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S-1 1 h32268sv1.htm RIATA ENERGY, INC. sv1

As filed with the Securities and Exchange Commission on February 10, 2006

Registration No. 333-

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Riata Energy, Inc.

(Exact name of registrant as specified in its charter)


Texas	1311	76-0002820
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

701 S. Taylor, Suite 390

Amarillo, Texas 79101

(806) 376-7904

(Address, including zip code, and telephone number, including

area code, of registrant’s principal executive offices)

Malone Mitchell, 3rd

President

701 S. Taylor, Suite 390

Amarillo, Texas 79101

(806) 376-7904

(Name, address, including zip code, and telephone number,

including area code, of agent for service)

Copies to:

Vinson & Elkins L.L.P.

2300 First City Tower, 1001 Fannin

Houston, Texas 77002

(713) 758-2222

Attn: T. Mark Kelly

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, please check the following box. þ

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

CALCULATION OF REGISTRATION FEE

Proposed Maximum

Title of Each Class of

Amount to be

Offering Price

Aggregate Offering

Amount of

Securities to be Registered

Registered

Per Share (1)

Price (1)

Registration Fee

Common Stock, par value $0.001

16,239,630

$17.00

$276,073,710

$29,540

(1)

Estimated solely for the purpose of calculating the registration fee in accordance with Rule 457(c) under the Securities Act 1933. No exchange or over-the-counter market exists for the registrant’s common stock. Shares of the registrant’s common stock issued to qualified institutional buyers in connection with its December 2005 private placement re eligible for trading on the PORTAL Market^®. The last sale of shares of the registrant’s common stock that was eligible for PORTAL, of which the registrant is aware, occurred on February 1, 2006 at a price of $17.00.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. The selling shareholders may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED FEBRUARY 10, 2006

Prospectus

Shares

Riata Energy, Inc.

Common Stock

This prospectus relates to up to shares of the common stock of Riata Energy, Inc., which may be offered for sale by the selling shareholders named in this prospectus. The selling shareholders acquired the shares of common stock offered by this prospectus in private placements in December 2005 and January 2006. We are registering the offer and sale of the shares of common stock to satisfy registration rights we have granted.

We are not selling any shares of common stock under this prospectus and will not receive any proceeds from the sale of common stock by the selling shareholders. The shares of common stock to which this prospectus relates may be offered and sold from time to time directly from the selling shareholders or alternatively through underwriters or broker-dealers or agents. The shares of common stock may be sold in one or more transactions, at fixed prices, at prevailing market prices at the time of sale or at negotiated prices. Please read “Plan of Distribution.”

We intend to apply to have our common stock listed on the New York Stock Exchange under the symbol “REI.”

Investing in our common stock involves a high degree of risk. See “Risk Factors” beginning on page 13.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or determined if this prospectus is accurate or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is , 2006

TABLE OF CONTENTS


Summary		1
Risk Factors		13
Forward-Looking Statements		25
Use of Proceeds		26
Dividend Policy		26
Unaudited Pro Forma Condensed Consolidated Financial Statements		27
Selected Historical Financial Data		36
Management’s Discussion and Analysis of Financial Condition and Results of Operations		39
Business		62
Management		85
Security Ownership of Certain Beneficial Owners and Management		93
Selling Shareholders		94
Plan of Distribution		95
Related Party Transactions		97
Description of Capital Stock		99
Certain U.S. Tax Consequences to Non-U.S. Holders		102
Legal Matters		105
Experts		105
Where You Can Find More Information		105
Index to Financial Statements		F-1
Appendix A: Glossary of Oil and Natural Gas Terms		A-1
Restated Articles of Incorporation
Amended and Restated Bylaws
Resale Registration Rights
2005 Stock Plan
Employee Participation Plan
First Amended Master Credit Ageement
Subsidiaries
Consent of PricewaterhouseCoopers LLP (Riata)
Consent of PricewaterhouseCoopers LLP (PetroSource)
Consent of Michael Harper & Associates
Consent of DeGolyer & MacNaughton

ABOUT THIS PROSPECTUS

You should rely only on the information contained in this prospectus or to which we have referred you. We and the selling shareholders have not authorized anyone to provide you with different information. The selling shareholders are not making an offer of these securities in any jurisdiction where such offer or sale is not permitted. You should assume that the information contained in this prospectus is accurate as of the date on the front of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus is part of a “shelf” registration statement that we filed with the Securities and Exchange Commission (the “SEC”) for a continuous offering. Under this prospectus, the selling shareholders may, from time to time, sell the shares of our common stock described in this prospectus in one or more offerings. This prospectus may be supplemented from time to time to add, update or change information in this prospectus. Any statement contained in this prospectus will be deemed to be modified or superseded for the purposes of this prospectus to the extent that a statement contained in a prospectus supplement modifies such statement. Any statement so modified will be deemed to constitute a part of this prospectus only as so modified, and any statement so modified will be deemed to constitute a part of this prospectus.

The registration statement containing this prospectus, including the exhibits to the registration statement, provides additional information about us, the selling shareholders and the shares of our common stock offered under this prospectus. The registration statement, including the exhibits, can be read on the SEC website or at the SEC offices mentioned under the heading “Where You Can Find More Information.”

Information contained in our website does not constitute part of this prospectus.

Riata Energy, Inc., our logo and other trademarks mentioned in this prospectus are the property of their respective owners.

This prospectus includes market share and industry data that we obtained from internal research, publicly available information and industry publications and surveys. Our internal research and forecasts are based upon management’s understanding of industry conditions, and such information has not been verified by any independent sources. Industry surveys and publications generally state that the information contained therein has been obtained from sources believed to be reliable.

SUMMARY

This summary contains basic information about us and the offering. Because it is a summary, it does not contain all the information that you should consider before investing in our common stock. You should read and carefully consider this entire prospectus before making an investment decision, especially the information presented under the heading “Risk Factors” and our consolidated and pro forma financial statements and the accompanying notes thereto included elsewhere in this prospectus. We have provided definitions for some of the oil and natural gas industry terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” on page A-1 of this prospectus. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. Unless otherwise noted, all natural gas amounts are net of CO_2. Except as otherwise indicated or required by the context, references in this prospectus to “we,” “us,” “our,” “Riata,” or the “Company” refer to the combined business of Riata Energy, Inc. and its subsidiaries.

On December 21, 2005, we acquired, in exchange for cash and shares of our common stock, additional undivided interests in certain of our oil and gas properties and assets, including all of the equity interests in Lariat Compression Company (“Larco”) and a substantial additional equity interest in PetroSource Energy Company, L.P. (“PetroSource”), resulting in its consolidation in our financial statements. We refer to these transactions in this prospectus as our “December 2005 acquisitions.” For more information regarding these transactions, please read “ — Recent Developments — Our December 2005 Acquisitions.”

Overview

Riata Energy, Inc. is an oil and natural gas company with its principal focus on exploration and production. We also own and operate drilling rigs and a related oil field services business; gas gathering, marketing and processing facilities; and, through our subsidiary PetroSource, CO₂ treating and transportation facilities and tertiary oil recovery operations. We believe that this vertical integration in our core operating areas is unique to a company of our size and provides us with operational flexibility and an advantageous cost structure. We began our exploration and production operations in 1986 in West Texas with limited acreage and production. To date, we have concentrated our exploration and production activities in West Texas where we have assembled a large, focused acreage position, and more recently, we have expanded our operations into our largely undeveloped acreage position in the Piceance Basin in northwestern Colorado. As a result of these exploration and production activities, we have grown our average net production to 20.2 Mmcfe per day for the month of September 2005. We also have acreage positions in the Anadarko and Arkoma Basins of Oklahoma. We continually seek to optimize our asset base and believe that our control of all of the components of oil and natural gas exploration and production — acreage, drilling, gathering, transportation and treating — provides us with significant competitive advantages. At September 30, 2005 after giving effect to our December 2005 acquisitions, our estimated proved reserves were 272 Bcfe. We have assembled an extensive oil and natural gas property base with 326 gross (190.5 net) wells, substantially all of which we operate, and interests in over 722,590 gross (226,037 net) acres as of September 30, 2005 after giving effect to our December 2005 acquisitions. Our large acreage position provides us with an extensive drilling inventory.

We began our oil field services business in 1986 and expanded this business in 1997 to include drilling with the acquisition of our first rig. We currently operate 20 drilling rigs and have 22 additional rigs on order or under construction with the last delivery scheduled in the first quarter of 2007. Twelve of these new rigs are expected to be owned through a 50/50 drilling rig joint venture. Our rig fleet and existing inventory of oil and natural gas prospects provide us with the opportunity to control and accelerate our drilling program.

Our estimated capital expenditures for 2005 were approximately $122 million, of which $75.8 million was spent as of September 30, 2005. We intend to increase our capital expenditures by approximately 89% in 2006 to $230 million. Our 2006 capital expenditures will be primarily related to growing our reserves production on our existing acreage. To this end, we plan to drill 115 gross wells in West Texas and 40 gross wells in the Piceance Basin, pursue tertiary oil recovery operations and purchase 10 of the additional drilling rigs described above and certain related oil field service equipment. In addition, we believe we are positioned to take advantage of attractive acquisition opportunities that may arise.

Areas of Operation

We operate primarily in two areas, West Texas and the Piceance Basin in northwestern Colorado. We also have non-operated interests in oil and natural gas properties in the Anadarko and Arkoma Basins in Oklahoma.

West Texas

We have drilled and developed natural gas reserves in the TransPecos region of West Texas since 1986. Historically, our primary focus has been in southern Pecos and central Terrell Counties. As of September 30, 2005 after giving effect to our December 2005 acquisitions, our estimated proved reserves in West Texas were 269 Bcfe. Our single largest focus has been the Pinon Field in Pecos County, which is located along the frontal edge of the Ouachita Overthrust, where 68% of our total proved reserves were located as of September 30, 2005 after giving effect to our December 2005 acquisitions. Our net production in West Texas was approximately 19.9 Mmcfe per day for the month of September 2005, a significant increase from our average daily production in 2001. Since we first acquired an interest in the Pinon Field in 1995, average daily production for the field has increased from 5.9 Mmcfe per day to 69.5 Mmcfe per day for the month of September 2005, or 1,078%. We do not include gross or net CO₂ production in the production or proved reserves reported above. As of September 30, 2005 after giving effect to our December 2005 acquisitions, we owned interests in 302 gross (179.1 net) producing wells and held oil and natural gas interests in 463,712 gross (166,722 net) acres in West Texas. We have currently identified more than 600 potential well locations on this acreage. We hold or have rights to substantial exploration acreage surrounding the Pinon Field in Pecos County. Furthermore, we have exploration acreage in the Val Verde Basin and Woodford and Barnett shale plays of the Delaware Basin.

