects, ventures or other


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arrangements of which such properties form a part or which relate to such properties or interests); (ii) Liens on an oil or gas producing property to secure obligations incurred or guarantees of obligations incurred in connection with or necessarily incidental to commitments for the purchase or sale of, or the transportation or distribution of, the products derived from such property; (iii) Liens arising under partnership agreements, oil and gas leases, overriding royalty agreements, net profits agreements, production payment agreements, royalty trust agreements, incentive compensation programs for geologists, geophysicists and other providers of technical services to the Company or a Restricted Subsidiary, master limited partnership agreements, farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of oil, gas or other hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, operating agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements which are customary in the Oil and Gas Business; provided, however, in all instances that such Liens are limited to the assets that are the subject of the relevant agreement, program, order or contract; (iv) Liens arising in connection with Production Payments and Reserve Sales; provided that such Liens are limited to the property that is subject to such Production Payments and Reserve Sales, and such Production Payments and Reserve Sales either (a) were created in connection with the acquisition or financing of the property and were incurred within 90 days after the acquisition of the property subject thereto, or (b) constitute Asset Sales made in compliance with the covenant described under “Certain Covenants — Limitation on Asset Sales;” and (v) Liens on pipelines or pipeline facilities that arise by operation of law.
 
“Opinion of Counsel” means a written opinion signed by legal counsel, who may be an employee of or counsel to the Company, satisfactory to the trustee.
 
“Original Senior Floating Rate Notes” means the Initial Senior Floating Rate Notes and any Exchange Notes issued in exchange therefor.
 
“Original Senior Notes” means the Initial Senior Notes, any PIK Notes (other than PIK Notes issued in respect of Additional Senior Notes) and any Exchange Notes issued in exchange therefor.
 
“Pari Passu Indebtedness” means any Indebtedness of the Company or a Guarantor that is pari passu in right of payment to the notes or Note Guaranty, as the case may be.
 
“Permitted Business Investments” means Investments and expenditures made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business as a means of actively engaging therein through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of Oil and Gas Business jointly with third parties, including (i) ownership interests in oil and gas properties or gathering, transportation, processing, storage or related systems and (ii) Investments and expenditures in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling arrangements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited) and other similar agreements (including for limited liability companies) with third parties, excluding, however, Investments in Persons other than Restricted Subsidiaries.
 
“Permitted Debt” has the meaning assigned to such term in the covenant described under “— Certain Covenants — Limitation on Indebtedness and Disqualified Stock.”
 
“Permitted Investments” mean:
 
(1) Investments in any Restricted Subsidiary or any Person which, as a result of such Investment, (a) becomes a Restricted Subsidiary or (b) is merged or consolidated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, the Company or any Restricted Subsidiary;
 
(2) Indebtedness of the Company or a Restricted Subsidiary described under clauses (4), (5) and (6) of the definition of “Permitted Debt;”


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(3) Investments in any of the “Loans” (as defined in the Unsecured Credit Agreement) or notes;
 
(4) Cash Equivalents;
 
(5) Investments in property, plant and equipment used in the ordinary course of business and Permitted Business Investments;
 
(6) Investments acquired by the Company or any Restricted Subsidiary in connection with an Asset Sale permitted under the covenant described under “Certain Covenants — Limitation on Asset Sales” to the extent such Investments are non-cash proceeds as permitted under such covenant;
 
(7) Investments in existence on March 22, 2007;
 
(8) Investments acquired in exchange for the issuance of Capital Stock of the Company (other than Disqualified Stock of the Company or a Restricted Subsidiary or Preferred Stock of a Restricted Subsidiary);
 
(9) Investments in prepaid expenses, negotiable instruments held for collection and lease, utility and worker’s compensation, performance and other similar deposits provided to third parties in the ordinary course of business;
 
(10) loans or advances to employees of the Company and its Restricted Subsidiaries in the ordinary course of business for bona fide business purposes of the Company and its Restricted Subsidiaries (including travel, entertainment and relocation expenses) in the aggregate amount outstanding at any one time of not more than $2,000,000;
 
(11) any Investments received in good faith in settlement or compromise of receivables or other obligations that were obtained in the ordinary course of business, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer;
 
(12) other Investments in the aggregate amount outstanding at any one time of up to the greater of (x) $25,000,000 and (y) 5.0% of Adjusted Consolidated Net Tangible Assets; and
 
(13) Guarantees received with respect to any Permitted Investment listed above.
 
In connection with any assets or property contributed or transferred to any Person as an Investment, the value of such property and assets shall be equal to the Fair Market Value at the time of Investment, without regard to subsequent changes in value.
 
“Permitted Liens” means
 
(1) any Lien existing on March 22, 2007 securing Indebtedness or obligations existing on March 22, 2007 and not otherwise referred to in this definition;
 
(2) any Lien with respect to the Senior Credit Facility (including with respect to any Guarantee thereof made by any Guarantor) or any successor Credit Facilities securing Indebtedness incurred thereunder that could be borrowed under the covenant described under “— Certain Covenants — Limitation on Indebtedness and Disqualified Stock;”
 
(3) any Lien securing the loans and other obligations arising under the Unsecured Credit Agreement;
 
(4) any Lien in favor of the Company or a Restricted Subsidiary;
 
(5) any Lien arising by reason of:
 
(A) any judgment, decree or order of any court, so long as such Lien is adequately bonded and any appropriate legal proceedings which may have been duly initiated for the review of such judgment, decree or order shall not have been finally terminated or the period within which such proceedings may be initiated shall not have expired;


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(B) taxes, assessments or governmental charges or claims that are not yet delinquent or which are being contested in good faith by appropriate proceedings promptly instituted and diligently conducted, provided that any reserve or other appropriate provision as will be required in conformity with GAAP will have been made therefor;
 
(C) security made in the ordinary course of business in connection with workers’ compensation, unemployment insurance or other types of social security;
 
(D) good faith deposits in connection with tenders, leases and contracts (other than contracts for the payment of Indebtedness);
 
(E) zoning restrictions, easements, licenses, reservations, title defects, rights of others for rights of way, utilities, sewers, electric lines, telephone or telegraph lines, and other similar purposes, provisions, covenants, conditions, waivers, restrictions on the use of property or minor irregularities of title (and with respect to leasehold interests, mortgages, obligations, Liens and other encumbrances incurred, created, assumed or permitted to exist and arising by, through or under a landlord or owner of the leased property, with or without consent of the lessee), none of which materially impairs the use of any parcel of property material to the operation of the business of the Company or any Restricted Subsidiary or the value of such property for the purpose of such business;
 
(F) deposits to secure public or statutory obligations, or in lieu of surety or appeal bonds;
 
(G) operation of law or contract in favor of mechanics, carriers, warehousemen, landlords, materialmen, laborers, employees, suppliers and similar persons, incurred in the ordinary course of business for sums which are not yet delinquent or are being contested in good faith by negotiations or by appropriate proceedings which suspend the collection thereof;
 
(H) normal depository arrangements with banks;
 
(6) any Lien securing Acquired Debt created prior to (and not created in connection with, or in contemplation of) the incurrence of such Indebtedness by the Company or any Restricted Subsidiary; provided that such Lien only secures the assets acquired in connection with the transaction pursuant to which the Acquired Debt became an obligation of the Company or a Restricted Subsidiary;
 
(7) any Lien to secure performance bids, leases (including, without limitation, statutory and common law landlord’s liens), statutory obligations, letters of credit and other obligations of a like nature and incurred in the ordinary course of business of the Company or any Subsidiary and not securing or supporting Indebtedness, and any Lien to secure statutory or appeal bonds;
 
(8) any Lien securing Indebtedness permitted to be incurred pursuant to clause (6) or clause (8) of the definition of Permitted Debt, so long as none of such Indebtedness constitutes debt for borrowed money;
 
(9) any Lien securing Capital Lease Obligations or Purchase Money Obligations incurred in accordance with clause (7) of the definition of Permitted Debt and which are incurred or assumed solely in connection with the acquisition, development or construction of real or personal, moveable or immovable property commencing within 90 days of such incurrence or assumption; provided that such Liens only extend to such acquired, developed or constructed property, such Liens secure Indebtedness in an amount not in excess of the original purchase price or the original cost of any such assets or repair, addition or improvement thereto, and the incurrence of such Indebtedness is permitted by the covenant described under “— Certain Covenants — Limitation on Indebtedness and Disqualified Stock;”
 
(10) leases and subleases of real property which do not materially interfere with the ordinary conduct of the business of the Company or any of its Restricted Subsidiaries;
 
(11) (A) Liens on property, assets or shares of stock of a Person at the time such Person becomes a Restricted Subsidiary or is merged with or into or consolidated with the Company or any of its Restricted Subsidiaries; provided, however, that such Liens are not created, incurred or assumed in connection with, or in contemplation of, such other Person becoming a Restricted Subsidiary or such merger or consolidation; provided further, that any such Lien may not extend to any other property owned by the Company or any


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Restricted Subsidiary and assets fixed or appurtenant thereto; and (B) Liens on property, assets or shares of capital stock existing at the time of acquisition thereof by the Company or any of its Restricted Subsidiaries; provided, however, that such Liens are not created, incurred or assumed in connection with, or in contemplation of, such acquisition and do not extend to any property other than the property so acquired;
 
(12) Oil and Gas Liens, in each case which are not incurred in connection with the borrowing of money;
 
(13) any extension, renewal, refinancing or replacement, in whole or in part, of any Lien described in the foregoing clauses (1) through (12) so long as no additional collateral is granted as security thereby; and
 
(14) in addition to the items referred to in clauses (1) through (13) above, Liens of the Company and its Restricted Subsidiaries to secure Indebtedness in an aggregate amount at any time outstanding which does not exceed 5.0% of Adjusted Consolidated Net Tangible Assets as most recently determined at such time.
 
“Permitted MLP Securities” means equity securities (including incentive distribution rights) of a master limited partnership (or limited liability company or similar business entity with pass-through treatment for U.S. Federal income tax purposes) that has a class of equity securities traded on the New York Stock Exchange, the American Stock Exchange or the Nasdaq Stock Market, provided that such master limited partnership (or other entity) is an Affiliate of the Company.
 
“Permitted Refinancing Indebtedness” means any Indebtedness of the Company or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to renew, extend, substitute, defease, refund, refinance or replace (“refinance”) other Indebtedness of the Company or any of its Restricted Subsidiaries (other than intercompany Indebtedness); provided that:
 
(1) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness being refinanced (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith);
 
(2) such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being refinanced;
 
(3) if the Indebtedness being refinanced is subordinated in right of payment to the notes, such Permitted Refinancing Indebtedness is subordinated in right of payment to the notes on terms at least as favorable to the holders as those contained in the documentation governing the Indebtedness being refinanced; and
 
(4) such Indebtedness is incurred either by the Company or by the Restricted Subsidiary, as applicable, that is the obligor on the Indebtedness refinanced.
 
“Person” means an individual, a corporation, a partnership, a limited liability company, an association, a trust or any other entity, including a government or political subdivision or an agency or instrumentality thereof.
 
“Preferred Stock” means, with respect to any Person, any Capital Stock of any class or classes (however designated) which is preferred as to the payment of dividends or distributions, or as to the distribution of assets upon any voluntary or involuntary liquidation or dissolution of such Person, over the Capital Stock of any other class in such Person.
 
“Production Payments” means, collectively, Dollar-Denominated Production Payments and Volumetric Production Payments.
 
“Production Payments and Reserve Sales” means the grant or transfer by the Company or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, Production Payment, partnership or other interest in oil and gas properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such properties, production or proceeds of production, subject to the obligation of the


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grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to the Company or a Restricted Subsidiary.
 
“Property” means, with respect to any Person, any interest of such Person in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, including Capital Stock and other securities issued by any other Person (but excluding Capital Stock or other securities issued by such first mentioned Person).
 
“principal” of any Indebtedness means the principal amount of such Indebtedness, (or if such Indebtedness was issued with original issue discount, the face amount of such Indebtedness less the remaining unamortized portion of the original issue discount of such Indebtedness), together with, unless the context otherwise indicates, any premium then payable on such Indebtedness.
 
“Purchase Money Obligation” means any Indebtedness secured by a Lien on assets related to the business of the Company or any Restricted Subsidiary which are purchased or constructed by the Company or such Restricted Subsidiary at any time after March 22, 2007; provided that
 
(1) the security agreement or conditional sales or other title retention contract pursuant to which the Lien on such assets is created (collectively a “Purchase Money Security Agreement”) shall be entered into within 90 days after the purchase or substantial completion of the construction of such assets and shall at all times be confined solely to the assets so purchased or acquired (together with any additions, accessions, and other related assets referred to in the last sentence of the above definition of “Liens”),
 
(2) at no time shall the aggregate principal amount of the outstanding Indebtedness secured thereby be increased, except in connection with the purchase of additions, improvements, and accessions thereto and except in respect of fees and other obligations in respect of such Indebtedness and
 
(3) (A) the aggregate outstanding principal amount of Indebtedness secured thereby (determined on a per asset basis in the case of any additions, improvements and accessions) shall not at the time such Purchase Money Security Agreement is entered into exceed 100% of the purchase price to the Company or the applicable Restricted Subsidiary of the assets subject thereto or (B) the Indebtedness secured thereby shall be with recourse solely to the assets so purchased or acquired subject to the last sentence of the above definition of “Liens”).
 
“Qualified Capital Stock” of any Person means any and all Capital Stock of such Person other than Disqualified Stock.
 
“Registration Rights Agreement” means (i) the Registration Rights Agreement dated on or about the Issue Date among the Company, the Guarantors and the trustee with respect to the Initial Notes, and (ii) with respect to any Additional Notes, any registration rights agreements between the Company, the Guarantors and the initial purchasers party thereto relating to rights given by the Company to the purchasers of Additional Notes to register such Additional Notes or exchange them for notes registered under the Securities Act.
 
“Restricted Payment” has the meaning assigned to such term in the covenant described under “— Certain Covenants — Limitation on Restricted Payments.”
 
“Restricted Subsidiary” of a Person means any Subsidiary of that Person that is not an Unrestricted Subsidiary.
 
“Revocation” has the meaning assigned to such term in the covenant described under “— Certain Covenants — Designation of Restricted and Unrestricted Subsidiaries.”
 
“S&P” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc., and any successor thereto.
 
“Sale Leaseback Transaction” means, with respect to the Company or any of its Restricted Subsidiaries, any arrangement with any Person providing for the leasing by the Company or any of its Restricted


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Subsidiaries of any real property or equipment, acquired or placed into service more than 180 days prior to such arrangement, whereby such property has been or is to be sold or transferred by the Company or any of its Restricted Subsidiaries to such Person.
 
“Securities Act” means the Securities Act of 1933.
 
“Senior Credit Facility” means that certain Credit Agreement dated as of November 21, 2006 among the Company (f/k/a Riata Energy, Inc.), Bank of America, N.A. and the other lenders party thereto, as such agreement, in whole or in part, in one or more instances, may be amended, renewed, extended, substituted, refinanced, restructured, replaced, supplemented or otherwise modified from time to time (including, without limitation, any successive amendments, renewals, extensions, substitutions, refinancings, restructurings, replacements, supplementations or other modifications of the foregoing).
 
“Series A Preferred Stock” means the Series A Convertible Preferred Stock of the Company issued pursuant to the Certificate of Designations filed on December 11, 2006.
 
“Shelf Registration Statement” means the Shelf Registration Statement as defined in a Registration Rights Agreement.
 
“Significant Subsidiary” means any Restricted Subsidiary that would be a “significant subsidiary” of the Company within the meaning of Rule 1-02 under Regulation S-X promulgated by the SEC as in effect on March 22, 2007.
 
“Stated Maturity” means (i) with respect to any Indebtedness, the date specified as the fixed date on which the final installment of principal of such Indebtedness is due and payable or (ii) with respect to any scheduled installment of principal of or interest on any Indebtedness, the date specified as the fixed date on which such installment is due and payable as set forth in the documentation governing such Indebtedness, not including any contingent obligation to repay, redeem or repurchase prior to the regularly scheduled date for payment.
 
“Subordinated Indebtedness” means any Indebtedness of the Company or any Guarantor which is subordinated in right of payment to the notes or the Note Guaranty, as the case may be.
 
“Subsidiary” of a Person means
 
(1) any corporation more than 50% of the outstanding voting power of the Voting Stock of which is owned or controlled, directly or indirectly, by such Person or by one or more other Subsidiaries of such Person, or by such Person and one or more other Subsidiaries thereof, or
 
(2) any limited partnership of which such Person or any Subsidiary of such Person is a general partner, or
 
(3) any other Person in which such Person, or one or more other Subsidiaries of such Person, or such Person and one or more other Subsidiaries, directly or indirectly, has more than 50% of the outstanding Capital Stock or has the power, by contract or otherwise, to direct or cause the direction of the policies, management and affairs thereof.
 
Unless otherwise specified, “Subsidiary” means a Subsidiary of the Company.
 
“Surviving Entity” has the meaning specified in “— Consolidation, Merger or Sale of Assets.”
 
“Surviving Guarantor Entity” has the meaning specified in “— Consolidation, Merger or Sale of Assets.”
 
“Trade Accounts Payable” of any Person means accounts payable or other obligations of that Person or any Restricted Subsidiary to trade creditors created or assumed by the Person or such Restricted Subsidiary in the ordinary course of business in connection with the obtaining of goods or services.
 
“Trust Indenture Act” means the Trust Indenture Act of 1939.
 
“U.S. Government Obligations” means obligations issued or directly and fully guaranteed or insured by the United States of America or by any agent or instrumentality thereof, provided that the full faith and credit of the United States of America is pledged in support thereof.


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“Unrestricted Subsidiary” means any Subsidiary of the Company that at the time of determination has previously been designated, and continues to be, an Unrestricted Subsidiary in accordance with the covenant described under “— Certain Covenants — Designation of Restricted and Unrestricted Subsidiaries.”
 
“Unrestricted Subsidiary Indebtedness” of any Unrestricted Subsidiary means Indebtedness of such Unrestricted Subsidiary:
 
(1) as to which neither the Company nor any Restricted Subsidiary is directly or indirectly liable (by virtue of the Company or any such Restricted Subsidiary being the primary obligor on, guarantor of, or otherwise liable in any respect to, such Indebtedness), except Guaranteed Debt of the Company or any Restricted Subsidiary to any Affiliate of the Company, in which case (unless the incurrence of such Guaranteed Debt resulted in a Restricted Payment at the time of incurrence) the Company shall be deemed to have made a Restricted Payment equal to the principal amount of any such Indebtedness to the extent guaranteed at the time such Affiliate is designated an Unrestricted Subsidiary and
 
(2) which, upon the occurrence of a default with respect thereto, does not result in, or permit any holder of any Indebtedness of the Company or any Restricted Subsidiary to declare, a default on such Indebtedness of the Company or any Restricted Subsidiary or cause the payment thereof to be accelerated or payable prior to its Stated Maturity;
 
provided that notwithstanding the foregoing, any Unrestricted Subsidiary may Guarantee the notes or any Credit Facility.
 
“Unsecured Credit Agreement” means that certain Credit Agreement dated as of March 22, 2007 among the Company (f/k/a Riata Energy, Inc.), Bank of America, N.A. and the other lenders party thereto, as such agreement, in whole or in part, in one or more instances, may be amended, renewed, extended, substituted, refinanced, restructured, replaced, supplemented or otherwise modified from time to time (including, without limitation, any successive amendments, renewals, extensions, substitutions, refinancings, restructurings, replacements, supplementations or other modifications of the foregoing).
 
“Volumetric Production Payment” means a production payment that is recorded as a sale in accordance with GAAP, whether or not the sale price must be recorded as deferred revenue, together with all undertakings and obligations in connection therewith.
 
“Voting Stock” of a Person means Capital Stock of such Person of the class or classes pursuant to which the holders thereof have the general voting power under ordinary circumstances to elect at least a majority of the board of directors, managers or trustees of such Person (irrespective of whether or not at the time Capital Stock of any other class or classes shall have or might have voting power by reason of the happening of any contingency).
 
“Ward Group” means (i) Tom L. Ward (“Ward”); (ii) Ward’s wife; (iii) any of Ward’s lineal descendants; (iv) Ward’s estate; (v) any trust of which at least one of the trustees is Ward, or the principal beneficiaries of which are any one or more of the Persons in (i)-(iv); (vi) any Person which is controlled by any one or more of the Persons in (i)-(v); and (vii) any group (within the meaning of the Exchange Act and the rules of the SEC thereunder as in effect on March 22, 2007) that includes one or more of Persons described in clauses (i) through (vi) above, provided that such Persons described in clauses (i) through (vi) above control more than 50% of the voting power of such group.
 
“Weighted Average Life to Maturity” means, as of the date of determination with respect to any Indebtedness, the quotient obtained by dividing (1) the sum of the products of (a) the number of years from the date of determination to the date or dates of each successive scheduled principal payment and (b) the amount of each such principal payment by (2) the sum of all such principal payments.
 
“Well Participation Program” means that certain Well Participation Program effective as of June 8, 2006 by and among the Company and certain executive officers of the Company, as in effect on March 22. 2007.
 
“Wholly Owned Restricted Subsidiary” means a Restricted Subsidiary all the Capital Stock of which is owned by the Company or another Wholly Owned Restricted Subsidiary (other than directors’ qualifying shares).


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CERTAIN U.S. FEDERAL TAX CONSIDERATIONS
 
The following discussion is a summary of certain United States federal income tax consequences relevant to the exchange of outstanding notes for exchange notes pursuant to the exchange offers. This discussion is based upon the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), applicable Treasury Regulations promulgated and proposed thereunder, judicial authority and administrative interpretations, as of the date of this prospectus, all of which are subject to change, possibly with retroactive effect, or are subject to different interpretations. This discussion does not consider the tax consequences arising under state, local or foreign law or United States federal tax consequences (e.g., estate or gift tax) other than United States federal income tax consequences.
 
We believe that the exchange of outstanding notes for exchange notes in the exchange offers will not constitute a taxable event. Consequently, you will not recognize gain or loss upon receipt of an exchange note in exchange for an outstanding note in the applicable exchange offer, your basis in the exchange note received in such exchange offer will be the same as your basis in the corresponding outstanding note immediately before the exchange, and your holding period in the exchange note will include your holding period in the outstanding note. The United States federal income tax consequences of holding and disposing of an exchange note received in the exchange offers will be the same as the United States federal income tax consequences of holding and disposing of an outstanding note.
 
Exchange Offers
 
We believe that the receipt of exchange notes in exchange for outstanding notes in the exchange offers will not be treated as a taxable exchange for United States federal income tax purposes. The exchange notes will not differ materially in kind or extent from the outstanding notes and, as a result, your exchange of outstanding notes for exchange notes will not constitute a taxable disposition of the outstanding notes for U.S. federal income tax purposes. As a result, you will not recognize taxable income, gain or loss on such exchange, your holding period for the exchange notes will generally include the holding period for the outstanding notes so exchanged, and your adjusted tax basis in the exchange notes will generally be the same as your adjusted tax basis in the outstanding notes so exchanged.
 
PLAN OF DISTRIBUTION
 
Based on interpretations by the staff of the SEC in no action letters issued to third parties, we believe that you may transfer exchange notes issued under the exchange offer in exchange for the outstanding notes if:
 
  •  you acquire the exchange notes in the ordinary course of your business; and
 
  •  you are not engaged in, and do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of such exchange notes.
 
You may not participate in the exchange offer if you are either:
 
  •  A broker-deal that acquired the outstanding notes directly from us, or
 
  •  An “affiliate,” as defined in Rule 405 of the Securities Act, of ours.
 
Each broker-dealer that receives exchange notes for its own account pursuant to an exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. To date, the staff of the SEC has taken the position that broker-dealers may fulfill their prospectus delivery requirements with respect to transactions involving an exchange of securities such as either of our exchange offers, other than a resale of an unsold allotment from the original sale of the outstanding notes, with the prospectus contained in this registration statement. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for outstanding notes where such outstanding notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of up to 180 days after the consummation of each exchange offer, we will make this prospectus, as amended or supplemented, available


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to any broker-dealer for use in connection with any such resale. In addition, until such date, all dealers effecting transactions in exchange notes may be required to deliver a prospectus.
 
If you wish to exchange your outstanding notes for exchange notes in the exchange offers, you will be required to make representations to us as described in “The Exchange Offers — Valid Tender” in this prospectus. As indicated in the letter of transmittal, you will be deemed to have made these representations by tendering your outstanding notes in the exchange offers. In addition, if you are a broker-dealer who receives exchange notes for your own account in exchange for outstanding notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge, in the same manner, that you will deliver a prospectus in connection with any resale by you of such exchange notes.
 
We will not receive any proceeds from any sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own account pursuant to the exchange offers may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of such methods of resale, at market prices prevailing at the time of resale, and at prices related to such prevailing market prices or negotiated prices.
 
Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to an exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of exchange notes and any commission or concession received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.
 
For a period of up to 180 days after the consummation of the exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offers other than commissions or concessions of any broker-dealers and will indemnify the holders of the outstanding notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.
 
LEGAL MATTERS
 
The validity of the exchange notes being offered hereby and certain other legal matters are being passed upon for us by Vinson & Elkins L.L.P., Houston, Texas.
 
EXPERTS
 
The financial statements of SandRidge Energy, Inc. as of December 31, 2007 and 2006 and for each of the three years in the period ended December 31, 2007 included in this Prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.
 
The combined financial statements of NEG Oil & Gas LLC and subsidiaries, excluding National Energy Group, Inc. and the 103/4% Senior Notes due from National Energy Group Inc., but including National Energy Group Inc.’s 50% membership interest in NEG Holding LLC as of December 31, 2005 and for each of the two years in the period ended December 31, 2005 included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in giving said report.
 
The estimated reserve evaluations and related calculations for our WTO properties as of December 31, 2005 and SandRidge Tertiary properties as of December 31, 2005, 2006 and 2007 have been included in this prospectus in reliance upon the report of DeGolyer and MacNaughton, independent petroleum engineering


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consultants, given upon their authority as experts in petroleum engineering. The estimated reserve evaluations and related calculations for our Piceance Basin properties as of December 31, 2005 and our WTO, East Texas, Gulf of Mexico, Gulf Coast and certain other properties as of December 31, 2006 and 2007 have been included in this prospectus in reliance upon the report of Netherland, Sewell & Associates, Inc., independent petroleum engineering consultants, given upon their authority as experts in petroleum engineering. The estimated reserve evaluations for certain of our other properties as of December 31, 2005 have been included in this prospectus in reliance upon the report of Harper & Associates, Inc., independent petroleum engineering consultants, given upon their authority as experts in petroleum engineering.
 
WHERE YOU CAN FIND MORE INFORMATION
 
We have filed with the SEC a registration statement on Form S-4 with respect to the exchange notes being offered by this prospectus. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the exchange notes offered by this prospectus, please review the full registration statement, including its exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington D.C. 20549. Copies of this material can also be obtained from the public reference section of the SEC at prescribed rates, or accessed at the SEC’s website at www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on its public reference room. In addition, we file with the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above.


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INDEX TO FINANCIAL STATEMENTS
 
         
SandRidge Energy, Inc. Audited Financial Statements
       
    F-2  
    F-3  
    F-4  
    F-5  
    F-6  
    F-7  
       
SandRidge Energy, Inc. Unaudited Financial Statements
       
    F-41  
    F-42  
    F-43  
    F-44  
    F-45  
       
NEG Oil & Gas LLC Audited Financial Statements
       
Combined Balance Sheet as of December 31, 2005
    F-60  
Combined Statements of Operations for the Years Ended December 31, 2004 and 2005
    F-61  
Combined Statements of Cash Flows for the Years Ended December 31, 2004 and 2005
    F-62  
Combined Statement of Changes in Total Member’s Equity for the Years Ended December 31, 2004 and 2005
    F-63  
Notes to Combined Financial Statements
    F-64  
NEG Oil & Gas LLC Unaudited Financial Statements
       
Combined Balance Sheets as of December 31, 2005 and September 30, 2006
    F-86  
Combined Statements of Operations for the Nine Month Periods Ended September 30, 2005 and 2006
    F-87  
Combined Statements of Cash Flows for the Nine Month Periods Ended September 30, 2005 and 2006
    F-88  
Combined Statement of Changes in Total Member’s Equity for the Nine Month Period Ended September 30, 2006
    F-89  
Notes to Combined Financial Statements
    F-90  


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Report of Independent Registered Public Accounting Firm
 
To the Board of Directors
and Stockholders of SandRidge Energy, Inc.
 
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, changes in stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of SandRidge Energy, Inc. and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
PricewaterhouseCoopers LLP
 
Houston, Texas
March 7, 2008


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SandRidge Energy, Inc. and Subsidiaries
 
Consolidated Balance Sheets
 
                 
    As of December 31,  
    2007     2006  
    (In thousands)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 63,135     $ 38,948  
Accounts receivable, net:
               
Trade
    94,741       89,774  
Related parties
    20,018       5,731  
Derivative contracts
    21,958        
Inventories
    3,993       2,544  
Deferred income taxes
    1,820       6,315  
Other current assets
    20,787       31,494  
                 
Total current assets
    226,452       174,806  
Oil and natural gas properties, using full cost method of accounting
               
Proved
    2,848,531       1,636,832  
Unproved
    259,610       282,374  
Less: accumulated depreciation and depletion
    (230,974 )     (60,752 )
                 
      2,877,167       1,858,454  
                 
Other property, plant and equipment, net
    460,243       276,264  
Derivative contracts
    270        
Investments
    7,956       3,584  
Restricted deposits
    31,660       33,189  
Other assets
    26,818       42,087  
                 
Total assets
  $ 3,630,566     $ 2,388,384  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Current maturities of long-term debt
  $ 15,350     $ 26,201  
Accounts payable and accrued expenses:
               
Trade
    215,497       129,799  
Related parties
    395       1,834  
Asset retirement obligation
    864        
Derivative contracts
          958  
                 
Total current liabilities
    232,106       158,792  
Long-term debt
    1,052,299       1,040,630  
Derivative contracts
          3,052  
Other long-term obligations
    16,817       21,219  
Asset retirement obligation
    57,716       45,216  
Deferred income taxes
    49,350       24,922  
                 
Total liabilities
    1,408,288       1,293,831  
                 
Commitments and contingencies (Note 16) 
               
Minority interest
    4,672       5,092  
Redeemable convertible preferred stock, $0.001 par value, 2,625 shares authorized, 2,184 and 2,137 shares issued and outstanding at December 31, 2007 and 2006, respectively
    450,715       439,643  
Stockholders’ equity:
               
Preferred stock, $0.001 par value; 47,375 shares authorized; no shares issued and outstanding in 2007 and 2006
           
Common stock, $0.001 par value, 400,000 shares authorized; 141,847 issued and 140,391 outstanding at December 31, 2007 and 93,048 issued and 91,604 outstanding at December 31, 2006
    140       92  
Additional paid-in capital
    1,686,113       574,868  
Treasury stock, at cost
    (18,578 )     (17,835 )
Retained earnings
    99,216       92,693  
                 
Total stockholders’ equity
    1,766,891       649,818  
                 
Total liabilities and stockholders’ equity
  $ 3,630,566     $ 2,388,384  
                 
 
The accompanying notes are an integral part of these consolidated financial statements.


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Consolidated Statements of Operations
 
                         
    Years Ended December 31,  
    2007     2006     2005  
    (In thousands, except per share amounts)  
 
Revenues:
                       
Natural gas and crude oil
  $ 477,612     $ 101,252     $ 49,987  
Drilling and services
    73,197       139,049       80,343  
Midstream and marketing
    107,765       122,896       147,133  
Other
    18,878       25,045       10,230  
                         
Total revenues
    677,452       388,242       287,693  
Expenses:
                       
Production
    106,192       35,149       16,195  
Production taxes
    19,557       4,654       3,158  
Drilling and services
    44,211       98,436       52,122  
Midstream and marketing
    94,253       115,076       141,372  
Depreciation, depletion and amortization — natural gas and crude oil
    173,568       26,321       9,313  
Depreciation, depletion and amortization — other
    53,541       29,305       14,893  
General and administrative
    61,780       55,634       11,908  
(Gain) loss on derivative contracts
    (60,732 )     (12,291 )     4,132  
(Gain) loss on sale of assets
    (1,777 )     (1,023 )     547  
                         
Total expenses
    490,593       351,261       253,640  
                         
Income from operations
    186,859       36,981       34,053  
                         
Other income (expense):
                       
Interest income
    5,423       1,109       206  
Interest expense
    (117,185 )     (16,904 )     (5,277 )
Minority interest
    276       (296 )     (737 )
Income (loss) from equity investments
    4,372       967       (384 )
                         
Total other income (expense)
    (107,114 )     (15,124 )     (6,192 )
                         
Income before income tax expense
    79,745       21,857       27,861  
Income tax expense
    29,524       6,236       9,968  
                         
Income from continuing operations
    50,221       15,621       17,893  
Income from discontinued operations (net of tax expense of $118 in 2005)
                229  
                         
Net income
    50,221       15,621       18,122  
Preferred stock dividends and accretion
    39,888       3,967        
                         
Income available to common stockholders
    10,333     $ 11,654     $ 18,122  
                         
Basic and Diluted Earnings Per Share:
                       
Income from continuing operations
  $ 0.46     $ 0.21     $ 0.31  
Income from discontinued operations, net of income tax
                0.01  
Preferred dividends
    (0.37 )     (0.05 )      
                         
Basic and diluted income per share available to common stockholders
  $ 0.09     $ 0.16     $ 0.32  
                         
Weighted average number of common shares outstanding:
                       
Basic
    108,828       73,727       56,559  
                         
Diluted
    110,041       74,664       56,737  
                         
 
The accompanying notes are an integral part of these consolidated financial statements.


F-4


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Consolidated Statements of Changes in Stockholders’ Equity
 
                                                         
                Additional
                         
    Preferred
    Common
    Paid-in
    Deferred
    Treasury
    Retained
       
    Stock     Stock     Capital     Compensation     Stock     Earnings     Total  
    (In thousands)  
 
Balance, December 31, 2004
  $ 23     $ 200     $     $     $     $ 59,108     $ 59,331  
Exchange of preferred stock for common stock
    (23 )     1       22                          
Purchase of treasury shares
          (5 )                 (17,335 )           (17,340 )
Stock split (change in par value)
          (141 )     141                          
Issuance of stock in acquisitions
          4       55,281                         55,285  
Stock offering, net of $18.0 million in offering costs
          12       173,110                         173,122  
Restricted shares
          2       15,366       (15,366 )                 2  
Amortization of deferred compensation
                      481                   481  
Net income
                                  18,122       18,122  
Dividends on preferred stock
                                  (1 )     (1 )
                                                         
Balance, December 31, 2005
          73       243,920       (14,885 )     (17,335 )     77,229       289,002  
Stock offering
                3,343                         3,343  
Change in accounting principle for stock-based compensation
                (14,885 )     14,885                    
Issuance of stock in acquisitions
          13       236,271                         236,284  
Stock offering, net of $3.9 million in offering costs
          6       97,427                           97,433  
Stock-based compensation
                8,792                         8,792  
Accretion on redeemable convertible preferred stock
                                  (157 )     (157 )
Purchase of treasury shares
                            (500 )           (500 )
Net income
                                  15,621       15,621  
                                                         
Balance, December 31, 2006
          92       574,868             (17,835 )     92,693       649,818  
Stock offerings, net of $4.5 million in offering costs
          50       1,113,314                         1,113,364  
Conversion of common stock to redeemable convertible preferred stock
          (1 )     (9,650 )                       (9,651 )
Accretion on redeemable convertible preferred stock
                                  (1,421 )     (1,421 )
Purchase of treasury stock
          (1 )                 (1,660 )           (1,661 )
Common stock issued under retirement plan
                379             917             1,296  
Stock-based compensation
                7,202                         7,202  
Net income
                                  50,221       50,221  
Redeemable convertible preferred stock dividend
                                  (42,277 )     (42,277 )
                                                         
Balance, December 31, 2007
  $     $ 140     $ 1,686,113     $     $ (18,578 )   $ 99,216     $ 1,766,891  
                                                         
 
The accompanying notes are an integral part of these consolidated financial statements.