We are currently operating 18 drilling rigs in West Texas, eight of which are drilling wells that we operate. By the end of 2006 we expect to have approximately 30 rigs operating in West Texas. In addition, we provide other oil field services integral to exploration and production programs in the area, including pulling units, underbalanced drilling systems, roustabout crews, dirt construction, trucking, rental tools and mud logging.

In connection with our exploration and production operations, we have interests in gathering, processing and treatment facilities. These include interests in three natural gas treatment plants, including the Pike’s Peak and Grey Ranch plants in Pecos and Terrell Counties, with combined gross treating capacities of 224 Mmcf per day. These plants separate CO₂ to make our produced natural gas marketable. We also operate or own an interest in approximately 238 miles of natural gas gathering pipelines and 22,000 horsepower of gas compression.

We engage in tertiary oil recovery operations through CO₂ flooding. We are the sole gatherer of CO₂ from four natural gas treatment plants in Pecos and Terrell Counties, our primary areas of operation. We own 231 miles of CO₂ transportation pipelines and lease or own 71,800 horsepower of CO₂ compression at these treatment plants. This CO₂ is used in our tertiary oil recovery operations and is sold to other companies involved in tertiary oil recovery. We also own a CO₂ recycling plant at our Wellman Unit in Terry County with a capacity of 30 Mmcf per day and 6,880 horsepower of gas compression. The Wellman plant separates CO₂ from the oil produced in our tertiary oil recovery operations. As of September 30, 2005 after giving effect to our December 2005 acquisitions, approximately 24% of our total proved reserves are associated with our tertiary oil recovery operations.

Piceance Basin

Located in northwestern Colorado, the Piceance Basin is a sedimentary basin in one of the country’s most prolific natural gas producing regions. In 1993, we entered the Piceance Basin with the purchase of leasehold interests on federal lands and have increased our acreage position substantially with current interests in 32,374 gross (15,679 net) acres as of September 30, 2005 after giving effect to our December 2005 acquisitions. During 2005, we began developing our acreage position in the Piceance Basin. Consequently,

only a small portion of our acreage is currently under development. We expect, however, to significantly increase our drilling activity in the basin in 2006.

As of September 30, 2005 after giving effect to our December 2005 acquisitions, our estimated net proved reserves in the Piceance Basin were 3.6 Bcfe, with net production of approximately 278 Mcfe per day for the month of September 2005. We currently have two of our drilling rigs operating in the basin, and expect to increase this number to five rigs by the end of 2006. We intend to drill the eastern portion of our acreage block using 20-acre spacing, which is the minimum allowed under current regulations. We are currently drilling wells in the western portion of our acreage for evaluation purposes. Under our current business plan, we expect to drill 40 gross (23.3 net) new wells in the Piceance Basin in 2006.

We also provide certain basic oil field services in the basin. Furthermore, we operate two natural gas processing plants, including the Sagebrush Plant, with a combined treating capacity of approximately 53 Mmcf per day, as well as 40 miles of pipeline gathering systems. These plants are interconnected with interstate and intrastate natural gas transmission systems. We intend to continue to expand our gathering systems in conjunction with the development of our acreage.

Oklahoma — Arkoma and Anadarko Basins

Our properties in Oklahoma are located in the Ouachita Overthrust portion of the Arkoma Basin, which has the same depositional environment as that of the Pinon Field in West Texas, and in the Anadarko Basin. As of September 30, 2005 after giving effect to our December 2005 acquisitions, we held interests in 192,504 gross (14,163 net) leasehold and option acres in a portion of the Arkoma Basin in eastern Oklahoma and 1,894 gross (1,024 net) leasehold and mineral acres in the Anadarko Basin of western Oklahoma.

Our Businesses

Prior to our December 2005 acquisitions, we conducted and reported our business in three related segments — exploration and production, drilling and oil field services and midstream gas services. As part of our December 2005 acquisitions, we acquired a controlling interest in PetroSource and will report its operations as our “CO₂ and Tertiary Oil Recovery” segment. Our business units are integrated across these business segments. Our oil field service and drilling business supports our exploration and development efforts and gives us greater operational flexibility and a favorable cost structure, which significantly enhances our exploration and development economics. Natural gas produced from our West Texas operations is transported and treated for the removal of CO₂ by our midstream business at the Pike’s Peak and Grey Ranch Plants. The CO₂ is captured by PetroSource, our tertiary oil recovery subsidiary, while our natural gas is sold to third-parties. PetroSource transports the CO₂ by pipeline to market for use by us and others in tertiary oil recovery operations. While most of PetroSource’s CO₂ is currently being sold to third-parties, a portion of our CO₂ will be redirected for use in our own CO₂ flood projects as our internal demand increases. In the Piceance Basin, the integration of our exploration and production business and our oil field services and midstream businesses provides us with flexibility and control over the timing and costs associated with the exploitation of our significant acreage position.

Exploration and Production

We aggressively explore for, develop and produce oil and natural gas reserves, with a focus on our proved reserves and extensive undeveloped acreage positions in West Texas and the Piceance Basin. We operate substantially all of our wells in West Texas and the Piceance Basin. We are also participating in drilling operations in the Arkoma and Anadarko Basins, currently as a non-operator. We employ our drilling rigs and other drilling services in the exploration and development of our operated wells, and to a lesser extent on our non-operated wells. This strategy reduces our exploration and development costs.

Drilling and Oil Field Services

We drill onshore for our own account in both West Texas and the Piceance Basin through our drilling and oil field services subsidiary, Lariat Services, Inc. (“Lariat Services”). In addition, we also drill wells for other oil and natural gas companies, primarily in the West Texas region. We believe that drilling with our own rigs allows us to control costs and maintain operating flexibility. In addition, in October 2005, we entered into a joint venture, Larclay, LLC (“Larclay”) with Clayton Williams Energy, Inc. (“CWEI”), pursuant to which we will jointly acquire 12 newly-constructed rigs to be used for drilling on CWEI’s prospects. We will have a 50% interest in Larclay.

We believe we are one of the largest privately held drilling contractors in the United States on a footage drilled basis. We believe our ownership of drilling rigs and related oil field services will continue to be a major catalyst of our growth. Except for maintenance and weather downtime, all of our rigs have been operating continuously since the acquisition of our first rig in 1997. Currently, ten of our rigs are working on properties operated by us. By the first quarter of 2007, we expect to increase the size of our drilling fleet to 42 rigs, including the 12 rigs that will be owned by Larclay.

Our current rig fleet is designed to drill in our specific areas of operation and have average horsepower of 1,000 and average depth capacity of 11,300 feet. The 22 rigs we expect to add in 2006 and the first quarter of 2007 have been ordered from Chinese manufacturers for an approximate aggregate purchase price of $126 million, which includes the cost of equipping the rigs in the U.S. We believe this is a lower cost when compared to newly-constructed U.S. manufactured rigs with similar capabilities. We anticipate that the arrival of these units will occur ahead of the bulk of the order backlogs of U.S. manufactured rigs. Our new rigs will have 1,000 to 2,000 horsepower, with an average depth capacity of 14,250 feet.

Our oil field services business conducts operations that complement our drilling services operation. These services include providing pulling units, mud logging, trucking, rental tools, location and road construction and roustabout services to ourselves and to third-parties. We also provide under-balanced drilling systems services for our own account. We continually seek opportunities to add services in the development of our integration model.

Midstream Gas Services

We provide gathering, compression, processing and treating services of natural gas in the TransPecos region of West Texas and the Piceance Basin, primarily through our wholly-owned subsidiary, ROC Gas Company (“ROC Gas”). In Pecos County, we operate and own 57.5% of the Pike’s Peak treatment plant, which has the capacity to treat 60 Mmcf per day of raw natural gas for the removal of CO₂ from natural gas produced in the Pinon Field and nearby areas. We also have a 50% interest in the partnership that leases and operates the Grey Ranch CO₂ treatment plant located in Pecos County, which has the capacity to treat 160 Mmcf per day of raw natural gas. Along with two other third-party plants in the Val Verde Basin, Pike’s Peak and Grey Ranch serve as the primary suppliers of CO₂ for our tertiary oil recovery operations. We also operate or own approximately 238 miles of West Texas natural gas gathering pipelines and over 22,000 horsepower of gas compression. In addition to servicing our exploration and production business, these assets also service other oil and natural gas companies.

Our Piceance Basin system consists of processing plants with 53 Mmcf per day of capacity and approximately 40 miles of pipeline gathering systems. We gather and transport our natural gas and third-party natural gas to market delivery points on the Questar and Rocky Mountain Natural Gas pipelines. An additional interconnect is planned for the Colorado Interstate Gas pipeline in early 2006. We also provide third-party natural gas marketing services.

CO₂ and Tertiary Oil Recovery Operations

Our CO₂ gathering and tertiary oil recovery operations are conducted through PetroSource, our majority-owned subsidiary. PetroSource is the sole gatherer of CO₂ from the four natural gas treatment plants located

in the Delaware and Val Verde Basins of West Texas. PetroSource owns 231 miles of CO₂ pipelines in West Texas with 71,800 horsepower of owned and leased gas compression.

West Texas is the most active tertiary oil recovery area in the United States, with 60 active floods, producing approximately 180 MBbls per day. CO₂ injection has proven to be effective in recovering oil that remains after traditional water flooding has been completed. In 2004 and 2005, we acquired two West Texas waterfloods, the Wellman and South Mallet Units, for the purpose of implementing tertiary oil recovery operations utilizing CO₂ injection. 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, large available CO₂ supply and our close proximity to potential CO₂ floods. We believe the Wellman and South Mallet Units will require a maximum of 45 Mmcf of CO₂ per day over the next five years. As of September 30, 2005, PetroSource had approximately 75 Mmcf per day of CO₂ in available supply. We expect the supply of CO₂ to increase as additional high CO₂ gas reserves are developed in the region, and we intend to seek additional opportunities to utilize our supply of CO₂. In 2005, we also acquired a related CO₂ transportation line to the Wellman Unit and CO₂ recycling plant.

We have assembled a management team highly skilled in CO₂ tertiary oil recovery operations, which includes engineers and geologists possessing over 53 combined years of experience in CO₂ flooding with other industry leaders. We believe our unique strategic position, existing infrastructure and industry expertise will enable us to generate substantial long-term cash flow from these operations. In addition, we believe, through our interest in PetroSource, we are one of the largest generators of marketable greenhouse gas emissions reduction credits under current environmental legislation.

Our Strategy

The principal elements of our strategy to maximize shareholder value are to:


	•	Grow Through Aggressive Drilling and Exploration on Existing Acreage. We expect to generate long-term reserve and production growth by aggressively developing our sizeable inventory of under-exploited properties in West Texas and developing our large acreage position in the core focus area of the Piceance Basin. We have an inventory of over 600 identified well locations in West Texas, and we plan to drill the eastern portion of our Piceance Basin acreage based on 20-acre spacing. In addition, we have identified over 50 exploration projects in West Texas.