F-5


Table of Contents

SandRidge Energy, Inc. and Subsidiaries
 
Consolidated Statements of Cash Flows
 
                         
    Years Ended December 31,  
    2007     2006     2005  
    (In thousands)  
 
CASH FLOWS FROM OPERATING ACTIVITIES:
                       
Net income
  $ 50,221     $ 15,621     $ 18,122  
Income from discontinued operations, net of tax
                229  
                         
Income from continuing operations
    50,221       15,621       17,893  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Provision for doubtful accounts
          2,528       33  
Depreciation, depletion and amortization
    227,109       55,626       24,206  
Debt issuance cost amortization
    15,998       299        
Deferred income taxes
    28,923       348       9,460  
Provision for inventory obsolescence
    203              
Unrealized (gain) loss on derivatives
    (26,238 )     1,878       1,296  
(Income) loss on sale of assets
    (1,777 )     (1,023 )     547  
Interest income — restricted deposits
    (1,354 )     (151 )      
(Gain) loss from equity investments, net of distributions
    (4,372 )     (956 )     846  
Stock-based compensation
    7,202       8,792       481  
Minority interest
    (276 )     296       737  
Changes in operating assets and liabilities increasing (decreasing) cash:
                       
Receivables
    (19,061 )     (2,648 )     (25,494 )
Inventories
    (1,730 )     (938 )     (46 )
Other current assets
    12,374       (22,238 )     (1,146 )
Other assets and liabilities, net
    (5,069 )     (2,131 )     775  
Accounts payable and accrued expenses
    75,299       12,046       33,709  
                         
Net cash provided by operating activities by continuing operations
    357,452       67,349       63,297  
Net cash provided by operating activities by discontinued operations
                347  
                         
Net cash provided by operating activities
    357,452       67,349       63,644  
                         
CASH FLOWS FROM INVESTING ACTIVITIES:
                       
Capital expenditures for property, plant and equipment
    (1,280,848 )     (306,541 )     (134,596 )
Acquisitions of assets, net of cash received of $0, $21,100 and $66
    (116,650 )     (1,054,075 )     (21,247 )
Proceeds from sale of assets
    9,034       19,742       3,327  
Proceeds from sale of investments
          2,373       413  
Contributions on equity investments
          (3,388 )     (1,350 )
Refunds of restricted deposits
    10,328              
Fundings of restricted deposits
    (7,445 )     (1,051 )      
Restricted cash
          2,373       (2,373 )
                         
Net cash used in investing activities for continuing operations
    (1,385,581 )     (1,340,567 )     (155,826 )
Net cash used in investing activities for discontinued operations
                (1,473 )
                         
Net cash used in investing activities
    (1,385,581 )     (1,340,567 )     (157,299 )
                         
CASH FLOWS FROM FINANCING ACTIVITIES:
                       
Proceeds from borrowings
    1,331,541       1,261,910       247,460  
Repayments of borrowings
    (1,332,219 )     (518,870 )     (301,285 )
Dividends paid-preferred
    (33,321 )           (1 )
Minority interests contributions (distributions)
    (144 )     (618 )     7,117  
Proceeds from issuance of common stock
    1,114,660       100,776       173,122  
Proceeds from issuance of redeemable convertible preferred stock
          439,486        
Purchase of treasury shares
    (1,661 )     (500 )      
Debt issuance costs
    (26,540 )     (15,749 )      
                         
Net cash provided by financing activities for continuing operations
    1,052,316       1,266,435       126,413  
Net cash provided by financing activities for discontinued operations
                 
                         
Net cash provided by financing activities
    1,052,316       1,266,435       126,413  
                         
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    24,187       (6,783 )     32,758  
CASH AND CASH EQUIVALENTS, beginning of year
    38,948       45,731       12,973  
                         
CASH AND CASH EQUIVALENTS, end of year
  $ 63,135     $ 38,948     $ 45,731  
                         
Supplemental Disclosure of Cash Flow Information:
                       
Cash paid for interest, net of amounts capitalized
  $ 83,567     $ 15,079     $ 7,222  
Cash paid for income taxes
    2,371       1,599        
Supplemental Disclosure of Noncash Investing and Financing Activities:
                       
Redeemable convertible preferred stock dividends, net of dividends paid
  $ 8,956     $     $  
Insurance premium financed
    1,496       5,023       2,133  
Accretion on redeemable convertible preferred stock
    1,421       157        
Common stock issued in connection with acquisitions
          236,284       55,285  
Assumption of restricted deposits and notes payable in connection with acquisition
          313,628        
Assets disposed in exchange for common stock
                17,335  
 
The accompanying notes are an integral part of these consolidated financial statements.


F-6


Table of Contents

SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements
 
1.   Summary of Significant Accounting Policies
 
Nature of Business.  SandRidge Energy, Inc. and its subsidiaries (formerly known as Riata Energy, Inc.) (collectively, the “Company” or “SandRidge”) is an oil and gas company with its principal focus on exploration, development and production related to oil and gas activities. SandRidge also owns and operates drilling rigs and provides related oil field services, midstream gas services operations, and CO2 and tertiary oil recovery operations. SandRidge’s primary exploration, development and production areas are concentrated in West Texas. The Company also operates significant interests in the Cotton Valley Trend in East Texas, Gulf Coast area, the Gulf of Mexico, Oklahoma, and the Piceance Basin in Colorado.
 
On November 21, 2006, the Company acquired all of the outstanding membership interests of NEG Oil & Gas LLC (“NEG”) (See Note 2).
 
Principles of Consolidation.  The consolidated financial statements include the accounts of SandRidge Energy, Inc. and its wholly owned or majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
 
Reclassifications.  Certain reclassifications have been made in prior period financial statements to conform with current period presentation.
 
Use of Estimates.  The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 
Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploitation and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect the Company’s future depletion, depreciation and amortization expenses.
 
The Company’s revenue, profitability, and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, regulatory developments and competition from other energy sources. The energy markets have historically been volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced.
 
Cash and Cash Equivalents.  The Company considers all highly-liquid instruments with a maturity of three months or less when purchased to be cash equivalents. Those securities are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period.
 
Restricted Cash.  Restricted cash of approximately $2.4 million at December 31, 2005 was pledged as collateral on certain bank debt. The restriction was released in April 2006.
 
Accounts Receivable, Net.  The Company has receivables for sales of oil, gas and natural gas liquids, as well as receivables related to the exploration and extraction services for oil, gas and natural gas liquids. Management has established an allowance for doubtful accounts. The allowance is evaluated by management


F-7


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
and is based on management’s periodic review of the collectibility of the receivables in light of historical experience, the nature and volume of the receivables, and other subjective factors.
 
Inventories.  Inventories consist of oil field services supplies and are stated at the lower of cost or market with cost determined on an average cost basis.
 
Debt Issue Costs.  The Company amortizes debt issue costs related to its senior credit facility, senior bridge facility and term loans as interest expense over the scheduled maturity period of the debt. Unamortized debt issuance costs were approximately $26.0 million as of December 31, 2007 and approximately $15.5 million as of December 31, 2006. The Company includes those unamortized costs in other assets.
 
Revenue Recognition and Gas Balancing.  Oil and natural gas revenues are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby the Company recognizes revenue on all oil and natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the oil and natural gas sold. Liabilities are recorded by the Company for imbalances greater than the Company’s proportionate share of remaining estimated oil and natural gas reserves. The Company has recorded a liability for gas imbalance positions related to gas properties with insufficient proved reserves of $1.6 million and $0.9 million at December 31, 2007 and 2006, respectively. The Company includes the gas imbalance positions in other long-term obligations.
 
The Company recognizes revenues and expenses generated from “daywork” drilling contracts as the services are performed, because the Company does not bear the risk of completion of the well. Under “footage” and “turnkey” contracts, the Company bears the risk of completion of the well; therefore, revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The duration of all three types of contracts ranges typically from 20 to 90 days. The entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on “turnkey” contracts that are still in process at the end of the period.
 
The Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one market to another are recognized over the term of the related drilling contract. The contract terms are typically from 20 to 90 days.
 
Revenues from the midstream services segment are derived from providing gathering, compression, treating, processing, transportation, balancing and sales services for producers and wholesale customers on natural gas pipelines, as well as other interconnected pipeline systems. Midstream gas services are primarily undertaken to realize incremental margins on gas purchased at the wellhead, and provide value-added services to customers. In general, natural gas purchased and sold by the midstream gas business is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Revenues are recognized upon delivery of natural gas to customers and/or when services are rendered, pricing is determinable and collectibility is reasonably assured.
 
Revenue from sales of CO2 is recognized when the product is delivered to the customer. The Company recognizes service fees related to the transportation of CO2 as revenue when the related service is provided.
 
Environmental Costs.  Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. Environmental costs accrued at December 31, 2007 and 2006 were not material.
 
Oil and Natural Gas Operations.  The Company uses the full cost method to account for its natural gas and oil properties. Under full cost accounting, all costs directly associated with the acquisition, exploration


F-8


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
and development of natural gas and oil reserves are capitalized into a “full cost pool.” These capitalized costs include costs of all unproved properties, internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. During 2007, the Company capitalized internal costs and interest expenses of $4.6 million and $0.3 million, respectively, to the full cost pool. No internal costs or interest expense was capitalized to the full cost pool in 2006 or 2005.
 
Capitalized costs are amortized using a unit-of-production method. Under this method, the provision for depreciation, depletion and amortization is computed at the end of each quarter by multiplying total production for such quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.
 
Costs associated with unproved properties are excluded from the total unamortized cost base until a determination has been made as to the existence of proved reserves. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and, thereby, subject to amortization. Sales and abandonments of natural gas and oil properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved natural gas and oil reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the reserve quantities of a cost center.
 
Under full cost accounting, total capitalized costs of natural gas and oil properties (net of accumulated depreciation, depletion and amortization) less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unevaluated properties, plus estimated salvage value, less income tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date.
 
The ceiling test is calculated using natural gas and oil prices in effect as of the balance sheet date, as adjusted for “basis” or location differentials as of the balance sheet date and held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of natural gas and oil. The Company may, from time-to-time, use derivative financial instruments to hedge against the volatility of natural gas prices. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows. Historically, the Company has not designated any of its derivative contracts as cash flow hedges. In addition, the future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling test calculation.
 
The costs associated with unproved properties are not initially included in the amortization base and relate to unproved leasehold acreage, wells and production facilities in progress and wells pending determination of the existence of proved reserves, together with capitalized interest costs for these projects. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination of the existence of proved reserves has been made or upon impairment of a lease. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and completed wells that have yet to be evaluated are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful.


F-9


Table of Contents

 
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 the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
 
Property, Plant and Equipment, Net.  Other capitalized costs, including drilling equipment, natural gas gathering and processing equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the straight-line method based on estimated useful lives. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 39 years.
 
Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in such estimates could cause the Company to reduce the carrying value of property and equipment.
 
When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations.
 
Investments.  Investments in affiliated companies are accounted for under the cost or equity method, based on the Company’s ability to exercise significant influence.
 
Asset Retirement Obligation.  The Company owns oil and natural gas properties which require expenditures to plug and abandon the wells when the oil and natural gas reserves in the wells are depleted. These expenditures are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). Asset retirement obligations are recorded as a liability at their estimated present value at the asset’s inception, with the offsetting increase to property cost. Periodic accretion expense of the estimated liability is recorded in the statements of operations.
 
Asset retirement obligations primarily represent the Company’s estimate of fair value to plug, abandon and remediate the oil and natural gas properties at the end of their productive lives, in accordance with applicable state laws. The Company has determined its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating the future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability, and what constitutes adequate restoration. Inherent in the present value calculation rates, are the timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding


F-10


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
adjustment is made to the related asset. The following is a reconciliation of the asset retirement obligation for the years ended December 31 (in thousands).
 
                         
    2007     2006     2005  
 
Asset retirement obligation, January 1
  $ 45,216     $ 6,979     $ 4,394  
Liability incurred upon acquiring and drilling wells
    3,265       2,996       2,779  
NEG acquisition
          40,343        
Revisions in estimated cash flows
    5,971       (5,700 )      
Liability settled in current period
    (9 )           (512 )
Accretion of discount expense
    4,137       598       318  
                         
Asset retirement obligation, December 31
    58,580       45,216       6,979  
Less: current portion
    864              
                         
Asset retirement obligation, net of current
  $ 57,716     $ 45,216     $ 6,979  
                         
 
Income Taxes.  Deferred income taxes are provided on temporary differences between financial statement and income tax reporting. Temporary differences are differences between the amounts of assets and liabilities reported for financial statement purposes and their tax bases. Deferred tax assets are recognized for temporary differences that will be deductible in future years’ tax returns and for operating loss and tax credit carryforwards. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. Deferred tax liabilities are recognized for temporary differences that will be taxable in future years’ tax returns.
 
The Company accounts for uncertain tax positions in accordance with FASB Interpretation No. 48 (“FIN 48), “Accounting for Uncertainty in Income Taxes.” Accordingly, the Company reports a liability for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return. The Company recognizes interest and penalties, if any, related to unrecognized tax benefits in income tax expense.
 
Minority Interest.  As of December 31, 2007, minority interest in the Company’s consolidated subsidiaries consisted of the following:
 
  •  26.19% interest in Sagebrush Pipeline, LLC; and
 
  •  1.29% interest in Cholla Pipeline, LP.
 
Concentration of Risk.  The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation up to $100,000. From time to time, the Company may have balances in these accounts that exceed the federally insured limit. The Company does not anticipate any loss associated with balances in excess of the federally insured limit.
 
Fair Value of Financial Instruments.  For certain of the Company’s financial instruments, including cash, accounts receivable and accounts payable, the carrying value approximates fair value because of their short maturity. The carrying value of borrowings under the senior credit facility and the notes payable approximates fair value because their interest rates are based on market indexes. The fair value of the fixed portion of the Company’s senior credit facility and convertible preferred stock approximate book value as reflected in the accompanying balance sheets.
 
Derivative Financial Instruments.  To manage risks related to increases in interest rates and changes in oil and gas prices, the Company occasionally enters into interest rate swaps and oil and gas derivatives contracts.


F-11


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
The Company recognizes all of its derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship, and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, the Company designates the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. For derivative instruments not designated as hedging instruments, the gain or loss is recognized in current earnings during the period of change. None of the Company’s derivatives were designated as hedging instruments during 2007, 2006 and 2005.
 
Stock-Based Compensation.  Effective January 1, 2006, the Company adopted SFAS No. 123-R, “Share-Based Payment” (“SFAS 123R”). SFAS 123R establishes the accounting for equity instruments exchanged for employee services. Under SFAS 123R, share-based compensation cost is measured at the grant date based on the calculated fair value of the award. The expense is recognized over the employees’ requisite service period, generally the vesting period of the award. SFAS 123R also requires the related excess tax benefit received upon exercise of stock options or vesting of restricted stock, if any, to be reflected in the statement of cash flows as a financing activity rather than an operating activity. The Company does not have any excess tax benefits.
 
Recent Accounting Pronouncements.  In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S generally accepted accounting principles to be measured at fair value. SFAS No. 157 clarifies guidance in FASB Concepts Statement No. 7 which discusses present value techniques in measuring fair value. Additional disclosures are also required for transactions measured at fair value. No new fair value measurements are prescribed, and SFAS No. 157 is intended to codify the several definitions of fair value included in various accounting standards. However, the application of this Statement may change current practices for certain companies. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. The Company will implement SFAS No. 157 on January 1, 2008. The Company continues to evaluate the impact of SFAS No. 157 on the consolidated financials statements.
 
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option For Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115,” which permits an entity to choose to measure certain financial assets and liabilities at fair value. SFAS No. 159 also revises provisions of SFAS No. 115 that apply to available-for-sale and trading securities. This statement is effective for fiscal years beginning after November 15, 2007. We do not believe the adoption of SFAS No. 159 will have a material impact on our consolidated financial position, results of operations, or cash flows.
 
In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations,” which replaces SFAS No. 141. SFAS No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008. The Company plans to implement this standard on January 1, 2009. The Company has not yet evaluated the potential impact of this standard.
 
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of Accounting Research Bulletin No. 51,” which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. The Statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. The Company plans to implement this standard on January 1, 2009. The Company has not evaluated the potential impact of this standard.


F-12


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
2.   Acquisitions and Dispositions
 
2005 Acquisitions
 
The Company closed the following acquisitions in 2005:
 
  •  Acquired additional equity interests in PetroSource Energy Company, LLC (“PetroSource”), which increased the Company’s ownership from 22.4% to 86.5%, resulting in the consolidation of PetroSource in the Company’s financial statements;
 
  •  Acquired from an executive officer and director the remaining 50% equity interest in the Company’s compression services subsidiary, Lariat Compression Company (“Larco”), resulting in it becoming a wholly-owned subsidiary;
 
  •  Acquired from an executive officer and director approximately 7,400 net acres of additional leasehold interest in West Texas in properties in which the Company previously held interests;
 
  •  Acquired approximately 2,503 net acres additional leasehold interest in property in the Piceance Basin in which the Company previously held interests;
 
  •  Acquired from a director additional working interests in Missouri and Nevada leases in which the Company previously held interests;
 
  •  Acquired an additional 19.5% before pay-out interest in the Company’s subsidiary, Sagebrush Pipeline LLC; and
 
  •  Acquired certain interests in several oil and natural gas properties in West Texas from Carl E. Gungoll Exploration, LLC and certain other parties. The purchase price was approximately $8.0 million, comprised of $5.4 million in cash, and 174,833 shares of common stock (valued at $2.6 million).
 
The acquisitions were financed with approximately $21.3 million in cash and the issuance of 3,685,690 shares of common stock with an aggregate value of approximately $55.3 million. Details are set forth below for each of the acquisition transactions (in thousands):
 
                                                         
    Addition to
                      Consideration Paid  
    Property,
                Change in
    Common
    Common
    Cash, Net of
 
    Plant &
    Addition to
    Elimination of
    Minority
    Stock No. of
    Stock at
    Cash
 
Acquisition Transaction
  Equipment     Net Assets(1)     Investments     Interest     Shares     $15/Share     Acquired  
 
PetroSource additional interests
  $ 73,744     $ (37,381 )   $ (3,052 )   $ 3,253       958     $ 14,372     $ 15,686  
Larco remaining interest
    5,054                   (2,446 )     500       7,500        
West Texas additional lease interests
    10,000                         667       10,000        
Piceance Basin additional interests
    17,565                         1,164       17,456       109  
Various additional lease interests
    268                         17       268        
Sagebrush additional interests
    689                   (2,378 )     204       3,067        
Gungoll lease interests
    8,074                         176       2,622       5,452  
                                                         
Totals
  $ 115,394     $ (37,381 )   $ (3,052 )   $ (1,571 )     3,686     $ 55,285     $ 21,247  
                                                         
 
 
(1) The purchase price for additional interests in PetroSource was approximately $30.1 million, comprised of $15.7 million in cash (net of $0.1 million in cash acquired), and approximately 958,000 shares of


F-13


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
SandRidge common stock (valued at $14.4 million). The purchase price has been allocated to accounts receivable of $4.5 million, other current assets of $0.1 million, other assets of $0.4 million, accounts payable and accrued expenses of $2.6 million, long-term debt of $37.4 million, and asset retirement obligations of $2.4 million.
 
The Company completed its purchase accounting allocations for the 2005 acquisitions in 2006 and recorded an additional $3.8 million deferred tax liability related to the Larco equity acquisition.
 
2006 Acquisitions and Dispositions
 
The Company closed the following acquisitions in 2006:
 
  •  On March 15, 2006, the Company acquired from an executive officer and director, an additional 12.5% interest in PetroSource. The acquisition consisted of the retirement of subordinated debt of approximately $1.0 million and a $4.5 million cash payment for the ownership interest acquired for a total acquisition price of approximately $5.5 million.
 
  •  On May 1, 2006, the Company purchased certain leases in developed and undeveloped properties from an oil and gas company. The purchase price was approximately $40.9 million in cash. The cash consideration was paid in July 2006.
 
  •  On May 26, 2006, the Company purchased several oil and natural gas properties from an oil and gas company. The purchase price was approximately $12.9 million, comprised of $8.2 million in cash, and 251,351 shares of Company common stock (valued at $4.7 million). The cash and equity consideration was paid in July 2006.
 
  •  On June 1, 2006, the Company purchased certain producing well interests from an executive officer and director. The purchase price was approximately $9.0 million in cash.
 
  •  On June 7, 2006, the Company acquired the remaining 1% interest in PetroSource Energy Company, a consolidated subsidiary, from an oil and gas company. The purchase price was 27,749 shares of Company common stock (valued at $0.5 million). As a result of this acquisition, the Company became the 100% owner of PetroSource.
 
The 2006 acquisitions described above were financed with approximately $63.7 million in cash and the issuance of 279,100 shares of common stock with an aggregate value of approximately $5.1 million. Details are set forth below for each of the acquisition transactions (in thousands):
 
                                                 
    Addition to
          Consideration Paid  
    Property,
    Change in
    Retirement of
    Common
             
    Plant &
    Minority
    Subordinated
    Stock No. of
    Common
       
Acquisition Transaction
  Equipment     Interest     Debt(1)     Shares     Stock     Cash  
 
PetroSource additional interests
  $ 2,116     $ (2,370 )   $ (1,003 )         $     $ 5,489  
Purchased leases
    40,960                               40,960  
Oil and natural gas properties
    12,850                   251       4,650       8,200  
Producing well interest from executive officer and director
    9,000                               9,000  
PetroSource additional interest (remaining 1% interest)
    85       (393 )           28       478        
                                                 
Totals
  $ 65,011     $ (2,763 )   $ (1,003 )     279     $ 5,128     $ 63,649  
                                                 
 
 
(1) Includes retirement of subordinated debt of $972,000 and accrued interest of $31,000.


F-14


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
 
In July 2006, the Company sold leaseholds and lease and well equipment for $16.0 million. The book basis of the assets at the time of the sale transaction was $3.7 million resulting in a gain of $12.3 million. The sale was accounted for as an adjustment to the full cost pool, with no gain recognized.
 
On November 21, 2006, the Company acquired all of the outstanding membership interests in NEG Oil & Gas, or NEG, for approximately $990.4 million in cash, the assumption of $300.0 million in debt, the receipt of cash of $21.1 million, and the issuance of 12,842,000 shares of the Company’s common stock (valued at approximately $231.2 million). With core assets in the Val Verde and Permian Basins of West Texas, including overlapping or contiguous interests in the WTO, the NEG acquisition has dramatically increased our exploration and production segment operations. To finance the NEG acquisition, the Company entered into a new $750 million senior credit facility and an $850 million senior unsecured bridge loan facility. The Company also issued $550 million of redeemable convertible preferred stock and common units (consisting of shares of common stock and a warrant to purchase convertible preferred stock upon the surrender of the common stock) in a private placement to certain eligible purchasers.
 
In the fourth quarter of 2007, we completed our valuation of assets acquired and liabilities assumed related to the NEG acquisition and allocated the appropriate fair values. Upon further refinement of the appraisal values, we have increased our values assigned to the properties acquired and reduced the value assigned to goodwill of $26.2 million. The accompanying balance sheet at December 31, 2006 includes the preliminary allocations of the purchase price for the NEG acquisition. The allocation of the purchase price to specific assets and liabilities were based, in part, upon an appraisal of the fair value of NEG assets.
 
The following table presents the final NEG acquisition purchase price allocation, including professional fees and other related acquisition costs, to the net assets acquired and liabilities assumed, based on the fair values at the acquisition date and including subsequent adjustments to the purchase price allocation (in thousands):
 
         
Cash and cash equivalents
  $ 21,100  
Accounts receivable
    30,840  
Other current assets
    6,025  
Property, plant and equipment
    1,524,072  
Restricted deposits
    31,987  
Other assets
    270  
         
Total assets acquired
    1,614,294  
Accounts payable and other current liabilities
    46,082  
Deferred income taxes
    2,189  
Long-term debt
    281,641  
Other long-term obligations
    1,357  
Asset retirement obligation
    40,343  
         
Net assets acquired
    1,242,682  
Less: Cash and cash equivalents acquired
    (21,100 )
         
Net amount paid for acquisition
  $ 1,221,582  
         
 
Pro Forma Information
 
The unaudited financial information in the table below summarizes the combined results of operations of SandRidge and NEG, on a pro forma basis, as though the companies had been combined as of January 1, 2005. The pro forma financial information is presented for informational purposes only and is not indicative of


F-15


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
the results of operations that would have been achieved if the acquisition had taken place on January 1, 2005 or of results that may occur in the future. The pro forma adjustments include estimates and assumptions based on currently available information. The Company believes the estimates and assumptions are reasonable, and the significant effects of the transactions are properly reflected. However, actual results may differ materially from this pro forma financial information. The following table presents the actual results for the years ended December 31, 2006 and 2005 and the respective unaudited pro forma information to reflect the NEG acquisition (in thousands, except per share amounts):
 
                                 
    Year Ended December 31,  
    2006     2005  
    Actual     Pro Forma     Actual     Pro Forma  
          (Unaudited)        
 
Revenues
  $ 388,242     $ 565,256     $ 287,693     $ 560,235  
Income (loss) from continuing operations
    15,621       36,337       17,893       (49,594 )
Net income (loss)
    15,621       36,337       18,122       (49,594 )
Basic and diluted earnings per share available (applicable) to common stockholders:
                               
Income (loss) from continuing operations
  $ 0.21     $ 0.40     $ 0.31     $ (0.96 )
Net income (loss) available to common stockholders
  $ 0.16     $ 0.04     $ 0.32     $ (0.96 )
 
2007 Acquisitions
 
The Company closed the following acquisitions in 2007:
 
  •  On October 9, 2007, the Company purchased developed and undeveloped properties located in West Texas from an oil and gas company. The purchase price was approximately $73.8 million, comprised of $25.0 million in cash and a $48.8 million note payable. The $25 million cash consideration paid was funded through a draw on the Company’s senior credit facility. All principal and accrued interest (interest at 7% annually) due on the note payable were repaid on November 9, 2007 with proceeds from the Company’s initial public offering. For additional discussion of the Company’s initial public offering, refer to Note 18 herein.
 
  •  On November 28, 2007, the Company purchased a gas treatment plant and related gathering system located in Pecos County, Texas. The purchase price of approximately $10.0 million was paid in cash.
 
  •  On November 29, 2007, the Company purchased leasehold acreage and producing well interests located predominantly in the WTO from a group of entities controlled by a significant shareholder. The purchase price of approximately $32.0 million was paid in cash.
 
3.   Discontinued Operations
 
On September 30, 2005, the Company exchanged substantially all of its land and agriculture operations with its majority shareholder. The majority shareholder exchanged 1,414,849 shares of the Company’s common stock for these operations. The shares were exchanged at their historical basis and the exchange was reflected as a treasury share transaction. The net book value of assets exchanged was $23.6 million. There was no gain (loss) recognized in this transaction. The land and agriculture operations are presented as discontinued operations, net of income taxes in the consolidated statements of operations.


F-16


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
The following table summarizes net revenue and net income from discontinued operations for the years ended December 31 (in thousands):
 
                         
    2007     2006     2005  
 
Revenues
  $     $     $ 1,683  
Operating expenses
                (1,336 )
                         
Income from discontinued operations
                347  
Income tax expense
                (118 )
                         
Net income from discontinued operations
  $     $     $ 229  
                         
 
No assets were classified as held for sale at December 31, 2007 or 2006.
 
4.   Accounts Receivable
 
A summary of accounts receivable is as follows (in thousands):
 
                 
    December 31,  
    2007     2006  
 
Oil and natural gas services
  $ 6,622     $ 8,489  
Oil and natural gas sales
    72,393       57,458  
Joint interest billing
    17,874       26,553  
Other
    90       299  
                 
      96,979       92,799  
Less allowance for doubtful accounts
    (2,238 )     (3,025 )
                 
Total accounts receivable, net
  $ 94,741     $ 89,774  
                 
 
The following tables show the balance in the allowance for doubtful accounts and activity for the years ended December 31 (in thousands).
 
                                 
          Additions
             
    Balance at
    Charged to
          Balance at
 
    Beginning of
    Costs and
          End of
 
Allowance for Doubtful Accounts
  Period     Expenses     Deductions(1)     Period  
 
Year ended December 31, 2005
  $ 1,074     $ 33     $ (256 )   $ 851  
Year ended December 31, 2006
  $ 851     $ 2,528     $ (354 )   $ 3,025  
Year ended December 31, 2007
  $ 3,025     $     $ (787 )   $ 2,238  
 
 
(1) Deductions represent the write-off/recovery of receivables.


F-17


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
 
5.   Other Current Assets
 
Other current assets consist of the following (in thousands):
 
                 
    December 31,  
    2007     2006  
 
Prepaid insurance
  $ 9,379     $ 7,604  
Prepaid drilling
    5,924       2,207  
Materials and supplies
    4,751       6,244  
Post closing receivable — NEG acquisition
          15,232  
Other
    733       207  
                 
Total other current assets
  $ 20,787     $ 31,494  
                 
 
6.  Property, Plant and Equipment
 
Property, plant and equipment consists of the following (in thousands):
 
                 
    December 31,  
    2007     2006  
 
Oil and natural gas properties:
               
Proved
  $ 2,848,531     $ 1,636,832  
Unproved
    259,610       282,374  
                 
Total oil and natural gas properties
    3,108,141       1,919,206  
Less accumulated depreciation and depletion
    (230,974 )     (60,752 )
                 
Net oil and natural gas properties capitalized costs
    2,877,167       1,858,454  
                 
Land
    1,149       738  
Non oil and gas equipment
    539,893       337,294  
Buildings and structures
    38,288       6,564  
                 
Total
    579,330       344,596  
Less accumulated depreciation, depletion and amortization
    (119,087 )     (68,332 )
                 
Net capitalized costs
    460,243       276,264  
                 
Total property, plant and equipment
  $ 3,337,410     $ 2,134,718  
                 
 
The amount of capitalized interest included in the above non oil and gas equipment balance at December 31, 2007 and 2006 was approximately $3.4 million and $1.4 million, respectively. The Company did not capitalize any interest in 2005.
 
On July 11, 2007, the Company purchased property to serve as its future corporate headquarters. The 3.51-acre site contains four buildings and is located in downtown Oklahoma City, Oklahoma. The purchase price was approximately $29.5 million in cash. Payment of the purchase price was funded through a draw on the Company’s senior credit facility.
 
Costs Excluded from Amortization
 
Costs associated with unproved properties related to continuing operations of $259.6 million as of December 31, 2007 are excluded from amounts subject to amortization. A summary of costs related to


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
unproved properties which have been excluded from oil and natural gas properties being amortized at December 31, 2007 and the year in which they were incurred is as follows:
 
                                         
                            Excluded
 
    Year Cost Incurred     Costs at
 
    Prior
                      December 31,
 
    Years     2005     2006     2007     2007  
 
Property acquisition
  $     $     $ 259,610     $     $ 259,610  
Exploration
                             
Development
                             
Capitalized interest
                             
                                         
Total costs incurred
  $     $     $ 259,610     $     $ 259,610  
                                         
 
The majority of the evaluation activities are expected to be completed within a four-year period. In addition, the Company’s internal engineers evaluate all properties on an annual basis. The average composite rates used for depreciation, depletion and amortization were $2.64 per Mcfe in 2007, $1.68 per Mcfe in 2006 and $1.23 per Mcfe in 2005.
 
7.   Investment in Affiliated Companies
 
The Company has certain investments that it accounts for under the equity method of accounting because it owns more than 20% and has significant influence but does not control. The equity method investments include the following:
 
Grey Ranch, L.P.  Grey Ranch is primarily engaged in process and transportation of gas and natural gas liquids. The Company purchased its investment during 2003. At December 31, 2007 and 2006, the Company owned 50% of Grey Ranch, L.P. and had approximately $4,176,000 and $2,201,000, respectively, recorded in the consolidated balance sheets relating to this investment. The Company contributed a disproportionate amount of capital into the partnership, amounting to approximately $750,000, as of December 31, 2007 and 2006. The excess amount contributed is being amortized over the average life of the partnership’s long-lived assets.
 
Larclay, L.P.  The Company and Clayton Williams Energy, Inc. (“CWEI”) each own a 50% interest in Larclay, L.P., a limited partnership formed to acquire drilling rigs and provide land drilling services. The Company purchased its investment in 2006 and accounts for it under the equity method of accounting. The Company serves as the operations manager of the partnership. CWEI was responsible for securing the financing and purchasing the rigs. The partnership financed 100% of the acquisition cost of the rigs through a guarantee by CWEI. At December 31, 2007 and 2006, the Company had approximately $3,780,000 and $1,383,000, respectively, recorded in the consolidated balance sheets relating to this investment.
 
8.   Restricted Deposits
 
Restricted deposits represent bank trust and escrow accounts required by the U.S. Department of Interior’s Minerals Management Service, surety bond underwriters, purchase agreements or other settlement agreements to satisfy the Company’s eventual responsibility to plug and abandon wells and remove structures when certain offshore fields are no longer in use. These restricted deposits were acquired as part of the NEG acquisition in November 2006 (See Note 2).


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
In connection with one of these agreements, the Company is required to make scheduled quarterly deposits of $0.8 million to an escrow account. Aggregate scheduled fundings under this agreement are as follows (in thousands):
 
         
 
Years ending December 31:
       
2008
  $ 3,200  
2009
    3,200  
2010 and none thereafter
    2,586  
 
Additionally, two of the agreements require us to deposit additional funds in an escrow account equal to 10% of the net proceeds, as defined, from certain of our offshore properties. During 2007, we deposited approximately $5.8 million in these escrow accounts.
 
During 2007, we were released from obligations under two of these escrow agreements. As a result, funds totaling $10.3 million were released from escrow accounts and returned to the Company.
 
9.   Accounts Payable and Accrued Expenses
 
Accounts payable and accrued expenses consist of the following (in thousands):
 
                 
    December 31,  
    2007     2006  
 
Accounts payable-trade
  $ 154,423     $ 103,683  
Redeemable convertible preferred stock dividends
    8,956        
Payroll and benefits
    15,690       10,718  
Drilling advances
    5,817       5,318  
Legal (current)
    5,000       5,000  
Accrued interest
    24,201       3,850  
Other
    1,410       1,230  
                 
Total accounts payable and accrued expenses
  $ 215,497     $ 129,799  
                 
 
10.   Long-Term Debt
 
Long-term obligations consist of the following (in thousands):
 
                 
    December 31,  
    2007     2006  
 
Senior term loans
  $ 1,000,000     $  
Senior credit facility
          140,000  
Senior bridge facility
          850,000  
Other notes payable:
               
Drilling rig fleet and related oil field services equipment
    47,836       61,105  
Mortgage
    19,651        
Sagebrush
          4,000  
Insurance financing
          7,240  
Other equipment and vehicles
    162       4,486  
                 
Total debt
    1,067,649       1,066,831  
Less: Current maturities of long-term debt
    15,350       26,201  
                 
Long-term debt
  $ 1,052,299     $ 1,040,630  
                 


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
Senior Credit Facility.  On November 21, 2006, the Company entered into a $750 million senior secured revolving credit facility (the “senior credit facility”). The senior credit facility matures on November 21, 2011.
 
The proceeds of the senior credit facility were used to (i) partially finance the NEG acquisition, (ii) refinance the existing senior secured revolving credit facility and NEG’s existing credit facility, and (iii) pay fees and expenses related to the NEG acquisition and the existing credit facility. Future borrowings under the senior credit facility will be available for capital expenditures, working capital and general corporate purposes and to finance permitted acquisitions of oil and gas properties and other assets related to the exploration, production and development of oil and gas properties. The senior credit facility will be available to be drawn on and repaid without restriction so long as the Company is in compliance with its terms, including certain financial covenants.
 
The senior credit facility contains various covenants that limit the Company and certain of its subsidiaries’ ability to grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. Additionally, the senior credit facility limits the Company and certain of its subsidiaries’ ability to incur additional indebtedness with certain exceptions, including under the senior term loans (as discussed below).
 