	•	Utilize “Vertigration” to Reduce Costs, Enhance Returns and Maintain Operating Flexibility. We intend to continue to integrate our exploration and production operations with our drilling and oil field services and CO₂ flooding businesses. By controlling our fleet of drilling rigs, gathering and treating assets and supply of necessary CO₂, we are able to better control costs and maintain a high degree of operational flexibility. We also seek opportunities to partner with other energy firms in key projects to maximize the value of our drilling and midstream businesses, thus further reducing costs. We refer to this strategy as “vertigration.”

	•	Pursue Low-Risk, Low-Cost Oil Reserves through CO₂ Flooding. We intend to capitalize on our sizeable CO₂ assets and tertiary oil recovery expertise to enhance oil recovery in mature oil fields in West Texas in which we own or will acquire an interest. We have acquired the Wellman and South Mallet Units, without allocating significant value to the reserves that we expect to recover through CO₂ flooding operations.

	•	Build Rig Fleet and Pursue Opportunistic Acquisitions. In 2006 and the first quarter of 2007, we expect to add 22 newly built drilling rigs which have been ordered from Chinese manufacturers. Given the current scarcity of rigs, we plan to evaluate opportunities to utilize our rigs to earn interests in projects operated by third-parties. We also will continuously evaluate acquisitions and other expansion opportunities for complementary oil field services in our areas of operation.

Competitive Strengths

We have a number of strengths that we believe will help us successfully execute our strategies:


	•	Experienced Management Team Focused on Delivering Long-term Shareholder Value. Our nine executive officers have a combined 186 years of experience working in or servicing the oil and natural gas industry and have an average age of 45. We focus on long-term growth and value over multiple industry cycles. We believe this strategy, along with the significant ownership position of our management, will allow us to increase long-term shareholder value.

	•	Large Acreage Position with Drilling Inventory. We have a large asset base of over 722,590 gross (226,037 net) leasehold acres as of September 30, 2005 after giving effect to our December 2005 acquisitions. This large acreage position provides us with significant drilling opportunities on both proved and unproved locations. We believe this drilling inventory of over 600 identified well locations in West Texas and our planned drilling based on 20-acre spacing in the eastern portion of our Piceance Basin acreage will allow us to grow our reserves and production for the next several years. In addition, we have identified over 50 exploration projects in West Texas.

	•	Geographically Concentrated Operations. We focus over 90% of our operations in West Texas and the Piceance Basin in northwestern Colorado. This geographic concentration positions us to secure additional acreage and allows us to establish economies of scale in both drilling and production operations in order to achieve lower production costs and generate increased cash flows from our producing properties.

	•	Vertical Integration of Operations. Our vertical integration increases efficiency and provides us with greater control over our operations, a lower cost structure and the ability to secure additional acreage in our areas of operations.

	•	Large Modern Fleet of Drilling Rigs. We currently have 20 rigs, and we expect to add 22 more by the first quarter of 2007. By controlling a large drilling fleet, we can develop our existing reserves and explore for new reserves. This provides us with a competitive advantage, especially during periods when the supply of rigs is scarce.

	•	Conservatively Leveraged Capital Structure. Following the completion of our proposed initial public offering, we will have a conservative capital structure and the financial flexibility to aggressively accelerate our extensive drilling program and to pursue opportunistic acquisitions in our core operating areas.

Recent Developments


	*Proposed Initial Public Offering*

On January 12, 2006, we filed a registration statement on Form S-1 with the SEC related to a proposed initial public offering of our common stock. We intend to complete this offering prior to the effectiveness of this shelf registration statement. The number of shares to be offered and the price range for the offering have not been determined.


	*Gungoll Acquisition*

On December 22, 2005, we acquired certain interests in several oil and natural gas properties in West Texas from Carl E. Gungoll Exploration, LLC and certain other parties for an aggregate purchase price of $8.1 million, consisting of $5.5 million in cash and $2.6 million in common stock, based on a price of $15 per share.

Restricted Stock

On December 21, 2005, we granted restricted stock awards to certain of our officers and employees in an aggregate amount of approximately 1.6 million shares. The issuance of the restricted stock awards will result in our recognition of a non-cash compensation expense, after income tax, of approximately $15.4 million over the vesting periods, subject to reduction in the event of any forfeitures.

December 2005 Private Placement

We recently sold 12.7 million shares of our common stock in a private placement to initial purchasers who resold those shares to certain eligible investors. We received net proceeds from this sale of approximately $175.7 million after deducting the initial purchasers’ discount of approximately $13.4 million and offering expenses of approximately $2.0 million. In this prospectus, we refer to this private placement as our December 2005 private placement. Approximately $105.5 million of the proceeds of our December 2005 private placement were used to repay outstanding bank debt and finance our December 2005 acquisitions described below. The remainder of the proceeds are being used for general corporate purposes, including the acceleration of our drilling program in West Texas and the Piceance Basin.

Our December 2005 Acquisitions

Contemporaneously with the closing of our December 2005 private placement, we effected a number of acquisitions which enhanced our position in our businesses and operating areas. In this prospectus, we refer to these acquisitions as our December 2005 acquisitions. These transactions included:


	•	the acquisition of additional equity interests in PetroSource, our CO₂ and tertiary oil recovery subsidiary, to increase our ownership interest from 22.4% to 86.5%, resulting in the consolidation of PetroSource in our financial statements;

	•	the acquisition of an additional 50% equity interest in our compression services subsidiary, Larco, from an executive officer and director resulting in it becoming a 100% wholly-owned subsidiary;

	•	the acquisition from an executive officer and director of approximately 7,400 net acres of additional leasehold interests in West Texas in properties in which we previously held interests;

	•	the acquisition of approximately 2,503 net acres of additional leasehold interests in properties in the Piceance Basin in which we previously held interests; and

	•	the acquisition from a director of additional working interests in Missouri and Nevada leases in which we previously held interests.

The December 2005 acquisitions were financed with approximately $15.9 million in cash funded out of the net proceeds of our December 2005 private placement and the issuance of 3,508,335 shares of our common stock with an aggregate value of approximately $52.6 million. Of these amounts, $0.3 million in cash was paid and 2,984,398 shares of common stock with an aggregate value of approximately $44.8 million were issued, to our officers and directors or their direct family members. See “Related Party Transactions.” For more information on these acquisition transactions, see “Unaudited Pro Forma Consolidated Condensed Financial Statements.”

Stock Split

On December 19, 2005, we effected a 281.562 for 1 stock split of our common stock. All share and per share information in this prospectus gives effect to the stock split.

Risk Factors

Investing in our common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile oil and natural gas prices and other material factors. You should read

carefully the section entitled “Risk Factors” beginning on page 13 for an explanation of these risks before investing in our common stock.

Our Offices

Our company was founded in 1984 and is incorporated in Texas. Our principal executive offices are located at 701 S. Taylor Street, Suite 390, Amarillo, Texas 79101, and our telephone number at that address is (806) 376-7904.

The Offering


Common stock offered by the selling shareholders(1)		shares

Common stock outstanding		shares

Dividend policy		We do not anticipate that we will pay cash dividends in the foreseeable future. In addition, our revolving credit facility may restrict the payment of dividends to holders of our common stock.

Use of Proceeds		We will not receive any proceeds from the sale of the shares of common stock by the selling shareholders.

Proposed New York Stock Exchange Symbol		“REI”


(1)	See “Selling Shareholders” for information on the selling shareholders.

Summary Consolidated Historical and Pro Forma Financial Data

Set forth below is our summary consolidated historical and pro forma financial data for the periods indicated. The historical financial data for the periods ended December 31, 2002, 2003 and 2004 and the balance sheet data as of December 31, 2003 and 2004 have been derived from our audited financial statements. Our historical financial data as of and for the nine months ended September 30, 2005 are derived from our unaudited financial statements and, in our opinion, have been prepared on the same basis as the audited financial statements and include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information. The pro forma financial data are derived from our unaudited pro forma financial statements included in this prospectus which gives pro forma effect to the transactions described in “Unaudited Pro Forma Condensed Consolidated Financial Statements.” You should read the following summary financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical and pro forma financial statements and related notes thereto appearing elsewhere in this prospectus. Our financial statements for the year ended December 31, 2002, 2003 and 2004 and the unaudited interim condensed financial statements as of and for the nine months ended September 30, 2005 have been restated to reflect the 281.562 for 1 stock split which occurred on December 19, 2005.


															Pro Forma

												Nine Months					Nine Months
			Year Ended December 31,									Ended			Year Ended		Ended
												September 30,			December 31,		September 30,
			2002			2003(1)			2004(2)			2005			2004		2005

			(in thousands, except per share data)
Statement of Operations Data:
Revenues			$	58,684		$	151,730		$	173,314		$	181,285		$	181,765	$	194,694
Expenses:
	Exploration and production			8,791			11,677			18,172			14,323			18,172		15,254
	Gas purchases and cost of sales			32,833			99,632			106,045			114,028			111,799		122,401
	Salaries and wages			6,093			10,699			18,920			20,415			20,082		21,914
	General and administrative			1,812			1,704			2,198			2,019			3,249		3,007
	Depreciation, depletion and amortization			7,072			12,345			13,411			15,314			17,049		19,502

		Total expenses		56,601			136,057			158,746			166,099			170,351		182,078

Operating income				2,083			15,673			14,568			15,186			11,414		12,616
Other income (expense)				(1,285	)		(145	)		(1,920	)		(5,082	)		668		(1,694	)
Income tax expense				289			5,307			4,321			3,435			4,108		3,713

Income from continuing operations			$	509		$	10,221		$	8,327		$	6,669		$	7,974	$	7,209

Income (loss) from discontinued operations (net of taxes)				1,105			(85	)		451			229
Extraordinary gain (loss) and cumulative effect of change in accounting principle				—			(1,636	)		12,544			—

Net income			$	1,614		$	8,500		$	21,322		$	6,898

Earnings per share — basic and diluted:
Income from continuing operations			$	0.01		$	0.18		$	0.15		$	0.12		$	0.11	$	0.10

Basic and diluted net income per share			$	0.03		$	0.15		$	0.38		$	0.12

	Weighted average number of common shares outstanding — basic and diluted			56,312			56,312			56,312			56,312			71,427		71,427


															Pro Forma

												Nine Months					Nine Months
			Year Ended December 31,									Ended			Year Ended		Ended
												September 30,			December 31,		September 30,
			2002			2003(1)			2004(2)			2005			2004		2005

			(in thousands, except per share data)
Selected Cash Flow and Other Financial Data:
Income from continuing operations			$	509		$	10,221		$	8,327		$	6,669		$	7,974	$	7,209
	Interest expense, net			916			1,105			1,622			2,938			156		1,201
	Income tax expense			289			5,307			4,321			3,435			4,108		3,713
	Depreciation, depletion and amortization			7,072			12,345			13,411			15,314			17,049		19,502

EBITDA(3)			$	8,786		$	28,978		$	27,681		$	28,356		$	29,287	$	31,625

	Reconciliation to net cash provided by operating activities by continuing operations:
		Depreciation, depletion and amortization		(7,072	)		(12,345	)		(13,411	)		(15,314	)
		Non-cash items		2,503			14,975			17,047			28,644
		Change in current assets and liabilities		5,034			2,173			7,639			5,325
		Interest expense, net		(916	)		(1,105	)		(1,622	)		(2,938	)
		Income tax expense		(289	)		(5,307	)		(4,321	)		(3,435	)

Net cash provided by operating activities by continuing operations			$	8,046		$	27,369		$	33,013		$	40,638

Net cash used in investing activities for continuing operations			$	(5,629	)	$	(31,103	)	$	(53,963	)	$	(76,625	)

Net cash provided by (used in) financing activities for continuing operations			$	(2,431	)	$	3,089		$	34,700		$	30,008

Capital expenditures			$	19,938		$	41,495		$	52,481		$	75,768


(1)	We adopted the provisions of SFAS 143 “Accounting for Retirement Obligations,” resulting in a cumulative effect change in accounting principal of $1.6 million.