The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for the (i) ratio of total funded debt to EBITDAX (as defined in the senior credit facility), (ii) ratio of EBITDAX to interest expense plus current maturities of long-term debt, and (iii) current ratio. The Company was in compliance with these financial covenants as of December 31, 2007.
 
The obligations under the senior credit facility are secured by first priority liens on all shares of capital stock of each of the Company’s present and future subsidiaries; all intercompany debt of the Company and its subsidiaries; and substantially all of the Company assets and the assets of its guarantor subsidiaries, including proved oil and natural gas reserves representing at least 80% of the present discounted value (as defined in the senior credit facility) of proved oil and natural gas reserves reviewed in determining the borrowing base for the senior credit facility. Additionally, the obligations under the senior credit facility are guaranteed by certain Company subsidiaries.
 
At the Company’s election, interest under the senior credit facility is determined by reference to (i) the LIBOR rate plus an applicable margin between 1.25% and 2.00% per annum or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin between 0.25% and 1.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average interest rate paid on amounts outstanding under our senior credit facility for the year ended December 31, 2007 was 7.34%.
 
The borrowing base of proved reserves was initially set at $300.0 million. As of December 31, 2006, the Company had $140.0 million of outstanding indebtedness on the senior credit facility. Proceeds from the Company’s sale of common stock on March 20, 2007, as described in Note 18, were used to pay outstanding borrowings under the Company’s senior credit facility.
 
The borrowing base was increased to $400.0 million on May 2, 2007, and to $700.0 million on September 14, 2007 where it remained at December 31, 2007. At December 31, 2007, the Company had no amounts outstanding under this facility. The Company repaid all amounts outstanding under this facility in November 2007. See Note 18 for further discussion.


F-21


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
If an event of default exists under the senior credit facility, the lenders may accelerate the maturity of the obligations outstanding under the senior credit facility and exercise other rights and remedies. Each of the following will be an event of default:
 
  •  failure to pay any principal when due or any interest, fees or other amount within certain grace periods;
 
  •  failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;
 
  •  bankruptcy or insolvency events involving the Company or its subsidiaries;
 
  •  a change of control (as defined in the senior credit facility).
 
Senior Bridge Facility.  On November 21, 2006, the Company also entered into a $850.0 million senior unsecured bridge facility (the “senior bridge facility”), which was repaid in March 2007. The Company expensed the remaining unamortized debt issuance costs related to the senior bridge facility of approximately $12.5 million to interest expense in March 2007.
 
Together with borrowings under the senior credit facility, the proceeds from the senior bridge facility were used to (i) partially finance the NEG acquisition, (ii) refinance existing senior secured revolving credit facility and NEG’s existing credit facility, and (iii) pay fees and expenses related to the NEG acquisition and the existing credit facility.
 
Senior Term Loans.  On March 22, 2007, the Company entered into $1.0 billion in senior unsecured term loans (the “senior term loans”). The closing of the senior term loans was generally contingent upon closing the private placement of common equity as described in Note 18. The senior term loans include both floating rate term loans and fixed rate term loans.
 
The Company issued $350.0 million at a variable rate with interest payable quarterly and principal due on April 1, 2014 (the “variable rate term loans”). The variable rate term loans bear interest, at the Company’s option, at the British Bankers Association LIBOR rate plus 3.625% or the higher of (i) the federal funds rate, as defined, plus 3.125% or (ii) a bank’s prime rate plus 2.625%. After April 1, 2009 the variable rate term loans may be prepaid in whole or in part with certain prepayment penalties. The average interest rates paid on amounts outstanding under the Company’s variable term loans for the year ended December 31, 2007 was 8.94%. Subsequent to year end, the Company entered into an interest rate swap to effectively fix the interest rate related to this portion of the term loan through April 1, 2011 (See Note 20).
 
The Company issued $650.0 million at a fixed rate of 8.625% with the principal due on April 1, 2015 (the “fixed rate term loans”). Under the terms of the fixed rate term loans, interest is payable quarterly and during the first four years interest may be paid, at the Company’s option, either entirely in cash or entirely with additional fixed rate term loans. If the Company elects to pay the interest due during any period in additional fixed rate term loans, the interest rate increases to 9.375% during such period. After April 1, 2011, the fixed rate term loans may be prepaid in whole or in part with certain prepayment penalties.
 
After March 22, 2008, but not later than April 30, 2008, the Company is required to offer to exchange the senior term loans for senior unsecured notes with registration rights and with identical terms and conditions as the term loans. If the Company does not complete the exchange of the senior term loans for senior unsecured notes with registration rights by May 31, 2008, the annual interest rate on the senior term loans will increase by 0.25% every 90 days up to a maximum of 0.50%.
 
Debt covenants under the senior term loans include financial covenants similar to those of the senior credit facility and include limitations on the incurrence of indebtedness, payment of dividends, asset sales, certain asset purchases, transactions with related parties, and consolidation or merger agreements. The Company incurred $26.1 million of debt issuance costs in connection with the senior term loans. These costs


F-22


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
are included in other assets and amortized over the term of the senior term loans. A portion of the proceeds from the senior term loans was used to repay the Company’s $850.0 million senior bridge facility.
 
Other Indebtedness.  The Company has financed a portion of its drilling rig fleet and related oil field services equipment through notes. At December 31, 2007, the aggregate outstanding balance of these notes was $47.8 million, with an annual fixed interest rate ranging from 7.64% to 8.87%. The notes have a final maturity date of December 1, 2011, require aggregate monthly installments for principal and interest in the amount of $1.2 million and are secured by the equipment. The notes have a prepayment penalty (currently 1-3%) in the event the Company repays the notes prior to maturity.
 
On November 15, 2007, the Company entered into a note payable in the amount of $20 million with a lending institution as a mortgage on the downtown Oklahoma City property purchased by the Company in July 2007 (see additional discussion in Note 6). This note is fully secured by one of the buildings and a parking garage located on the downtown property, bears interest at 6.08% annually, and matures on November 15, 2022. Payments of principal and interest in the amount of approximately $0.5 million are due on a quarterly basis through the maturity date. During 2008, the Company expects to make payments of principal and interest on this note totaling $0.8 million and $1.2 million, respectively.
 
Prior to 2007, the Company financed the purchase of various vehicles, oil field services equipment and other equipment through various notes payable. The aggregate outstanding balance of these notes as of December 31, 2006 was $4.5 million. Additionally, the Company financed its insurance payment made in 2007. These notes were substantially repaid during 2007 with borrowings under our senior credit facility. Also, in 2007 we repaid a $4.0 million loan incurred in 2005 for the purpose of completing a gas processing plant and pipeline in Colorado.
 
Prior Senior Credit Facility.  On November 21, 2006, we replaced a $130 million revolving credit facility with our existing senior credit facility. The prior senior credit facility bore interest at the Company’s option at either LIBOR plus 2.15% or the Bank of America, N.A. prime rate. The Company paid a commitment fee on the unused portion of the borrowing base amount equal to 1/8% per annum. The prior senior credit facility was collateralized by natural gas and oil properties representing at least 80% of the present discounted value of the Company’s proved reserves and by a negative pledge on any of the Company’s non-mortgaged properties.
 
Maturities of Long-Term Debt.  Aggregate maturities of long-term debt during the next five years are as follows (in thousands):
 
         
 
Years ending December 31:
       
2008
  $ 15,350  
2009
    16,580  
2010
    12,476  
2011
    7,222  
2012
    1,052  
Thereafter
    1,014,969  
         
Total debt
  $ 1,067,649  
         
 
11.   Other Long-Term Obligations
 
The Company has recorded a long-term obligation for amounts to be paid under a litigation settlement agreement with Conoco, Inc. entered into in January 2007. The Company agreed to pay approximately $25.0 million plus interest, payable in $5.0 million increments on April 1, 2007, July 1, 2008, July 1, 2009, July 1, 2010, and July 1, 2011. The $5.0 million payment made in 2007 has been included in accounts


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
payable-trade in the accompanying consolidated balance sheet as of December 31, 2006, and the $5.0 million payment to be made in 2008 has been included in accounts payable-trade in the accompanying consolidated balance sheet as of December 31, 2007. Unpaid settlement amounts of approximately $15.0 million and $20.0 million have been included in other long-term obligations in the accompanying consolidated balance sheets as of December 31, 2007 and 2006, respectively.
 
12.   Derivatives
 
The Company has entered into various derivative contracts including fixed price swaps, collars and basis swaps with counterparties. The contracts expire on various dates through December 31, 2009.
 
At December 31, 2007, the Company’s open commodity derivative contracts consisted of the following:
 
                         
                Weighted Avg.
 
Period
 
Commodity
   
Notional
   
Fixed Price
 
 
Fixed price swaps:
                       
November 2007 — March 2008
    Natural gas       1,520,000 MmBtu     $ 8.51  
November 2007 — June 2008
    Natural gas       4,860,000 MmBtu     $ 8.05  
November 2007 — June 2008
    Natural gas       9,720,000 MmBtu     $ 8.20  
January 2008
    Natural gas       310,000 MmBtu     $ 8.24  
January 2008 — June 2008
    Natural gas       3,640,000 MmBtu     $ 7.99  
January 2008 — June 2008
    Natural gas       3,640,000 MmBtu     $ 7.99  
January 2008 — December 2008
    Natural gas       3,660,000 MmBtu     $ 8.23  
January 2008 — December 2008
    Natural gas       3,660,000 MmBtu     $ 8.48  
January 2008 — December 2008
    Natural gas       3,660,000 MmBtu     $ 9.00  
April 2008 — June 2008
    Natural gas       910,000 MmBtu     $ 7.17  
May 2008 — August 2008
    Natural gas       2,460,000 MmBtu     $ 8.38  
July 2008
    Natural gas       310,000 MmBtu     $ 8.00  
July 2008
    Natural gas       310,000 MmBtu     $ 8.02  
July 2008 — September 2008
    Natural gas       920,000 MmBtu     $ 7.43  
July 2008 — September 2008
    Natural gas       920,000 MmBtu     $ 7.49  
July 2008 — September 2008
    Natural gas       920,000 MmBtu     $ 8.06  
July 2008 — September 2008
    Natural gas       920,000 MmBtu     $ 8.07  
July 2008 — September 2008
    Natural gas       920,000 MmBtu     $ 8.23  
July 2008 — September 2008
    Natural gas       920,000 MmBtu     $ 8.36  
July 2008 — December 2008
    Natural gas       1,840,000 MmBtu     $ 8.31  
July 2008 — December 2008
    Natural gas       1,840,000 MmBtu     $ 8.59  
August 2008
    Natural gas       310,000 MmBtu     $ 8.00  
August 2008
    Natural gas       310,000 MmBtu     $ 8.07  
September 2008
    Natural gas       300,000 MmBtu     $ 8.05  
September 2008
    Natural gas       300,000 MmBtu     $ 8.10  
October 2008 — December 2008
    Natural gas       920,000 MmBtu     $ 7.96  
October 2008 — December 2008
    Natural gas       1,840,000 MmBtu     $ 8.00  
October 2008 — December 2008
    Natural gas       920,000 MmBtu     $ 8.07  


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
                         
                Weighted Avg.
 
Period
 
Commodity
   
Notional
   
Fixed Price
 
 
October 2008 — December 2008
    Natural gas       920,000 MmBtu     $ 8.11  
October 2008 — December 2008
    Natural gas       920,000 MmBtu     $ 8.16  
October 2008 — December 2008
    Natural gas       920,000 MmBtu     $ 8.32  
October 2008 — December 2008
    Natural gas       920,000 MmBtu     $ 8.83  
January 2009 — March 2009
    Natural gas       900,000 MmBtu     $ 8.56  
January 2009 — March 2009
    Natural gas       900,000 MmBtu     $ 8.60  
January 2009 — March 2009
    Natural gas       900,000 MmBtu     $ 8.65  
January 2009 — March 2009
    Natural gas       900,000 MmBtu     $ 8.91  
Collars:
                       
January 2008 — June 2008
    Crude oil       42,000 Bbls     $ 50.00 - $83.35  
July 2008 — December 2008
    Crude oil       54,000 Bbls     $ 50.00 - $82.60  
Waha basis swaps:
                       
January 2008 — December 2008
    Natural gas       10,980,000 MmBtu     $ (0.57 )
January 2008 — December 2008
    Natural gas       7,320,000 MmBtu     $ (0.585 )
January 2008 — December 2008
    Natural gas       7,320,000 MmBtu     $ (0.59 )
January 2008 — December 2008
    Natural gas       3,660,000 MmBtu     $ (0.595 )
January 2008 — December 2008
    Natural gas       3,660,000 MmBtu     $ (0.625 )
January 2008 — December 2008
    Natural gas       7,320,000 MmBtu     $ (0.635 )
January 2008 — December 2008
    Natural gas       7,320,000 MmBtu     $ (0.6525 )
May 2008 — August 2008
    Natural gas       2,460,000 MmBtu     $ (0.45 )
June 2008 — August 2008
    Natural gas       920,000 MmBtu     $ (0.4808 )
September 2008 — December 2008
    Natural gas       2,440,000 MmBtu     $ (0.7930 )
January 2009 — December 2009
    Natural gas       3,650,000 MmBtu     $ (0.47 )
January 2009 — December 2009
    Natural gas       3,650,000 MmBtu     $ (0.49 )
January 2009 — December 2009
    Natural gas       3,650,000 MmBtu     $ (0.4975 )
 
These derivatives have not been designated as hedges. The Company records all derivatives on the balance sheet at fair value. Changes in derivative fair values are recognized in earnings. Cash settlements and valuation gains and losses are included in (gain) loss on derivative contracts in the consolidated statements of operations. The following summarizes the cash settlements and valuation gains and losses for the years ended December 31 (in thousands):
 
                         
    2007     2006     2005  
 
Realized (gain) loss
  $ (34,494 )   $ (14,169 )   $ 2,836  
Unrealized (gain) loss
    (26,238 )     1,878       1,296  
                         
(Gain) loss on derivative contracts
  $ (60,732 )   $ (12,291 )   $ 4,132  
                         
 
13.   Retirement and Deferred Compensation Plans
 
Retirement Plan.  The Company maintains a 401(k) retirement plan for its employees. Under the plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by regulations promulgated by the Internal Revenue Service. Prior to August 2006, the Company made matching contributions equal to 50% on the first 6% of employee deferred wages (maximum 3% matching). The Company modified the 401(k) retirement plan in August 2006 to change the matching contributions to equal a match of 100% on the first 15% of employee deferred wages (maximum 15% matching). The plan was also modified to make the matching contributions payable in Company common stock. Accrued payables in the amounts of $5.2 million and

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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
$1.3 million are reflected in the consolidated balance sheets as of December 31, 2007 and 2006, respectively, related to the matching contributions. During June 2007, the Company satisfied its matching obligation related to employees’ contributions made in 2006 through a transfer of treasury stock (See Note 18). For 2007, 2006 and 2005, retirement plan expense was approximately $4.9 million, $1.5 million and $0.3 million, respectively.
 
Deferred Compensation Plan.  Effective February 1, 2007 the Company established a non-qualified deferred compensation plan in order to provide our employees with flexibility in meeting their future income needs and assisting them in their retirement planning. Pursuant to the terms of the deferred compensation plan, eligible highly compensated employees are provided the opportunity to defer income in excess of the IRA annual limitations on qualified 401(k) retirement plans. The 2007 annual 401(k) deferral limit for employees under age 50 was $15,500. Employees turning age 50 or over in 2007 could defer up to $20,500.
 
14.   Income Taxes
 
On January 1, 2007, the Company adopted the provisions of FIN 48. The Company has determined that no uncertain tax positions exist and therefore no reserves have been recorded for purposes of FIN 48 as of December 31, 2007. As a result, the Company has not recorded any additional liabilities for any unrecognized tax benefits as of December 31, 2007. The Company and its subsidiaries file income tax returns in the U.S. federal and various state jurisdictions. Tax years 1994 to present remain open for the majority of taxing authorities. The Company’s accounting policy is to recognize interest and penalties, if any, related to unrecognized tax benefits as income tax expense. The Company does not have an accrued liability for the payment of penalties and interest at December 31, 2007.
 
Significant components of the Company’s deferred tax assets (liabilities) are as follows (in thousands):
 
                 
    December 31,  
    2007     2006  
 
Deferred tax assets (liabilities):
               
Current:
               
Accrued liabilities
  $ 1,820     $ 4,451  
Other
          1,864  
                 
Total current deferred tax assets
  $ 1,820     $ 6,315  
                 
Noncurrent:
               
Property, plant and equipment
  $ (45,537 )   $ (25,692 )
Net operating loss carryforwards
    2,397        
Other
    (6,210 )     770  
                 
Total noncurrent deferred tax liabilities
  $ (49,350 )   $ (24,922 )
                 
 
The provisions for income taxes for continuing operations consisted of the following components for the years ended December 31 (in thousands):
 
                         
    2007     2006     2005  
 
Current:
                       
Federal
  $     $ 3,235     $ 508  
State
    601       2,653        
                         
      601       5,888       508  
                         
Deferred:
                       
Federal
    28,121       345       9,460  
State
    802       3        
                         
      28,923       348       9,460  
                         
Total provision for income taxes
  $ 29,524     $ 6,236     $ 9,968  
                         


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
A reconciliation of the provision for income taxes from continuing operations at the statutory federal tax rates to the Company’s actual provision for income taxes is as follows for the years ended December 31 (in thousands):
 
                         
    2007     2006     2005  
 
Computed at federal statutory rates
  $ 27,911     $ 7,650     $ 9,543  
State taxes, net of federal benefit
    912       1,724       390  
Nondeductible expenses
    312       84       35  
Percentage depletion deduction
          (3,488 )      
Change in rate
          326        
Other
    389       (60 )      
                         
Total provision for income taxes
  $ 29,524     $ 6,236     $ 9,968  
                         
 
As of December 31, 2007, the Company had $6.8 million of net operating loss carryforwards that will begin to expire in 2023. The Company, as of December 31, 2007, had approximately $0.5 million of alternative minimum tax credits that do not expire.
 
15.   Earnings 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).
 
                         
    2007     2006     2005  
 
Weighted average basic common shares outstanding
    108,828       73,727       56,559  
Effect of dilutive securities:
                       
Restricted stock
    1,213       937       178  
                         
Weighted average diluted common and potential common shares outstanding
    110,041       74,664       56,737  
                         
 
In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding redeemable convertible preferred stock. Under this method, the Company assumes the conversion of the preferred stock to common stock and determines if this is more dilutive than including the preferred stock dividends (paid and unpaid) in the computation of income available to common stockholders. The Company determined the if-converted method is not more dilutive and has included preferred stock dividends in the determination of income available to common stockholders.
 
16.   Commitments and Contingencies
 
Operating Leases.  The Company has obligations under noncancelable operating leases, primarily for the use of office space and equipment. Total rental expense under operating leases for the years ended December 31, 2007, 2006 and 2005 was approximately $2.3 million, $1.1 million and $1.1 million, respectively.


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
Future minimum lease payments under noncancelable operating leases (with initial lease terms in excess of one year) as of December 31, 2007 are as follows (in thousands):
 
         
Years ending December 31:
       
2008
  $ 2,139  
2009
    1,102  
2010
    110  
2011
    110  
2012
    45  
Thereafter
     
         
    $ 3,506  
         
 
Litigation.  The Company is a defendant in lawsuits from time to time in the normal course of business. In management’s opinion, the Company is not currently involved in any legal proceedings which, individually or in the aggregate, could have a material effect on the financial condition, operations and/or cash flows of the Company.
 
17.   Redeemable Convertible Preferred Stock
 
In November 2006, the Company sold 2,136,667 shares of redeemable convertible preferred stock in order to finance a portion of the NEG acquisition and received net proceeds from this sale of approximately $439.5 million after deducting offering expenses of approximately $9.3 million (See Note 2). Each holder of the redeemable convertible preferred stock is entitled to quarterly cash dividends at the annual rate of 7.75% of the accreted value of its redeemable convertible preferred stock. The accreted value was $210 per share as of December 31, 2007 and 2006. Each share of convertible preferred stock was initially convertible into ten (10.2 currently) shares of common stock at the option of the holder, subject to certain anti-dilution adjustments. A summary of dividends declared and paid on the redeemable convertible preferred stock is as follows (in thousands, except per share data):
 
                         
        Dividends
           
Declared
 
Dividend Period
  per Share     Total    
Date Paid
 
January 31, 2007
  November 21, 2006 — February 1, 2007   $ 3.21     $ 6,859     February 15, 2007
May 8, 2007
  February 2, 2008 — May 1, 2007     3.97       8,550     May 15, 2007
June 8, 2007
  May 2, 2007 — August 1, 2007     4.10       8,956     August 15, 2007
September 24, 2007
  August 2, 2007 — November 1, 2007     4.10       8,956     November 15, 2007
December 16, 2007
  November 2, 2007 — February 1, 2008     4.10       8,956     February 15, 2008
 
On March 30, 2007, certain holders of the Company’s common units (consisting of shares of common stock and a warrant to purchase redeemable convertible preferred stock upon the surrender of common stock) exercised warrants to purchase redeemable convertible preferred stock. The holders exchanged 526,316 shares of common stock for 47,619 shares of redeemable convertible preferred stock.
 
Approximately $38.5 million and $3.8 million in paid and unpaid dividends have been included in the Company’s earnings per share calculations for the years ended December 31, 2007 and 2006, respectively, as presented in the accompanying consolidated statements of operations.


F-28


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
18.   Stockholders’ Equity
 
The following table presents information regarding SandRidge’s common stock (in thousands):
 
                 
    December 31,  
    2007     2006  
 
Shares authorized
    400,000       400,000  
Shares outstanding at end of period
    140,391       91,604  
Shares held in treasury
    1,456       1,444  
 
The Company is authorized to issue 50,000,000 shares of preferred stock, $0.001 par value, of which 2,625,000 shares are designated as redeemable convertible preferred. As of December 31, 2007 and 2006 there were 2,184,286 and 2,136,667 shares, respectively, of redeemable convertible preferred stock outstanding (See Note 17). There were no undesignated preferred shares outstanding as of December 31, 2007 and 2006.
 
Stock Split.  On December 19, 2005, the Company effected a 281.562 for 1 stock split. All references in the accompanying financial statements have been restated to reflect this stock split. The Company also authorized 400,000,000 shares of common stock with a par value of $0.001 per share.
 
Common Stock Issuance.  In December 2005, the Company sold 12.5 million shares of common stock in a private placement and received net proceeds from this sale of approximately $173.1 million after deducting the initial purchasers’ discount of $16.8 million and offering expenses of approximately $1.2 million. Approximately $105.5 million of the proceeds of the offering were used to repay outstanding bank debt and finance the Company’s December 2005 acquisitions (See Note 2).
 
In January 2006, the Company issued an additional 239,630 shares of common stock upon exercise of an over-allotment option. The Company issued these shares at a price of $15.00 per share after deducting the purchasers’ fee of $0.3 million. The Company received net proceeds from the sale of approximately $3.3 million.
 
In November 2006, the Company sold 5.3 million common units (consisting of shares of common stock ($18.00 per share) and a warrant ($1.00 per share) to purchase convertible preferred stock upon the surrender of the common stock) as part of the NEG acquisition and received net proceeds from this sale of approximately $97.4 million after deducting the offering expenses of approximately $3.9 million (See Note 2).
 
In March 2007, the Company sold approximately 17.8 million shares of common stock for net proceeds of $318.7 million after deducting offering expenses of approximately $1.4 million. The stock was sold in private sales to various investors including Tom L. Ward, the Company’s Chairman of the Board of Directors and Chief Executive Officer, who invested $61.4 million in exchange for approximately 3.4 million shares of common stock.
 
On November 9, 2007, the Company completed an initial public offering (the “IPO”) of its common stock. The Company sold 28,700,000 shares of SandRidge common stock, including 4,710,000 shares sold directly to an entity controlled by Tom L. Ward. The shares were sold at a price of $26 per share. After deducting underwriting discounts of approximately $38.3 million and estimated offering expenses of approximately $3.1 million, the Company received net proceeds of approximately $704.8 million. This transaction priced after market close on November 5, 2007. In conjunction with the IPO, the underwriters were granted an option to purchase 3,679,500 additional shares of the Company’s common stock. The underwriters fully exercised this option and purchased the additional shares on November 6, 2007. After deducting underwriting discounts of approximately $5.7 million, the Company received net proceeds of approximately $89.9 million from these additional shares. This offering generated total gross proceeds to the Company of $841.8 million and total net proceeds of approximately $794.7 million to the Company after deducting total underwriting discounts of approximately $44.0 million and other offering expenses of approximately $3.1 million. The


F-29


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
aggregate net proceeds of approximately $794.7 million received by the Company at closing on November 9, 2007 were utilized as follows (in millions):
 
         
Repayment of outstanding balance and accrued interest on senior credit facility
  $ 515.9  
Repayment of note payable and accrued interest incurred in connection with recent acquisition
    49.1  
Excess cash to fund future capital expenditures
    229.7  
         
Total
  $ 794.7  
         
 
Treasury Stock.  The Company makes required tax payments on behalf of employees as their stock awards vest and then withholds a number of vested shares having a value on the date of vesting equal to the tax obligation. As a result of such transactions, the Company withheld 44,649 shares at a total value of $0.8 million and 29,000 shares at a total value of $0.5 million during the years ended December 31, 2007 and 2006, respectively. These shares were accounted for as treasury stock.
 
On June 28, 2007, the Company purchased 39,844 shares of its common stock into treasury through an open market repurchase transaction in order to fund a portion of its 401(k) matching obligation as described below. Cash consideration for these shares of approximately $0.8 million was paid in July 2007.
 
On June 29, 2007, the Company transferred 72,044 shares of its treasury stock to an account established for the benefit of the Company’s 401(k) Plan. The transfer was made in order to satisfy the Company’s $1.3 million accrued payable to match employee contributions made to the plan during 2006. Historical cost of the shares transferred totaled approximately $0.9 million, resulting in an increase to the Company’s additional paid-in capital of approximately $0.4 million.
 
Restricted Stock.  The Company issues restricted stock awards under incentive compensation plans which vest over specified periods of time. Awards issued prior to 2006 had vesting periods of one, four or seven years. All awards issued during and after 2006 have four year vesting periods. Shares of restricted common stock are subject to restriction on transfer and certain conditions to vesting.
 
The Company granted restricted stock awards of approximately 1.6 million shares in December 2005. The stock awards included (i) 153,667 shares scheduled to vest on December 31, 2006, (ii) 904,833 shares scheduled to vest on June 30, 2010, and (iii) 493,667 shares scheduled to vest on June 30, 2013. In June 2006, the Company modified the vesting periods of the one year period and four year period restricted stock awards. One year restricted stock awards were modified to vest on October 1, 2006, rather than December 31, 2006, and four year restricted stock awards were modified to vest 25% each January 1, for four years, beginning January 1, 2007, rather than all vesting on June 30, 2010. The Company recognized compensation cost related to these modifications of $17,250 in June 2006.
 
Additionally, the Company modified the vesting period related to restricted shares awarded to certain executive officers who resigned in June 2006 and August 2006 as a component of their separations from the Company. The Board of Directors agreed to immediately vest all of the executive officers’ restricted stock, a total of 222,000 shares, including 20,334 shares which would have vested in 2006, 150,000 shares which would have vested in 2010, and 51,666 shares which would have vested in 2013. The Company recognized compensation cost related to these modifications of $2.3 million in the year ended December 31, 2006.
 
In December 2006, the Company accelerated the vesting of 39,960 restricted shares on behalf of certain employees who resigned from the Company in late December 2006. These shares had been scheduled to vest on January 1, 2007. The Company recognized additional compensation cost in December 2006 for these shares of approximately $0.1 million due to the modification. Other restricted shares held by these employees were forfeited.


F-30


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
Restricted stock activity for the year ended December 31, 2007 was as follows (shares in thousands):
 
                 
          Weighted-
 
    Number of
    Average Grant
 
    Shares     Date Fair Value  
 
Unvested restricted shares outstanding at December 31, 2006
    937     $ 15.88  
Granted
    1,600       19.79  
Vested
    (466 )     15.62  
Canceled
    (144 )     15.15  
                 
Unvested restricted shares outstanding at December 31, 2007
    1,927     $ 19.25  
                 
 
For the year ended December 31, the Company recognized stock-based compensation expense related to restricted stock of approximately $7.2 million in 2007, $8.8 million in 2006, and $0.5 million in 2005. Stock-based compensation expense is reflected in general and administrative expense in the consolidated statements of operations.
 
As of December 31, 2007, there was approximately $30.5 million of unrecognized compensation cost related to unvested restricted stock awards which is expected to be recognized over a weighted average period of 2.21 years.
 
19.   Related Party Transactions
 
During the ordinary course of business, the Company has transactions with certain shareholders and other related parties. These transactions primarily consist of purchases of drilling equipment and sales of oil field service supplies. Following is a summary of significant transactions with such related parties for the years ended December 31 (in thousands):
 
                         
    2007   2006   2005
 
Sales to and reimbursements from related parties
  $ 118,631     $ 14,102     $ 12,673  
                         
Purchases of services from related parties
  $ 77,555     $ 4,811     $ 37  
                         
 
In August 2006, the Company sold various non-energy related assets to the Company’s former President and Chief Operating Officer, N. Malone Mitchell, 3rd, for approximately $6.1 million in cash. The sale transaction resulted in a $0.8 million gain recognized in earnings by the Company in August 2006. The gain is included in gain on sale of assets in the consolidated statements of operations.
 
In September 2006, the Company entered into a facilities lease with a member of its Board of Directors. The Company believes that the payments to be made under this lease are at fair market rates. Rent expense related to the lease totaled $1.3 million and $0.3 million for the years ended December 31, 2007 and 2006, respectively. The lease extends to August 2009.
 
In May 2007, the Company purchased leasehold acreage from a partnership controlled by a director. The purchase price was approximately $8.3 million in cash.
 
In June 2007, the Company purchased certain producing well interests from a director. The purchase price was approximately $3.5 million in cash.
 
Larclay, L.P.  The Company and CWEI each own a 50% interest in Larclay, L.P., a limited partnership formed to acquire drilling rigs and provide land drilling services. Larclay currently owns 12 rigs, one of which has not yet been assembled. The Company purchased its investment in 2006 and accounts for it under the equity method of accounting. The Company serves as the operations manager of the partnership. CWEI is responsible for financing and purchasing the rigs. The Company had sales to and cost reimbursements from Larclay for the years ended December 31, 2007 and 2006 of $53.3 million and $1.6 million, respectively. As


F-31


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
of December 31, 2007 and 2006, the Company had accounts receivable — related party due from Larclay of $16.6 million and $3.0 million, respectively. Additionally, the Company contracted with Larclay to utilize rigs for drilling. For the year ended December 31, 2007 the amount we were billed for these services was $33.3 million. As of December 31, 2007, the Company had accounts payable — related party due to Larclay of $0.3 million. The Company made no purchases from Larclay in 2006.
 
See Note 2 for a discussion of additional related party transactions.
 
20.   Subsequent Events
 
In January 2008, the Company entered into an interest rate swap to fix the variable LIBOR interest rate on the $350.0 million floating rate portion of its term loan at 6.26% for the period from April 1, 2008 to April 1, 2011. This swap has not been designated as a hedge.
 
21.   Industry Segment Information
 
SandRidge has four business segments: Exploration and Production, Drilling and Oil Field Services, Midstream Services, and Other representing its four main business units offering different products and services. The Exploration and Production segment is engaged in the development, acquisition and production of oil and natural gas properties. The Drilling and Oil Field Services segment is engaged in the land contract drilling of oil and natural gas wells. The Midstream Gas Services segment is engaged in the purchasing, gathering, processing and treating of natural gas. The Other segment transports CO2 to market for use by the Company and others in tertiary oil recovery operations and other miscellaneous operations.
 
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 SandRidge’s operating segments based on operating income, which is defined as operating revenues less operating expenses and depreciation, depletion and amortization. Summarized financial information concerning the Company’s segments is shown in the following table (in thousands):
 
                         
    2007     2006     2005  
 
Revenues:
                       
Exploration and production
  $ 479,321     $ 106,990     $ 54,425  
Elimination of inter-segment revenue
    574       577       374  
                         
Exploration and production, net of inter-segment revenue
    478,747       106,413       54,051  
                         
Drilling and oil field services
    261,818       211,055       109,766  
Elimination of inter-segment revenue
    188,616       72,398       29,615  
                         
Drilling and oil field services, net of inter-segment revenue
    73,202       138,657       80,151  
                         
Midstream services
    285,065       192,960       192,503  
Elimination of inter-segment revenue
    177,487       70,068       45,004  
                         
Midstream services, net of inter-segment revenues
    107,578       122,892       147,499  
                         
Other
    29,286       21,411       6,164  
Elimination of inter-segment revenue
    11,361       1,131       172  
                         
Other, net of inter-segment revenue
    17,925       20,280       5,992  
                         
Total revenues
  $ 677,452     $ 388,242     $ 287,693  
                         


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
                         
    2007     2006     2005  
 
Operating Income:
                       
Exploration and production
  $ 198,913     $ 17,069     $ 14,886  
Drilling and oil field services
    10,473       32,946       18,295  
Midstream services
    6,783       3,528       4,096  
Other
    (29,310 )     (16,562 )     (3,224 )
                         
Total operating income
    186,859       36,981       34,053  
Interest expense, net
    (111,762 )     (15,795 )     (5,071 )
Other income (expense), net
    4,648       671       (1,121 )
                         
Income before income taxes
  $ 79,745     $ 21,857     $ 27,861  
                         
Identifiable Assets(1):
                       
Exploration and production
  $ 3,143,137     $ 2,091,459     $ 243,612  
Drilling and oil field services
    271,563       175,169       100,995  
Midstream services
    127,822       75,606       33,845  
Other
    88,044       46,150       80,231  
                         
Total assets
  $ 3,630,566     $ 2,388,384     $ 458,683  
                         
Capital Expenditures:
                       
Exploration and production
  $ 1,046,552     $ 170,872     $ 61,227  
Drilling and oil field services
    123,232       89,810       43,730  
Midstream services
    63,828       16,975       25,904  
Other
    47,236       28,884       3,735  
                         
Total capital expenditures
  $ 1,280,848     $ 306,541     $ 134,596  
                         
Depreciation, Depletion and Amortization
                       
Exploration and production
  $ 175,565     $ 28,104     $ 8,796  
Drilling and oil field services
    37,792       20,268       11,851  
Midstream services
    6,641       3,180       1,652  
Other
    7,110       4,074       1,907  
                         
Total depreciation, depletion and amortization
  $ 227,108     $ 55,626     $ 24,206  
                         
 
 
(1) Identifiable assets are those used in SandRidge’s operations in each industry segment.
 
Major Customer.  During 2007, the Company had sales in excess of 10% of total revenues to an oil and gas purchaser ($76.1 million or 11.2% of total revenues). There were no customers that accounted for 10% or more of our total revenues in 2006 or 2005.

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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
22.   Supplemental Information on Oil and Gas Producing Activities (Unaudited)
 
The Supplementary Information on Oil and Gas Producing Activities is presented as required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.” The supplemental information includes capitalized costs related to oil and gas producing activities; costs incurred for the acquisition of oil and gas producing activities, exploration and development activities; and the results of operations from oil and gas producing activities. Supplemental information is also provided for per unit production costs; oil and gas production and average sales prices; the estimated quantities of proved oil and gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.
 
The Company’s capitalized costs consisted of the following (in thousands):
 
Capitalized Costs Related to Oil and Gas Producing Activities
 
                         
    December 31,  
    2007     2006     2005  
 
Oil and natural gas properties:
                       
Proved
  $ 2,848,531     $ 1,636,832     $ 160,789  
Unproved
    259,610       282,374       33,974  
                         
Total oil and natural gas properties
    3,108,141       1,919,206       194,763  
Less accumulated depreciation and depletion
    (230,974 )     (60,752 )     (35,029 )
                         
Net oil and natural gas properties capitalized costs
  $ 2,877,167     $ 1,858,454     $ 159,734  
                         
 
Costs Incurred in Property Acquisition, Exploration and Development Activities
 
                         
    2007     2006     2005  
 
Acquisitions of properties
                       
Proved
  $ 303,282     $ 1,311,029     $ 14,554  
Unproved
          268,839       21,085  
Exploration(1)
    361,973       18,612       2,527  
Development
    485,348       115,153       60,364  
                         
Total cost incurred
  $ 1,150,603     $ 1,713,633     $ 98,530  
                         
 
 
(1) 2007 amount includes seismic costs of $38.6 million.