(2)	We recognized an extraordinary gain from the recognition of negative goodwill of $12.5 million related to our purchase of the Foreland Corporation in December 2004.

(3)	EBITDA means earnings (income from continuing operations) before interest, income taxes, depreciation, depletion and amortization. EBITDA is a non-GAAP financial measure. We believe that EBITDA is a widely accepted financial indicator and we use it to provide us with additional information about our ability to meet our future requirements for debt service, capital expenditures and working capital. In addition, the financial covenants under our revolving credit facility are calculated using EBITDA. EBITDA should not, however, be considered in isolation or as a substitute for net income, income from continuing operations, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles or as a measure of our profitability or liquidity. Our definition of EBITDA may not be comparable to similarly titled measures of other companies.


		At December 31,				At		Pro Forma at
						September 30,		September 30,
		2003		2004		2005		2005

		(in thousands)
Balance Sheet Data:
Cash and cash equivalents		$	176	$	12,973	$	5,868	$	94,768
Other current assets			30,842		38,543		59,847		64,513
Property, plant and equipment, net			60,841		99,188		160,673		261,467
Intangibles, net			—		214		50		412
Investments			4,592		5,281		5,413		2,833
Held for sale			20,882		22,504		—		—
Value of interest rate swaps			—		—		72		—
Other assets			963		2,684		312		519

	Total assets	$	118,296	$	181,387	$	232,235	$	424,512

Current liabilities			66,630		63,097		104,112		106,103
Long-term debt			4,807		56,318		72,103		33,133
Other long-term liabilities			17,298		10,907		6,230		8,709

	Total liabilities		88,735		130,322		182,445		147,945

Minority interest			1,710		1,894		11,062		9,568
Total shareholders’ equity			27,851		49,171		38,728		266,999

	Total liabilities and shareholders’ equity	$	118,296	$	181,387	$	232,235	$	424,512

Summary Operating and Reserve Data

The following estimates of net proved oil and natural gas reserves are based on reserve reports dated September 30, 2005, prepared in their entirety by our independent petroleum engineers. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business — Exploration and Production” in evaluating the material presented below.


								Nine Months
								Ended
		Year Ended December 31,						September 30,

		2002		2003		2004		2004		2005

Production Data:
	Natural Gas (Mmcf)		3,909		6,706		6,708		5,079		4,885
	Oil (MBbls)		45		38		37		25		31
	Combined Volumes (Mmcfe)		4,182		6,936		6,930		5,229		5,073
	Daily Combined Volumes (Mmcfe/d)		11.5		19.0		18.9		19.2		18.6
Average Prices:
	Natural Gas (per Mcf)	$	2.96	$	3.99	$	4.43	$	4.25	$	5.85
	Oil (per Bbl)	$	27.10	$	26.62	$	34.03	$	30.16	$	41.72
	Combined (Mcfe)	$	3.06	$	4.01	$	4.47	$	4.27	$	5.89


	At December 31,				At		Pro Forma at
					September 30,		September 30,
	2003		2004		2005(2)		2005(2)(3)

Estimated Proved Reserves(1):
Natural Gas (Bcf)(4)		121.3		144.5		195.3		203.6
Oil (MBbls)		649.8		682.0		697.8		11,457.0
Total (Bcfe)		125.2		148.5		199.5		272.4
PV-10 (in millions)(5)	$	232.7	$	293.5	$	746.9	$	943.9	(6)
Standardized Measure of Discounted Net Cash Flows (in millions)(7)	$	157.3	$	199.0		n/a		n/a


(1)	In accordance with SEC requirements, 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, 2003, December 31, 2004 and September 30, 2005, which were $5.39 per Mcf of natural gas and $29.25 per barrel of oil at December 31, 2003, $5.67 per Mcf of natural gas and $40.22 per barrel of oil at December 31, 2004 and $10.50 per Mcf of natural gas and $66.90 per barrel of oil at September 30, 2005.

(2)	Excludes reserves of Brooklaw Field and certain Oklahoma properties for which a September 30, 2005 reserve report was unavailable. Proved reserves for these properties as of December 31, 2004 were 2.0 Bcf with an associated Standardized Measure of Discounted Net Cash Flows of $1.5 million and an associated PV-10 of $2.2 million.

(3)	Gives pro forma effect to the proved reserves acquired as a result of the acquisition of additional interests in, and resulting consolidation of PetroSource, as a subsidiary of the Company and the other acquisitions described under “Unaudited Pro Forma Condensed Consolidated Financial Statements.”

(4)	Given the nature of our natural gas reserves, a significant amount of our production contains high CO₂ gas. These figures are net of CO₂.

(5)	PV-10 represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, and production, discounted at 10% per annum to reflect timing of future cash flows and using pricing assumptions. PV-10 differs from Standardized Measure of Discounted Net Cash Flows because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represent an estimate of fair market value of our oil and natural gas properties. PV-10 is used by the industry and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.

(6)	Includes the PV-10 associated with the reserves and the future net revenues of PetroSource, which were determined using the prices for natural gas and oil that PetroSource realized as of September 30, 2005, which were $6.76 per Mcf of natural gas and $59.44 per barrel of oil.

(7)	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, production, 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, which was $75.4 million and $94.5 million at December 31, 2003 and 2004, respectively.

RISK FACTORS

An investment in our common stock involves a high degree of risk. You should carefully consider the following risks and all of the other information contained in this prospectus before deciding to invest in our common stock. The risks described below are not the only ones facing our company. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect our company.

Risks Related to the Oil and Natural Gas Industry and Our Business


	*Oil and natural gas prices are volatile, and a decline in oil and natural gas prices can significantly affect our financial results and impede our growth.*

Our revenue, profitability and cash flow depend upon the prices and demand for oil and natural gas. The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our cash flow. In addition, demand for our oil field service operations is primarily determined by current and anticipated oil and natural gas prices and the related general production spending and level of drilling activities in our areas of operations. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:


	•	the domestic and foreign supply of oil and natural gas;

	•	the price of foreign imports;

	•	overall domestic and global 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 and transportation capacity;

	•	the difference in price we receive at our point of sale and the posted commodities exchange price;

	•	domestic and foreign governmental regulations; and

	•	the price and availability of alternative fuels.

Lower oil and natural gas prices may not only decrease our revenues on a per share basis, but also may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, successful efforts accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.


	Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this prospectus.

In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas 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. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:


	•	actual prices we receive for oil and natural gas;

	•	the amount and timing of actual production;

	•	supply of and demand for oil and natural gas; 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 oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.


	A significant portion of our acreage in the Piceance Basin is currently subject to litigation. In addition, we are party to certain other legal proceedings, the ultimate outcome of which cannot be predicted. Any adverse determination in any of these proceedings could have a material adverse effect on our reserves, financial condition and results of operations.

We have commenced a declaratory judgment proceeding against certain parties to determine the rights of the parties to oil and natural gas interests in our Piceance Basin acreage. If we experience an unfavorable judgment in this proceeding, the other parties involved could be entitled to up to a 25% working interest in approximately 8,000 net acres in the western portion of our Piceance Basin acreage and a 12¹/2% to 25% net profit or reversionary interest in all of our Piceance Basin acreage. Such a judgment would materially decrease our PV-10 values and our future cash flows and adversely affect our business.

In addition, we are party to various litigation matters arising out of the normal course of business, including other matters concerning the size of our ownership interest in certain of our acreage positions. The ultimate outcome of each of these matters cannot presently be determined, nor can the liability that may potentially result from each of these matters be reasonably estimated at this time for every case. The liability

we may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of the amounts currently accrued with respect to such matters. In addition, a negative outcome in several of these matters could reduce our current reserve amounts and acreage positions. As a result, these matters may potentially be material to our financial condition and results of operation. Please read “Business — Litigation” for a summary of currently material pending litigation matters.


	Malone Mitchell, 3rd, and his immediate family own a controlling interest in our company. Their interests may conflict with those of our other shareholders, and other shareholders’ voting power may be limited.

As of December 31, 2005, Malone Mitchell, 3rd, our Chief Executive Officer, and his immediate family owned approximately 70% of our outstanding common stock. Accordingly, Mr. Mitchell and his immediate family will have the ability to control the outcome of matters requiring a shareholder vote, including the election of directors, adoption of amendments to our articles of incorporation or bylaws or approval of transactions that result in a change of control. This concentrated ownership makes it less likely that any other shareholder or group of shareholders will be able to affect the way we are managed or the direction of our business. It may also delay or prevent a change in our management or voting control.

Conflicts of interest may arise between us and Mr. Mitchell or his family. For example, we lease substantial West Texas acreage from the family of Mr. Mitchell. The interests of the Mitchell family in this acreage are not necessarily aligned with ours and could be in conflict with our interests. It may be in the best interests of the Mitchell family to choose to drill more wells or to drill more rapidly on Mitchell family leases as opposed to leases in which the Mitchell family does not have an interest. Furthermore, current and anticipated future prospects are located on lands owned by Mr. Mitchell’s relatives in West Texas. In order to develop these prospects, we may enter into transactions related to the exploration, development and production of oil and natural gas with parties related to Mr. Mitchell and whose interests may conflict with ours. The resolution of such conflicts may not be in our best interest.


	*Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.*

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our reserve reports at September 30, 2005, show an aggregate decline rate after 2005 of approximately 10.3% per year in our total estimated proved reserves as of September 30, 2005 after giving effect to our December 2005 acquisitions. Because total estimated proved reserves include our proved undeveloped reserves at September 30, 2005, production will decline at this rate even if those proved undeveloped reserves are developed and the wells produce as expected. This rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.


	Our potential drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

As of September 30, 2005, only 374 of our potential well locations were attributed to proved undeveloped reserves. These potential drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas 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 oil or natural gas 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.


	*Prospects that we decide to drill may not yield natural gas or oil in commercially viable quantities.*

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 oil or natural gas. 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. However, 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 and testing whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to recover drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the reserve or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. For the nine months ended September 30, 2005, 13.3% of the development wells we drilled were dry holes and 54.5% of the exploration wells we drilled were 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.

One of our growth strategies is to capitalize on opportunistic acquisitions of oil and natural gas reserves. However, our reviews of acquired properties are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. In addition, a portion of the properties we acquire are intended for our tertiary oil recovery operations using CO₂ floods. Not all reservoirs respond to CO₂ flooding, and these properties may not respond as anticipated. Ordinarily, we will focus our review efforts on the higher value properties and will sample the remainder. However, 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 West Texas and the Piceance Basin may take longer and may require higher levels of capital expenditures than we currently anticipate.

Of the estimated proved reserves that we own or have under lease in West Texas and the Piceance Basin as of September 30, 2005 after giving effect to our December 2005 acquisitions, approximately 77% are proved undeveloped reserves. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. In addition, the development of 24% of these reserves will require the use of CO₂ flooding, the success of which is less predictable than traditional development techniques. 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.


	*Substantially all of our producing properties are located in West Texas, making us vulnerable to risks associated with operating in one major geographic area.*

As of September 30, 2005 after giving effect to our December 2005 acquisitions, approximately 99% of our proved reserves and approximately 98% of our production were located in West Texas. A substantial portion of our West Texas proved oil and natural gas reserves are concentrated in and adjacent to a single field, the Pinon Field. In addition, a substantial portion of our West Texas 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 West Texas may contain natural gas that is high in CO₂ content, which can negatively affect our economics.*

The reservoirs of many of our prospects in West Texas 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 averaged 10 to 14%. We do not know the amount of CO₂ we will encounter in any exploration well until it is drilled. As a result, sometimes we encounter CO₂ levels in our development 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 gas. Since the treatment expenses are incurred on an Mcf basis, we will incur a higher effective treating cost per Mbtu of gas sold for natural gas with a higher CO₂ content. As a result, high CO₂ gas wells must produce at much higher rates than sweet gas wells to be economic, especially in a low natural gas price environment.


	*Our contract drilling operations depend on the level of activity in the oil and natural gas exploration and production industry.*

Our contract drilling operations depend on the level of activity in oil and natural gas exploration and production in our operating markets. Both short-term and long-term trends in oil and natural gas prices affect the level of that activity. Because oil and natural gas prices are volatile, the level of exploration and production activity can also be volatile. Any decrease from current oil and natural gas prices would depress the level of exploration and production activity. This, in turn, would likely result in a decline in the demand for our drilling services to third-parties. Ten of our rigs are currently drilling wells that we operate. If our exploration and production operations decline, we could have difficulty finding third-party customers for these rigs.


	*A disruption in the manufacture or import of our new build rigs could delay our drilling schedule.*

We currently have 22 new build drilling rigs on order from Chinese manufacturers. Any event causing the disruption of manufacturing or imports from China, including financial, political and financial instability, strikes, health concerns regarding infectious diseases, adverse weather conditions or natural disasters or acts of war or terrorism in the United States or worldwide, may require us to modify our drilling schedule, delay the exploitation and development of our acreage and increase our costs of operation. Any such disruption could materially affect our production, financial condition and results of operations.


	*We may experience difficulty in staffing, including on our new drilling rigs.*

We are planning to increase our number of drilling rigs substantially. We are also increasing the level of our activity substantially. This will require us to add additional employees to staff our drilling rigs and add staff to other departments. We may experience difficulty in finding a sufficient number of experienced crews to work on our drilling rigs and experienced staff in other departments to complete the work required.


	A significant decrease in natural gas production in our areas of operation, due to the decline in production from existing wells, depressed commodity prices or otherwise, could 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. The effect of such a material decrease would be to reduce our revenues, operating income and cash flows. Fluctuations in energy prices can greatly affect production rates and investments by our exploration and production business and third-parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. We have no control over 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, therefore, 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. As a consequence of such declines, our revenues and cash flows could be materially adversely affected.


	Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

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. 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 successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.

We often gather 2-D and 3-D seismic data over large areas. Our interpretation of seismic data delineates for us those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, it would result in our having made substantial expenditures to acquire and analyze 2-D and 3-D data without having an opportunity to attempt to benefit from those expenditures.


	*Drilling for and producing oil and natural gas 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 oil and natural gas 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.

We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, 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, thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not covered in full or in part by insurance could have a material adverse impact on our business activities, financial condition and results of operations.


	*We depend on a limited number of key personnel who would be difficult to replace.*

We depend on the performance of our executive officers and other key employees, especially Malone Mitchell, 3rd, our Chief Executive Officer. The loss of any member of our senior management or other key employee could negatively impact our ability to execute our strategy. We do not maintain key person life insurance policies on any of our employees.


	*Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.*

Market conditions or a lack of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-parties. Our failure to obtain such services on acceptable terms could 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.


	*Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.*

Oil and natural gas operations in the Piceance Basin are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas, drilling and other oil and natural gas activities can only be conducted during the spring and summer months. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.


	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 oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. To date, we have financed capital expenditures primarily with proceeds from bank borrowings and cash generated by operations. We intend to finance our capital expenditures with cash flow from operations and our existing 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 oil and natural gas we are able to produce from existing wells;

	•	the prices at which oil and natural gas are sold; and

	•	our ability to acquire, locate and produce new reserves.

If our revenues decrease as a result of lower oil and natural gas 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. We may, from time to time, need to seek additional financing. Our revolving credit facility contains covenants restricting our ability to incur additional indebtedness without the consent of the lender. There can be no assurance that our lender will provide this consent or as to the availability or terms of any additional financing.

Even if additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves.


	Our revolving credit facility and other debt financing have restrictions and financial covenants, and we may have difficulty obtaining additional credit, which could adversely affect our operations.

We will depend on our revolving credit facility for a portion of future capital needs. The revolving credit facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We also are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt financing could result in a default under those facilities, which could cause all of our existing indebtedness to be immediately due and payable.

The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lender in its sole discretion on a semiannual basis, based upon projected revenues from the oil and natural gas properties securing our loan. The lender can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility, and any increase in the borrowing base requires its consent. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other oil and natural gas 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.


	*Our derivative activities could result in financial losses or could reduce our income.*

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, and may in the future, enter into derivative arrangements for a portion of our oil and natural gas production, including collars and price-fix 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 earnings. For example, we incurred a charge of $8.6 million to our earnings during the nine months ended September 30, 2005 as a result of the change in the fair value of our derivative instruments, due to rising commodity prices. Derivative arrangements 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 actual prices received.

In addition, these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements.


	*Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.*

The oil and natural gas industry is intensely competitive, and we compete with companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas properties.


	*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 oil and natural gas 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 local 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, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on us. For instance, the United States Minerals Management Service, or MMS, may suspend or terminate our operations on federal leases for failure to pay royalties or comply with safety and environmental regulations.


	*Our operations expose us to potentially substantial costs and liabilities with respect to environmental, health and safety matters.*

We may incur substantial costs and liabilities as a result of environmental, health and safety requirements applicable to our oil and natural gas exploration, production, transportation, treatment, and other activities. These costs and liabilities could arise under a wide range of environmental and safety laws, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with environmental 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. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.

Strict, joint and several liability to remediate contamination may be imposed under certain environmental laws, which could cause us to become liable for, among other things, the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New 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, we cannot assure you that the costs to comply with environmental, health or safety laws or regulations or the liabilities incurred in connection with them will not significantly and adversely affect our business, financial condition or results of operations.


	*The inability of one or more of our customers to meet their obligations may adversely affect our financial results.*

Substantially all of our accounts receivable for oil and natural gas sales, drilling and oil field services and midstream gas services result from billings to third-parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.

Risks Related Our Common Stock


	*A significant portion of our outstanding shares of common stock may be sold in the public market in the near future, which could lower the market price of our common stock.*

As of February 10, 2006, we had 73,154,130 shares of common stock issued and outstanding. Of these shares, shares (approximately %) are freely tradable, including the shares being registered pursuant to this registration statement. In connection with our proposed initial public offering, we and our executive officers, directors and certain of our existing shareholders (including the selling shareholders) intend to enter into lock-up agreements with the underwriters under which such holders of restricted shares will agree that, other than in this offering and subject to certain exceptions, they will not, directly or indirectly, offer, sell, contract to sell, pledge or otherwise dispose of or hedge any common stock or securities convertible into or exchangeable for shares of common stock, or publicly announce the intention to do any of the foregoing, without the prior written consent of the underwriters for a period of 180 days from the date of the proposed initial public offering. Upon the expiration of these lock-up agreements, a total of additional shares, which are “restricted securities” within the meaning of Rule 144 under the Securities Act, will be eligible for sale subject to volume limitations and other restrictions contained in Rule 144.

In addition, we may file one or more registration statements with the SEC on Form S-8 providing for the registration of up to 7,074,252 shares of our common stock issued or reserved for issuance under our stock option plans. Subject to the exercise of unexercised options or the expiration or waiver of vesting conditions for restricted stock and the expiration of lock-ups we and certain of our shareholders have entered into, shares

registered under these registration statements on Form S-8 will be available for resale immediately in the public market without restriction.

Sales of substantial amounts of our common stock, or the perception that such sales will occur, may have a material adverse effect on our stock price.

There has been no active trading market for our common stock, and an active trading market may not develop.

There is currently no public market for our common stock. We intend to apply to list our common stock on the New York Stock Exchange in connection with our proposed initial public offering prior to the effectiveness of this registration statement. We do not know if an active trading market will develop for our common stock or how the common stock will trade in the future, which may make it more difficult for you to sell your shares.


	*The market price for our shares of common stock may be highly volatile and could be subject to wide fluctuations.*

The market price for shares of our common stock may be highly volatile and could be subject to wide fluctuations, even if an active trading market develops. Some of the factors that could negatively affect our share price include:


	•	actual or anticipated variations in our reserve estimates and quarterly operating results;

	•	liquidity and the registration of our common stock for public resale;

	•	sales of our common stock by our shareholders;

	•	changes in oil and natural gas prices;

	•	changes in our cash flows from operations or earnings estimates;

	•	publication of research reports about us or the exploration and production industry generally;

	•	increases in market interest rates which may increase our cost of capital;

	•	changes in applicable laws or regulations, court rulings and enforcement and legal actions;

	•	changes in market valuations of similar companies;

	•	adverse market reaction to any increased indebtedness we incur in the future;

	•	additions or departures of key management personnel;

	•	actions by our shareholders;

	•	speculation in the press or investment community regarding our business;

	•	large volume of sellers of our common stock pursuant to our resale registration statement with a relatively small volume of purchasers;

	•	general market and economic conditions; and

	•	domestic and international economic, legal and regulatory factors unrelated to our performance.