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
 
The Company’s results of operations from oil and gas producing activities for each of the years 2007, 2006 and 2005 are shown in the following table (in thousands):
 
Results of Operations for Oil and Gas Producing Activities
 
         
For the Year Ended December 31, 2005
       
Revenues
  $ 48,405  
Expenses:
       
Production costs
    19,353  
Depreciation, depletion and amortization expenses
    8,995  
         
Total expenses
    28,348  
         
Income before income taxes
    20,057  
Provision for income taxes
    7,020  
         
Results of operations for oil and gas producing activities
  $ 13,037  
         
For the Year Ended December 31, 2006
       
Revenues
  $ 101,252  
Expenses:
       
Production costs
    39,803  
Depreciation, depletion and amortization expenses
    25,723  
         
Total expenses
    65,526  
         
Income before income taxes
    35,726  
Provision for income taxes
    10,718  
         
Results of operations for oil and gas producing activities
  $ 25,008  
         
For the Year Ended December 31, 2007
       
Revenues
  $ 477,612  
Expenses:
       
Production costs
    125,749  
Depreciation, depletion and amortization expenses
    169,392  
         
Total expenses
    295,141  
         
Income before income taxes
    182,471  
Provision for income taxes
    65,690  
         
Results of operations for oil and gas producing activities
  $ 116,781  
         
 
The table below represents the Company’s estimate of proved crude oil and natural gas reserves attributable to the Company’s net interest in oil and gas properties based upon the evaluation by the Company and its independent petroleum engineers of pertinent geological and engineering data in accordance with United States Securities and Exchange Commission regulations. Estimates of substantially all of the Company’s proved reserves have been prepared by the team of independent reservoir engineers and geoscience professionals and are reviewed by members of the Company’s senior management with professional training in petroleum engineering to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the United States Securities and Exchange Commission.


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton, independent oil and gas consultants, have prepared the estimates of proved reserves of natural gas and crude oil attributable to several portions of the Company’s net interest in oil and gas properties as of the end of one or more of 2007, 2006 and 2005. Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in us or our properties and are not employed on a contingent basis. Netherland, Sewell & Associates, Inc. prepared the estimates of proved reserves for all of our properties other than those held by PetroSource, which constitute approximately 89% of our total proved reserves as of December 31, 2007. DeGolyer and MacNaughton prepared the estimates of proved reserves for PetroSource, which constitute approximately 8% of our total proved reserves as of December 31, 2007. The small remaining portion of estimates of proved reserves were based on Company estimates.
 
The Company believes the geologic and engineering data examined provides reasonable assurance that the proved reserves are recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.
 
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Proved developed reserves are the quantities of crude oil, natural gas liquids and natural gas expected to be recovered through existing investments in wells and field infrastructure under current operating conditions. Proved undeveloped reserves require additional investments in wells and related infrastructure in order to recover the production.
 
During 2007, the Company recognized additional reserves attributable to extensions and discoveries as a result of successful drilling in the Piñon Field. Drilling expenditures of $97.1 resulted in the addition of 44.7 Bcfe of net proved developed reserves by extending the field boundaries as well as proving the producing capabilities of formations not previously captured as proved reserves. The remaining 55.1 Bcfe of net proved reserves for 2007 are proved undeveloped reserves associated with direct offsets to the 2007 drilling program extending the boundaries of the Piñon Field and zone identification. Changes in reserves associated with the development drilling have been accounted for in revisions of previous reserve estimates.
 
During 2006, the Company recognized additional reserves attributable to extensions and discoveries as a result of successful drilling in the Piñon Field. Drilling expenditures of $18.6 million resulted in the addition of 10.9 Bcfe of net proved developed reserves by extending the field boundaries as well as proving the producing capabilities of formations not previously captured as proved reserves. The remaining 83.1 Bcfe of net proved reserves for 2006 are proved undeveloped reserves associated with direct offsets to the 2006 drilling program extending the boundaries of the Piñon Field and zone identification. Changes in reserves associated with the development drilling have been accounted for in revisions of previous reserve estimates.


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
Reserve Quantity Information
 
                 
    Crude Oil
    Nat. Gas
 
    (MBbls)     (MMcf)(a)  
 
Proved developed and undeveloped reserves:
               
As of December 31, 2004
    682       144,452  
Revisions of previous estimates
    108       11,679  
Acquisitions of new reserves
    9,518       32,022  
Extensions and discoveries
    200       56,133  
Production
    (72 )     (6,873 )
                 
As of December 31, 2005
    10,436       237,413  
Revisions of previous estimates
    1,250       19,139  
Acquisitions of new reserves
    13,753       514,170  
Extensions and discoveries
    58       93,396  
Production
    (322 )     (13,410 )
                 
As of December 31, 2006
    25,175       850,708  
Revisions of previous estimates
    5,492       318,639  
Acquisitions of new reserves
    53       75,139  
Extensions and discoveries
    7,849       104,501  
Production
    (2,042 )     (51,958 )
                 
As of December 31, 2007
    36,527       1,297,029  
                 
Proved developed reserves:
               
As of December 31, 2004
    231       50,981  
As of December 31, 2005
    899       69,377  
As of December 31, 2006
    10,994       308,296  
As of December 31, 2007
    12,532       590,358  
 
 
(a) Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
 
The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with SFAS No. 69. The assumptions that underlie the computation of the standardized measure of discounted cash flows may be summarized as follows:
 
  •  the standardized measure includes the Company’s estimate of proved crude oil, natural gas liquids and natural gas reserves and projected future production volumes based upon year-end economic conditions;
 
  •  pricing is applied based upon year-end market prices adjusted for fixed or determinable contracts that are in existence at year-end. The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:
 
                         
    At December 31,  
    2007     2006     2005  
 
Natural gas (per Mcf)
  $ 6.46     $ 5.32     $ 8.40  
Crude oil (per barrel)
  $ 87.47     $ 54.62     $ 54.02  


F-37


Table of Contents

 
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, 2005
       
Future cash inflows from production
  $ 2,558,668  
Future production costs
    (653,748 )
Future development costs(a)
    (296,489 )
Future income tax expenses
    (546,867 )
         
Undiscounted future net cash flows
    1,061,564  
10% annual discount
    (562,410 )
         
Standardized measure of discounted future net cash flows
  $ 499,154  
         
As of December 31, 2006
       
Future cash inflows from production
  $ 5,901,660  
Future production costs
    (1,623,216 )
Future development costs(a)
    (931,947 )
Future income tax expenses
    (638,599 )
         
Undiscounted future net cash flows
    2,707,898  
10% annual discount
    (1,267,752 )
         
Standardized measure of discounted future net cash flows
  $ 1,440,146  
         
As of December 31, 2007
       
Future cash inflows from production
  $ 11,578,381  
Future production costs
    (2,706,208 )
Future development costs(a)
    (1,640,500 )
Future income tax expenses
    (1,782,909 )
         
Undiscounted future net cash flows
    5,448,764  
10% annual discount
    (2,730,227 )
         
Standardized measure of discounted future net cash flows
  $ 2,718,537  
         
 
 
(a) Includes abandonment costs.


F-38


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
 
The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):
 
Changes in the Standardized Measure of Discounted Future Net Cash Flows
From Proved Oil and Gas Reserves
 
         
Present value as of December 31, 2004
  $ 198,962  
Changes during the year:
       
Revenues less production and other costs
    (29,052 )
Net changes in prices, production and other costs
    225,227  
Development costs incurred
    56,368  
Net changes in future development costs
    (86,828 )
Extensions and discoveries
    96,514  
Revisions of previous quantity estimates
    47,501  
Accretion of discount
    28,981  
Net change in income taxes
    (155,250 )
Purchases of reserves in-place
    196,206  
Timing differences and other(a)
    (79,475 )
         
Net change for the year
    300,192  
         
Present value as of December 31, 2005
  $ 499,154  
Revenues less production and other costs
    (61,449 )
Net changes in prices, production and other costs
    (294,437 )
Development costs incurred
    75,323  
Net changes in future development costs
    (75,466 )
Extensions and discoveries
    126,061  
Revisions of previous quantity estimates
    54,313  
Accretion of discount
    73,643  
Net change in income taxes
    (36,962 )
Purchases of reserves in-place
    1,135,062  
Timing differences and other(a)
    (55,096 )
         
Net change for the year
    940,992  
         
Present value as of December 31, 2006
  $ 1,440,146  
Changes during the year:
       
Revenues less production and other costs
    (351,863 )
Net changes in prices, production and other costs
    800,630  
Development costs incurred
    485,348  
Net changes in future development costs
    (723,943 )
Extensions and discoveries
    328,094  
Revisions of previous quantity estimates
    998,729  
Accretion of discount
    88,596  
Net change in income taxes
    (537,835 )
Purchases of reserves in-place
    155,051  
Timing differences and other(a)
    35,584  
         
Net change for the year
    1,278,391  
         
Present value as of December 31, 2007
  $ 2,718,537  
         
 
 
(a) The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.


F-39


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Consolidated Financial Statements — (Continued)
 
 
23.   Quarterly Financial Results (Unaudited)
 
Our operating results for each quarter of 2007 and 2006 are summarized below (in thousands, except per share data).
 
                                 
    First
    Second
    Third
    Fourth
 
    Quarter     Quarter     Quarter     Quarter  
 
2007:
                               
Total revenues
  $ 149,064     $ 159,063     $ 153,648     $ 215,677  
                                 
Income from operations
  $ 14,408     $ 75,160     $ 59,716     $ 37,575  
                                 
Net income (loss)
  $ (19,493 )   $ 34,564     $ 20,920     $ 14,230  
                                 
Income (loss) available (applicable) to common stockholders
  $ (28,459 )   $ 22,270     $ 11,607     $ 4,915  
                                 
Basic and diluted:
                               
Net income (loss) available (applicable) to common stockholders(1)
  $ (0.31 )   $ 0.21     $ 0.11     $ 0.04  
                                 
2006:
                               
Total revenues
  $ 85,915     $ 87,915     $ 89,650     $ 124,762  
                                 
Income from operations
  $ 3,468     $ 6,757     $ 8,576     $ 18,180  
                                 
Net income (loss)
  $ 8,383     $ 5,649     $ 4,895     $ (3,306 )
                                 
Income (loss) available (applicable) to common stockholders
  $ 8,383     $ 5,649     $ 4,895     $ (7,273 )
                                 
Basic and diluted:
                               
Net income (loss) available (applicable) to common stockholders(1)
  $ 0.12     $ 0.08     $ 0.07     $ (0.10 )
                                 
 
 
(1) Income (loss) available (applicable) to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of income (loss) available (applicable) to common stockholders for each of the four quarters may not equal the fiscal year amount.


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Table of Contents

SandRidge Energy, Inc. and Subsidiaries
 
Condensed Consolidated Balance Sheets
 
                 
    March 31,
    December 31,
 
    2008     2007  
    (Unaudited)
 
    (In thousands)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 726     $ 63,135  
Accounts receivable, net:
               
Trade
    112,674       94,741  
Related parties
    23,037       20,018  
Derivative contracts
          21,958  
Inventories
    4,864       3,993  
Deferred income taxes
    1,428       1,820  
Other current assets
    20,373       20,787  
                 
Total current assets
    163,102       226,452  
Crude oil and natural gas properties, using full cost method of accounting
               
Proved
    3,204,557       2,848,531  
Unproved
    259,610       259,610  
Less: accumulated depreciation and depletion
    (294,729 )     (230,974 )
                 
      3,169,438       2,877,167  
                 
Other property, plant and equipment, net
    506,156       460,243  
Derivative contracts
    2,145       270  
Investments
    8,815       7,956  
Restricted deposits
    32,633       31,660  
Other assets
    25,543       26,818  
                 
Total assets
  $ 3,907,832     $ 3,630,566  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Current maturities of long-term debt
  $ 15,662     $ 15,350  
Accounts payable and accrued expenses:
               
Trade
    242,324       215,497  
Related parties
    1,747       395  
Asset retirement obligation
    882       864  
Derivative contracts
    123,284        
                 
Total current liabilities
    383,899       232,106  
Long-term debt
    1,263,270       1,052,299  
Other long-term obligations
    16,817       16,817  
Asset retirement obligation
    60,748       57,716  
Deferred income taxes
    18,341       49,350  
                 
Total liabilities
    1,743,075       1,408,288  
                 
Commitments and contingencies (Note 11) 
               
Minority interest
    4,875       4,672  
Redeemable convertible preferred stock, $0.001 par value, 2,625 shares authorized; 1,844 and 2,184 shares issued and outstanding at March 31, 2008 and December 31, 2007, respectively
    380,893       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; 147,516 issued and 146,206 outstanding at March 31, 2008 and 141,847 issued and 140,391 outstanding at December 31, 2007
    144       140  
Additional paid-in capital
    1,763,225       1,686,113  
Treasury stock, at cost
    (17,389 )     (18,578 )
Retained earnings
    33,009       99,216  
                 
Total stockholders’ equity
    1,778,989       1,766,891  
                 
Total liabilities and stockholders’ equity
  $ 3,907,832     $ 3,630,566  
                 


F-41


Table of Contents

SandRidge Energy, Inc. and Subsidiaries
 
Condensed Consolidated Statements of Operations
 
                 
    Three Months Ended
 
    March 31,  
    2008     2007  
    (Unaudited)
 
    (In thousands except per share amounts)  
 
Revenues:
               
Natural gas and crude oil
  $ 205,487     $ 90,176  
Drilling and services
    12,334       27,895  
Midstream and marketing
    46,409       26,187  
Other
    4,856       4,806  
                 
Total revenues
    269,086       149,064  
Expenses:
               
Production
    34,188       21,974  
Production taxes
    9,220       2,933  
Drilling and services
    7,169       18,777  
Midstream and marketing
    40,418       23,420  
Depreciation, depletion and amortization — natural gas and crude oil
    65,076       32,684  
Depreciation, depletion and amortization — other
    17,965       10,160  
General and administrative
    20,994       12,468  
Loss on derivative contracts
    136,844       23,181  
Loss (gain) on sale of assets
    23       (1 )
                 
Total expenses
    331,897       145,596  
                 
(Loss) income from operations
    (62,811 )     3,468  
                 
Other income (expense):
               
Interest income
    796       1,088  
Interest expense
    (25,172 )     (35,429 )
Minority interest
    (835 )     (146 )
Income from equity investments
    859       1,025  
                 
Total other (expense) income
    (24,352 )     (33,462 )
                 
Loss before income tax benefit
    (87,163 )     (29,994 )
Income tax benefit
    (30,538 )     (10,501 )
                 
Net loss
    (56,625 )     (19,493 )
Preferred stock dividends and accretion
    9,582       8,966  
                 
Loss applicable to common stockholders
  $ (66,207 )   $ (28,459 )
                 
Basic and diluted loss per share applicable to common stockholders
  $ (0.47 )   $ (0.31 )
                 
Weighted average number of common shares outstanding:
               
Basic
    141,044       92,442  
                 
Diluted
    141,044       92,442  
                 


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Table of Contents

SandRidge Energy, Inc. and Subsidiaries
 
Condensed Consolidated Statement of Changes in Stockholders’ Equity
 
                                         
          Additional
                   
    Common
    Paid-in
    Treasury
    Retained
       
    Stock     Capital     Stock     Earnings     Total  
    (Unaudited)
 
    (In thousands)  
 
Three months ended March 31, 2008
                                       
Balance, December 31, 2007
  $ 140     $ 1,686,113     $ (18,578 )   $ 99,216     $ 1,766,891  
Purchase of treasury stock
                (1,254 )           (1,254 )
Common stock issued under retirement plan
          2,566       2,443             5,009  
Conversion of redeemable convertible preferred stock to common stock
    4       71,305                   71,309  
Accretion on redeemable convertible preferred stock
                      (1,487 )     (1,487 )
Stock-based compensation
          3,241                   3,241  
Net loss
                      (56,625 )     (56,625 )
Redeemable convertible preferred stock dividend
                      (8,095 )     (8,095 )
                                         
Balance, March 31, 2008
  $ 144     $ 1,763,225     $ (17,389 )   $ 33,009     $ 1,778,989  
                                         


F-43


Table of Contents

SandRidge Energy, Inc. and Subsidiaries
 
Condensed Consolidated Statements of Cash Flows
 
                 
    Three Months Ended
 
    March 31,  
    2008     2007  
    (Unaudited)
 
    (In thousands)  
 
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net loss
  $ (56,625 )   $ (19,493 )
Adjustments to reconcile net loss to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    83,041       42,844  
Debt issuance cost amortization
    1,097       12,752  
Deferred income taxes
    (30,617 )     (10,501 )
Unrealized loss on derivative contracts
    143,367       21,662  
Loss (gain) on sale of assets
    23       (1 )
Interest income — restricted deposits
    (192 )     (266 )
Income from equity investments, net of distributions
    (859 )     (1,025 )
Stock-based compensation
    3,241       1,071  
Minority interest
    835       146  
Changes in operating assets and liabilities
    13,378       (3,226 )
                 
Net cash provided by operating activities
    156,689       43,963  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Capital expenditures for property, plant and equipment
    (418,650 )     (181,095 )
Proceeds from sale of assets
    452       26  
Fundings of restricted deposits
    (781 )     (1,477 )
                 
Net cash used in investing activities
    (418,979 )     (182,546 )
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Proceeds from borrowings
    340,220       1,142,772  
Repayments of borrowings
    (128,937 )     (1,136,845 )
Dividends paid — preferred
    (9,516 )     (6,859 )
Minority interest (distributions) contributions
    (632 )     762  
Proceeds from issuance of common stock
          318,925  
Purchase of treasury stock
    (1,254 )     (661 )
Debt issuance costs
          (25,000 )
                 
Net cash provided by financing activities
    199,881       293,094  
                 
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
    (62,409 )     154,511  
CASH AND CASH EQUIVALENTS, beginning of year
    63,135       38,948  
                 
CASH AND CASH EQUIVALENTS, end of period
  $ 726     $ 193,459  
                 
Supplemental Disclosure of Noncash Investing and Financing Activities:
               
Insurance premiums financed
  $     $ 1,496  
Accretion on redeemable convertible preferred stock
  $ 1,487     $ 350  


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Table of Contents

SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements
(Unaudited)
 
1.   Basis of Presentation
 
Nature of Business.  SandRidge Energy, Inc., together with its subsidiaries (collectively, the “Company” or “SandRidge”), is a natural gas and crude oil company with its principal focus on exploration, development and production. SandRidge also owns and operates natural gas gathering, marketing and processing facilities and CO2 treating and transportation facilities and conducts tertiary oil recovery operations. In addition, SandRidge owns and operates drilling rigs and a related oil field services business operating under the Lariat Services, Inc. brand name. SandRidge’s primary exploration, development and production areas are concentrated in West Texas. The Company also operates significant interests in the Cotton Valley Trend in East Texas, the Gulf Coast area, the Mid-Continent and the Gulf of Mexico.
 
On November 21, 2006, the Company acquired all of the outstanding membership interests of NEG Oil & Gas LLC (“NEG”).
 
Interim Financial Statements.  The accompanying condensed consolidated financial statements as of December 31, 2007 have been derived from the audited financial statements contained in the Company’s annual report on Form 10-K for the fiscal year ended December 31, 2007 (the “2007 Form 10-K”). The unaudited interim condensed consolidated financial statements of SandRidge have been prepared by the Company in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2007 Form 10-K. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary to state fairly the information in the Company’s unaudited condensed consolidated financial statements have been included. These condensed financial statements should be read in conjunction with the financial statements and notes thereto included in the 2007 Form 10-K.
 
2.   Significant Accounting Policies
 
For a description of the Company’s accounting policies, refer to Note 1 of the consolidated financial statements included in the 2007 Form 10-K.
 
Reclassifications.  Certain reclassifications have been made in prior period financial statements to conform with current period presentation.
 
Recent Accounting Pronouncements.  Effective January 1, 2008, SandRidge implemented Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not require new fair value measurements. SFAS No. 157 did not have an effect on the Company’s financial statements other than requiring additional disclosures regarding fair value measurements. See Note 4.
 
In February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB 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 adoption of FSP 157-2 is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.
 
In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations,” which replaces SFAS No. 141. SFAS No. 141(R) establishes principles and requirements for how an acquirer recognizes and


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements — (Continued)
 
measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008. The Company plans to implement this standard on January 1, 2009. The Company has not yet evaluated the potential impact of this standard.
 
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin No. 51,” which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. The Statement 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 Company has not yet evaluated the potential impact of this standard.
 
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. The Statement 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. The Company has not yet evaluated the potential impact of this standard.
 
3.   Property, Plant and Equipment
 
Property, plant and equipment consists of the following (in thousands):
 
                 
    March 31,
    December 31,
 
    2008     2007  
 
Crude oil and natural gas properties:
               
Proved
  $ 3,204,557     $ 2,848,531  
Unproved
    259,610       259,610  
                 
Total crude oil and natural gas properties
    3,464,167       3,108,141  
Less accumulated depreciation and depletion
    (294,729 )     (230,974 )
                 
Net crude oil and natural gas properties capitalized costs
    3,169,438       2,877,167  
                 
Land
    1,344       1,149  
Non crude oil and natural gas equipment
    602,488       539,893  
Buildings and structures
    39,225       38,288  
                 
Total
    643,057       579,330  
Less accumulated depreciation, depletion and amortization
    (136,901 )     (119,087 )
                 
Net capitalized costs
    506,156       460,243  
                 
Total property, plant and equipment
  $ 3,675,594     $ 3,337,410  
                 
 
The amount of capitalized interest included in the above non crude oil and natural gas equipment balance at March 31, 2008 and December 31, 2007 was approximately $3.7 million and $3.4 million, respectively.


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements — (Continued)
 
4.   Fair Value Measurements
 
The Company implemented SFAS No. 157 effective January 1, 2008 for its financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and liabilities that are being 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 measurements. The statement requires fair value measurements be classified and disclosed in one of the following categories:
 
Level 1:  Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
 
Level 2:  Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
 
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 Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. Per SFAS No. 157, the Company has classified its derivative contracts into one of the three levels based upon the data relied upon to determine the fair value. The fair values of the Company’s natural gas and crude oil swaps, crude oil collars and interest rate swap are based upon quotes obtained from counterparties to the derivative contracts and are designated as Level 3 as the Company does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2. The following table summarizes the valuation of the Company’s financial assets and liabilities by SFAS No. 157 pricing levels as of March 31, 2008:
 
                                 
    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)     FairValue  
    (In thousands)  
 
Derivative assets
  $     $     $ 2,145     $ 2,145  
Derivative liabilities
                (123,284 )     (123,284 )
                                 
    $     $     $ (121,139 )   $ (121,139 )
                                 
 
The determination of the fair values above incorporates various factors required under SFAS No. 157. These factors include not only the impact of the Company’s nonperformance risk on its liabilities, but also the credit standing of the counterparties.


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements — (Continued)
 
The table below sets forth a reconciliation for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the first quarter of 2008 (in thousands):
 
         
Derivative contracts as of December 31, 2007
  $ 22,228  
Total gains or losses (realized/unrealized)
    (136,038 )
Purchases, issuances and settlements
    (7,329 )
Transfers in and out of Level 3
     
         
Derivative contracts as of March 31, 2008
  $ (121,139 )
         
Change in unrealized gains (losses) on derivative contracts still held as of March 31, 2008
  $ (143,367 )
         
 
5.   Asset Retirement Obligation
 
A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation for the period from December 31, 2007 to March 31, 2008 is as follows (in thousands):
 
         
Asset retirement obligation, December 31, 2007
  $ 58,580  
Liability incurred upon acquiring and drilling wells
    1,730  
Revisions in estimated cash flows
     
Liability settled in current period
     
Accretion of discount expense
    1,320  
         
Asset retirement obligation, March 31, 2008
    61,630  
Less: Current portion
    882  
         
Asset retirement obligation, net of current
  $ 60,748  
         
 
6.   Long-Term Debt
 
Long-term debt consists of the following (in thousands):
 
                 
    March 31,
    December 31,
 
    2008     2007  
 
Senior term loans
  $ 1,000,000     $ 1,000,000  
Senior credit facility
    215,000        
Other notes payable:
               
Drilling rig fleet and related oil field services equipment
    44,347       47,836  
Mortgage
    19,450       19,651  
Other equipment and vehicles
    135       162  
                 
Total debt
    1,278,932       1,067,649  
Less: Current maturities of long-term debt
    15,662       15,350  
                 
Long-term debt
  $ 1,263,270     $ 1,052,299  
                 
 
Senior Term Loans.  On March 22, 2007, the Company issued $1.0 billion of senior unsecured term loans (the “senior term loans”). The closing of the senior term loans was generally contingent upon closing the private placement of common equity as described in Note 13. The senior term loans include both floating rate term loans and fixed rate term loans. A portion of the proceeds from the senior term loans was used to repay the Company’s $850.0 million senior bridge facility, which was paid in full in March 2007.


F-48


Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements — (Continued)
 
The Company issued $350.0 million at a variable rate with interest payable quarterly and principal due on April 1, 2014 (the “variable rate term loans”). The variable rate term loans bear interest, at the Company’s option, at the LIBOR rate plus 3.625% or the higher of (i) the federal funds rate, as defined, plus 3.125% or (ii) a bank’s prime rate plus 2.625%. After April 1, 2009, the variable rate term loans may be prepaid in whole or in part with certain prepayment penalties. The average interest rate paid on amounts outstanding under the Company’s variable term loans for the three month period ended March 31, 2008 was 8.36%.
 
In January 2008, the Company entered into an interest rate swap to fix the variable LIBOR interest rate on the variable rate term loans at 6.26% for the period from April 1, 2008 to April 1, 2011. This swap has not been designated as a hedge.
 
The Company issued $650.0 million at a fixed rate of 8.625% with the principal due on April 1, 2015 (the “fixed rate term loans”). Under the terms of the fixed rate term loans, interest is payable quarterly and during the first four years interest may be paid, at the Company’s option, either entirely in cash or entirely with additional fixed rate term loans. If the Company elects to pay the interest due during any period in additional fixed rate term loans, the interest rate increases to 9.375% during such period. After April 1, 2011, the fixed rate term loans may be prepaid in whole or in part with certain prepayment penalties.
 
Debt covenants under the senior term loans include financial covenants similar to those of the senior credit facility and include limitations on the incurrence of indebtedness, payment of dividends, asset sales, certain asset purchases, transactions with related parties, and consolidation or merger.
 
The Company incurred $26.1 million of debt issuance costs in connection with the senior term loans. These costs are included in other assets and amortized over the term of the senior term loans.
 
On March 28, 2008, the Company commenced an offer to exchange the senior term loans for senior unsecured notes with registration rights, as required under the senior term loan credit agreement. See Note 15.
 
Senior Credit Facility.  On November 21, 2006, the Company entered into a $750.0 million senior secured revolving credit facility (the “senior credit facility”). 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 initial proceeds of the senior credit facility were used to (i) partially finance the acquisition of NEG, (ii) refinance the existing senior secured revolving credit facility and NEG’s existing credit facility, and (iii) pay fees and expenses related to the NEG acquisition and the existing credit facility.
 
The senior credit facility contains various covenants that limit the Company and certain of its subsidiaries’ ability to grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s 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 term loans (as discussed above).
 
The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for the (i) ratio of total funded debt to EBITDAX (as defined in the senior credit facility), (ii) ratio of EBITDAX to interest expense plus current maturities of long-term debt, and (iii) current ratio. The Company was in compliance with all of the covenants under the senior credit facility as of March 31, 2008.
 
The obligations under the senior credit facility are secured by first priority liens on all shares of capital stock of each of the Company’s present and future subsidiaries; all intercompany debt of the Company and its subsidiaries; and substantially all of the Company’s assets and the assets of its guarantor subsidiaries, including proved crude oil and natural gas reserves representing at least 80% of the present discounted value (as defined in the senior credit facility) of proved crude oil and natural gas reserves reviewed in determining the


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements — (Continued)
 
borrowing base for the senior credit facility. Additionally, the obligations under the senior credit facility are guaranteed by certain Company subsidiaries.
 
At the Company’s election, interest under the senior credit facility is determined by reference to (i) the LIBOR rate plus an applicable margin between 1.25% and 2.00% per annum or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin between 0.25% and 1.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three month period. The average interest rate paid on amounts outstanding under our senior credit facility for the three month period ended March 31, 2008 was 4.57%.
 
The borrowing base of proved reserves was initially set at $300.0 million. The borrowing base was increased to $400.0 million on May 2, 2007, to $700.0 million on September 14, 2007 and to $1.2 billion on April 4, 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 on April 4, 2008. At March 31, 2008, the Company had $215.0 million in outstanding indebtedness under this facility.
 
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 NEG’s 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. 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.
 
Other Indebtedness.  The Company has financed a portion of its drilling rig fleet and related oil field services equipment through notes. At March 31, 2008, the aggregate outstanding balance of these notes was $44.3 million, with an annual fixed interest rate ranging from 7.64% to 8.87%. The notes have a final maturity date of December 1, 2011, require aggregate monthly installments for principal and interest in the amount of $1.2 million and are secured by the equipment. The notes have a prepayment penalty (currently ranging from 1 to 3%) that is triggered if the Company repays the notes prior to maturity.
 
On November 15, 2007, the Company entered into a note payable in the amount of $20.0 million with a lending institution 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 expects to make payments of principal and interest on this note totaling $0.8 million and $1.2 million, respectively.
 
Prior to 2007, the Company financed the purchase of various vehicles, oil field services equipment and other equipment through various notes payable. The aggregate outstanding balance of these notes as of December 31, 2006 was $4.5 million. Additionally, the Company financed its insurance premium payment made in 2007. These notes were substantially repaid during 2007 with borrowings under the Company’s senior credit facility. 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.
 
For the three months ended March 31, 2008 and 2007, interest payments, net of amounts capitalized, were approximately $25.4 million and $28.5 million, respectively.


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements — (Continued)
 
7.   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. On March 30, 2007, the Company made the first $5.0 million settlement payment plus accrued interest. The $5.0 million payment to be made on July 1, 2008 has been included in accounts payable-trade in the accompanying condensed consolidated balance sheets as of March 31, 2008 and December 31, 2007. The unpaid settlement amount of approximately $15.0 million has been included in other long-term obligations in the accompanying condensed consolidated balance sheets as of March 31, 2008 and December 31, 2007.
 
8.   Derivative Contracts
 
The Company has entered into various derivative contracts including collars, fixed price swaps, basis swaps and interest rate swaps with counterparties. The contracts expire on various dates through December 31, 2011.
 
At March 31, 2008, the Company’s open commodity derivative contracts consisted of the following:
 
Natural Gas
 
                 
    Notional
  Weighted Avg.
Period and Type of Contract
  (in MMBtus)   Fixed Price
 
April 2008 — June 2008
               
Price swap contracts
    17,900     $ 7.69  
Basis swap contracts
    13,350     $ (0.59 )
July 2008 — September 2008
               
Price swap contracts
    18,100     $ 8.23  
Basis swap contracts
    15,640     $ (0.57 )
October 2008 — December 2008
               
Price swap contracts
    17,480     $ 8.67  
Basis swap contracts
    14,720     $ (0.65 )
January 2009 — March 2009
               
Price swap contracts
    6,300     $ 9.12  
Basis swap contracts
    2,700     $ (0.49 )
April 2009 — June 2009
               
Price swap contracts
    910     $ 8.10  
Basis swap contracts
    2,730     $ (0.49 )
July 2009 — September 2009
               
Basis swap contracts
    2,760     $ (0.49 )
October 2009 — December 2009
               
Basis swap contracts
    2,760     $ (0.49 )
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 )


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements — (Continued)
 
Crude Oil
 
                 
    Notional
    Weighted Avg.
 
Period and Type of Contract
  (in MBbls)     Fixed Price  
 
April 2008 — June 2008
               
Price swap contracts
    270     $ 95.04  
Collar contracts
    21     $ 50.00 — 83.35  
July 2008 — September 2008
               
Price swap contracts
    225     $ 94.33  
Collar contracts
    27     $ 50.00 — 82.60  
October 2008 — December 2008
               
Price swap contracts
    225     $ 93.17  
Collar contracts
    27     $ 50.00 — 82.60  
 
In January 2008, the Company entered into an interest rate swap to fix the variable LIBOR interest rate on its variable rate term loans at 6.26% for the period April 1, 2008 to April 1, 2011.
 
These derivatives have not been designated as hedges. The Company records all derivatives on the balance sheet at fair value. Changes in derivative fair values are recognized in earnings. Cash settlements and valuation gains and losses for commodity derivative contracts are included in loss on derivative contracts in the condensed consolidated statements of operations. The following table summarizes the cash settlements and valuation gains and losses on commodity derivative contracts for the three month periods ended March 31, 2008 and 2007 (in thousands):
 
                 
    Three Months Ended March 31,  
    2008     2007  
 
Realized (gain) loss
  $ (7,329 )   $ 1,519  
Unrealized loss
    144,173       21,662  
                 
Loss on derivative contracts
  $ 136,844     $ 23,181  
                 
 
An unrealized gain of $0.8 million related to the interest rate swap is included in interest expense in the condensed consolidated statement of operations for the three month period ended March 31, 2008.
 
9.   Income Taxes
 
In accordance with applicable generally accepted accounting principles, the Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing income taxes on a current year-to-date basis.
 
For the three months ended March 31, 2008 and 2007, income tax payments were approximately $0.2 million and $0.4 million, respectively.
 
10.   Earnings Per Share
 
Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of awards of restricted stock. The following table


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Table of Contents

 
SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements — (Continued)
 
summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share, for the three month periods ended March 31, 2008 and 2007 (in thousands):
 
                 
    Three Months Ended March 31,  
    2008     2007  
 
Weighted average basic common shares outstanding
    141,044       92,442  
Effect of dilutive securities:
               
Restricted stock
           
                 
Weighted average diluted common and potential common shares outstanding
    141,044       92,442  
                 
 
For the three month periods ended March 31, 2008 and 2007, restricted stock awards covering 2.2 million shares and 1.3 million shares, respectively, 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 loss applicable to common stockholders.
 
11.   Commitments and Contingencies
 
The Company is a defendant in certain lawsuits from time to time in the normal course of business. In management’s opinion, the Company is not currently involved in any legal proceedings which, individually or in the aggregate, could have a material effect on the financial condition, operations and/or cash flows of the Company.
 
12.   Redeemable Convertible Preferred Stock
 
In November 2006, the Company sold 2,136,667 shares of redeemable convertible preferred stock in order to finance a portion of the NEG acquisition and received net proceeds from this sale of approximately $439.5 million after deducting offering expenses of approximately $9.3 million. Each holder of the redeemable convertible preferred stock is entitled to quarterly cash dividends at the annual rate of 7.75% of the accreted value of its redeemable convertible preferred stock. The accreted value was $210 per share as of March 31, 2008 and December 31, 2007. Each share of convertible preferred stock was initially convertible into ten (10.2 currently) shares of common stock at the option of the holder, subject to certain anti-dilution adjustments. A summary of dividends declared and paid on the redeemable convertible preferred stock is as follows (in thousands except per share data):
 
                         
        Dividends
           
Declared
 
Dividend Period
  per Share     Total    
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)    


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SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements — (Continued)
 
 
(1) Includes $0.6 million of prorated dividends paid to holders of redeemable convertible preferred shares who converted to shares of common stock in March 2008. The remaining dividends of $7.5 million were paid subsequent to March 31, 2008.
 
Approximately $8.1 million and $8.6 million in paid and unpaid dividends have been included in the Company’s earnings per share calculations for the three month periods ended March 31, 2008 and 2007, respectively, as presented in the accompanying condensed consolidated statements of operations.
 
On March 30, 2007, certain holders of the Company’s 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 Company’s redeemable convertible preferred stock elected to convert those shares into 3,465,593 shares of the Company’s common stock. The conversion resulted in an increase to additional paid in capital of $71.3 million, which represents the difference between the par value of the common stock issued and the carrying value of the redeemable convertible preferred shares converted. Additionally, the Company recorded a one-time charge to retained earnings for $1.1 million in accelerated accretion expense related to the converted redeemable convertible preferred shares.
 
Beginning in the second quarter of 2008, the Company may convert all outstanding shares of redeemable convertible preferred stock at the then conversion rate if certain conditions have been met. See Note 15.
 
13.   Stockholders’ Equity
 
The following table presents information regarding SandRidge’s common stock (in thousands):
 
                 
    March 31,
    December 31,
 
    2008     2007  
 
Shares authorized
    400,000       400,000  
Shares outstanding at end of period
    146,206       140,391  
Shares held in treasury
    1,310       1,456  
 
The Company is authorized to issue 50,000,000 shares of preferred stock, $0.001 par value, of which 2,625,000 shares are designated as redeemable convertible preferred. As of March 31, 2008 and December 31, 2007, there were 1,844,464 and 2,184,286 shares, respectively, of redeemable convertible preferred stock outstanding. (See Note 12.) There were no undesignated preferred shares outstanding as of March 31, 2008 and December 31, 2007.
 
Common Stock Issuance.  In March 2007, the Company sold approximately 17.8 million shares of common stock for net proceeds of $318.7 million after deducting offering expenses of approximately $1.4 million. The stock was sold in private sales to various investors including Tom L. Ward, the Company’s 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 Tom L. Ward, at a price of $26 per share. After deducting underwriting discounts of approximately $44.0 million and offering expenses of approximately $3.1 million, the Company received net


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SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements — (Continued)
 
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 (see additional discussion at Note 12).
 
Treasury Stock.  The Company makes required tax payments on behalf of employees as their restricted stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. As a result of such transactions, the Company withheld approximately 38,000 and 37,000 shares at a total value of $1.3 million and $0.7 million during the three month periods ended March 31, 2008 and 2007, respectively. These shares were accounted for as treasury stock.
 
During the first quarter 2008, the Company transferred 184,484 shares of its treasury stock into an account established for the benefit of the Company’s 401(k) Plan. The transfer was made in order to satisfy the Company’s $5.0 million accrued payable to match employee contributions made to the plan during 2007. Historical cost of the shares transferred totaled approximately $2.4 million, resulting in an increase to the Company’s additional paid-in capital of approximately $2.6 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 to vesting.
 
For the three months ended March 31, 2008 and 2007, the Company recognized stock-based compensation expense related to restricted stock of $3.2 million and $1.1 million, respectively. Stock-based compensation expense is reflected in general and administrative expense in the condensed consolidated statements of operations.
 
14.   Related Party Transactions
 
In the ordinary course of business, the Company engages in transactions with certain shareholders and other related parties. These transactions primarily consist of purchases of drilling equipment and sales of oil field service supplies. Following is a summary of significant transactions with such related parties for the three month periods ended March 31, 2008 and 2007 (in thousands):
 
                 
    Three Months Ended March 31,  
    2008     2007  
 
Sales to and reimbursements from related parties
  $ 25,356     $ 2,319  
                 
Purchases of services from related parties
  $ 19,890     $ 6,785  
                 
 
The Company leases office space in Oklahoma City from a member of its Board of Directors. The Company believes that the payments made under this lease are at fair market rates. Rent expense related to the lease totaled $0.4 million and $0.3 million for the three month periods ended March 31, 2008 and 2007, respectively. The lease expires in August 2009.


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SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements — (Continued)
 
Larclay, L.P.  The Company and Clayton Williams Energy, Inc. (“CWEI”) each own a 50% interest in Larclay, L.P., a limited partnership formed in 2006 to acquire drilling rigs and provide land drilling services. Larclay currently owns 12 rigs, one of which has not yet been assembled. The Company serves as the operations manager of the partnership. Under the partnership agreement, CWEI was responsible for rig financing and purchasing. The Company had sales to and cost reimbursements from Larclay for the three months ended March 31, 2008 and 2007 of $10.9 million and $2.3 million, respectively. As of March 31, 2008 and December 31, 2007, the Company had accounts receivable — related party due from Larclay of $18.3 million and $16.6 million, respectively. Additionally, the Company contracted with Larclay to utilize rigs for drilling. For the three month periods ended March 31, 2008 and 2007, the Company was billed $10.7 million and $6.8 million, respectively, for these services. As of March 31, 2008 and December 31, 2007, the Company had accounts payable — related party due to Larclay of $1.5 million and $0.3 million, respectively.
 
15.   Subsequent Events
 
Increase in Borrowing Base.  In April 2008, the Company’s borrowing base under its senior credit facility was increased to $1.2 billion from $700.0 million and the total available under the facility was increased to $1.75 billion from $750.0 million.
 
Exchange of Senior Term Loans.  On May 1, 2008, the Company issued $650.0 million of its Senior Notes due 2015 in exchange for an equal outstanding principal amount of its fixed rate term loans and $350.0 million of its Senior Floating Rate Notes due 2014 in exchange for an equal outstanding principal amount of its variable rate term loans. 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 have been issued with registration rights.
 
Conversion of 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. This conversion resulted in a one-time charge to retained earnings of $6.1 million in accelerated accretion expense related to the remaining offering costs of the 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.
 
Sale of Assets.  In May 2008, the Company entered into an agreement, along with other parties, to sell substantially all of its assets located in the Piceance Basin of Colorado to a subsidiary of The Williams Companies, Inc. The total purchase price is $285 million with net proceeds to the Company estimated to be approximately $140 million, subject to closing adjustments and allocation of the sales price among multiple sellers. Assets to be sold include undeveloped acreage, working interests in wells, gathering and compression systems and other facilities related to the wells. The sale is subject to customary closing conditions and is expected to close during the second quarter of 2008.
 
16.   Industry Segment Information
 
SandRidge has four business segments: exploration and production, drilling and oil field services, midstream gas services, and other. These segments represent the Company’s four main business units, each offering different products and services. The exploration and production segment is engaged in the development, acquisition and production of crude oil and natural gas properties. The drilling and oil field services segment is engaged in the land contract drilling of crude oil and natural gas wells. The midstream gas services segment is engaged in the purchasing, gathering, processing and treating of natural gas. The other segment


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SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements — (Continued)
 
includes transporting CO2 to market for use by the Company and others in tertiary oil recovery operations and other miscellaneous operations.
 
Management evaluates the performance of the Company’s business segments based on operating income, which is defined as segment operating revenues less operating expenses and depreciation, depletion and amortization. Summarized financial information concerning the Company’s segments is shown in the following table (in thousands):
 
                 
    Three Months Ended March 31,  
    2008     2007  
 
Revenues:
               
Exploration and production
  $ 206,966     $ 92,634  
Elimination of inter-segment revenue
    (44 )     (1,808 )
                 
Exploration and production, net of inter-segment revenue
    206,922       90,826  
                 
Drilling and oil field services
    79,838       56,915  
Elimination of inter-segment revenue
    (67,516 )     (29,020 )
                 
Drilling and oil field services, net of inter-segment revenue
    12,322       27,895  
                 
Midstream gas services
    148,235       61,422  
Elimination of inter-segment revenue
    (103,148 )     (35,235 )
                 
Midstream gas services, net of inter-segment revenue
    45,087       26,187  
                 
Other
    5,854       5,753  
Elimination of inter-segment revenue
    (1,099 )     (1,597 )
                 
Other, net of inter-segment revenue
    4,755       4,156  
                 
Total revenues
  $ 269,086     $ 149,064  
                 
Operating (Loss) Income:
               
Exploration and production
  $ (47,389 )   $ 371  
Drilling and oil field services
    (2,148 )     5,202  
Midstream gas services
    32       1,350  
Other
    (13,306 )     (3,455 )
                 
Total operating (loss) income
    (62,811 )     3,468  
Interest income
    796       1,088  
Interest expense
    (25,172 )     (35,429 )
Other income
    24       879  
                 
Loss before income tax benefit
  $ (87,163 )   $ (29,994 )
                 
Capital Expenditures:
               
Exploration and production
  $ 354,765     $ 127,582  
Drilling and oil field services
    17,921       41,242  
Midstream gas services
    38,721       9,543  
Other
    7,243       2,728  
                 
Total capital expenditures
  $ 418,650     $ 181,095  
                 


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SandRidge Energy, Inc. and Subsidiaries
 
Notes to Condensed Consolidated Financial Statements — (Continued)
 
                 
    Three Months Ended March 31,  
    2008     2007  
 
Depreciation, Depletion and Amortization:
               
Exploration and production
  $ 65,590     $ 33,211  
Drilling and oil field services
    12,348       7,163  
Midstream gas services
    2,774       1,113  
Other
    2,329       1,357  
                 
Total depreciation, depletion and amortization
  $ 83,041     $ 42,844  
                 
 
                 
    March 31,
    December 31,
 
    2008     2007  
 
Identifiable Assets(1):
               
Exploration and production
  $ 3,364,879     $ 3,143,137  
Drilling and oil field services
    272,374       271,563  
Midstream gas services
    169,578       127,822  
Other
    101,001       88,044  
                 
Total
  $ 3,907,832     $ 3,630,566  
                 
 
 
(1) Identifiable assets are those used in SandRidge’s operations in each business segment.

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Report of Independent Registered Public Accounting Firm
 
To the Member
NEG Oil & Gas LLC
 
We have audited the accompanying combined balance sheet of NEG Oil & Gas LLC and subsidiaries excluding National Energy Group, Inc., and the 103/4% Senior Notes due from National Energy Group, Inc., but including National Energy Group Inc.’s 50% membership interest in NEG Holding LLC (collectively, the “Company”) as of December 31, 2005 and the related statements of operations, changes in total member’s equity and cash flows for each of the two years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.
 
In our opinion, the combined financial statements referred to above, present fairly, in all material respects, the financial position of NEG Oil & Gas LLC and subsidiaries excluding National Energy Group, Inc. and the 103/4% Senior Notes due from National Energy Group Inc., but including National Energy Group Inc.’s 50% membership interest in NEG Holding LLC as of December 31, 2005, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
 
/s/  GRANT THORNTON LLP
 
Houston, Texas
October 27, 2006


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
COMBINED BALANCE SHEET AS OF DECEMBER 31, 2005
 
         
(In thousands)  
 
Current assets:
       
Cash and cash equivalents
  $ 102,322  
Accounts receivable, net
    53,378  
Notes receivable
    10  
Drilling prepayments
    3,281  
Other
    9,798  
         
Total current assets
    168,789  
         
Oil and gas properties, at cost (full cost method)
    1,229,923  
Accumulated depreciation, depletion and amortization
    (488,560 )
         
Net oil and gas properties
    741,363  
         
Other property and equipment
    6,029  
Accumulated depreciation
    (4,934 )
         
Net other property and equipment
    1,095  
Restricted deposits
    24,267  
Other assets
    4,842  
         
Total assets
  $ 940,356  
         
Current Liabilities:
       
Accounts payable
  $ 18,105  
Accounts payable revenue
    11,454  
Accounts payable — affiliates
    1,660  
Current portion of notes payable
    2,503  
Advance from affiliate
    39,800  
Prepayments from partners
    121  
Accrued interest
    162  
Accrued interest — affiliates
    2,194  
Income tax payable — affiliate
    2,749  
Derivative financial instruments
    68,039  
         
Total current liabilities
    146,787  
         
Commitments and contingencies
       
Credit facility
    300,000  
Gas balancing
    1,108  
Derivative financial instruments
    17,893  
Other liabilities
    250  
Asset retirement obligation
    41,228  
         
Total liabilities
    507,266  
         
Member’s equity
    433,090  
         
Total liabilities and member’s equity
  $ 940,356  
         
 
The accompanying notes are an integral part of these combined financial statements.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
COMBINED STATEMENTS OF OPERATIONS
 
                 
    For the Years Ended December 31,  
    2004     2005  
    (In thousands)  
 
Revenues:
               
Oil and gas sales — gross
  $ 144,430     $ 261,398  
Unrealized derivative losses
    (9,179 )     (69,254 )
                 
Oil and gas revenues — net
    135,251       192,144  
Plant revenues
    2,737       6,711  
                 
Total revenues
    137,988       198,855  
                 
Costs and expenses:
               
Lease operating
    14,912       27,437  
Transportation and gathering
    3,144       4,978  
Plant and field operations
    3,918       3,769  
Production and ad valorem taxes
    10,883       16,560  
Depreciation, depletion and amortization
    60,394       91,100  
Accretion of asset retirement obligation
    593       3,019  
General and administrative
    11,650       14,152  
                 
Total costs and expenses
    105,494       161,015  
                 
Operating income
    32,494       37,840  
Interest expense
    (3,428 )     (8,198 )
Interest expense — affiliate
    (3,054 )     (3,047 )
Interest income and other
    930       810  
Interest income from related parties
    150        
Equity in loss on investment
    (519 )     (1,118 )
Severance tax refund
    4,468        
(Loss) gain on sale of assets
    1,686       9  
Gain on sale of equity investment
          5,512  
                 
Income before income taxes
    32,727       31,808  
Income tax benefit (expense)
    (260 )     2,932  
                 
Income before minority interest
    32,467       34,740  
Minority interest
    (812 )      
                 
Net income
  $ 31,655     $ 34,740  
                 
 
The accompanying notes are an integral part of these combined financial statements.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
COMBINED STATEMENTS OF CASH FLOWS
 
                 
    For the Years Ended December 31,  
    2004     2005  
    (In thousands)  
 
Operating activities:
               
Net income
  $ 31,655     $ 34,740  
Noncash adjustments:
               
Deferred income tax benefit
    (144 )     (2,935 )
Depreciation depletion and amortization
    60,394       91,100  
Minority interest
    812        
Unrealized derivative losses
    9,179       69,254  
(Gain) loss on sale of assets
    (1,686 )     (9 )
Accretion of asset retirement obligation
    593       3,019  
Equity in loss on investment
    519       1,118  
Gain on sale of equity investment
          (5,512 )
Provision for doubtful accounts
    790       470  
Interest income-restricted deposits
          (494 )
Amortization of note discount
    281       81  
Amortization of note costs
    494       1,148  
Changes in operating assets and liabilities:
               
Accounts receivable
    (6,340 )     (13,496 )
Drilling prepayments
    249       179  
Derivative deposit
    1,700        
Other assets
    (1,030 )     (4,883 )
Note receivable
    (1,258 )     3,098  
Accounts payable and accrued liabilities
    12,014       (8,545 )
                 
Net cash provided by operating activities
    108,222       168,333  
                 
Investing activities:
               
Acquisition, exploration, and development costs
    (114,974 )     (315,880 )
Proceeds from sales of oil and gas properties
    4,981       1,329  
Purchases of furniture, fixtures and equipment
    (289 )     (511 )
Proceeds from sale of furniture, fixtures and equipment
          12  
Equity investment
    (1,200 )     (454 )
Investment in restricted deposits
          (4,973 )
Proceeds from sale of equity investment
          7,227  
                 
Net cash used in investing activities
    (111,482 )     (313,250 )
                 
Financing activities:
               
Debt issuance costs
    (440 )     (4,666 )
Net cash contributed by member
    23,753        
Repurchase of membership interest
    (4,136 )      
Proceeds from affiliate borrowings
          161,800  
Repayment of affiliate borrowings
          (98,357 )
Guaranteed payment to member
    (15,978 )     (15,978 )
Equity contribution
          5,326  
Dividend payment to member
          (78,000 )
Proceeds from credit facility
    8,000       379,100  
Principal payments on debt
    (9,365 )     (1,898 )
Repayment of credit facility
          (130,934 )
                 
Net cash provided (used) by financing activities
    1,834       216,393  
                 
Increase in cash and cash equivalents
    (1,426 )     71,476  
Cash and cash equivalents at beginning of period
    32,272       30,846  
                 
Cash and cash equivalents at end of period
  $ 30,846     $ 102,322  
                 
Supplemental cash flow information:
               
Cash paid for interest
  $ 5,471     $ 8,483  
                 
Cash paid for income taxes
  $ 50     $  
                 
 
The accompanying notes are an integral part of these combined financial statements.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
COMBINED STATEMENT OF CHANGES IN TOTAL MEMBER’S EQUITY
 
         
(In thousands)  
 
Total member’s equity — January 1, 2004
  $ 285,211  
Contribution from member — National Offshore
    91,561  
Contribution from member — National Onshore minority interest
    2,218  
Purchase of minority membership interest
    (4,136 )
Guaranteed payment to member
    (15,978 )
Net income
    31,655  
         
Total member’s equity — December 31, 2004
    390,531  
         
Contribution of Notes Payable to AREP
    89,143  
Equity Contribution
    5,326  
Contribution of deferred tax assets
    (5,471 )
Contribution of deferred tax liabilities
    12,799  
Guaranteed payment to member
    (15,978 )
Dividend distribution
    (78,000 )
Net income
    34,740  
         
Total member’s equity — December 31, 2005
  $ 433,090  
         
 
The accompanying notes are an integral part of these combined financial statements.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS
December 31, 2004 and 2005
 
1.   Organization and Background
 
The accompanying combined financial statements present NEG Oil & Gas LLC and subsidiaries, excluding National Energy Group, Inc. and the 103/4% Senior Notes due from National Energy Group, but including National Energy Group’s 50% membership interest in NEG Holding LLC (collectively, “the Company”). The Company is an oil and natural gas exploration and production company engaged in the exploration, development, production and operations of natural gas and oil properties, primarily located in Texas, Oklahoma, Arkansas and Louisiana (both onshore and in the Gulf of Mexico).
 
NEG Oil & Gas LLC is wholly-owned by American Real Estate Holdings Limited Partnership (“AREH”). AREH is 99% owned by American Real Estate Partners, L.P. (“AREP”). AREP is a publicly traded limited partnership that is majority owned by Mr. Carl C. Icahn.
 
NEG Oil & Gas LLC was formed on December 2, 2004 to hold the oil and gas investments of the Company’s ultimate parent company, AREP and, as of December 31, 2005 had the following assets and operations:
 
  •  A 50.01% ownership interest in National Energy Group, Inc (National Energy Group), a publicly traded oil and gas management company. National Energy Group’s principal asset consists of its 50% membership interest in NEG Holding LLC (Holding, LLC).
 
  •  $148.6 million principal amount of 103/4% Senior Notes due from National Energy Group (the “103/4% Senior Notes”).
 
  •  A 50% managing membership interest in Holding, LLC.
 
  •  The oil and gas operations of National Onshore LP (formerly TransTexas Gas Corporation); and
 
  •  The oil and gas operations of National Offshore LP (formerly Panaco, Inc.)
 
All of the above assets initially were acquired by entities owned or controlled by Mr. Icahn and subsequently acquired by AREP (through subsidiaries) in various purchase transactions. In accordance with generally accepted accounting principles, assets transferred between entities under common control are accounted for at historical cost similar to a pooling of interest and the financial statements are combined from the date of acquisition by an entity under common control. The financial statements include the combined results of operations, financial position and cash flows of each of the above entities since its initial acquisition by entities owned or controlled by Mr. Icahn (the “Period of Common Control”).
 
On September 7, 2006, AREP signed a letter of intent to sell NEG Oil & Gas LLC and subsidiaries, excluding National Energy Group, Inc. and the 103/4% Senior Notes due from National Energy Group, but including National Energy Group’s 50% membership interest in Holding LLC to Riata Energy, Inc., DBA SandRidge Energy, Inc. (“Riata Energy”) The combined financial statements include the entities to be sold to Riata Energy.
 
Background
 
National Energy Group, Inc. — In February, 1999 National Energy Group was placed under involuntary, court ordered bankruptcy protection. Effective August 4, 2000 National Energy Group emerged from involuntary bankruptcy protection with affiliates of Mr. Icahn owning 49.9% of the common stock and $165 million principal amount of debt securities (“Senior Notes”). As mandated by National Energy Group’s Plan of Reorganization, Holding LLC was formed and on September 1, 2001, National Energy Group contributed to Holding LLC all of its oil and natural gas properties in exchange for an initial membership


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
interest in Holding LLC. National Energy Group retained $4.3 million in cash. On September 1, 2001, an affiliate of Mr. Icahn contributed to Holding LLC oil and natural gas assets, cash and a $10.9 million note receivable from National Energy Group in exchange for the remaining membership interest, which was designated the managing membership interest. Concurrently, in September, 2001, but effective as of May 2001, Holding LLC formed a 100% owned subsidiary, NEG Operating Company, LLC (“Operating LLC”) and contributed all of its oil and natural gas assets to Operating LLC.
 
In October 2003, AREP acquired all outstanding Senior Notes ($148.6 million principal amount at October 2003) and 5,584,044 shares of common stock of National Energy Group from entities affiliated with Mr. Icahn for aggregate consideration of approximately $148.1 million plus approximately $6.7 million of accrued interest on the Senior Notes. As a result of this transaction and the acquisition by AREP of additional shares of National Energy Group, AREP beneficially owned 50.1% of the outstanding stock of National Energy Group and had effective control. In June 2005, all of the stock of National Energy Group and the $148.6 million principal amount of Senior Notes owned by AREP was contributed to the Company and National Energy Group became a 50.1% owned subsidiary. The accrued, but unpaid interest on the $148.6 million principal amount of Senior Notes was retained by AREP. National Energy Group and the Senior Notes will be retained by AREP and not purchased by Riata Energy.
 
NEG Holding LLC — On June 30, 2005, AREP acquired the managing membership interest in Holding LLC from an affiliate of Mr. Icahn for an aggregate consideration of approximately $320 million. The membership interest acquired constituted all of the membership interests other than the membership interest already owned by National Energy Group. The combined financial statements include the consolidation of the acquired 50% membership interest in Holding LLC, together with the 50% membership interest owned by National Energy Group. The Period of Common Control for Holding LLC began on September 1, 2001, the initial funding of Holding LLC.
 
The Holding LLC Operating Agreement — Holding LLC is governed by an operating agreement effective May 12, 2001, which provides for management and control of Holding LLC by the Company and distributions to National Energy Group and the Company based on a prescribed order of distributions (the “Holding LLC Operating Agreement”).
 
Order of Distributions
 
Pursuant to the Holding LLC Operating Agreement, distributions from Holding LLC to National Energy Group and the Company shall be made in the following order:
 
1. Guaranteed payments (“Guaranteed Payments”) are to be paid to National Energy Group, calculated on an annual interest rate of 103/4% on the outstanding priority amount (“Priority Amount”). The Priority Amount includes all outstanding debt owed to the Company, including the amount of National Energy Group’s 103/4% Senior Notes. As of December 31, 2005, the Priority Amount was $148.6 million. The Guaranteed Payments will be made on a semi-annual basis.
 
2. The Priority Amount is to be paid to National Energy Group. Such payment is to occur by November 6, 2006.
 
3. An amount equal to the Priority Amount and all Guaranteed Payments paid to National Energy Group, plus any additional capital contributions made by the Company, less any distributions previously made by Holding LLC to the Company, is to be paid to the Company.
 
4. An amount equal to the aggregate annual interest (calculated at prime plus 1/2% on the sum of the Guaranteed Payments), plus any unpaid interest for prior years (calculated at prime plus 1/2% on the sum


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
of the Guaranteed Payments), less any distributions previously made by Holding LLC to the Company, is to be paid to NEG Oil & Gas.
 
5. After the above distributions have been made, any additional distributions will be made in accordance with the ratio of NEG Oil & Gas and National Energy Group’s respective capital accounts. (Capital accounts as defined in the Holding LLC Operating Agreement.)
 
Redemption Provision in the Holding LLC Operating Agreement
 
The Holding LLC Operating Agreement contains a provision that allows the managing member (NEG Oil & Gas), at any time, in its sole discretion, to redeem National Energy Group’s membership interest in Holding LLC at a price equal to the fair market value of such interest determined as if Holding LLC had sold all of its assets for fair market value and liquidated.
 
Prior to closing the Riata Energy purchase transaction, AREP will cause NEG Oil & Gas to exercise the redemption provision and dividend the 103/4% Senior Notes to AREP or enter into transactions with a similar effect such that NEG Oil & Gas will own 100% of Holding LLC and no longer own the 103/4% Senior Notes receivable from National Energy Group. AREP will indemnify NEG Oil & Gas for any costs associated with the exercise of the redemption provision. The Holding LLC Operating Agreement will be cancelled.
 
National Onshore LP — On November 14, 2002, National Onshore filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Corpus Christi Division. National Onshore’s First Amended Joint Plan of Reorganization submitted by an entity affiliated with Mr. Icahn, as modified on July 8, 2003 (the “National Onshore Plan”), was confirmed by the Bankruptcy Court on August 14, 2003 effective August 28, 2003.
 
As of the effective date of the National Onshore Plan, an entity affiliated with Mr. Icahn owned 89% of the outstanding shares of National Onshore. During June 2004, the entity affiliated with Mr. Icahn acquired an additional 5.7% of the outstanding shares of National Onshore from certain other stockholders. During December 2004, National Onshore acquired the remaining 5.3% of the outstanding shares that were not owned by an affiliate of Mr. Icahn. The difference between the purchase price for both acquisitions and the minority interest liability was treated as a purchase price adjustment which reduced the full cost pool.
 
On December 6, 2004, AREP purchased from an affiliates of Mr. Icahn $27.5 million aggregate principal amount, or 100%, of the outstanding term notes issued by National Onshore (the “National Onshore Notes”). The purchase price was $28.2 million, which equals the principal amount of the National Onshore Notes plus accrued unpaid interest. The notes are payable annually in equal consecutive annual payments of $5.0 million, with the final installment due August 28, 2008. Interest is payable semi-annually in February and August at the rate of 10% per annum.
 
On April 6, 2005, AREP acquired 100% of the outstanding stock of National Onshore from entities owned by Mr. Icahn for an aggregate consideration of $180 million. The operations of National Onshore are considered to have been contributed to the Company on August 28, 2003 at a historical cost of approximately $116.3 million, representing the historical basis in the assets and liabilities of National Onshore of the entities owned by Mr. Icahn. AREP contributed the National Onshore Notes, but not the accrued and unpaid interest through the date of contribution, to the Company on June 30, 2005. The Period of Common Control of National Onshore began on August 28, 2003.
 
National Offshore LP — On July 16, 2002, National Offshore filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court of the Southern District of Texas. On November 3, 2004, the Bankruptcy Court entered a confirmation order for the National


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
Offshore’s Plan of Reorganization (the “National Offshore Plan”). The National Offshore Plan became effective November 16, 2004 and National Offshore began operating as a reorganized entity. Upon emergence from bankruptcy, an entity controlled by Mr. Icahn owned 100% of the outstanding common stock of National Offshore.
 
On December 6, 2004, AREP purchased $38.0 million aggregate principal amount of term loans issued by National Offshore, which constituted 100% of the outstanding term loans of National Offshore from an affiliate of Mr. Icahn. On June 30, 2005, AREP contributed the National Offshore term loan, but not the accrued and unpaid interest through the date of contribution, to the Company.
 
On June 30, 2005, AREP acquired 100% of the equity of National Offshore from affiliates of Mr. Icahn for consideration valued at approximately $125.0 million. The Period of Common Control for National Offshore began on November 16, 2004 when National Offshore emerged from bankruptcy. The acquisition of National Offshore has been recorded effective December 31, 2004. The historical cost of approximately $91.6 million, representing the historical basis in the assets and liabilities of National Offshore of the affiliates of Mr. Icahn, was considered to have been contributed to the Company on December 31, 2004.
 
2.   Significant Accounting Policies
 
Basis of Presentation
 
The combined financial statements include the accounts of NEG Oil & Gas LLC and subsidiaries excluding National Energy Group and the 103/4% Senior Notes due from National Energy Group, but including National Energy Group’s 50% membership interest in NEG Holding LLC (the Company). All material intercompany accounts and transactions have been eliminated in the combined financial statements. Investments in subsidiaries over which the Company has significant influence, but not control, are reported using the equity method.
 
Accounting Estimates
 
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities 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 these estimates.
 
Cash and Cash Equivalents
 
Cash and cash equivalents may include demand deposits, short-term commercial paper, and/or money-market investments with maturities of three months or less when purchased. Cash in bank deposit accounts are generally maintained at high credit quality financial institutions and may exceed federally insured limits. The Company has not experienced any losses in such accounts and does not believe it is exposed to any significant risk of loss.
 
Oil and Natural Gas Properties
 
The Company utilizes the full cost method of accounting for its crude oil and natural gas properties. Under the full cost method, all productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of crude oil and natural gas reserves are capitalized and amortized on the units-of-production method based upon total proved reserves. The Company elects to include its current unevaluated properties in the full cost pool. Conveyances of properties, including gains or losses on abandonments of


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
properties, are treated as adjustments to the cost of crude oil and natural gas properties, with no gain or loss recognized unless the sale or disposition represents a significant portion of the Company’s oil and natural gas reserves.
 
Under the full cost method, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at 10% per year (the ceiling limitation) plus the lower of cost or fair value of unevaluated properties, if any. In arriving at estimated future net revenues, estimated lease operating expenses, development costs, abandonment costs, certain production related ad-valorem taxes, and estimated corporate income taxes relating to oil and gas properties, if any, are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes which are fixed and determinable by existing contracts. Such contracts may include derivative contracts that meet the accounting requirements and are documented, designated and accounted for as cash flow hedges. None of the Company’s derivatives contracts were accounted for as cash flow hedges. Consequently, prices were held constant indefinitely. The net book value is compared to the ceiling limitation on a quarterly basis. The excess, if any, of the net book value above the ceiling limitation is required to be written off as a non-cash expense. The Company did not incur a ceiling writedown in 2004 and 2005. There can be no assurance that there will not be writedowns in future periods under the full cost method of accounting as a result of sustained decreases in oil and natural gas prices or other factors.
 
The Company has capitalized internal costs of $1.0 million and $1.1 million for the years ended December 31, 2004 and 2005, respectively, as cost of oil and natural gas properties. Oil and natural gas properties include cumulative capitalized internal costs of $3.5 million as of December 31, 2005. Such capitalized costs include salaries and related benefits of individuals directly involved in the Company’s acquisition, exploration, and development activities based on a percentage of their salaries. These costs do not include any costs related to production, general corporate overhead, or similar activities.
 
Costs associated with production and general corporate activities are expensed in the period incurred. Production costs are costs incurred to operate and maintain the Company’s wells and related equipment and include cost of labor, well service and repair, location maintenance, power and fuel, transportation, cost of product, property taxes, production and severance taxes and production related general and administrative costs.
 
The Company receives reimbursement for administrative and overhead expenses incurred on behalf of other working interest owners on properties the Company operates. Such reimbursements are recorded as reductions to general and administrative expenses to the extent of actual costs incurred. Reimbursements in excess of actual costs incurred, if any, are credited to the full cost pool to be recognized through lower cost amortization as production occurs. Historically, the Company has not received any administrative and overhead reimbursements in excess of costs incurred.
 
The Company is subject to extensive federal, state, and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
The Company’s operations are subject to all of the risks inherent in oil and natural gas exploration, drilling and production. These hazards can result in substantial losses to the Company due to personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, or suspension of operations. The Company maintains insurance of various types customary in the industry to cover its operations and believes it is insured prudently against certain of these risks. In addition, the Company maintains operator’s extra expense coverage that provides coverage for the care, custody and control of wells drilled by the Company. The Company’s insurance does not cover every potential risk associated with the drilling and production of oil and natural gas. As a prudent operator, the Company does maintain levels of insurance customary in the industry to limit its financial exposure in the event of a substantial environmental claim resulting from sudden and accidental discharges. However, 100% coverage is not maintained. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on the Company’s financial condition and results of operations. Moreover, no assurance can be given that the Company will be able to maintain adequate insurance in the future at rates it considers reasonable. The Company believes that it operates in compliance with government regulations and in accordance with safety standards which meet or exceed industry standards.
 
Other Property and Equipment
 
Other property and equipment includes furniture, fixtures, and other equipment. Such assets are recorded at cost and are depreciated over their estimated useful lives using the straight-line method.
 
The Company’s investment in Longfellow Ranch Field includes an interest in a gas separation facility. This investment is included in the oil and natural gas properties and depleted over the life of the reserves.
 
Maintenance and repairs are charged against income when incurred; renewals and betterments, which extend the useful lives of property and equipment, are capitalized.
 
Income Taxes
 
NEG Oil & Gas and Holding LLC are taxed as partnerships under applicable federal and state laws. No income taxes have been provided on the income of NEG Oil & Gas since these taxes are the responsibility of the member. Income tax liabilities and assets reflect the obligations and assets of its consolidated entities.
 
National Onshore and National Offshore were organized as corporations and were subject to corporate income tax until their acquisition by NEG Oil & Gas. For income tax purposes, through the date of acquisition by NEG Oil & Gas, the taxable income or loss of National Onshore and its subsidiaries and National Offshore are included in the consolidated income tax return of the Starfire Holding Corp. (“Starfire”) controlled group. National Onshore and its subsidiaries and National Offshore entered into tax allocation agreements with Starfire, an entity owned by Mr. Icahn. The tax allocation agreements provide for payments of tax liabilities to Starfire, calculated as if National Onshore and its subsidiaries and National Offshore each filed a consolidated income tax return separate from the Starfire controlled group. Additionally, the agreements provide for payments from Starfire to National Onshore and its subsidiaries or National Offshore for any previously paid tax liabilities that are reduced as a result of subsequent determinations by any government authority, or as a result of any tax losses or credits that are allowed to be carried back to prior years.
 
The Company accounts for income tax assets and liabilities of its consolidated corporate entities in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (SFAS 109). SFAS 109 requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the financial statements carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date. The Company maintains valuation allowances where it is determined more likely than not that all or a portion of a deferred tax asset will not be realized. Changes in valuation allowances from period to period are included in the Company’s tax provision in the period of change. In determining whether a valuation allowance is warranted, the Company takes into account such factors as prior earnings history, expected future earnings, carryback and carryforward periods, and tax planning strategies.
 
Accounts Receivable
 
The Company sells crude oil and natural gas to various customers. In addition, the Company participates with other parties in the operation of crude oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of crude oil and natural gas or participants in crude oil and natural gas wells for which the Company serves as the operator. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. Crude oil and natural gas sales are generally unsecured.
 
The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. Provisions for bad debts and recoveries on accounts previously charged-off are added to the allowance.
 
Accounts receivable allowance for bad debt totaled approximately $0.2 million at December 31, 2005. At December 31, 2005, the carrying value of the Company’s accounts receivable approximates fair value.
 
Revenue Recognition
 
Revenues from the sale of natural gas and oil produced are recognized upon the passage of title, net of royalties.
 
Natural Gas Production Imbalances
 
The Company accounts for natural gas production imbalances using the sales method, whereby the Company recognizes revenue on all natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the natural gas sold. Liabilities are recorded by the Company for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for gas balancing of $1.1 million at December 31, 2005.
 
Comprehensive Income
 
Comprehensive income is defined as the change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. There were no differences between net earnings and total comprehensive income in 2004 and 2005.
 