	*We do not anticipate paying any dividends on our common stock in the foreseeable future.*

We do not expect to declare or pay any cash or other dividends in the foreseeable future on our common stock, as we intend to use cash flow generated by operations to expand our business. Our revolving credit facility restricts our ability to pay cash dividends on our common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that restrict our ability to declare or pay cash dividends on our common stock.


	*We do not anticipate paying any dividends on our common stock in the foreseeable future.*


	*We will incur increased costs as a result of being a public company.*

As a privately held company, we have not been responsible for the corporate governance and financial reporting practices and policies required of a publicly traded company. Following the earlier of the completion of our proposed initial public offering or the effectiveness of this registration statement, we will be a public company and will incur significant legal, accounting and other expenses that we did not incur in the past. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules implemented by the SEC and the New York Stock Exchange, requires changes in corporate governance practices of public companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly.


	*You may experience dilution of your ownership interests due to the future issuance of additional shares of our common stock.*

We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present shareholders and purchasers of common stock offered hereby. We are authorized to issue 400,000,000 shares of common stock and 50,000,000 shares of preferred stock with preferences and rights as determined by our Board of Directors. As of February 10, 2006, we had 73,154,130 shares of common stock outstanding. Pursuant to our stock incentive plan, we will also reserve 5,522,085 shares of our common stock for future issuance as restricted stock, stock options or other equity-based grants to employees and directors. We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for common stock in connection with the hiring of personnel, future acquisitions, future private placements of our securities for capital raising purposes or for other business purposes. The potential issuance of additional shares of common stock may create downward pressure on the trading price of our common stock.


	Our articles of incorporation and bylaws and the Texas Business Corporation Act contain provisions that could discourage an acquisition or change of control of our company, which could adversely affect the price of our common stock.

Our articles of incorporation authorize our board of directors to issue preferred stock without shareholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third-party to acquire control of us. In addition, provisions of the articles of incorporation and bylaws, such as no cumulative voting rights, limitations on shareholder proposals at meetings of shareholders and restrictions on the ability of our shareholders to call special meetings, could also make it more difficult for a third-party to acquire control of us. Our bylaws provide that our board of directors is divided into three classes, each elected for staggered three-year terms. Thus, control of the board of directors cannot be changed in one year; rather, at least two annual meetings must be held before a majority of the members of the board of directors could be changed. In addition, the Texas Business Corporation Act imposes restrictions on mergers and other business combinations between us and any holder of 20% or more of our outstanding common stock.

These provisions of Texas law and our articles of incorporation and bylaws may delay, defer or prevent a tender offer or takeover attempt that a shareholder might consider in his or her best interest, including attempts that might result in a premium over the market price for the common stock.

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 oil and natural gas prices;

	•	discovery, estimation, development and replacement of oil and natural gas 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 oil and natural gas;

	•	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 oil and natural gas;

	•	competition in the oil and natural gas industry;

	•	governmental regulation and taxation of the oil and natural gas industry; and

	•	developments in oil-producing and natural gas-producing countries.

USE OF PROCEEDS

The selling shareholders will receive all of the proceeds from any sales of our common stock pursuant to this registration statement, and we will not receive any such proceeds. See “Selling Shareholders.”

DIVIDEND POLICY

We paid a cash dividend on our common stock in the amount of $0.02 per share on the 56,312,400 shares then outstanding in December of 2003. We do not anticipate declaring or paying any cash dividends in the foreseeable future. We currently intend to retain all available funds and any future earnings for use in the operation and expansion of our business, including exploration, development and acquisition activities. In addition, our revolving credit facility may restrict the payment of dividends to holders of common stock. Accordingly, if our dividend policy were to change in the future, our ability to pay dividends would be subject to this restriction and our then existing conditions, including our results of operations, financial condition, contractual obligations, capital requirements, business prospects and other factors deemed relevant by our board of directors.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following unaudited pro forma condensed consolidated financial statements give effect to our December 2005 private placement of 12.7 million shares of our common stock and the application of net proceeds of approximately $175.7 million and the following transactions, which occurred on December 21, 2005 and are referred to in this prospectus as our December 2005 acquisitions:


	•	Our acquisition of additional equity interests in PetroSource to increase our ownership percentage from 22.4% to 86.5% together with $5.9 million principal of subordinated notes of PetroSource, including $371,000 in accrued interest, for an aggregate of $30.1 million. The total includes cash of $15.8 million and $14.3 million of our common stock valued at $15 per share.

	•	Our acquisition of an additional equity interest in Sagebrush Pipeline, LLC to increase our ownership percentage in Sagebrush from 50.1% to 69.8% in exchange for common stock totaling $3.1 million.

	•	Our acquisition from an executive officer and director of the remaining 50% equity interest in Larco in exchange for common stock totaling $7.5 million.

	•	Our acquisition from an executive officer and director of additional working interests in West Texas leases in which we already held interests in exchange for common stock totaling $10.0 million.

	•	Our acquisition of additional working interests in a portion of the leases in the Piceance Basin in which we already held interests in exchange for common stock and cash totaling $17.5 million.

	•	Our acquisition from a director of additional working interests in Missouri and Nevada leases in which we already owned interests for common stock totaling $268,000.

	•	Our repayment of $71.0 million of debt from the net proceeds of our December 2005 private placement.

On September 30, 2005, Mr. Mitchell and his family exchanged 2.5% of our then outstanding common stock for our 100% interest in Longfellow Ranch Partners, LP, which exchange is reflected on our historical September 30, 2005 balance sheet. Longfellow Ranch Partners owns surface and mineral or royalty interests under a significant amount of our exploration and development lands in West Texas, including the Longfellow Ranch. As part of the exchange, we leased back the undeveloped mineral rights at the same royalty rates we had historically incurred in the area and the developed minerals were assigned to us subject to existing lease royalty burdens. No pro forma adjustments to the pro forma statements of operations are necessary to reflect this transaction since the revenues and expenses associated with this business are reflected as discontinued operations in the historical condensed consolidated financial statements and the lease we entered into relates to undeveloped mineral rights.

The pro forma financial statements do not give effect to our proposed initial public offering or the application of the net proceeds as set forth under “Use of Proceeds.”

In addition, the pro forma financial statements do not reflect the effects of the grant of restricted stock awards of approximately 1.6 million shares on December 21, 2005, which awards will vest after one, four and seven years. The issuance of the restricted stock will result in our recognition of a non-cash compensation expense, after income tax.

The unaudited pro forma condensed statements of consolidated operations for the nine months ended September 30, 2005 and 2004 and for the year ended December 31, 2004 assume the closing of our December 2005 private placement and our December 2005 acquisitions occurred on January 1, 2004. The unaudited pro forma condensed consolidated balance sheet shows the financial effects of the closing of the offering and the pro forma transactions described above as if they occurred on September 30, 2005.

The pro forma adjustments reflect the consolidation of PetroSource into our financial statements as a result of the acquisition of a controlling interest in PetroSource. The acquisitions of additional interests in Larco and Sagebrush resulted in adjustments to minority interests in the pro forma financial statements since Larco and Sagebrush have historically been consolidated in our financial statements. The acquisition of the

additional working interests for all the properties acquired does not result in any pro forma adjustments to the statement of operations because there have been no material historical operations on those properties. Pro forma adjustments relating to the proposed offering include the reduction in debt on the balance sheet using cash proceeds from the offering and the write-off of associated deferred financing costs of $210,000 and a gain of $72,000 related to the termination of an interest rate swap agreement. The write-off of deferred financing costs and the gain on the termination of the interest rate swap agreement are reflected in the pro forma condensed consolidated balance sheet but not in the pro forma condensed consolidated statement of operations since they are non-recurring expenses directly related to the offering. Interest expense related to debt that was repaid or acquired by us was correspondingly reduced in the pro forma statements of operations.

The unaudited pro forma condensed consolidated financial statements and related pro forma information are based on assumptions that we believe are reasonable under the circumstances and are intended for informational purposes only. They are not necessarily indicative of the financial results that would have occurred if the transactions described herein had taken place on the dates indicated, nor are they indicative of the future consolidated results of the combined company.

Our unaudited pro forma condensed consolidated financial statements should be read in conjunction with the notes accompanying our unaudited pro forma condensed consolidated financial statements and with our historical consolidated financial statements and related notes thereto and the historical consolidated financial statements and related notes thereto of PetroSource included in this prospectus starting on page F-1.

Riata Energy, Inc.

Unaudited Pro Forma Condensed Consolidated

Statements of Operations

For the Nine Months Ended September 30, 2005

(in thousands except per share amounts)


			Riata			PetroSource			Pro Forma			Riata
			Historical			Historical			Adjustments			Pro Forma

REVENUES			$	181,285		$	13,409		$	—		$	194,694
EXPENSES
	Exploration and production			14,323			931			—			15,254
	Gas purchases and cost of sales			114,028			8,373			—			122,401
	Salaries and wages			20,415			1,499			—			21,914
	General and administrative costs			2,019			988			—			3,007
	Depreciation, depletion and amortization			15,314			2,760			1,428	(a)		19,502

		Total expenses		166,099			14,551			1,428			182,078

INCOME (LOSS) FROM OPERATIONS				15,186			(1,142	)		(1,428	)		12,616

OTHER INCOME (EXPENSE)
	Interest expense, net			(2,938	)		(1,530	)		3,267	(b)		(1,201	)
	Minority interest			(968	)		—			1,084	(c)		116
	Income (loss) from equity investment			(1,176	)		—			567	(d)		(609	)

		Total		(5,082	)		(1,530	)		4,918			(1,694	)

INCOME (LOSS) BEFORE INCOME TAX EXPENSE				10,104			(2,672	)		3,490			10,922
	Income tax expense			(3,435	)		—			(278	)(e)		(3,713	)

INCOME (LOSS) FROM CONTINUING OPERATIONS			$	6,669		$	(2,672	)	$	3,212		$	7,209

INCOME PER SHARE
	Basic and diluted		$	0.12								$	.10	(j)

	Weighted average shares			56,312									71,427	(j)

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

Riata Energy, Inc.

Unaudited Pro Forma Condensed Consolidated

Statements of Operations

For the Nine Months Ended September 30, 2004

(in thousands except per share amounts)


			Riata			PetroSource			Pro Forma			Riata
			Historical			Historical			Adjustments			Pro Forma

REVENUES			$	126,498		$	4,729		$	—		$	131,227
EXPENSES
	Exploration and production			12,975			—			—			12,975
	Gas purchases and cost of sales			75,628			3,528			—			79,156
	Salaries and wages			14,608			845			—			15,453
	General and administrative costs			1,426			624			—			2,050
	Depreciation, depletion and amortization			9,380			985			1,428	(a)		11,793

		Total expenses		114,017			5,982			1,428			121,427

INCOME (LOSS) FROM OPERATIONS				12,481			(1,253	)		(1,428	)		9,800

OTHER INCOME (EXPENSE)
	Interest expense, net			(1,145	)		(1,066	)		2,094	(b)		(117	)
	Minority interest			(135	)		—			375	(c)		240
	Income (loss) from equity investment			(120	)		243			293	(d)		416

		Total		(1,400	)		(823	)		2,762			539

INCOME (LOSS) BEFORE INCOME TAX EXPENSE				11,081			(2,076	)		1,334			10,339
Income tax benefit (expense)				(3,767	)		(45	)		297	(e)		(3,515	)

INCOME (LOSS) FROM CONTINUING OPERATIONS			$	7,314		$	(2,121	)	$	1,631		$	6,824

INCOME PER SHARE
	Basic and diluted		$	0.13								$	.10	(j)

	Weighted average shares			56,312									71,427

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

Riata Energy, Inc.

Unaudited Pro Forma Condensed Consolidated

Statements of Operations

For the Year Ended December 31, 2004

(in thousands except per share amounts)


			Riata			PetroSource			Pro Forma			Riata
			Historical			Historical			Adjustments			Pro Forma

REVENUES			$	173,314		$	8,451		$	—		$	181,765
EXPENSES
	Exploration and production			18,172			—			—			18,172
	Gas purchases and costs of sales			106,045			5,754			—			111,799
	Salaries and wages			18,920			1,162			—			20,082
	General and administrative costs			2,198			1,051			—			3,249
	Depreciation, depletion and amortization			13,411			1,734			1,904	(a)		17,049

		Total expenses		158,746			9,701			1,904			170,351

INCOME (LOSS) FROM OPERATIONS				14,568			(1,250	)		(1,904	)		11,414

OTHER INCOME (EXPENSE)
	Interest expense, net			(1,622	)		(1,426	)		2,892	(b)		(156	)
	Minority interest			(262	)		—			470	(c)		208
	Income (loss) from equity investment			(36	)		243			409	(d)		616

		Total		(1,920	)		(1,183	)		3,771			668

INCOME (LOSS) BEFORE INCOME TAX EXPENSE				12,648			(2,433	)		1,867			12,082
	Income tax benefit (expense)			(4,321	)		(45	)		258	(e)		(4,108	)

INCOME (LOSS) FROM CONTINUING OPERATIONS			$	8,327		$	(2,478	)	$	2,125		$	7,974

INCOME PER SHARE
	Basic and diluted		$	0.15								$	.11	(j)

	Weighted average shares			56,312									71,427

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

Riata Energy, Inc.

Unaudited Pro Forma Condensed Consolidated Balance Sheet

September 30, 2005


									Purchase and
				Riata			PetroSource		Non-offering			Offering			Riata
				Historical			Historical		Adjustments			Adjustments(f)			Pro Forma

ASSETS
Current assets
	Cash and cash equivalents			$	5,868		$	66	$	—		$	159,820	(f)	$	94,768
													(70,986	)(g)
	Accounts and notes receivable, net
		Trade			52,086			4,543		—			—			56,629
		Related parties			1,673			—		—			—			1,673
	Inventories				2,653			—		—			—			2,653
	Deferred income taxes				563			—		—			—			563
	Other current assets				2,872			123		—			—			2,995

		Total current assets			65,715			4,732		—			88,834			159,281
Property, plant and equipment, net					160,673			48,833		51,961	(h)		—			261,467
Goodwill and Intangibles, net					50			—		362	(h)		—			412
Investments					5,413			—		(2,580	)(h)		—			2,833
Other assets					384			417		(210	)(h)		(72	)(g)		519

			Total assets	$	232,235		$	53,982	$	49,533		$	88,762		$	424,512


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
	Current maturities of long-term debt			$	9,226		$	9,759	$	—		$	(9,995	)(g)	$	8,990
	Amount payable to sellers				—			—		15,898	(h)		(15,898	)(f)		—
	Accounts payable
		Trade			53,145			801		—			—			53,946
		Related parties			47			—		—			—			47
	Accrued expenses				32,185			1,797		(371	)(i)		—			33,611
	Derivative contracts				9,509			—		—			—			9,509

			Total current liabilities		104,112			12,357		15,527			(25,893	)		106,103
Long-term debt					72,103			27,678		(5,657	)(i)		(60,991	)(g)		33,133
Asset retirement obligation					4,740			2,429		50	(h)		—			7,219
Deferred income taxes					1,490			—		—			—			1,490

		Total liabilities			182,445			42,464		9,920			(86,884	)		147,945

Commitments and contingencies
Minority interest					11,062			—		(1,494	)(h)		—			9,568
Shareholders’ equity
	Common stock				196			—		(138	)(h)		13	(f)		71
	Additional paid-in capital				22			—		52,763	(h)		175,705	(f)		228,490
	Treasury stock, at cost				(17,335	)		—		—			—			(17,335	)
	Retained earnings				55,845			11,518		(11,518	)(i)		(72	)(g)		55,773

			Total shareholders’ equity		38,728			11,518		41,107			175,646			266,999

			Total liabilities and shareholders’ equity	$	232,235		$	53,982	$	49,533		$	88,762		$	424,512

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

Riata Energy, Inc.

Notes to Unaudited Pro Forma Condensed

Consolidated Financial Statements

These unaudited pro forma condensed consolidated financial statements and underlying pro forma adjustments are based upon information currently available and certain estimates and assumptions made by management of Riata; therefore, actual results could materially differ from the pro forma information. However, Riata believes the assumptions provide a reasonable basis for presenting the significant effects of the transactions noted herein. Riata believes the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma information.

These unaudited pro forma condensed consolidated financial statements reflect the issuance of 12.7 million shares at a price of $15 per share in our December 2005 private placement resulting in pro forma net proceeds after expenses and commissions of $175.7 million.

The lettered pro forma adjustments made to our unaudited condensed consolidated historical financial statements are described as follows:


	(a) Reflects the incremental increase in depreciation, depletion and amortization resulting from the pro forma addition of assets acquired in the acquisition transactions. The estimated useful lives related to these assets range from seven to fifteen years.

	(b) Reflects the reduction of pro forma interest expense resulting from the pro forma repayment and elimination of $76.6 million indebtedness with net proceeds of the offering.

	(c) Reflects the net pro forma adjustments to minority interest, including (i) recording a minority interest of $335,000 for the year ended December 31, 2004 and $286,000 and $361,000 for the nine month periods ended September 30, 2004 and 2005, respectively, resulting from the consolidation of PetroSource in our financial statements, and (ii) eliminating a minority interest of $135,000 for the year ended December 31, 2004 and $89,000 million and $723,000 for the nine month periods ended September 30, 2004 and 2005, respectively, resulting from the acquisition of the remaining interests in Larco.

	(d) Reflects the pro forma elimination of loss from equity investment in PetroSource upon the acquisition of controlling interests in PetroSource resulting in its consolidation.

	(e) Reflects pro forma adjustment to income tax expense to reflect total combined pro forma income taxes expenses assuming a 34% statutory rate.

	(f) Reflects the issuance of 12.7 million shares in our December 2005 private placement, raising pro forma net proceeds of $175.7 million, after deducting a 7% discount fee and approximately $2 million in expenses, and the application of net proceeds to pay amounts owed sellers in the acquisition transactions of 15.9 and, together with available cash, to repay bank debt of $71.0 million. Remaining pro forma net proceeds from our December 2005 private placement are added to cash and cash equivalents and are available for the other uses.

	(g) Reflects the pro forma use of net proceeds to pay down bank debt as described in (f) above and elimination of a gain of $72,000 related to the termination of an interest rate swap.

Riata Energy, Inc.

Notes to Unaudited Pro Forma Condensed

Consolidated Financial Statements — (Continued)

(h) Reflects the pro forma purchase adjustments for the acquisition transactions described in the introduction to these unaudited pro forma condensed consolidated financial statements. The acquisition transactions are being effected by the issuance of 3,508,335 shares of common stock with an aggregate value of $52.6 million, and additional cash payment obligations to sellers of $15.9 million. The pro forma purchase adjustments (stated in thousands) are set forth in detail below for each of the acquisition transactions:


											Consideration Paid

		Addition to		Addition to							Change
		Property,		Asset				Elimination			in			Common		Common
		Plant &		Retirement		Addition to		of			Minority			Stock No.		Stock at
Acquisition Transaction		Equipment		Obligation		Goodwill		Investments			Interest			of Shares		$15/share		Cash

		(dollars and shares in thousands)
PetroSource additional interests		$	18,671	$	—	$	—	$	(2,580	)	$	3,253			956	$	14,335	$	15,789
Piceance Basin additional lease interests			17,565		50		—		—			—			1,164		17,456		109
West Texas additional lease interests			10,000		—		—		—			—			667		10,000		—
Larco remaining interest			5,457		—		—		—			(2,043	)		500		7,500		—
Various additional lease interests			268		—		—		—			—			17		268		—
Sagebrush additional interests			—		—		362		—			(2,704	)		204		3,067		—

	Totals	$	51,961	$	50	$	362	$	(2,580	)	$	(1,494	)		3,508	$	52,626	$	15,898


	The value of common stock consideration paid in the acquisition transactions is allocated between common stock and additional paid in capital at $0.001 par value.

	(i) Accounts for the elimination of intercompany accounts in the consolidation of PetroSource.

	(j) Reflects adjustments to the shares issued in the acquisition transactions and the offering:


Shares at September 30, 2005			55,179,165
Shares issued in the acquisition transactions			3,508,335
Shares issued in the offering			12,739,630

			71,427,130

Riata Energy, Inc.

Notes to Unaudited Pro Forma Condensed

Consolidated Financial Statements — (Continued)

Summary Pro Forma Reserve Data

The following table sets forth summary pro forma information with respect to the combined estimated net proved oil and natural gas reserves as of December 31, 2004.