Derivatives
 
From time to time, the Company enters into various derivative instruments consisting principally of no cost collar options (the “Derivative Contracts”) to reduce its exposure to price risk in the spot market for


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
natural gas and oil. The Company follows Statement of Financial Accounting Standards No. 133 (SFAS 133), Accounting for Derivative Instruments and Hedging Activities, which was amended by Statement of Financial Accounting Standards No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities. These pronouncements established accounting and reporting standards for derivative instruments and for hedging activities, which generally require recognition of all derivatives as either assets or liabilities in the balance sheet at their fair value. The accounting for changes in fair value depends on the intended use of the derivative and its resulting designation. The Company elected not to designate these instruments as hedges for accounting purposes, accordingly the cash settlements and valuation gains and losses are included in oil and natural gas sales. The following summarizes the cash settlements and valuation gains and losses for the years ended December 31, 2004 and 2005 (amounts in thousands):
 
                 
    2004     2005  
 
Realized loss — (net cash payments)
  $ 16,625     $ 51,263  
Unrealized loss
    9,179       69,254  
                 
Loss on Derivative Contracts
  $ 25,804     $ 120,517  
                 
 
The following is a summary of the Company’s Derivative Contracts as of December 31, 2005:
 
                         
Type of Contract
  Production Month   Volume per Month   Floor     Ceiling  
 
No cost collars
  Jan-Dec 2006   31,000 Bbls   $ 41.65     $ 45.25  
No cost collars
  Jan-Dec 2006   16,000 Bbls     41.75       45.40  
No cost collars
  Jan-Dec 2006   570,000 MmBtu     6.00       7.25  
No cost collars
  Jan-Dec 2006   120,000 MmBtu     6.00       7.28  
No cost collars
  Jan-Dec 2006   500,000 MmBtu     4.50       5.00  
No cost collars
  Jan-Dec 2006   46,000 Bbls     60.00       68.50  
 
(The Company participates in a second ceiling at $84.50 on the 46,000 Bbls)
No cost collars
  Jan-Dec 2007   30,000 Bbls     57.00       70.50  
No cost collars
  Jan-Dec 2007   30,000 Bbls     57.50       72.00  
No cost collars
  Jan-Dec 2007   930,000 MmBtu     8.00       10.23  
No cost collars
  Jan-Dec 2008   46,000 Bbls     55.00       69.00  
No cost collars
  Jan-Dec 2008   750,000 MmBtu     7.00       10.35  
 
While the use of derivative contracts can limit the downside risk of adverse price movements, it may also limit future gains from favorable movements. The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity. Credit risk related to derivative activities is managed by requiring minimum credit standards for counter parties, periodic settlements, and mark to market valuations.
 
A liability of $85.9 million (including a current liability of $68.0 million) was recorded by the Company as of December 31, 2005 in connection with these contracts. Prior to the execution of the Company’s new credit facility, during 2005 the Company was required to provide security to counter parties for its Derivative Contracts in loss positions.
 
On December 22, 2005, concurrent with the execution of the Company’s new credit facility (see note 9) the Company novated all of Derivative Contracts with Shell Trading (US) outstanding as of that date with identical Derivative Contracts with Citicorp (USA), Inc. as the counter party. Under this transaction, no contracts were settled, Citicorp (USA) replaced Shell Trading (US) as the counter party and no gain or loss was recorded.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
Under the new credit facility, Derivatives Contracts with certain lenders under the credit facility do not require cash collateral or letters of credit and rank pari passu with the credit facility. All cash collateral and letters of credit have been released as of December 31, 2005.
 
Accounting for Asset Retirement Obligations
 
The Company accounts for its asset retirement obligations under Statement of Financial Accounting Standards No. 143 (SFAS 143), Accounting for Asset Retirement Obligations. SFAS 143 provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets. Under SFAS 143, an asset retirement obligation is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the related asset.
 
The Company’s asset retirement obligation represents expected future costs to plug and abandon its wells, dismantle facilities, and reclamate sites at the end of the related assets’ useful lives.
 
Recent Accounting Pronouncements
 
On December 16, 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payment” that will require compensation costs related to share-based payment transactions (e.g., issuance of stock options and restricted stock) to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. Statement 123(R) replaces SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” For us, SFAS 123(R) is effective for the first reporting period beginning after June 15, 2005. Entities that use the fair-value-based method for either recognition or disclosure under SFAS 123 are required to apply SFAS 123(R)using a modified version of prospective application. Under this method, an entity records compensation expense for all awards it grants after the date of adoption. In addition, the entity is required to record compensation expense for the unvested portion of previously granted awards that remain outstanding at the date of adoption. In addition, entities may elect to adopt SFAS 123(R)using a modified retrospective method whereby previously issued financial statements are restated based on the expense previously calculated and reported in their pro forma footnote disclosures. The Company had no share based payments subject to this standard.
 
In December 2004, the FASB issued Statement 153, “Exchanges of Nonmonetary Assets”, an amendment of APB Opinion No. 29, to clarify the accounting for nonmonetary exchanges of similar productive assets. SFAS 153 provides a general exception from fair value measurement for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The Statement will be applied prospectively and is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company does not have any nonmonetary transactions for any period presented that this Statement would apply.
 
In March 2005, the FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations — an Interpretation of FASB Statement No. 143 (“Interpretation”). This Interpretation clarifies that the term conditional asset retirement obligation as used in FASB Statement No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. This Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. This Interpretation is effective for the Company’s year ended December 31, 2005. The adoption of this Interpretation did not impact the Company’s combined financial position or results of operations.
 
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3 (“SFAS No. 154”). SFAS No. 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS No. 154 will become effective for the Company’s fiscal year beginning January 1, 2006. The impact of SFAS No. 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS No. 154 to have a material impact on the Company’s combined financial position, results of operations or cash flows.
 
On February 16, 2006, the FASB issued Statement 155, “Accounting for Certain Hybrid Instruments — an amendment of FASB Statements No. 133 and 140.” The statement amends Statement 133 to permit fair value measurement for certain hybrid financial instruments that contain an embedded derivative, provides additional guidance on the applicability of Statement 133 and 140 to certain financial instruments and subordinated concentrations of credit risk. The new standard is effective for the first fiscal year that begins after September 15, 2006 (January 1, 2007 for the Company). We have no hybrid instruments subject to this standard.
 
3.   Management Agreements
 
The management and operation of Operating LLC is being undertaken by National Energy Group pursuant to the Management Agreement (the “Operating LLC Management Agreement”) which Operating LLC entered into with National Energy Group. However, neither National Energy Group’s officers nor directors control the strategic direction of Operating LLC’s oil and natural gas business, including oil and natural gas drilling and capital investments, which are controlled by the managing member of Holding LLC (NEG Oil & Gas). The Operating LLC management agreement provides that National Energy Group will manage Operating LLC’s oil and natural gas assets and business until the earlier of November 1, 2006, or such time as Operating LLC no longer owns any of the managed oil and natural gas properties. National Energy Group’s employees conduct the day-to-day operations of Operating LLC’s oil and natural gas business, and all costs and expenses incurred in the operation of the oil and natural gas properties are borne by Operating LLC, although the Operating LLC Management Agreement provides that the salary of National Energy Group’s Chief Executive Officer shall be 70% attributable to the managed oil and natural gas properties, and the salaries of each of the General Counsel and Chief Financial Officer shall be 20% attributable to the managed oil and natural gas properties. In exchange for National Energy Group’s management services, Operating LLC pays National Energy Group a management fee equal to 115% of the actual direct and indirect administrative and reasonable overhead costs that National Energy Group incurs in operating the oil and natural gas properties. National Energy Group or Operating LLC may seek to change the management fee to within the range of 110%-115% as such change is deemed warranted. However, both have agreed to consult with each other to ensure that such administrative and reasonable overhead costs attributable to the managed properties are properly reflected in the management fee that is paid. In addition, Operating


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
LLC has agreed to indemnify National Energy Group to the extent National Energy Group incurs any liabilities in connection with National Energy Group’s operation of the assets and properties of Operating LLC, except to the extent of National Energy Group’s gross negligence or misconduct. Operating LLC incurred $6.2 million and $5.6 million in general and administrative expenses for the years ended December 31, 2004 and 2005, respectively under this agreement.
 
On August 28, 2003, National Energy Group entered into a management agreement to manage the oil and natural gas business of National Onshore. The National Onshore management agreement was entered in connection with a plan of reorganization for National Onshore proposed by Thornwood Associates LP, an entity affiliated with Carl C. Icahn (the “National Onshore Plan”). On August 28, 2003, the United States Bankruptcy Court, Southern District of Texas, issued an order confirming the National Onshore Plan. NEG Oil & Gas owns all of the reorganized National Onshore, which is engaged in the exploration, production and transmission of oil and natural gas, primarily in South Texas, including the Eagle Bay field in Galveston Bay, Texas and the Southwest Bonus field located in Wharton County, Texas. Bob G. Alexander and Philip D. Devlin, National Energy Group’s President and CEO, and National Energy Group’s Vice President, Secretary and General Counsel, respectively, have been appointed to the reorganized National Onshore Board of Directors and act as the two principal officers of National Onshore and its subsidiaries, Galveston Bay Pipeline Corporation and Galveston Bay Processing Corporation. Randall D. Cooley, National Energy Group’s Vice President and CFO, has been appointed Treasurer of reorganized National Onshore and its subsidiaries.
 
The National Onshore Management Agreement provides that National Energy Group shall be responsible for and have authority with respect to all of the day-to-day management of National Onshore business, but will not function as a Disbursing Agent as such term is defined in the National Onshore Plan. As consideration for National Energy Group services in managing the National Onshore business, National Energy Group receives a monthly fee of $0.3 million. The National Onshore Management Agreement is terminable (i) upon 30 days prior written notice by National Onshore, (ii) upon 90 days prior written notice by National Energy Group, (iii) upon 30 days following any day where High River designees no longer constitute the National Onshore Board of Directors, unless otherwise waived by the newly-constituted Board of Directors of National Onshore, or (iv) as otherwise determined by the Bankruptcy Court. The Company recorded $4.7 million and $4.8 million in general and administrative expenses for the years ended December 31, 2004 and 2005, respectively, under this agreement.
 
On November 3, 2004, the United States Bankruptcy Court for the Southern District of Texas issued an order effective November 16, 2004 confirming a plan of reorganization for National Offshore (“National Offshore Plan”). In connection with the National Offshore Plan, National Energy Group entered into a Management Agreement with National Offshore (the “National Offshore Management Agreement) pursuant to the Bankruptcy Court’s order confirming the effective date of the National Offshore Plan. NEG Oil & Gas owns all of the reorganized National Offshore. Mr. Bob G. Alexander, National Energy Group’s President and CEO, has been appointed to the reorganized National Offshore Board of Directors and acts as the reorganized National Offshore’s President. Mr. Philip D. Devlin, National Energy Group’s Vice President, General Counsel and Secretary, has been appointed to serve in the same capacities for National Offshore. Mr. Randall D. Cooley, National Energy Group’s Vice President and CFO, has been appointed as Treasurer of the reorganized National Offshore. In exchange for management services, National Energy Group receives a monthly fee equal to 115% of the actual direct and indirect administrative overhead costs that are incurred in operating and administering the National Offshore oil and natural gas properties. The Company recorded $0.7 million and $4.2 million in general and administrative expenses for the years ended December 31, 2004 and 2005, respectively, under this agreement.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
Substantially concurrent with the Riata Energy purchase transaction the management agreements will be terminated.
 
4.   Contributions of National Onshore and National Offshore
 
National Onshore — On August 28, 2003, the effective date of the confirmation of National Onshore’s bankruptcy plan, an entity affiliated with Mr. Icahn owned 89% of the outstanding shares of National Onshore. The assets and liabilities of National Onshore were considered to have been contributed to the Company on that date at the historical cost of the entity affiliated with Mr. Icahn.
 
During June 2004, the entity affiliated with Mr. Icahn acquired an additional 5.7% of the outstanding shares of National Onshore from certain other stockholders at a cost of approximately $2.2 million. The $2.2 million purchase is recorded as a capital contribution from member in 2004. In December 2004, the remaining 5.3% of National Onshore shares not owned by the entity affiliated with Mr. Icahn was purchased by National Onshore at a cost of $4.1 million. The share repurchase is reflected as a purchase of membership interest in 2004. The difference between the purchase price for both acquisitions and the minority interest liability was treated as an adjustment to the historical cost basis which reduced the full cost pool.
 
National Offshore — Effective December 31, 2004, the Period of Common Control of National Offshore, the following assets and liabilities were considered to have been contributed to the Company (amounts in thousands):
 
         
Assets contributed
       
Cash and cash equivalents
  $ 23,753  
Accounts receivable
    10,482  
Drilling prepayments
    2,601  
Deferred tax assets, net
    1,943  
Other
    2,051  
Oil and natural gas properties
    128,673  
Restricted deposits
    23,519  
Deferred taxes
    592  
         
Total assets
    193,614  
         
Liabilities assumed
       
Accounts payable
    11,235  
Accounts payable — affiliate
    555  
Current portion of note payable to affiliate
    5,429  
Prepayments from partners
    652  
Accrued interest — affiliates
    288  
Income tax payable — affiliate
    156  
Accounts payable — revenue
    716  
Accounts payable — other
    10  
Derivative financial instruments
    903  
Note payable to affiliate — net of current maturities
    32,571  
Asset retirement obligation
    49,538  
         
Total liabilities assumed
    102,053  
         
Net assets contributed
  $ 91,561  
         


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
5.   Acquisitions
 
In March 2005, the Company purchased an additional interest in Longfellow Ranch for $31.9 million.
 
In October 2005, the Company executed a purchase and sale agreement to acquire Minden Field assets near its existing production properties in East Texas. This acquisition consists of 3,500 acres with 17 producing wells and numerous drilling opportunities. The purchase price was approximately $85.0 million, which was subsequently reduced to $82.3 million after purchase price adjustments, and the transaction closed on November 8, 2005.
 
6.   Sale of West Delta Properties
 
In March 2005, the Company sold its rights and interest in West Delta 52, 54, and 58 to a third party in exchange for the assumption of existing future asset retirement obligations on the properties and a cash payment of $0.5 million. The estimated fair value of the asset retirement obligations assumed by the purchaser was approximately $16.8 million. In addition, the Company transferred to the purchaser approximately $4.7 million in an escrow account that the Company had funded relating to the asset retirement obligations on the properties. The full cost pool was reduced by approximately $11.6 million and no gain or loss was recognized on the transaction.
 
7.   Investments/Note Receivable
 
In October 2003, the Company committed to an investment of $6.0 million in PetroSource Energy Company, LLC (“PetroSource”). The Company’s commitment was to acquire 24.8% of the outstanding stock for a price of $3.0 million and to advance $3.0 million as a subordinated loan bearing 6% interest due in six years. The Company initially purchased $1.8 million in stock and funded $1.8 million of the loan in October 2003. In February 2004, the Company purchased an additional $1.2 million of stock and funded the remaining $1.2 million loan commitment. PetroSource is in the business of selling CO2 and also owns pipelines and compressor stations for delivery purposes. During 2004, PetroSource sold additional equity shares which reduced the Company’s ownership to 20.63%. The Company recorded losses of $0.5 million, and $1.1 million in 2004 and 2005, respectively, as a result of accounting for the PetroSource investment under the equity method. During 2005, the Company invested an additional $0.5 million in PetroSource stock. In December 2005, the Company sold its entire investment in PetroSource, including the subordinate loan, for total proceeds of $10.5 million and recorded a gain of $5.5 million.
 
In April 2002, the Company entered into a revolving credit commitment to extend advances to an unrelated third party. Under the terms of the revolving credit arrangement, the Company agreed to make advances from time to time, as requested by the unrelated third party and subject to certain limitations, in an amount up to $5.0 million. Advances made under the revolving credit commitment bear interest at prime rate plus 2% and are collateralized by inventory and receivables. As of December 31, 2004, the Company determined that a portion of the total outstanding advances of $1.3 million had been impaired and recorded a loss of $0.8 million. As of December 31, 2005, the Company determined that the majority of the total outstanding advance of $1.27 million had been impaired and recorded an additional loss of $0.5 million bringing the total allowance to $1.26 million. The loss is recorded as an impairment of note receivable and is included in general and administrative expenses.
 
8.   Restricted Deposits
 
In connection with the National Offshore transaction, the Company acquired restricted deposits aggregating $23.5 million. The restricted deposits represent bank trust and escrow accounts required to be set up by surety bond underwriters and certain former owners of National Offshore’s offshore properties. In accordance


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
with requirements of the U.S. Department of Interior’s Minerals Management Service (“MMS”), National Offshore was required to put in place surety bonds and/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 National Offshore’s 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.
 
The restricted deposits include the following:
 
1. A $4.2 million escrow account for the East Breaks 109 and 110 fields set up in favor of the surety bond underwriter who provides a surety bond to the MMS. The escrow account is fully funded as of December 31, 2005.
 
2. A $6.9 million escrow account for the East Breaks 165 and 209 fields set up in favor of the surety bond underwriter who provides a surety bond to the former owners of the fields and the MMS. The escrow account is fully funded as of December 31, 2005.
 
3. A $4.1 million escrow account set up in favor of a major oil company. The Company is required to make additional deposits to the escrow account in an amount equal to 10% of the net cash flow (as defined in the escrow agreement) from the properties that were acquired from the major oil company.
 
4. A $3.8 million escrow account that was required to be set up by the bankruptcy settlement proceedings of National Offshore. The Company is required to make monthly deposits based on cash flows from certain wells, as defined in the agreement.
 
5. A $5.3 million escrow account required to be set up by the MMS relating to East Breaks properties. The Company is required to make quarterly deposits to the escrow account of $0.8 million. Additionally, for some of the East Break properties, the Company will be required to deposit additional funds in the East Break escrow accounts, representing the difference between the required escrow deposit under the surety bond and actual escrow deposit balance at various points in time in the future. Aggregate payments to the East Breaks escrow accounts are as follows (in thousands):
 
         
Year Ended December 31,
     
 
2006
  $ 3,200  
2007
    6,100  
2008
    3,200  
2009
    3,200  
2010
    5,000  
Thereafter
    4,000  
         
    $ 24,700  
         
 
9.   Debt
 
The Company’s debt consists of credit facilities, notes payable, note payable to affiliates and senior notes payable to affiliates.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
Credit Facilities
 
The Operating LLC Credit Facility
 
On December 29, 2003, Holding LLC entered into a Credit Agreement (the “Mizuho Facility”) with certain commercial lending institutions, including Mizuho Corporate Bank, Ltd. as the Administrative Agent and the Bank of Texas, N.A. and the Bank of Nova Scotia as Co-Agents.
 
The Credit Agreement provided for a loan commitment amount of up to $145.0 million and a letter of credit commitment of up to $15 million (provided, the outstanding aggregate amount of the unpaid borrowings, plus the aggregate undrawn face amount of all outstanding letters of credit shall not exceed the borrowing base under the Credit Agreement). The Credit Agreement provided further that the amount available to the Operating LLC at any time was subject to certain restrictions, covenants, conditions and changes in the borrowing base calculation. In partial consideration of the loan commitment amount, Operating LLC has pledged a continuing security interest in all of its oil and natural gas properties and its equipment, inventory, contracts, fixtures and proceeds related to its oil and natural gas business.
 
At Operating LLC’s option, interest on borrowings under the Credit Agreement bear interest at a rate based upon either the prime rate or the LIBOR rate plus, in each case, an applicable margin that, in the case of prime rate loans, can fluctuate from 0.75% to 2.50% per annum. Fluctuations in the applicable interest rate margins are based upon Operating LLC’s total usage of the amount of credit available under the Credit Agreement, with the applicable margins increasing as Operating LLC’s total usage of the amount of the credit available under the Credit Agreement increases.
 
At the closing of the Credit Agreement, Operating LLC borrowed $43.8 million to repay $42.9 million owed by Operating LLC to an affiliate of Mr. Icahn under the secured loan arrangement which was then terminated and to pay administrative fees in connection with this borrowing. Approximately $1.4 million of loan issuance costs was capitalized in connection with the closing of this transaction.
 
The Credit Agreement required, among other things, semiannual engineering reports covering oil and natural gas properties, and maintenance of certain financial ratios, including the maintenance of a minimum interest coverage, a current ratio, and a minimum tangible net worth.
 
NEG Oil & Gas LLC Senior Secured Revolving Credit Facility
 
On December 22, 2005, the Company entered into a credit agreement, dated as of December 20, 2005, with Citicorp USA, Inc., as administrative agent, Bear Stearns Corporate Lending Inc., as syndication agent, and other lender parties thereto (the “NEG Credit Facility”). The NEG Credit Facility is secured by substantially all the assets of the Company and its subsidiaries, has a five-year term and permits payments and re-borrowings, subject to a borrowing base calculation based on the proved oil and gas reserves of the Company and its subsidiaries. Under the NEG Credit Facility, the Company will be permitted to borrow up to $500 million, and the initial borrowing base is set at $335 million. The Company used a portion of the initial $300 million funding under the NEG Credit Facility to purchase the Mizuho Facility. On a combined basis, the Mizuho Facility is no longer outstanding.
 
In consideration of each lender’s commitment to make loans under the NEG Credit Facility, the Company is required to pay a quarterly commitment fee ranging from 0.375% to 0.50% of the available borrowing base. Commitment fees are based upon the facility utilization levels.
 
At the Company’s option, borrowings under the NEG Credit Facility bear interest at Base Rate or Euro Dollar Rate, as defined in the borrowing agreement, plus, in each case, an applicable margin that, in the case of Base Rate loans, can fluctuate from 0.00% to 0.75% per annum, and, in the case of Euro Dollar loans, can


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
fluctuate from 1.00% to 1.75% per annum. Fluctuations in the applicable interest rate margins are based upon the Company’s total usage of the amount of credit available under the NEG Credit Facility, with the applicable margins increasing as the Company’s total usage of the amount of the credit available under the NEG Credit Facility increases. Base Rate and Euro Dollar Rate fluctuate based upon Prime rate or LIBOR, respectively. At December 31, 2005, the interest rate on the outstanding amount under the credit facility was 6.44% and $14.6 million was available for future borrowings.
 
NEG Credit Facility agreement requires, among other things, semiannual engineering reports covering oil and natural gas properties, limitation on distributions, and maintenance of certain financial ratios, including maintenance of leverage ratio, current ratio and a minimum tangible net worth. The Company was in compliance with all covenants at December 31, 2005.
 
In addition to purchasing the Mizuho Facility, the Company used the proceeds from the NEG Credit Facility to (1) repay a loan of approximately $85 million by AREP used to purchase properties in the Minden Field; (2) pay a distribution of $78.0 million, and (3) pay transaction costs.
 
Notes Payable
 
Notes payable at December 31, 2005 consist of the following (amounts in thousands):
 
         
 
Notes payable to various prior creditors of National Onshore in settlement of bankruptcy claims. The notes are generally payable over a 30 month period with a stated interest rate of 6%; however, the notes have been discounted to an effective rate of 10%
  $ 2,503  
Note payable — asset acquisition
     
         
Total
    2,503  
Less Current maturities
    (2,503 )
         
    $  
         
 
Notes Payable to Affiliates
 
During 2005, the Company borrowed $25.0 million from AREP and repaid $1.4 million. The remaining outstanding balance of $23.6 million, excluding accrued and unpaid interest, along with notes payable detailed above, were contributed to the Company.
 
Advance from Affiliate
 
During 2005, AREP made unsecured non-interest bearing advance of $49.8 million, payable on demand, to fund their drilling programs as well as to fund derivative contract deposits, of which $39.8 million were outstanding at December 31, 2005. The outstanding balance was repaid in January 2006.
 
Deferred Loan Costs
 
The Company capitalized approximately $1.5 million in external direct costs associated with the Credit Agreement which was being amortized (approximately $0.05 million per month) as deferred loan costs. Upon execution of the NEG Credit Facility, the Company expensed the unamortized deferred loan cost of $0.4 million relating to the Mizuho Facility in December 2005.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
Additionally, the Company capitalized $4.7 million in external direct costs associated with the NEG Credit Facility executed on December 22, 2005. The deferred costs will be amortized over the term of the facility as additional interest expense.
 
Five Year Maturities
 
Aggregate annual maturities of debt for fiscal years 2006 to 2010 are as follows: 2006 — $42.3 million; 2007 — $0 million; 2008 — $0; 2009 — $0; 2010 — $300.0 million.
 
10.   Income Taxes
 
National Onshore and National Offshore were organized as corporations until their respective acquisitions by NEG Oil & Gas LLC, and were subject to corporate taxes up until the date of acquisition as part of a tax sharing agreement with the Starfire, Inc. consolidated group. The Company accounts for income taxes of National Onshore and National Offshore according to Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (SFAS 109). SFAS 109 requires the recognition of deferred tax assets, net of applicable reserves, related to net operating loss carryforwards and certain temporary differences. The standard requires recognition of a future tax benefit to the extent that realization of such benefit is more likely than not. Otherwise, a valuation allowance is applied.
 
The (provision) benefit for U.S. federal income taxes attributable to continuing operations is as follows (amounts in thousands):
 
                 
    Year Ended December 31,  
    2004     2005  
 
Current
  $ (404 )   $ (3 )
Deferred
    144       2,935  
                 
    $ (260 )   $ 2,932  
                 
 
On April 6, 2005, TransTexas merged into National Onshore, a limited partnership, resulting in the treatment of an asset sale for tax purposes and subsequent liquidation into its parent company. Upon the TransTexas merger into National Onshore, the net deferred tax liabilities of approximately $9.9 million were credited to equity, in accordance with SFAS 109.
 
On June 30, 2005, pursuant to the Panaco purchase agreement, Panaco merged into National Offshore LP. In accordance with SFAS 109, for financial reporting purposes, the net deferred tax assets of approximately $2.6 million were debited to equity.
 
The reconciliation of income taxes computed at the U.S. federal statutory tax rates to the provision (benefit) for income taxes on income from continuing operations is as follows:
 
                 
    Year Ended December 31,  
    2004     2005  
 
Federal statutory rate
    35.0 %     35.0 %
Income not subject to taxation
    (31.2 )%     (44.0 )%
Valuation allowance on deferred tax assets
    (3.0 )%      
Other
          (0.2 )%
                 
      0.8 %     (9.2 )%
                 


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
11.   Commitments and Contingencies
 
During 2000 and 2001 National Energy Group entered into several hedge contracts with Enron North America Corp (“Enron NAC”). In 2001 Enron Corporation and many Enron Corporation affiliates and subsidiaries, including Enron NAC filed for protection under Chapter 11 of the US bankruptcy code. The derivative contracts were subsequently contributed to Holding LLC and then to Operating LLC. Operating LLC has filed a claim for damages in the Enron NAC bankruptcy proceeding and our designee has been appointed as a representative to the official committee of unsecured creditors. The Company’s claim is unsecured. During 2005, we received $0.2 million in partial settlement of our claims which was recorded in interest income and other. In April 2006, we received an additional payment of $1.0 million and we should receive additional distributions from the Enron bankruptcy proceeding in accordance with its plan of reorganization. We will record such additional payments, if any, when the amounts are known.
 
Other than routine litigation incidental to its business operations which are not deemed by the Company to be material, there are no additional legal proceedings in which the Company, is a defendant.
 
Environmental Matters
 
The Company’s operations and properties are subject to extensive federal, state, and local laws and regulations relating to the generation, storage, handling, emission, transportation, and discharge of materials into the environment. Permits are required for various of the Company’s operations, and these permits are subject to revocation, modification, and renewal by issuing authorities. The Company’s operations are also subject to federal, state, and local laws and regulations that impose liability for the cleanup or remediation of property which has been contaminated by the discharge or release of hazardous materials or wastes into the environment. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines or injunctions, or both. The Company believes that it is in material compliance with applicable environmental laws and regulations. Noncompliance with such laws and regulations could give rise to compliance costs and administrative penalties. Management does not anticipate that the Company will be required in the near future to expend amounts that are material to the financial condition or operations of the Company by reason of environmental laws and regulations, but because such laws and regulations are frequently changed and, as a result, may impose increasingly strict requirements, the Company is unable to predict the ultimate cost of complying with such laws and regulations.
 
12.   Asset Retirement Obligation
 
In June 2001, the Financial Accounting Standards Board (FASB) issued Statements of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and/or normal use of the assets. It also requires the Company to record a corresponding asset that is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The ARO assets are recorded on the balance sheet as part of the Company’s full cost pool and are included in the amortization base for the purposes of calculating depreciation, depletion and amortization expense. For the purpose of calculating the ceiling test, the future cash outflows associated with settling the ARO liability are excluded from the computation of the discounted present value of estimated future net revenues.
 
The following is a rollforward of the abandonment obligation as of December 2005 (amounts in thousands).


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
         
Balance as of January 1, 2005
  $ 56,524  
Add: Accretion
    3,019  
Drilling additions
    2,067  
Less: Revisions
    (2,813 )
Settlements
    (431 )
Dispositions
    (17,138 )
         
Balance as of December 31, 2005
  $ 41,228  
         
 
13.   Severance tax refund
 
During 2002, the Company applied for “high-cost/tight-gas formation” designation from the Railroad Commission of Texas for a portion of the Company’s South Texas production. For qualifying wells, “high-cost/tight-gas formation” production is either exempt from tax or taxed at a reduced rate until certain capital costs are recovered. The designation was approved in 2004 and was retroactive to the date of initial production. During 2004, the Company recognized a gain of approximately $4.5 million for the refund of prior period severance taxes, for which the Company’s severance tax payments were reduced by approximately $3.2 million.
 
14.   Crude Oil and Natural Gas Producing Activities
 
Costs incurred in connection with the exploration, development, and exploitation of the Company’s crude oil and natural gas properties for the years ended December 31, 2004 and 2005 are as follows (amounts in thousands except depletion rate per Mcfe):
 
                 
    Year Ended December 31,  
    2004     2005  
 
Acquisition of properties
  $     $ 114,244  
Properties contributed by member
    128,673        
Exploration costs
    62,209       75,357  
Development costs
    52,765       124,305  
Depletion rate per Mcfe
  $ 2.11     $ 2.33  
 
As of December 31, 2005, all capitalized costs are included in the full cost pool and are subject to amortization. Revenues from individual purchasers that exceed 10% of crude oil and natural gas sales are as follows:
 
                 
    Year Ended December 31,  
    2004     2005  
 
Plains All American
  $ 19,857     $ 41,345  
Duke Energy
    33,958       44,850  
Kinder Morgan
    18,005       14,402  
Crosstex Energy Services, Inc. 
    5,081       22,790  
Riata Energy, Inc. 
    29,846       52,300  
Seminole Energy Services
    19,568       27,315  
Louis Dreyfus
          26,790  


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
15.   Supplementary Crude Oil and Natural Gas Reserve Information (Unaudited)
 
The revenues generated by the Company’s operations are highly dependent upon the prices of, and demand for, oil and natural gas. The price received by the Company for its oil and natural gas production depends on numerous factors beyond the Company’s control, including seasonality, the condition of the U.S. economy, foreign imports, political conditions in other oil and natural gas producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic governmental regulations, legislation and policies.
 
The Company has made ordinary course capital expenditures for the development and exploitation of oil and natural gas reserves, subject to economic conditions. The Company has interests in crude oil and natural gas properties that are principally located onshore in Texas, Louisiana, Oklahoma, Arkansas, Gulf Coast and offshore in the Gulf of Mexico. The Company does not own or lease any crude oil and natural gas properties outside the United States.
 
In 2004, estimates of the Company’s reserves and future net revenues were prepared by Netherland, Sewell & Associates, Inc., Prator Bett, LLC and DeGolyer and MacNaughton. In 2005, estimates of the Company’s reserves and future net revenues were prepared by Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton. Estimated proved net recoverable reserves as shown below include only those quantities that can be expected to be recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods.
 
In 2004, extension and discovery reserve additions were largely impacted by the successful drilling on the Longfellow Ranch. Drilling on the Longfellow Ranch in 2003 extended field producing boundaries as well as the discovery of two new fields. The East Texas Region in 2004 extended producing boundaries adding proved reserves for the Cotton Valley Reservoir. A new field discovery in the Gulf Coast area resulted in new reserves along with three extension wells. In 2005, continued drilling in the West Texas Region, Longfellow Ranch, and the East Texas Region, Cotton Valley development resulted in 86% of the added extension and discovery gas reserves. Changes in reserves associated with development drilling have been accounted for in revisions of previous estimates.
 
Proved developed reserves represent only those reserves expected to be recovered through existing wells. Proved undeveloped reserves include those reserves expected to be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure is required for recompletion.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
Net quantities of proved developed and undeveloped reserves of natural gas and crude oil, including condensate and natural gas liquids, are summarized as follows:
 
                 
    Crude Oil
    Natural Gas
 
    (MBbl)     ( MMcf)  
 
December 31, 2003
    8,166       206,260  
Reserves of Panaco contributed by member
    5,204       25,982  
Sales of reserves in place
    (16 )     (344 )
Extensions and discoveries
    524       50,226  
Revisions of previous estimates
    204       9,810  
Production
    (1,484 )     (18,895 )
                 
December 31, 2004
    12,598       273,039  
Purchase of reserves in place
    483       94,937  
Sales of reserves in place
    (625 )     (7,426 )
Extensions and discoveries
    743       79,592  
Revisions of previous estimates
    495       17,015  
Production
    (1,790 )     (28,107 )
                 
December 31, 2005
    11,904       429,050  
                 
Proved developed reserves:
               
December 31, 2004
    8,955       151,452  
                 
December 31, 2005
    8,340       200,520  
                 
 
Reservoir engineering is a subjective process of estimating the volumes of underground accumulations of oil and natural gas which cannot be measured precisely. The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve estimates prepared by other engineers might differ from the estimates contained herein. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Future prices received for the sale of oil and natural gas may be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
 
The following is a summary of a standardized measure of discounted net cash flows related to the Company’s proved crude oil and natural gas reserves. For these calculations, estimated future cash flows from estimated future production of proved reserves were computed using crude oil and natural gas prices as of the end of each period presented. Future development, production and net asset retirement obligations attributable to the proved reserves were estimated assuming that existing conditions would continue over the economic lives of the individual leases and costs were not escalated for the future.
 
The Company cautions against using the following data to determine the fair value of its crude oil and natural gas properties. To obtain the best estimate of fair value of the crude oil and natural gas properties, forecasts of future economic conditions, varying discount rates, and consideration of other than proved reserves would have to be incorporated into the calculation. In addition, there are significant uncertainties inherent in


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC. AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP INC., BUT INCLUDING NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
 
estimating quantities of proved reserves and in projecting rates of production that impair the usefulness of the data.
 
The standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves as of December 31, 2005 are summarized as follows (amounts in thousands):
 
         
Future cash inflows
  $ 4,891,094  
Future production costs
    (1,029,393 )
Future development costs
    (527,399 )
Future income tax expense
     
         
Future net cash flows
    3,334,302  
10% annual discount for estimated timing of cash flows
    (1,562,242 )
         
Standardized measure of discounted future net cash flows
  $ 1,772,060  
         
 
The following are the principal sources of change in the standardized measure of discounted future net cash flows (amounts in thousands):
 
                 
    Year Ended December 31,  
    2004     2005  
 
Beginning of Period
  $ 613,752     $ 771,280  
Purchases of reserves
          415,208  
Contribution of reserves by member
    75,239        
Sales of reserves in place
    (1,375 )     (34,820 )
Sales and transfers of crude oil and natural gas produced, net of production costs
    (130,640 )     (205,838 )
Net changes in prices and production costs
    16,686       408,909  
Development costs incurred during the period and changes in estimated future development costs
    (89,491 )     (150,639 )
Extensions and discoveries, less related costs
    193,022       411,092  
Income taxes
          24,097  
Revisions of previous quantity estimates
    31,730       68,937  
Accretion of discount
    62,050       77,128  
Changes in production rates (timing) and other
    307       (13,294 )
                 
Net change
    157,528       1,000,780  
                 
End of Period
  $ 771,280     $ 1,772,060  
                 
 
During recent years, there have been significant fluctuations in the prices paid for crude oil in the world markets. The net weighted average prices of crude oil and natural gas at December 31, 2004 and 2005, used in the above table were $41.80 and $57.28 per barrel of crude oil, respectively, and $5.93 and $9.59 per thousand cubic feet of natural gas, respectively.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC
 
 
COMBINED BALANCE SHEETS AS OF DECEMBER 31, 2005 AND SEPTEMBER 30, 2006
 
                 
    December 31,
    September 30,
 
    2005     2006  
          (Unaudited)  
    (In thousands)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 102,322     $ 26,362  
Accounts receivable, net
    53,378       53,436  
Notes receivable
    10       9  
Drilling prepayments
    3,281       3,755  
Derivative financial instruments
          14,158  
Other
    9,798       5,788  
                 
Total current assets
    168,789       103,508  
                 
Oil and gas properties, at cost (full cost method)
    1,229,923       1,409,776  
Accumulated depreciation, depletion and amortization
    (488,560 )     (562,635 )
                 
Net oil and gas properties
    741,363       847,141  
                 
Other property and equipment
    6,029       6,232  
Accumulated depreciation
    (4,934 )     (5,173 )
                 
Net other property and equipment
    1,095       1,059  
Restricted deposits
    24,267       30,713  
Derivative financial instruments
          15,787  
Other assets
    4,842       8,296  
                 
Total assets
  $ 940,356     $ 1,006,504  
                 
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
               
Accounts payable
  $ 18,105     $ 20,058  
Accounts payable — revenue
    11,454       9,759  
Accounts payable — affiliates
    1,660       1,569  
Current portion of notes payable
    2,503        
Advance from affiliate
    39,800        
Prepayments from partners
    121       823  
Accrued interest
    162       61  
Accrued interest — affiliates
    2,194       2,194  
Income tax payable — affiliate
    2,749       2,749  
Derivative financial instruments
    68,039        
                 
Total current liabilities
    146,787       37,213  
                 
Commitments and contingencies
               
Credit facility
    300,000       300,000  
Gas balancing
    1,108       1,108  
Derivative financial instruments
    17,893        
Other liabilities
    250       250  
Deferred income tax liability
          2,128  
Asset retirement obligation
    41,228       47,609  
                 
Total liabilities
    507,266       388,308  
                 
Member’s equity
    433,090       618,196  
                 
Total liabilities and member’s equity
  $ 940,356     $ 1,006,504  
                 
 
The accompanying notes are an integral part of these combined financial statements.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC. BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

COMBINED STATEMENTS OF OPERATIONS
Nine Month Periods Ended September 30, 2005 and 2006
 
                 
    Nine Months Ended
 
    September 30,  
    2005     2006  
    (Unaudited)
 
    (In thousands)  
 
Revenues:
               
Oil and gas sales — gross
  $ 193,633     $ 208,800  
Unrealized derivatives (losses) gains
    (111,631 )     115,877  
                 
Oil and gas revenues — net
    82,002       324,677  
Plant revenues
    4,707       5,799  
                 
Total revenues
    86,709       330,476  
                 
Costs and expenses:
               
Lease operating
    19,632       26,817  
Transportation and gathering
    3,764       3,441  
Plant and field operations
    2,644       3,270  
Production and ad valorem taxes
    11,184       8,948  
Depreciation, depletion and amortization
    65,756       74,408  
Accretion of asset retirement obligation
    2,290       2,112  
General and administrative
    10,651       10,281  
                 
Total costs and expenses
    115,921       129,277  
Operating income (loss)
    (29,212 )     201,199  
Interest expense
    (4,856 )     (16,738 )
Interest expense — affiliate
    (3,047 )      
Interest income and other
    185       4,788  
                 
Income (loss) before income taxes
    (36,930 )     189,249  
Income tax benefit (expense)
    2,932       (2,143 )
                 
Net income (loss)
  $ (33,998 )   $ 187,106  
                 
 
The accompanying notes are an integral part of these combined financial statements.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

COMBINED STATEMENTS OF CASH FLOWS
Nine Month Periods Ended September 30, 2005 and 2006
 
                 
    Nine Months Ended
 
    September 30,  
    2005     2006  
    (Unaudited)
 
    (In thousands)  
 
Operating activities:
               
Net income (loss)
  $ (33,998 )   $ 187,106  
Noncash adjustments:
               
Deferred income tax expense (benefit)
    (2,932 )     2,128  
Depreciation, depletion and amortization
    65,756       74,408  
Unrealized derivative losses (gains)
    111,631       (115,877 )
Accretion of asset retirement obligation
    2,290       2,112  
Amortization of note discount
    66       27  
Equity in loss on investment
    917        
Interest income-restricted deposits
    (265 )     (616 )
Amortization of note costs
    527       773  
Gain on sale of assets
    (9 )     (2 )
Changes in operating assets and liabilities:
               
Accounts receivable
    (9,270 )     (212 )
Drilling prepayments
    (1,616 )     (475 )
Derivative deposit
    (64,068 )      
Other assets
    2,369       3,920  
Accounts payable and accrued liabilities
    (7,605 )     1,013  
                 
Net cash provided by operating activities
    63,793       154,305  
                 
Investing activities:
               
Acquisition, exploration, and development costs
    (183,479 )     (175,619 )
Proceeds from sales of oil and gas properties
    679       37  
Purchases of furniture, fixtures and equipment
    (398 )     (293 )
Equity investment
    (454 )      
Investment in restricted deposits
    (3,538 )     (5,832 )
                 
Net cash used in investing activities
    (187,190 )     (181,707 )
                 
Financing activities:
               
Debt issuance costs
          (573 )
Guaranteed payment to member
    (7,989 )     (7,989 )
Equity contribution
          7,989  
Proceeds from/repayment of affiliate borrowings
    73,443       (39,800 )
Dividend payment to member
          (2,000 )
Proceeds from credit facility
    59,100        
Principal payments on debt
    (1,554 )     (2,530 )
Deferred equity costs
          (3,655 )
                 
Net cash provided by (used in) financing activities
    123,000       (48,558 )
                 
Decrease in cash and cash equivalents
    (397 )     (75,960 )
Cash and cash equivalents at beginning of period
    30,846       102,322  
                 
Cash and cash equivalents at end of period
  $ 30,449     $ 26,362  
                 
Supplemental cash flow information:
               
Cash paid for interest
  $ 13,205     $ 16,052  
                 
 
The accompanying notes are an integral part of these combined financial statements.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

COMBINED STATEMENT OF CHANGES IN TOTAL MEMBER’S EQUITY
Nine Month Period Ended September 30, 2006
(2006 Amounts Unaudited)
 
         
(In thousands)  
Total member’s equity — December 31, 2005
  $ 433,090  
Dividend distribution
    (2,000 )
Equity contribution
    7,989  
Guaranteed payment to member
    (7,989 )
Net income
    187,106  
         
Total member’s equity — September 30, 2006
  $ 618,196  
         
 
The accompanying notes are an integral part of these combined financial statements.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS
September 30, 2006
(Unaudited)
 
1.   Organization, Basis of Presentation and Background
 
The accompanying combined financial statements present NEG Oil & Gas LLC and subsidiaries excluding National Energy Group, Inc., and the 103/4% Senior Notes due from National Energy Group, Inc., but including National Energy Group, Inc.’s 50% interest in NEG Holding LLC (collectively “the Company”). The Company is an oil and gas exploration and production company engaged in the exploration, development, production and operations of natural gas and oil properties, primarily located in Texas, Oklahoma, Arkansas and Louisiana (both onshore and in the Gulf of Mexico).
 
NEG Oil & Gas, LLC is wholly-owned by American Real Estate Holdings Limited Partnership (“AREH”). AREH is 99% owned by American Real Estate Partners, L.P. (“AREP”). AREP is a publicly traded limited partnership that is majority owned by Mr. Carl C. Icahn.
 
NEG Oil & Gas LLC was formed on December 2, 2004 to hold the oil and gas investments of the Company’s ultimate parent company, AREP. As of September 30, 2006 the Company’s assets and operations consist of the following:
 
  •  A 50.01% ownership interest in National Energy Group, Inc (National Energy Group), a publicly traded oil and gas management company. National Energy Group’s principal asset consists of its 50% membership interest in NEG Holding LLC (Holding, LLC);
 
  •  $148.6 million principal amount of 103/4% Senior Notes due from National Energy Group (the “103/4% Senior Notes”).
 
  •  A 50% managing membership interest in Holding, LLC;
 
  •  The oil and gas operations of National Onshore LP; and
 
  •  The oil and gas operations of National Offshore LP.
 
All of the above assets initially were acquired by entities owned or controlled by Mr. Icahn and subsequently acquired by AREP (through subsidiaries) in various purchase transactions. In accordance with generally accepted accounting principles, assets transferred between entities under common control are accounted for at historical cost similar to a pooling of interest and the financial statements are combined from the date of acquisition by an entity under common control. The financial statements include the results of operations, financial position and cash flows of each of the above entities since its initial acquisition by entities owned or controlled by Mr. Icahn (the “Period of Common Control”).
 
On September 7, 2006, AREP signed a letter of intent to sell NEG Oil & Gas LLC and subsidiaries, excluding National Energy Group and the 103/4% Senior Notes due from National Energy Group, but including National Energy Group’s 50% interest in Holding LLC to Riata Energy, Inc., DBA Riata Energy, Inc. (“Riata Energy”) The combined financial statements include the entities to be sold to Riata Energy.
 
Basis of Presentation
 
The accompanying unaudited combined interim financial statements have been prepared in accordance both with accounting principles generally accepted in the United States of America for interim financial information, and Article 10 of Regulation S-X and are fairly presented. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, these financial statements contain all adjustments, consisting of normal recurring accruals, necessary to present fairly the financial position, results of operations and cash


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS (Unaudited) — (Continued)
 
flows for the periods indicated. The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results may differ from these estimates. Our financial data for the nine month periods ended September 30, 2005 and 2006 should be read in conjunction with our audited financial statements for the year ended December 31, 2005 including the notes thereto.
 
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement 109 (“FIN 48”), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is “more-likely-than-not” of being sustained if the position were to be challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the “more-likely-than-not” threshold, the largest amount of tax benefit that is greater than 50 percent likely of being recognized upon ultimate settlement with the taxing authority, is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. The Company is currently evaluating the impact of adopting FIN 48 on its financial statements.
 
In September 2006, the SEC issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 provides guidance on how to evaluate prior period financial statement misstatements for purposes of assessing their materiality in the current period. If the prior period effect is material to the current period, then the prior period is required to be corrected. Correcting prior year financial statements would not require an amendment of prior year financial statements, but such corrections would be made the next time the company files the prior year financial statements. Upon adoption, SAB 108 allows a one-time transitional cumulative effect adjustment to retained earnings for corrections of prior period misstatements required under this statement. SAB 108 is effective for fiscal years beginning after November 15, 2006. The adoption of SAB 108 is not expected to be material to the Company’s consolidated financial statements.
 
Background
 
National Energy Group, Inc — In February, 1999 National Energy Group was placed under involuntary, court ordered bankruptcy protection. Effective August 4, 2000 National Energy Group emerged from involuntary bankruptcy protection with affiliates of Mr. Icahn owning 49.9% of the common stock and $165 million principal amount of debt securities (“Senior Notes”). As mandated by National Energy Group’s Plan of Reorganization, Holding LLC was formed and on September 1, 2001, National Energy Group contributed to Holding LLC all of its oil and natural gas properties in exchange for an initial membership interest in Holding LLC. National Energy Group retained $4.3 million in cash. On September 1, 2001, an affiliate of Mr. Icahn contributed to Holding LLC oil and natural gas assets, cash and a $10.9 million note receivable from National Energy Group in exchange for the remaining membership interest, which was designated the managing membership interest. Concurrently, in September, 2001, but effective as of May 2001, Holding LLC formed a 100% owned subsidiary, NEG Operating Company, LLC (“Operating LLC”) and contributed all of its oil and natural gas assets to Operating LLC.
 
In October 2003, AREP acquired all outstanding Senior Notes ($148.6 million principal amount at October 2003) and 5,584,044 shares of common stock of National Energy Group from entities affiliated with Mr. Icahn for aggregate consideration of approximately $148.1 million plus approximately $6.7 million of accrued interest on the Senior Notes. As a result of this transaction and the acquisition by AREP of additional


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS (Unaudited) — (Continued)
 
shares of National Energy Group, AREP beneficially owned 50.01% of the outstanding stock of National Energy Group and had effective control. In June 2005, all of the stock of National Energy Group and the $148.6 million principal amount of Senior Notes owned by AREP was contributed to the Company and National Energy Group became a 50.01% owned subsidiary. The accrued, but unpaid interest on the $148.6 million principal amount of Senior Notes was retained by AREP. National Energy Group and the 103/4% Senior Notes will be retained by AREP.
 
NEG Holding LLC — On June 30, 2005, AREP acquired the managing membership interest in Holding LLC from an affiliate of Mr. Icahn for an aggregate consideration of approximately $320 million and contributed it to the Company. The membership interest acquired constituted all of the membership interests other than the membership interest already owned by National Energy Group. The combined financial statements include the consolidation of the acquired 50% membership interest in Holding LLC, together with the 50% membership interest owned by National Energy Group. The Period of Common Control for Holding LLC began on September 1, 2001, the initial funding of Holding LLC.
 
The Holding LLC Operating Agreement
 
Holding LLC is governed by an operating agreement effective May 12, 2001, which provides for management and control of Holding LLC by the Company and distributions to National Energy Group and the Company based on a prescribed order of distributions (the “Holding LLC Operating Agreement”).
 
Order of Distributions
 
Pursuant to the Holding LLC Operating Agreement, distributions from Holding LLC to National Energy Group and the Company shall be made in the following order:
 
1. Guaranteed payments (“Guaranteed Payments”) are to be paid to National Energy Group, calculated on an annual interest rate of 103/4% on the outstanding priority amount (“Priority Amount”). The Priority Amount includes all outstanding debt owed to NEG Oil & Gas, including the amount of National Energy Group’s 103/4% Senior Notes. As of December 31, 2005, the Priority Amount was $148.6 million. The Guaranteed Payments will be made on a semi-annual basis.
 
2. The Priority Amount is to be paid to National Energy Group. Such payment is to occur by November 6, 2006. This did not occur November 6, 2006 due to the pending transaction with Riata Energy as described above.
 
3. An amount equal to the Priority Amount and all Guaranteed Payments paid to National Energy Group, plus any additional capital contributions made by NEG Oil & Gas, less any distributions previously made by Holding LLC to NEG Oil & Gas, is to be paid to NEG Oil & Gas.
 
4. An amount equal to the aggregate annual interest (calculated at prime plus 1/2% on the sum of the Guaranteed Payments), plus any unpaid interest for prior years (calculated at prime plus 1/2% on the sum of the Guaranteed Payments), less any distributions previously made by Holding LLC to NEG Oil & Gas, is to be paid to NEG Oil & Gas.
 
5. After the above distributions have been made, any additional distributions will be made in accordance with the ratio of NEG Oil & Gas and National Energy Group’s respective capital accounts. (Capital accounts as defined in the Holding LLC Operating Agreement.)


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS (Unaudited) — (Continued)
 
 
Redemption Provision in the Holding LLC Operating Agreement
 
The Holding LLC Operating Agreement contains a provision that allows the managing member (NEG Oil & Gas), at any time, in its sole discretion, to redeem National Energy Group’s membership interest in Holding LLC at a price equal to the fair market value of such interest determined as if Holding LLC had sold all of its assets for fair market value and liquidated.
 
Prior to closing the Riata Energy purchase transaction, AREP will cause NEG Oil & Gas to exercise the redemption provision and dividend the 103/4% Senior Notes to AREP or enter into transactions with a similar effect such that NEG Oil & Gas will own 100% of Holding LLC and no longer own the 103/4% Senior Notes receivable from National Energy Group. AREP will indemnify NEG Oil & Gas for any costs associated with the exercise of the redemption provision. The Holding LLC Operating Agreement will be cancelled.
 
National Onshore LP — On November 14, 2002, National Onshore filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Corpus Christi Division. National Onshore’s First Amended Joint Plan of Reorganization submitted by an entity affiliated with Mr. Icahn, as modified on July 8, 2003 (the “National Onshore Plan”), was confirmed by the Bankruptcy Court on August 14, 2003 effective August 28, 2003.
 
As of the effective date of the National Onshore Plan, an entity affiliated with Mr. Icahn owned 89% of the outstanding shares of National Onshore. During June 2004, the entity affiliated with Mr. Icahn acquired an additional 5.7% of the outstanding shares of National Onshore from certain other stockholders. During December 2004, National Onshore acquired the remaining 5.3% of the outstanding shares that were not owned by an affiliate of Mr. Icahn. The difference between the purchase price for both acquisitions and the minority interest liability was treated as a purchase price adjustment which reduced the full cost pool.
 
On December 6, 2004, AREP purchased from an affiliate of Mr. Icahn $27.5 million aggregate principal amount, or 100%, of the outstanding term notes issued by National Onshore (the “National Onshore Notes”). The purchase price was $28.2 million, which equaled the principal amount of the National Onshore Notes plus accrued unpaid interest. The notes are payable annually in equal consecutive annual payments of $5.0 million, with the final installment due August 28, 2008. Interest is payable semi-annually in February and August at the rate of 10% per annum.
 
On April 6, 2005, AREP acquired 100% of the outstanding stock of National Onshore from entities owned by Mr. Icahn for an aggregate consideration of $180 million. The operations of National Onshore are considered to have been contributed to the Company on August 28, 2003 at a historical cost of approximately $116.3 million, representing the historical basis in the assets and liabilities of National Onshore of the entities owned by Mr. Icahn. AREP contributed The National Onshore Notes, but not the accrued and unpaid interest through the date of contribution, to the Company on June 30, 2005. The Period of Common Control of National Onshore began on August 28, 2003.
 
National Offshore LP — On July 16, 2002, National Offshore filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court of the Southern District of Texas. On November 3, 2004, the Bankruptcy Court entered a confirmation order for the National Offshore’s Plan of Reorganization (the “National Offshore Plan”). The National Offshore Plan became effective November 16, 2004 and National Offshore began operating as a reorganized entity. Upon emergence from bankruptcy, an entity controlled by Mr. Icahn owned 100% of the outstanding common stock of National Offshore.
 
On December 6, 2004, AREP purchased $38.0 million aggregate principal amount of term loans issued by National Offshore, which constituted 100% of the outstanding term loans of National Offshore from an


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS (Unaudited) — (Continued)
 
affiliate of Mr. Icahn. On June 30, 2005, AREP contributed the National Offshore term loan, but not the accrued and unpaid interest through the date of contribution, to the Company.
 
On June 30, 2005, AREP acquired 100% of the equity of National Offshore from affiliates of Mr. Icahn for consideration valued at approximately $125.0 million. The Period of Common Control for National Offshore began on November 16, 2004 when National Offshore emerged from bankruptcy. The acquisition of National Offshore has been recorded effective December 31, 2004. The historical cost of approximately $91.6 million, representing the historical basis in the assets and liabilities of National Offshore of the affiliates of Mr. Icahn, was considered to have been contributed to the Company on December 31, 2004.
 
2.   Management Agreements
 
The management and operation of Operating LLC is being undertaken by National Energy Group pursuant to the Management Agreement (the “Operating LLC Management Agreement”) which Operating LLC entered into with National Energy Group. However, neither National Energy Group’s officers nor directors control the strategic direction of Operating LLC’s oil and natural gas business, including oil and natural gas drilling and capital investments, which are controlled by the managing member of Holding LLC (NEG Oil & Gas). The Operating LLC management agreement provides that National Energy Group will manage Operating LLC’s oil and natural gas assets and business until the earlier of December 15, 2006 (previously November 1, 2006, before the amendment of such agreement effective October 30, 2006) or such time as Operating LLC no longer owns any of the managed oil and natural gas properties. National Energy Group’s employees conduct the day-to-day operations of Operating LLC’s oil and natural gas business, and all costs and expenses incurred in the operation of the oil and natural gas properties are borne by Operating LLC, although the Operating LLC Management Agreement provides that the salary of National Energy Group’s Chief Executive Officer shall be 70% attributable to the managed oil and natural gas properties, and the salaries of each of the General Counsel and Chief Financial Officer shall be 20% attributable to the managed oil and natural gas properties. In exchange for National Energy Group’s management services, Operating LLC pays National Energy Group a management fee equal to 115% of the actual direct and indirect administrative and reasonable overhead costs that National Energy Group incurs in operating the oil and natural gas properties. National Energy Group or Operating LLC may seek to change the management fee to within the range of 110%-115% as such change is deemed warranted. However, both have agreed to consult with each other to ensure that such administrative and reasonable overhead costs attributable to the managed properties are properly reflected in the management fee that is paid. In addition, Operating LLC has agreed to indemnify National Energy Group to the extent National Energy Group incurs any liabilities in connection with National Energy Group’s operation of the assets and properties of Operating LLC, except to the extent of National Energy Group’s gross negligence or misconduct. Operating LLC incurred $3.7 million and $5.5 million in general and administrative expenses for the nine month periods ended September 30, 2005 and 2006, respectively under this agreement.
 
On August 28, 2003, National Energy Group entered into a management agreement to manage the oil and natural gas business of National Onshore. The National Onshore management agreement was entered in connection with a plan of reorganization for National Onshore proposed by Thornwood Associates LP, an entity affiliated with Carl C. Icahn (the “National Onshore Plan”). On August 28, 2003, the United States Bankruptcy Court, Southern District of Texas, issued an order confirming the National Onshore Plan. NEG Oil & Gas owns all of the reorganized National Onshore, which is engaged in the exploration, production and transmission of oil and natural gas, primarily in South Texas, including the Eagle Bay field in Galveston Bay, Texas and the Southwest Bonus field located in Wharton County, Texas. Bob G. Alexander and Philip D. Devlin, National Energy Group’s President and CEO, and National Energy Group’s Vice President, Secretary and General Counsel, respectively, have been appointed to the reorganized National Onshore Board of Directors


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS (Unaudited) — (Continued)
 
and act as the two principal officers of National Onshore and its subsidiaries, Galveston Bay Pipeline Corporation and Galveston Bay Processing Corporation. Randall D. Cooley, National Energy Group’s Vice President and CFO, has been appointed Treasurer of reorganized National Onshore and its subsidiaries.
 
The National Onshore Management Agreement provides that National Energy Group shall be responsible for and have authority with respect to all of the day-to-day management of National Onshore business, but will not function as a Disbursing Agent as such term is defined in the National Onshore Plan. As consideration for National Energy Group services in managing the National Onshore business, National Energy Group receives a monthly fee of $0.3 million. The National Onshore Management Agreement is terminable (i) upon 30 days prior written notice by National Onshore, (ii) upon 90 days prior written notice by National Energy Group, (iii) upon 30 days following any day where High River designees no longer constitute the National Onshore Board of Directors, unless otherwise waived by the newly-constituted Board of Directors of National Onshore, or (iv) as otherwise determined by the Bankruptcy Court. The Company recorded $3.5 million and $3.6 million in general and administrative expenses for the nine month periods ended September 30, 2005 and 2006, respectively, under this agreement.
 
On November 3, 2004, the United States Bankruptcy Court for the Southern District of Texas issued an order effective November 16, 2004 confirming a plan of reorganization for National Offshore (“National Offshore Plan”). In connection with the National Offshore Plan, National Energy Group entered into a Management Agreement with National Offshore (the “National Offshore Management Agreement”) pursuant to the Bankruptcy Court’s order confirming the effective date of the National Offshore Plan. NEG Oil & Gas owns all of the reorganized National Offshore. Mr. Bob G. Alexander, National Energy Group’s President and CEO, has been appointed to the reorganized National Offshore Board of Directors and acts as the reorganized National Offshore’s President. Mr. Philip D. Devlin, National Energy Group’s Vice President, General Counsel and Secretary, has been appointed to serve in the same capacities for National Offshore. Mr. Randall D. Cooley, National Energy Group’s Vice President and CFO, has been appointed as Treasurer of the reorganized National Offshore. In exchange for management services, National Energy Group receives a monthly fee equal to 115% of the actual direct and indirect administrative overhead costs that are incurred in operating and administering the National Offshore oil and natural gas properties. The Company recorded $2.9 million and $4.1 million in general and administrative expenses for the nine month periods ended September 30, 2005 and 2006, respectively, under this agreement.
 
Substantially concurrent with the Riata Energy purchase transaction the management agreements will be terminated.
 
3.   Derivatives
 
From time to time, the Company enters into various derivative instruments consisting principally of no cost collar options (the “Derivative Contracts”) to reduce its exposure to price risk in the spot market for natural gas and oil. The Company follows Statement of Financial Accounting Standards No. 133 (SFAS 133), Accounting for Derivative Instruments and Hedging Activities, which was amended by Statement of Financial Accounting Standards No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities. These pronouncements established accounting and reporting standards for derivative instruments and for hedging activities, which generally require recognition of all derivatives as either assets or liabilities in the balance sheet at their fair value. The accounting for changes in fair value depends on the intended use of the derivative and its resulting designation. The Company elected not to designate these instruments as hedges for accounting purposes, accordingly the cash settlements and valuation gains and losses are included in oil and


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS (Unaudited) — (Continued)
 
natural gas sales. The following summarizes the cash settlements and valuation gains and losses for the nine month periods ended September 30, 2005 and 2006 (amounts in thousands):
 
                 
    Nine Months Ended
 
    September 30,  
    2005     2006  
 
Realized loss — (net cash payments)
  $ (19,486 )   $ (25,014 )
Unrealized gain (loss)
    (111,631 )     115,877  
                 
Gain (loss) on Derivative Contracts
  $ (131,117 )   $ 90,863  
                 
 
The following is a summary of the Company’s Derivative Contracts as of September 30, 2006:
 
                                 
Type of Contract
  Production Month     Volume per Month     Floor     Ceiling  
 
No cost collars
    Oct-Dec 2006       31,000 BBLS     $ 41.65     $ 45.25  
No cost collars
    Oct-Dec 2006       16,000 Bbls       41.75       45.40  
No cost collars
    Oct-Dec 2006       570,000 MMBTU       6.00       7.25  
No cost collars
    Oct-Dec 2006       120,000 MMBTU       6.00       7.28  
No cost collars
    Oct-Dec 2006       500,000 MMBTU       4.50       5.00  
No cost collars
    Oct-Dec 2006       46,000 Bbls       60.00       68.50  
(The Company participates in a second ceiling at $84.50 on the 46,000 Bbls)
No cost collars
    Jan-Dec 2007       30,000 Bbls       57.00       70.50  
No cost collars
    Jan-Dec 2007       30,000 Bbls       57.50       72.00  
No cost collars
    Jan-Dec 2007       930,000 MMBTU       8.00       10.23  
No cost collars
    Jan-Dec 2007       1,000 Bbls       65.00       87.40 (A)
No cost collars
    Jan-Dec 2007       7,000 Bbls       65.00       86.00 (A)
No cost collars
    Jan-Dec 2007       330,000 MMBTU       9.60       12.10 (A)
No cost collars
    Jan-Dec 2007       100,000 MMBTU       9.55       12.60 (A)
No cost collars
    Jan-Dec 2008       46,000 Bbls       55.00       69.00  
No cost collars
    Jan-Dec 2008       750,000 MMBTU       7.00       10.35  
No cost collars
    Jan-Dec 2008       9,000 Bbls       65.00       81.25 (A)
No cost collars
    Jan-Dec 2008       70,000 MMBTU       8.75       11.90 (A)
No cost collars
    Jan-Dec 2008       270,000 MMBTU       8.80       11.45 (A)
No cost collars
    Jan-Dec 2009       19,000 Bbls       65.00       78.50 (A)
No cost collars
    Jan-Dec 2009       26,000 Bbls       65.00       77.00 (A)
No cost collars
    Jan-Dec 2009       330,000 MMBTU       7.90       10.80 (A)
No cost collars
    Jan-Dec 2009       580,000 MMBTU       7.90       11.00 (A)
 
 
(A) On October 17, 2006 the Company terminated the derivative contract. See Note 12.
 
While the use of derivative contracts can limit the downside risk of adverse price movements, it may also limit future gains from favorable movements. The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity. Credit risk related to derivative activities is managed by requiring minimum credit standards for counter parties, periodic settlements, and mark to market valuations.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS (Unaudited) — (Continued)
 
 
A liability of $85.9 million (including a current liability of $68.0 million) and an asset of $29.9 million (including a current asset of $14.1 million) was recorded by the Company as of December 31, 2005 and September 30, 2006, respectively, in connection with these contracts. As of December 31, 2004, the Company had issued $11.0 million in letters of credit securing the Company’s derivative position. During 2005, the Company was required to provide security to counter parties for its Derivative Contracts in loss positions.
 
On December 22, 2005, concurrent with the execution of the company’s new credit facility the Company novated all of Derivative Contracts with Shell Trading (US) outstanding as of that date with identical Derivative Contracts with Citicorp (USA), Inc. as the counter party. Under this transaction, no contracts were settled, Citicorp (USA) replaced Shell Trading (US) as the counterparty and no gain or loss was recorded. Under the new credit facility, Derivatives Contracts with certain lenders under the credit facility do not require cash collateral or letters of credit and rank pari passu with the credit facility. All cash collateral and letters of credit have been released as of December 31, 2005.
 
As a condition to closing the Riata purchase transaction, all derivatives contracts will be terminated or assumed by AREP. See Note 12.
 
4.   Acquisitions
 
On July 10, 2006, we acquired an additional interest in our East Breaks 160 offshore block from BP America for approximately $14.1 million which increased our interest in East Breaks to approximately 66%. As a condition to closing the acquisition, we were required to issue a $16.0 million letter of credit to BP America to collaterize the potential plugging and abandonment liability associated with the offshore block. The purchase price was paid from cash on hand.
 
In March 2005, the Company purchased an additional interest in Longfellow Ranch for $31.9 million.
 
In October 2005, the Company executed a purchase and sale agreement to acquire Minden Field assets near its existing production properties in East Texas. This acquisition consists of 3,500 acres with 17 producing wells and numerous drilling opportunities. The purchase price was approximately $85.0 million, which was subsequently reduced to $82.3 million after purchase price adjustments, and the transaction closed on November 8, 2005.
 
5.   Sale of West Delta Properties
 
In March 2005, the Company sold its rights and interest in West Delta 52, 54, and 58 to a third party in exchange for the assumption of existing future asset retirement obligations on the properties and a cash payment of $0.5 million. The estimated fair value of the asset retirement obligations assumed by the purchaser was approximately $16.8 million. In addition, the Company transferred to the purchaser approximately $4.7 million in an escrow account that the Company had funded relating to the asset retirement obligations on the properties. The full cost pool was reduced by approximately $11.6 million and no gain or loss was recognized on the transaction.
 
6.   Investments/Note Receivable
 
In October 2003, the Company committed to an investment of $6.0 million in PetroSource Energy Company, LLC (“PetroSource”). The Company’s commitment was to acquire 24.8% of the outstanding stock for a price of $3.0 million and to advance $3.0 million as a subordinated loan bearing 6% interest due in six years. The Company initially purchased $1.8 million in stock and funded $1.8 million of the loan in October 2003. In February 2004, the Company purchased an additional $1.2 million of stock and funded the remaining $1.2 million loan commitment. PetroSource is in the business of selling CO2 and also owns


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS (Unaudited) — (Continued)
 
pipelines and compressor stations for delivery purposes. During 2004, PetroSource sold additional equity shares which reduced the Company’s ownership to 20.63%. During 2005, the Company invested an additional $0.5 million in PetroSource stock. In December 2005, the Company sold its entire investment in PetroSource, including the subordinate loan, for total proceeds of $10.5 million and recorded a gain of $5.5 million.
 
In April 2002, the Company entered into a revolving credit commitment to extend advances to an third party. Under the terms of the revolving credit arrangement, the Company agreed to make advances from time to time, as requested by the third party and subject to certain limitations, in an amount up to $5.0 million. Advances made under the revolving credit commitment bear interest at prime rate plus 2% and are collateralized by inventory and receivables. As of December 31, 2004, the Company determined that a portion of the total outstanding advances of $1.3 million had been impaired and recorded a loss of $0.8 million. As of December 31, 2005, the Company determined that the majority of the total outstanding advance of $1.27 million had been impaired and recorded an additional loss of $0.5 million bringing the total allowance to $1.26 million.
 
7.   Restricted Deposits
 
In connection with the National Offshore transaction, the Company acquired restricted deposits aggregating $23.5 million. The restricted deposits represent bank trust and escrow accounts required to be set up by surety bond underwriters and certain former owners of National Offshore’s offshore properties. In accordance with requirements of the MMS, National Offshore was required to put in place surety bonds and/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 National Offshore’s 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.
 
The restricted deposits include the following at September 30, 2006:
 
1. A $4.4 million escrow account for the East Breaks 109 and 110 fields set up in favor of the surety bond underwriter who provides a surety bond to the MMS. The escrow account was fully funded as of September 30, 2006.
 
2. A $7.0 million escrow account for the East Breaks 165 and 209 fields set up in favor of the surety bond underwriter who provides a surety bond to the former owners of the fields and the MMS. The escrow account was fully funded as of September 30, 2006.
 
3. A $6.0 million escrow account set up in favor of a major oil company. The Company is required to make additional deposits to the escrow account in an amount equal to 10% of the net cash flow (as defined in the escrow agreement) from the properties that were acquired from the major oil company.
 
4. A $5.5 million escrow account that was required to be set up by the bankruptcy settlement proceedings of National Offshore. The Company is required to make monthly deposits based on cash flows from certain wells, as defined in the agreement.
 
5. $7.8 million in escrow accounts required to be set up by the MMS relating to East Breaks properties. The Company is required to make quarterly deposits to the escrow accounts of $0.8 million. Additionally, for some of the East Break properties, the Company will be required to deposit additional funds in the East Break escrow accounts, representing the difference between the required escrow deposit


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS (Unaudited) — (Continued)
 
under the surety bond and actual escrow deposit balance at various points in time in the future. Aggregate payments to the East Breaks escrow accounts are as follows (in thousands):
 
         
Year Ended December 31,
     
 
Remainder of 2006
    800  
2007
    6,100  
2008
    3,200  
2009
    3,200  
2010
    5,000  
Thereafter
    4,000  
         
    $ 22,300  
         
 
8.   Debt
 
The Company’s debt consists of credit facilities, notes payable, note payable to affiliates and senior notes payable to affiliates.
 
Credit Facilities
 
The Operating LLC Credit Facility
 
On December 29, 2003, Holding LLC entered into a Credit Agreement (the “Mizuho Facility”) with certain commercial lending institutions, including Mizuho Corporate Bank, Ltd. as the Administrative Agent and the Bank of Texas, N.A. and the Bank of Nova Scotia as Co-Agents.
 
The Credit Agreement provided for a loan commitment amount of up to $145.0 million and a letter of credit commitment of up to $15 million (provided, the outstanding aggregate amount of the unpaid borrowings, plus the aggregate undrawn face amount of all outstanding letters of credit shall not exceed the borrowing base under the Credit Agreement). The Credit Agreement provided further that the amount available to the Operating LLC at any time was subject to certain restrictions, covenants, conditions and changes in the borrowing base calculation. In partial consideration of the loan commitment amount, Operating LLC has pledged a continuing security interest in all of its oil and natural gas properties and its equipment, inventory, contracts, fixtures and proceeds related to its oil and natural gas business.
 
At Operating LLC’s option, interest on borrowings under the Credit Agreement bear interest at a rate based upon either the prime rate or the LIBOR rate plus, in each case, an applicable margin that, in the case of prime rate loans, can fluctuate from 0.75% to 2.50% per annum. Fluctuations in the applicable interest rate margins are based upon Operating LLC’s total usage of the amount of credit available under the Credit Agreement, with the applicable margins increasing as Operating LLC’s total usage of the amount of the credit available under the Credit Agreement increases.
 
At the closing of the Credit Agreement, Operating LLC borrowed $43.8 million to repay $42.9 million owed by Operating LLC to an affiliate of Mr. Icahn under the secured loan arrangement which was then terminated and to pay administrative fees in connection with this borrowing. Approximately $1.4 million of loan issuance costs was capitalized in connection with the closing of this transaction.
 
The Credit Agreement required, among other things, semiannual engineering reports covering oil and natural gas properties, and maintenance of certain financial ratios, including the maintenance of a minimum interest coverage, a current ratio, and a minimum tangible net worth.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS (Unaudited) — (Continued)
 
 
NEG Oil & Gas LLC Senior Secured Revolving Credit Facility
 
On December 22, 2005, NEG Oil & Gas entered into a credit agreement, dated as of December 20, 2005, with Citicorp USA, Inc., as administrative agent, Bear Stearns Corporate Lending Inc., as syndication agent, and other lender parties thereto (the “NEG Credit Facility”). The NEG Credit Facility is secured by substantially all the assets of NEG Oil & Gas and its subsidiaries, has a five-year term and permits payments and re-borrowings, subject to a borrowing base calculation based on the proved oil and gas reserves of the Company and its subsidiaries. Under the NEG Credit Facility, the Company will be permitted to borrow up to $500 million, and the initial borrowing base is set at $335 million. The Company used a portion of the initial $300 million funding under the NEG Credit Facility to purchase the Operating LLC Credit Facility. On a combined basis, the Operating LLC Credit Facility is no longer outstanding.
 
In consideration of each lender’s commitment to make loans under the NEG Credit Facility, the Company is required to pay a quarterly commitment fee ranging from 0.375% to 0.50% of the available borrowing base. Commitment fees are based upon the facility utilization levels.
 
At the Company’s option, borrowings under the NEG Credit Facility bear interest at Base Rate or Euro Dollar Rate, as defined in the borrowing agreement, plus, in each case, an applicable margin that, in the case of Base Rate loans, can fluctuate from 0.00% to 0.75% per annum, and, in the case of Euro Dollar loans, can fluctuate from 1.00% to 1.75% per annum. Fluctuations in the applicable interest rate margins are based upon the Company’s total usage of the amount of credit available under the NEG Credit Facility, with the applicable margins increasing as the Company’s total usage of the amount of the credit available under the NEG Credit Facility increases. Base Rate and Euro Dollar Rate fluctuate based upon Prime rate or LIBOR, respectively. At September 30, 2006 the interest rate on the outstanding amount under the credit facility was 7.38% and $14.8 million was available for future borrowings.
 
NEG Credit Facility agreement requires, among other things, semiannual engineering reports covering oil and natural gas properties, limitation on distributions, and maintenance of certain financial ratios, including maintenance of leverage ratio, current ratio and a minimum tangible net worth. The Company was in compliance with all covenants at September 30, 2006.
 
In addition to purchasing the Operating LLC Credit Facility, the Company used the proceeds from the NEG Credit Facility to (1) repay a loan of approximately $85 million by AREP used to purchase properties in the Minden Field; (2) pay a distribution of $78.0 million, and (3) pay transaction costs.
 
Notes Payable
 
Notes payable consist of the following (amounts in thousands):
 
                 
    December 31,
    September 30,
 
    2005     2006  
 
Notes payable to various prior creditors of National Onshore in settlement of bankruptcy claims. The notes are generally payable over a 30 month period with a stated interest rate of 6%; however, the notes have been discounted to an effective rate of 10%
  $ 2,503     $  
Less Current maturities
    (2,503 )      
                 
    $     $  
                 


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS (Unaudited) — (Continued)
 
Advance from Affiliate
 
During 2005, AREP made unsecured non-interest bearing advance of $49.8 million, payable on demand, to fund their drilling programs as well as to fund derivative contract deposits, of which $39.8 million were outstanding at December 31, 2005. The outstanding balance was repaid in January 2006.
 
9.   Income Taxes
 
National Onshore and National Offshore were organized as corporations until their respective acquisitions by NEG Oil & Gas, LLC, and were subject to corporate taxes up until the date of acquisition as part of a tax sharing arrangement with the Starfire, Inc. consolidated group. The Company accounts for income taxes of National Onshore and National Offshore according to Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (SFAS 109). SFAS 109 requires the recognition of deferred tax assets, net of applicable reserves, related to net operating loss carryforwards and certain temporary differences. The standard requires recognition of a future tax benefit to the extent that realization of such benefit is more likely than not. Otherwise, a valuation allowance is applied.
 
In May 2006, the State of Texas enacted legislation that replaces the taxable capital and earned surplus components of its franchise tax with a new franchise tax that is based on modified gross revenue. The new franchise tax becomes effective beginning with the 2007 tax year. The current franchise tax remains in effect through the end of 2006.
 
In accordance with generally accepted accounting principles in the United States, the new franchise tax is based on a measure of income, and thus accounted for in accordance with Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” (SFAS 109). The provisions of SFAS 109 require recognition of the effects of the tax law change in the period of enactment. During the nine month period ended September 30, 2006, the Company recorded an income tax expense and a deferred tax liability of $2.1 million to record effects of the change in Texas franchise law.
 
10.   Commitments and Contingencies
 
During the nine month period ended September 30, 2006, we entered into four drilling contracts to provide us with drilling rigs at specified drilling day rates. Due to previous commitments of the drilling rig operators, we have not taken delivery of the drilling rigs as of September 30, 2006. Our future obligations, and the estimated year of expenditure, under the drilling rig contracts are estimated as follows (dollar amounts in thousands):
 
                                         
          Estimated Commitment as of
 
          September 30, 2006  
Expected Drilling Location
 
Contract Duration
    Total     2006     2007     2008  
 
Onshore West Texas
    Six wells (approximately 3 months )   $ 1,201     $ 1,201     $     $  
Onshore East Texas
    18 months       10,900       1,800       7,300       1,800  
Onshore East Texas
    18 months       10,900       1,200       7,300       2,400  
Offshore
    6 months       8,100             8,100        
                                         
Total estimated commitments
          $ 31,101     $ 4,201     $ 22,700     $ 4,200  
                                         
 
During 2000 and 2001 National Energy Group entered into several hedge contracts with Enron North America Corp (“Enron NAC”). In 2001, Enron Corporation and many Enron Corporation affiliates and subsidiaries, including Enron NAC filed for protection under Chapter 11 of the US bankruptcy code. The


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS (Unaudited) — (Continued)
 
derivative contracts were subsequently contributed to Holding LLC and then to Operating LLC. Operating LLC has filed a claim for damages in the Enron NAC bankruptcy proceeding and our designee has been appointed as a representative to the official committee of unsecured creditors. The Company’s claim is unsecured. We received $0.2 million and $1.0 million for the nine month periods ended September 30, 2005 and 2006, respectively, in partial settlement of our claims, which was recorded in interest income and other. In October 2006, we received an additional $.9 million.
 
The Company expects to receive additional distributions from the Enron bankruptcy proceeding in accordance with its plan of reorganization. We will record such additional payments, if any, when the amounts are known.
 
Other than routine litigation incidental to its business operations which are not deemed by the Company to be material, there are no additional legal proceedings in which the Company, is a defendant.
 
Environmental Matters
 
The Company’s operations and properties are subject to extensive federal, state, and local laws and regulations relating to the generation, storage, handling, emission, transportation, and discharge of materials into the environment. Permits are required for various of the Company’s operations, and these permits are subject to revocation, modification, and renewal by issuing authorities. The Company’s operations are also subject to federal, state, and local laws and regulations that impose liability for the cleanup or remediation of property which has been contaminated by the discharge or release of hazardous materials or wastes into the environment. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines or injunctions, or both. The Company believes that it is in material compliance with applicable environmental laws and regulations. Noncompliance with such laws and regulations could give rise to compliance costs and administrative penalties. Management does not anticipate that the Company will be required in the near future to expend amounts that are material to the financial condition or operations of the Company by reason of environmental laws and regulations, but because such laws and regulations are frequently changed and, as a result, may impose increasingly strict requirements, the Company is unable to predict the ultimate cost of complying with such laws and regulations.
 
11.   Asset Retirement Obligation
 
In June 2001, the Financial Accounting Standards Board (FASB) issued Statements of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and/or normal use of the assets. It also requires the Company to record a corresponding asset that is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The ARO assets are recorded on the balance sheet as part of the Company’s full cost pool and are included in the amortization base for the purposes of calculating depreciation, depletion and amortization expense. For the purpose of calculating the ceiling test, the future cash outflows associated with settling the ARO liability are excluded from the computation of the discounted present value of estimated future net revenues.


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NEG OIL & GAS LLC AND SUBSIDIARIES, EXCLUDING NATIONAL ENERGY GROUP, INC.
AND THE 103/4% SENIOR NOTES DUE FROM NATIONAL ENERGY GROUP, INC., BUT INCLUDING
NATIONAL ENERGY GROUP INC.’S 50% MEMBERSHIP INTEREST IN NEG HOLDING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS (Unaudited) — (Continued)
 
 
The following is a rollforward of the asset retirement obligation as of December 31, 2005 and September 30, 2006 (amounts in thousands).
 
         
Balance as of December 31, 2005
  $ 41,228  
Add: Accretion
    2,112  
Drilling additions
     
Acquired properties
    4,269  
Less: Revisions
     
Settlements
     
Dispositions
     
         
Balance as of September 30, 2006
  $ 47,609  
         
 
12.   Subsequent Events
 
As a condition to closing the Riata Energy purchase transaction, the Company is required to terminate or otherwise assign all derivatives contracts to AREP. On October 17, 2006, the Company terminated all of its derivatives contracts for 2009 production and some of it derivatives contracts relating to 2007 and 2008 production. The Company received $17.6 million in cash upon termination of the contracts. No gain or loss was recognized upon termination because the derivatives contracts are recorded at fair market value.


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ANNEX A
LETTER OF TRANSMITTAL
To Tender
[85/8% Senior Notes Due 2015][Senior Floating Rate Notes Due 2014]
of
SANDRIDGE ENERGY, INC.
Pursuant to the Exchange Offer and Prospectus dated
June   , 2008
 
 
THE EXCHANGE OFFER AND WITHDRAWAL RIGHTS WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON          , 2008 (THE “EXPIRATION DATE”), UNLESS THE EXCHANGE OFFER IS EXTENDED BY THE COMPANY.
 
The Exchange Agent for the Exchange Offer is:
 
WELLS FARGO BANK, NATIONAL ASSOCIATION
 
         
Delivery by Registered
or Certified Mail:

Wells Fargo Bank, NA
Corporate Trust Operations
MAC N9303-121
PO Box 1517
Minneapolis, MN 55480
  Facsimile Transmissions:
(Eligible Institutions Only)

(214) 777-4086
Attention: Patrick T.
Giordano, Corporate Trust
Services
  Overnight Delivery
or Regular Mail:

Wells Fargo Bank, NA
Corporate Trust Operations
MAC N9303-121
Sixth & Marquette Avenue
Minneapolis, MN 55479
    To Confirm by Telephone
or for Information Call:
(214) 740-1573
   
 
IF YOU WISH TO EXCHANGE ISSUED AND OUTSTANDING [SENIOR NOTES DUE 2015][SENIOR FLOATING RATE NOTES DUE 2014] (THE “OUTSTANDING NOTES”) FOR AN EQUAL AGGREGATE PRINCIPAL AMOUNT OF NEW [SENIOR NOTES DUE 2015][SENIOR FLOATING RATE NOTES DUE 2014] PURSUANT TO THE EXCHANGE OFFER, YOU MUST VALIDLY TENDER (AND NOT WITHDRAW) OUTSTANDING NOTES TO THE EXCHANGE AGENT PRIOR TO 5:00 P.M., NEW YORK CITY TIME, ON THE EXPIRATION DATE BY CAUSING AN AGENT’S MESSAGE TO BE RECEIVED BY THE EXCHANGE AGENT PRIOR TO SUCH TIME.
 
 
The Prospectus, dated          , 2008 (the “Prospectus”), of SandRidge Energy, Inc., a Delaware corporation (the “Company”), and this Letter of Transmittal (the “Letter of Transmittal”), together describe the Company’s offer (the “Exchange Offer”) to exchange its [85/8% Senior Notes Due 2015][Senior Floating Rate Notes Due 2014] (the “Exchange Notes”) that have been registered under the Securities Act of 1933, as amended (the “Securities Act”), for a like principal amount of its issued and outstanding [Senior Notes Due 2015][Senior Floating Rate Notes Due 2014] (the “Outstanding Notes”). Capitalized terms used but not defined herein have the respective meaning given to them in the Prospectus.
 
The Company reserves the right, at any time or from time to time, to extend the Exchange Offer at its discretion, in which event the term “Expiration Date” shall mean the latest date to which the Exchange Offer is extended. The Company shall notify the Exchange Agent by oral or written notice and each registered holder of the Outstanding Notes of any extension by press release prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.


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This Letter of Transmittal is to be used by holders of the Outstanding Notes. Tender of Outstanding Notes is to be made according to the Automated Tender Offer Program (“ATOP”) of The Depository Trust Company (“DTC”) pursuant to the procedures set forth in the prospectus under the caption “The Exchange Offer — Procedures for Tendering.” DTC participants that are accepting the Exchange Offer must transmit their acceptance to DTC, which will verify the acceptance and execute a book-entry delivery to the Exchange Agent’s DTC account. DTC will then send a computer generated message known as an “agent’s message” to the Exchange Agent for its acceptance. For you to validly tender your Outstanding Notes in the Exchange Offer, the Exchange Agent must receive, prior to the Expiration Date, an agent’s message under the ATOP procedures that confirms that:
 
  •  DTC has received your instructions to tender your Outstanding Notes; and
 
  •  You agree to be bound by the terms of this Letter of Transmittal.
 
By using the ATOP procedures to tender outstanding notes, you will not be required to deliver this Letter of Transmittal to the Exchange Agent. However, you will be bound by its terms, and you will be deemed to have made the acknowledgments and the representations and warranties it contains, just as if you had signed it.
 
PLEASE READ THE ACCOMPANYING INSTRUCTIONS CAREFULLY.
 
Ladies and Gentlemen:
 
1. By tendering Outstanding Notes in the Exchange Offer, you acknowledge receipt of the Prospectus and this Letter of Transmittal.
 
2. By tendering Outstanding Notes in the Exchange Offer, you represent and warrant that you have full authority to tender the Outstanding Notes described above and will, upon request, execute and deliver any additional documents deemed by the Company to be necessary or desirable to complete the tender of Outstanding Notes.
 
3. You understand that the tender of the Outstanding Notes pursuant to all of the procedures set forth in the Prospectus will constitute an agreement between and the Company as to the terms and conditions set forth in the Prospectus.
 
4. By tendering Outstanding Notes in the Exchange Offer, you acknowledge that the Exchange Offer is being made in reliance upon interpretations contained in no-action letters issued to third parties by the staff of the Securities and Exchange Commission (the “SEC”), including Exxon Capital Holdings Corp., SEC No-Action Letter (available April 13, 1989), Morgan Stanley & Co. Inc., SEC No-Action Letter (available June 5, 1991) and Shearman & Sterling, SEC No-Action Letter (available July 2, 1993), that the Exchange Notes issued in exchange for the Outstanding Notes pursuant to the Exchange Offer may be offered for resale, resold and otherwise transferred by holders thereof (other than a broker-dealer who purchased Outstanding Notes exchanged for such Exchange Notes directly from the Company to resell pursuant to Rule 144A or any other available exemption under the Securities Act of 1933, as amended (the “Securities Act”) and any such holder that is an “affiliate” of the Company within the meaning of Rule 405 under the Securities Act), without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that such Exchange Notes are acquired in the ordinary course of such holders’ business and such holders are not participating in, and have no arrangement with any person to participate in, the distribution of such Exchange Notes.
 
5. By tendering Outstanding Notes in the Exchange Offer, you represent and warrant that:
 
a. the Exchange Notes acquired pursuant to the Exchange Offer are being obtained in the ordinary course of your business, whether or not you are the holder;
 
b. neither you nor any such other person is engaging in or intends to engage in a distribution of such Exchange Notes;


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c. neither you nor any such other person has an arrangement or understanding with any person to participate in the distribution of such Exchange Notes; and
 
d. neither you nor any such other person is an “affiliate,” as such term is defined under Rule 405 promulgated under the Securities Act, of the Company.
 
6. You may, if you are unable to make all of the representations and warranties contained in Item 5 above and as otherwise permitted in the Registration Rights Agreement (as defined below), elect to have your Outstanding Notes registered in the shelf registration statement described in the Registration Rights Agreement, dated as of May 1, 2008 (the “Registration Rights Agreement”), by and among the Company and the Guarantors (as defined therein). Such election may be made only by notifying the Company in writing at 1601 N.W. Expressway, Suite 1600, Oklahoma City, Oklahoma 73118, Attention: Chief Financial Officer. By making such election, you agree, as a holder of Outstanding Notes participating in a shelf registration, to indemnify and hold harmless the Company, each of the directors of the Company, each of the officers of the Company who signs such shelf registration statement, each person who controls the Company within the meaning of either the Securities Act or the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and each other holder of Outstanding Notes, from and against any and all losses, claims, damages or liabilities caused by any untrue statement or alleged untrue statement of a material fact contained in any shelf registration statement or prospectus, or in any supplement thereto or amendment thereof, or caused by the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; but only with respect to information relating to the undersigned furnished in writing by or on behalf of the undersigned expressly for use in a shelf registration statement, a prospectus or any amendments or supplements thereto. Any such indemnification shall be governed by the terms and subject to the conditions set forth in the Registration Rights Agreement, including, without limitation, the provisions regarding notice, retention of counsel, contribution and payment of expenses set forth therein. The above summary of the indemnification provision of the Registration Rights Agreement is not intended to be exhaustive and is qualified in its entirety by the Registration Rights Agreement.
 
7. If you are a broker-dealer who will receive Exchange Notes for your own account in exchange for Outstanding Notes that were acquired as a result of market-making activities or other trading activities, you acknowledge, by tendering Outstanding Notes in the Exchange Offer, that you will deliver a prospectus in connection with any resale of such Exchange Notes; however, by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an “underwriter” within the meaning of the Securities Act. If you are a broker-dealer and Outstanding Notes held for your own account were not acquired as a result of market-making or other trading activities, such Outstanding Notes cannot be exchanged pursuant to the Exchange Offer.
 
8. Any of your obligations hereunder shall be binding upon your successors, assigns, executors, administrators, trustees in bankruptcy and legal and personal representatives of the undersigned.
 
INSTRUCTIONS
 
FORMING PART OF THE TERMS AND CONDITIONS OF THE EXCHANGE OFFER
 
1. Book-Entry Confirmations.
 
Any confirmation of a book-entry transfer to the Exchange Agent’s account at DTC of Outstanding Notes tendered by book-entry transfer, as well as an agent’s message, and any other documents required by this Letter of Transmittal, must be received by the Exchange Agent at its address set forth herein prior to 5:00 P.M., New York City time, on the Expiration Date.
 
2. Partial Tenders.
 
Tenders of Outstanding Notes will be accepted only in integral multiples of $1,000. The entire principal amount of Outstanding Notes delivered to the Exchange Agent will be deemed to have been tendered unless otherwise communicated to the Exchange Agent. If the entire principal amount of all Outstanding Notes is not tendered, then Outstanding Notes for the principal amount of Outstanding Notes not


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tendered and Notes issued in exchange for any Outstanding Notes accepted will be delivered to the holder via the facilities of DTC promptly after the Outstanding Notes are accepted for exchange.
 
3. Validity of Tenders.
 
All questions as to the validity, form, eligibility (including time of receipt), acceptance, and withdrawal of tendered Outstanding Notes will be determined by the Company, in its sole discretion, which determination will be final and binding. The Company reserves the absolute right to reject any or all tenders not in proper form or the acceptance for exchange of which may, in the opinion of counsel for the Company, be unlawful. The Company also reserves the absolute right to waive any of the conditions of the Exchange Offer or any defect or irregularity in the tender of any Outstanding Notes. The Company’s interpretation of the terms and conditions of the Exchange Offer (including the instructions on this Letter of Transmittal) will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of Outstanding Notes must be cured within such time as the Company shall determine. Although the Company intends to notify holders of defects or irregularities with respect to tenders of Outstanding Notes, neither the Company, the Exchange Agent, nor any other person shall be under any duty to give notification of any defects or irregularities in tenders or incur any liability for failure to give such notification. Tenders of Outstanding Notes will not be deemed to have been made until such defects or irregularities have been cured or waived. Any Outstanding Notes received by the Exchange Agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned by the Exchange Agent to the tendering holders via the facilities of DTC, as soon as practicable following the Expiration Date.
 
4. Waiver of Conditions.
 
The Company reserves the absolute right to waive, in whole or part, any of the conditions to the Exchange Offer set forth in the Prospectus or in this Letter of Transmittal.
 
5. No Conditional Tender.
 
No alternative, conditional, irregular or contingent tender of Outstanding Notes will be accepted.
 
6. Request for Assistance or Additional Copies.
 
Requests for assistance or for additional copies of the Prospectus or this Letter of Transmittal may be directed to the Exchange Agent at the address or telephone number set forth on the cover page of this Letter of Transmittal. Holders may also contact their broker, dealer, commercial bank, trust company or other nominee for assistance concerning the Exchange Offer.
 
7. Withdrawal.
 
Tenders may be withdrawn only pursuant to the limited withdrawal rights set forth in the Prospectus under the caption “The Exchange Offers — Withdrawal Rights.”
 
8. No Guarantee of Late Delivery.
 
There is no procedure for guarantee of late delivery in the Exchange Offer.
 
IMPORTANT:  By using the ATOP procedures to tender outstanding notes, you will not be required to deliver this Letter of Transmittal to the Exchange Agent. However, you will be bound by its terms, and you will be deemed to have made the acknowledgments and the representations and warranties it contains, just as if you had signed it.


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ANNEX B
 
GLOSSARY OF NATURAL GAS AND OIL TERMS
 
The following is a description of the meanings of some of the natural gas and oil industry terms used in this prospectus.
 
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.
 
Bcfe.  Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
 
Btu or British thermal unit.  The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
 
Condensate.  Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
 
CO2.  Carbon Dioxide.
 
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.
 
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 crude oil or other liquid hydrocarbons.
 
Mcf.  Thousand cubic feet of natural gas.
 
Mcfe.  Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
 
MmBbls.  Million barrels of crude oil or other liquid hydrocarbons.
 
Mmboe.  Million barrels of crude oil equivalent.
 
MBtu.  Thousand British Thermal Units.
 
MmBtu.  Million British Thermal Units.
 
Mmcf.  Million cubic feet of natural gas.
 
Mmcfe.  Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
 
Mmcfe/d.  Mmcfe per day.


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Net acres or net wells.  The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.
 
Present value of future net revenues (PV-10).  The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation and without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization. PV-10 is calculated using an annual discount rate of 10%.
 
Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
 
Prospect.  A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
 
Proved developed reserves.  Has the meaning given to such term in Rule 4-10(a)(3) of Regulation S-X, which defines proved developed reserves as:
 
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
 
Proved reserves.  Has the meaning given to such term in Rule 4-10(a)(2) of Regulation S-X, which defines proved reserves as:
 
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
 
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
 
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
 
(iii) Estimates of proved reserves do not include the following: (A) Oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas


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liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
 
Proved undeveloped reserves.  Has the meaning given to such term in Rule 4-10(a)(4) of Regulation S-X, which defines proved undeveloped reserves as:
 
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
 
Pulling Units.  Pulling units are used in connection with completions and workover operations.
 
PV-10.  Please see “Present value of future net revenues.”
 
Rental Tools.  A variety of rental tools and equipment, ranging from trash trailers to blow out preventors to sand separators, for use in the oil field.
 
Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
 
Roustabout Services.  The provision of manpower to assist in conducting oil field operations.
 
Standardized Measure or Standardized Measure of Discounted Future Net Cash Flows.  The present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes and asset retirement obligations on future net revenues.
 
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.
 
Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.


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PART II
 
INFORMATION NOT REQUIRED IN PROSPECTUS
 
Item 20.   Indemnification of Directors and Officers
 
Section 145 of the Delaware General Corporation Law (“DGCL”) provides that a corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. Section 145 further provides that a corporation similarly may indemnify any such person serving in any such capacity who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that he is or was a director, officer, employee or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees) actually and reasonably incurred in connection with the defense or settlement of such action or suit if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the Delaware Court of Chancery or such other court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all of the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Delaware Court of Chancery or such other court shall deem proper. The Company’s certificate of incorporation and bylaws provide that indemnification shall be to the fullest extent permitted by the DGCL for all current or former directors or officers of the Company. As permitted by the DGCL, the certificate of incorporation provides that directors of the Company shall have no personal liability to the Company or its stockholders for monetary damages for breach of fiduciary duty as a director, except (1) for any breach of the director’s duty of loyalty to the Company or its stockholders, (2) for acts or omissions not in good faith or which involve intentional misconduct or knowing violation of law, (3) under Section 174 of the DGCL or (4) for any transaction from which a director derived an improper personal benefit.
 
Item 21.   Exhibits and Financial Statement Schedules
 
(a) Exhibits:
 
Reference is made to the Index to Exhibits following the signature pages hereto, which Index to Exhibits is hereby incorporated into this item.
 
Item 22.   Undertakings
 
Each undersigned registrant hereby undertakes:
 
(a)(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:
 
(i) To include any prospectus required by section 10(a)(3) of the Securities Act of 1933;
 
(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration


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statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement;
 
(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;
 
(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof; and
 
(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.
 
(b) That, for purposes of determining any liability under the Securities Act of 1933, each filing of the registrant’s annual report pursuant to section 13(a) or section 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
 
(c) To respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11, or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.
 
(d) To supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in this registration statement when it became effective.
 
(e) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of a registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.


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SIGNATURES
 
Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma, in the State of Oklahoma on June 24, 2008.
 
SANDRIDGE ENERGY, INC.
 
    By: 
/s/  TOM L. WARD
Name:     Tom L. Ward
  Title:  President, Chief Executive Officer and Chairman of the Board
 
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Tom L. Ward, Richard Gognat and Justin 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 (including pre-effective and post-effective amendments) to this Registration Statement and any registration statement for the same offering filed pursuant to Rule 462 under the Securities Act of 1933, as amended, 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 Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates indicated below.
 
             
Signature
 
Title
 
Date
 
         
/s/  TOM L. WARD

Tom L. Ward
  President, Chief Executive Officer And Chairman of the Board
(Principal Executive Officer)
  June 24, 2008
         
/s/  DIRK M. VAN DOREN

Dirk M. Van Doren
  Chief Financial Officer and Executive
Vice President
(Principal Financial Officer)
  June 24, 2008
         
/s/  RANDALL D. COOLEY

Randall D. Cooley
  Senior Vice President of Accounting (Principal Accounting Officer)   June 24, 2008
         
/s/  DAN JORDAN

Dan Jordan
  Director   June 19, 2008
         
/s/  BILL GILLILAND

Bill Gilliland
  Director   June 24, 2008


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Signature
 
Title
 
Date
 
         
/s/  ROY T. OLIVER, JR.

Roy T. Oliver, Jr.
  Director   June 18, 2008
         
/s/  STUART W. RAY

Stuart W. Ray
  Director   June 24, 2008
         
/s/  D. DWIGHT SCOTT

D. Dwight Scott
  Director   June 24, 2008
         
/s/  JEFF SEROTA

Jeff Serota
  Director   June 24, 2008

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SIGNATURES
 
Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma, in the State of Oklahoma on June 24, 2008.
 
SANDRIDGE HOLDINGS, INC.
 
SANDRIDGE OPERATING COMPANY
 
LARIAT SERVICES, INC.
 
SANDRIDGE MIDSTREAM, INC.
 
SANDRIDGE ONSHORE, LLC
 
SANDRIDGE EXPLORATION AND PRODUCTION, LLC
 
SANDRIDGE OFFSHORE, LLC
 
INTEGRA ENERGY, LLC
 
SANDRIDGE TERTIARY, LLC
 
 
  By: 
/s/  TOM L. WARD
Name:     Tom L. Ward
  Title:  Chief Executive Officer
 
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Tom L. Ward, Richard Gognat and Justin 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 (including pre-effective and post-effective amendments) to this Registration Statement and any registration statement for the same offering filed pursuant to Rule 462 under the Securities Act of 1933, as amended, 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.


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Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates indicated below.
 
SANDRIDGE HOLDINGS, INC.
 
SANDRIDGE OPERATING COMPANY
 
LARIAT SERVICES, INC.
 
SANDRIDGE MIDSTREAM, INC.
 
SANDRIDGE ONSHORE, LLC
 
SANDRIDGE EXPLORATION AND PRODUCTION, LLC
 
SANDRIDGE OFFSHORE, LLC
 
INTEGRA ENERGY, LLC
 
SANDRIDGE TERTIARY, LLC
 
 
             
Signature
 
Title
 
Date
 
         
/s/  TOM L. WARD

Tom L. Ward
  Chief Executive Officer And Sole Director* (Principal Executive Officer)   June 24, 2008
         
/s/  DIRK M. VAN DOREN

Dirk M. Van Doren
  Chief Financial Officer (Principal Financial Officer)   June 24, 2008
         
/s/  RANDALL D. COOLEY

Randall D. Cooley
  Senior Vice President
(Principal Accounting Officer)
  June 24, 2008
 
*   Tom L. Ward serves as sole director of SandRidge Holdings, Inc., SandRidge Operating Company, Lariat Services, Inc. and SandRidge Midstream, Inc. Mr. Ward also serves as (i) Chief Executive Officer of SandRidge Holdings, Inc., the sole member of SandRidge Offshore, LLC, SandRidge Exploration and Production, LLC and SandRidge Onshore, LLC, (ii) Chief Executive Officer of SandRidge Operating Company, the sole member of Integra Energy, LLC, and (iii) President, Chief Executive Officer and Chairman of the Board of SandRidge Energy, Inc., the sole member of SandRidge Tertiary, LLC


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EXHIBIT INDEX
 
                     
Exhibit
      Filed Herewith (*) or Incorporated by
  File
 
Number
 
Description
 
Reference to Exhibit No.
 
Number
 
 
                     
  3 .1   Certificate of Incorporation   3.1 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  3 .2   Bylaws   3.3 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  4 .1   Indenture dated as of May 1, 2008 among SandRidge Energy, Inc. and the several guarantors named therein, and Wells Fargo Bank, National Association, as trustee   4.1 to Form 8-K filed on May 2, 2008     1-33784  
                     
  4 .2   Registration Rights Agreement dated as of May 1, 2008 among SandRidge Energy, Inc. and the several guarantors named therein for the benefit of the holders of the Notes   4.2 to Form 8-K filed on May 2, 2008     1-33784  
                     
  4 .3   Indenture dated as of May 20, 2008 among SandRidge Energy, Inc. and the several guarantors named therein, and Wells Fargo Bank, National Association, as trustee   4.1 to Form 8-K filed on May 21, 2008     1-33784  
                     
  4 .4   Registration Rights Agreement dated as of May 20, 2008 among SandRidge Energy, Inc., the several guarantors named therein and Banc of America Securities LLC, Barclays Capital Inc. and J.P. Morgan Securities Inc., as representatives of the several initial purchasers   4.2 to Form 8-K filed on May 21, 2008     1-33784  
                     
  5 .1   Opinion of Vinson & Elkins LLP   *        
                     
  10 .1   Executive Nonqualified Excess Plan   10.1 to Form 10-K filed on March 7, 2008     1-33784  
                     
  10 .2   2005 Stock Plan of SandRidge Energy, Inc.    10.2 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .2.1   Form of Restricted Stock Award Agreement under 2005 Stock Plan   10.2.1 to Form 10-K filed on March 7, 2008     1-33784  
                     
  10 .3   Employment Participation Plan of SandRidge Energy, Inc.    10.3 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .4   Well Participation Plan of SandRidge Energy, Inc   10.4 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .5.1   Employment Agreement of Tom L. Ward, dated June 8, 2006   10.11 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .5.2   Employment Agreement of Larry K. Coshow, dated September 2, 2006   10.12 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .5.3   Employment Agreement of Dirk M. Van Doren, effective January 1, 2008   10.5.2 to 10-Q filed on May 8, 2008     1-33784  
                     
  10 .5.4   Employment Agreement of Matthew K. Grubb, effective January 1, 2008   10.5.3 to Form 10-Q filed on May 8, 2008     1-33784  
                     
  10 .5.5   Employment Agreement of Todd N. Tipton, effective January 1, 2008   10.5.4 to Form 10-Q filed on May 8, 2008     1-33784  


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Exhibit
      Filed Herewith (*) or Incorporated by
  File
 
Number
 
Description
 
Reference to Exhibit No.
 
Number
 
 
                     
  10 .5.6   Employment Agreement of Larry K. Cowshow, effective January 1, 2008   10.5.5 to Form 10-Q filed on May 8, 2008     1-33784  
                     
  10 .5.7   Form of Employment Agreement for Senior Vice Presidents   10.5.6 to Form 10-Q filed on May 8, 2008     1-33784  
                     
  10 .5.8   Employment Separation Agreement of Larry K. Cowshow, dated April 14, 2008   10.5.7 to Form 10-Q filed on May 8, 2008     1-33784  
                     
  10 .6   Form of Indemnification Agreement for directors and officers   10.5 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .7   Senior Credit Facility, dated November 21, 2006, by and among SandRidge Energy, Inc. (as successor by merger to Riata Energy, Inc.) and Bank of America, N.A., as Administrative Agent and Banc of America Securities LLC as Lead Arranger and Book Running Manager   10.6 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .7.1   Amendment No. 1 to Senior Credit Facility, dated November 21, 2006 by and among SandRidge Energy, Inc.    10.9 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .7.2   Amendment No. 2 to Senior Credit Facility, dated November 21, 2006   10.10 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .7.3   Amendment No. 3, dated September 14, 2007, to Senior Credit Facility, dated November 21, 2006, by and among SandRidge Energy, Inc. (as successor by merger to Riata Energy, Inc.) and Bank of America, N.A., as Administrative Agent and Banc of America Securities LLC as Lead Arranger and Book Running Manager   10.7.3 to Form 10-Q filed on May 8, 2008     1-33784  
                     
  10 .7.4   Amendment No. 4, dated April 4, 2008, to Senior Credit Facility, dated November 21, 2006, by and among SandRidge Energy, Inc. (as successor by merger to Riata Energy, Inc.) and Bank of America, N.A., as Administrative Agent and Banc of America Securities LLC as Lead Arranger and Book Running Manager   10.7.4 to Form 10-Q filed on May 8, 2008     1-33784  
                     
  10 .8   Partnership Interest Purchase Agreement, dated November 21, 2005 by and among Riata Energy, Inc. and Matthew McCann   10.13 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .9   Purchase and Sale Agreement, dated December 4, 2005 by and between Gillco Energy, LP, as Seller and Riata Energy, Inc., Riata Piceance, LLC, MidContinent Resources, LLC, and ROC Gas Company, as Buyer   10.14 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  

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Exhibit
      Filed Herewith (*) or Incorporated by
  File
 
Number
 
Description
 
Reference to Exhibit No.
 
Number
 
 
                     
  10 .10   Purchase and Sale Agreement, dated December 4, 2005 by and between Wallace Jordan, LLC and Daniel White Jordan, as Sellers and Riata Energy, Inc., Sierra Madera CO 2 Pipeline, LLC, Riata Piceance, LLC, and ROC Gas Company, as Buyers   10.15 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .11   Purchase and Sale Agreement, dated August 29, 2006 by and among Alsate Management and Investment Company and Longfellow Ranch Partners, LP   10.16 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .12   Purchase and Sale Agreement, dated June 7, 2007 by and between Wallace Jordan, LLC and SandRidge Energy, Inc.    10.17 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .13   Office Lease Agreement, dated March 6, 2006 by and between 1601 Tower Properties, L.L.C. and Riata Energy, Inc.    10.18 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .13.1   First Amendment, dated October 19, 2006 to Office Lease Agreement, dated March 6, 2006   10.19 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .13.2   Second Amendment, dated January 26, 2007 to Office Lease Agreement   10.20 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  10 .14   Letter Agreement for Acquisition of Properties, dated September 21, 2007 by and between SandRidge Energy, Inc., Longfellow Energy, LP, Dalea Partners, LP and N. Malone Mitchell, 3rd   10.21 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  12 .1   Computation of Ratio of Earnings to Fixed Charges   *        
                     
  21 .1   Subsidiaries of SandRidge Energy, Inc.    21.1 to Registration Statement on Form S-1 filed on January 30, 2008     333-148956  
                     
  23 .1   Consent of PricewaterhouseCoopers LLP   *        
                     
  23 .2   Consent of Grant Thornton LLP   *        
                     
  23 .3   Consent of DeGolyer and MacNaughton   *        
                     
  23 .4   Consent of Netherland, Sewell & Associates, Inc.    *        
                     
  23 .5   Consent of Harper & Associates, Inc.    *        
                     
  23 .6   Consent of Vinson & Elkins L.L.P. (Contained in Exhibit 5.1)   *        
                     
  24 .1   Powers of Attorney (included on signature pages)   *        

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