					December 2005
		Riata			Acquisitions			Pro Forma

Estimated Quantities of Oil and Natural Gas Reserves at December 31, 2004
Proved Reserves
	Oil (MBbl)		682			2,597			3,279
	Gas (Mmcf)		144,452			6,743			151,195
	Mmcfe		148,544			22,322			170,866
Proved Developed Reserves
	Oil (MBbl)		231			376			607
	Gas (Mmcf)		50,981			143			51,124
	Mmcfe		52,364			2,402			54,765
Standardized Measure of Discounted Future Net Cash Flows December 31, 2004 (in thousands)
Future cash inflows			843,647			132,885			976,532
Future development costs			(77,588	)		(11,911	)		(89,499	)
Future production expense			(227,257	)		(63,272	)		(290,529	)
Future income tax expense			(183,193	)		(19,619	)		(202,812	)

Future net cash flows			355,609			38,083			393,692
Discounted at 10% per year			(156,647	)		(24,195	)		(180,842	)

Standardized measure of discounted future net cash flows			198,962			13,888			212,850

SELECTED HISTORICAL FINANCIAL DATA

Set forth below is our selected consolidated historical and pro forma financial data for the periods indicated. The historical financial data for the periods ended December 31, 2002, 2003 and 2004 and the balance sheet data as of December 31, 2002, 2003 and 2004 have been derived from our audited financial statements. Our historical financial data as of and for the nine months ended September 30, 2004 and 2005 are derived from our unaudited financial statements and, in our opinion, have been prepared on the same basis as the audited financial statements and include all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of this information. The historical financial data for the periods ended December 31, 2000 and 2001 have been derived from unaudited financial statements. You should read the following summary financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical financial statements and related notes thereto appearing elsewhere in this prospectus. Our financial statements for the year ended December 31, 2000, 2001, 2002, 2003 and 2004 and the unaudited interim condensed financial statements as of and for the nine months ended September 30, 2005 reflect the 281.562 for 1 stock split effective December 19, 2005.


																		Nine Months
			Year Ended December 31,															Ended
																		September 30,
			2000			2001			2002			2003(1)			2004(2)			2005

			(in thousands, except per share data)
Statement of Operations Data:
Revenues			$	18,559		$	37,492		$	58,684		$	151,730		$	173,314		$	181,285
Expenses:
	Exploration and production			5,917			8,693			8,791			11,677			18,172			14,323
	Gas purchases and cost of sales			644			13,171			32,833			99,632			106,045			114,028
	Salaries and wages			3,459			5,989			6,093			10,699			18,920			20,415
	General and administrative			1,299			1,729			1,812			1,704			2,198			2,019
	Depreciation, depletion and amortization			2,607			5,265			7,072			12,345			13,411			15,314

		Total expenses		13,926			34,847			56,601			136,057			158,746			166,099

Operating income				4,633			2,645			2,083			15,673			14,568			15,186
Other expense				(824	)		(1,334	)		(1,285	)		(145	)		(1,920	)		(5,082	)
Income tax expense				1,295			446			289			5,307			4,321			3,435

Income from continuing operations			$	2,514		$	865		$	509		$	10,221		$	8,327		$	6,669

Income (loss) from discontinued operations (net of taxes)				167			75			1,105			(85	)		451			229
Extraordinary gain (loss) and cumulative effect of change in accounting principle				—			—			—			(1,636	)		12,544			—

Net income			$	2,681		$	940		$	1,614		$	8,500		$	21,322		$	6,898

Earnings per share — basic and diluted:
Income from continuing operations			$	0.04		$	0.02		$	0.01		$	0.18		$	0.15		$	0.12
Basic and diluted net income per share			$	0.05		$	0.02		$	0.03		$	0.15		$	0.38		$	0.12

	Weighted average number of common shares outstanding — basic and diluted			56,312			56,312			56,312			56,312			56,312			56,312


																		Nine Months
			Year Ended December 31,															Ended
																		September 30,
			2000			2001			2002			2003(1)			2004(2)			2005

			(in thousands, except per share data)
Selected Cash Flow and Other Financial Data:
Income from continuing operations			$	2,681		$	865		$	509		$	10,221		$	8,327		$	6,669
	Interest expense, net			1,211			1,384			916			1,105			1,622			2,938
	Income tax expense			1,295			264			289			5,307			4,321			3,435
	Depreciation, depletion and amortization			2,607			5,265			7,072			12,345			13,411			15,314

EBITDA(3)			$	7,794		$	7,778		$	8,786		$	28,978		$	27,681		$	28,356
	Reconciliation to net cash provided by operating activities by continuing operations:
		Depreciation, depletion and amortization		(2,607	)		(5,265	)		(7,072	)		(12,345	)		(13,411	)		(15,314	)
		Non-cash items		2,301			2,793			2,503			14,975			17,047			28,644
		Change in current assets and liabilities		7,585			4,837			5,034			2,173			7,639			5,325
		Interest expense, net		(1,211	)		(1,384	)		(916	)		(1,105	)		(1,622	)		(2,938	)
		Income tax expense		(1,295	)		(264	)		(289	)		(5,307	)		(4,321	)		(3,435	)

Net cash provided by operating activities by continuing operations			$	12,567		$	8,495		$	8,046		$	27,369		$	33,013		$	40,638

Net cash used in investing activities for continuing operations			$	(6,073	)	$	(17,152	)	$	(5,629	)	$	(31,103	)	$	(53,963	)	$	(76,625	)

Net cash provided by (used in) financing activities for continuing operations			$	(4,652	)	$	6,821		$	(2,431	)	$	3,089		$	34,700		$	30,008

Capital expenditures			$	6,081		$	15,247		$	19,938		$	41,495		$	52,481		$	75,768


(1)	We adopted the provisions of SFAS 143 “Accounting for Retirement Obligations,” resulting in a cumulative effect change in accounting principle of $1.6 million.

(2)	We recognized an extraordinary gain from the recognition of negative goodwill of $12.5 million related to our acquisition of the Foreland Corporation in December 2004.

(3)	EBITDA means earnings (income from continuing operations) before interest, income taxes, depreciation, depletion and amortization. EBITDA is a non-GAAP financial measure. We believe that EBITDA is a widely accepted financial indicator and we use it to provide us with additional information about our ability to meet our future requirements for debt service, capital expenditures and working capital. In addition, the financial covenants under our revolving credit facility are calculated using EBITDA. EBITDA should not, however, be considered in isolation or as a substitute for net income, income from continuing operations, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles or as a measure of our profitability or liquidity. Our definition of EBITDA may not be comparable to similarly titled measures of other companies.


		As of December 31,										As of
												September 30,
		2000		2001		2002		2003		2004		2005

		(in thousands)
Balance Sheet Data:
Cash and cash equivalents		$	1,853	$	18	$	1,876	$	176	$	12,973	$	5,868
Other current assets			13,593		11,961		20,801		30,842		38,543		59,847
Property, plant and equipment, net			18,199		36,918		41,055		60,841		99,188		160,673
Intangibles, net			—		—		—		—		214		50
Investments			305		305		1,939		4,592		5,281		5,413
Held for sale			19,889		19,950		19,792		20,882		22,504		—
Derivative contracts			—		—		—		—		—		72
Other assets			—		—		—		963		2,684		312

	Total assets	$	53,839	$	69,152	$	85,463	$	118,296	$	181,387	$	232,235

Current liabilities			23,874		27,915		34,765		66,630		63,097		104,112
Long-term debt			8,052		13,643		19,058		4,807		56,318		72,103
Other long-term liabilities			8,106		11,087		9,573		17,298		10,907		6,230

	Total liabilities		40,032		52,645		63,396		88,735		130,322		182,445

Minority interest			7		914		1,664		1,710		1,894		11,062
Total shareholders’ equity			13,800		15,593		20,403		27,851		49,171		38,728

	Total liabilities and shareholders’ equity	$	53,839	$	69,152	$	85,463	$	118,296	$	181,387	$	232,235

MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the accompanying financial statements and related notes thereto included elsewhere in 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 oil and natural gas, 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, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Recent Developments


	*Proposed Initial Public Offering*


	*Gungoll Acquisition*

Restricted Stock

On December 21, 2005, we granted restricted stock awards to certain of our officers and employees in an aggregate amount of approximately 1.6 million shares.

December 2005 Private Placement

We recently sold 12.7 million shares of our common stock in our December 2005 private placement to initial purchasers who resold those shares to certain eligible investors. We received net proceeds from this sale of approximately $175.7 million after deducting the initial purchasers’ discount of approximately $13.4 million and offering expenses of approximately $2.0 million. Approximately $105.5 million of the proceeds of our December 2005 private placement were used to repay outstanding bank debt and finance our December 2005 acquisitions described below. The remainder of the proceeds are being used for general corporate purposes, including the acceleration of our drilling program in West Texas and the Piceance Basin.

Our December 2005 Acquisitions

Contemporaneously with the closing of our December 2005 private placement, we effected our December 2005 acquisitions which enhanced our position in our businesses and operating areas. These transactions included:


	•	the acquisition of additional equity interests in PetroSource, our CO₂ and tertiary oil recovery subsidiary, to increase our ownership interest from 22.4% to 86.5%, resulting in the consolidation of PetroSource in our financial statements;

	•	the acquisition of an additional 50% equity interest in our compression services subsidiary, Larco, from an executive officer and director resulting in it becoming a 100% wholly-owned subsidiary;

	•	the acquisition from an executive officer and director of approximately 7,400 net acres of additional leasehold interests in West Texas in properties in which we previously held interests;

	•	the acquisition of approximately 2,503 net acres of additional leasehold interests in properties in the Piceance Basin in which we previously held interests; and

	•	the acquisition from a director of additional working interests in Missouri and Nevada leases in which we previously held interests.

The December 2005 acquisitions were financed with approximately $15.9 million in cash funded out of the net proceeds of our December 2005 private placement and the issuance of 3,508,335 shares of our common stock with an aggregate value of approximately $52.6 million. Of these amounts, $0.3 million in cash was paid and 2,984,398 shares of common stock with an aggregate value of approximately $44.8 million were issued, to our officers and directors or their direct family members. See “Related Party Transactions.” For more information on these acquisitions, see “Unaudited Pro Forma Consolidated Condensed Financial Statements.”

Unless otherwise indicated, the information contained in this “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” does not give effect to the transactions described above.

Overview of Our Company

We are an oil and natural gas company with our principal focus on exploration and production. 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 treating and transportation facilities. Prior to our December 2005 acquisitions, we conducted and reported our business in three related segments — exploration and production, drilling and oil field services and midstream gas services. As part of our December 2005 acquisitions, we acquired a controlling interest in PetroSource and will report its operations as our “CO₂ and Tertiary Oil Recovery” segment.

Operating income is computed as segment operating revenue less direct operating costs. These measurements provide important information to us about the activity and profitability of our lines of business. Set forth in the table below is financial information regarding each of our current segments.

Segment Overview


									Nine Months Ended
			Year Ended December 31,						September 30,

			2002		2003		2004		2004		2005

			(in thousands)
Revenue:
	Exploration and production		$	15,539	$	32,285	$	35,059	$	26,415	$	32,705
	Drilling and oil field services			10,888		19,970		39,211		26,924		55,452
	Midstream gas services			32,257		99,475		99,044		73,159		93,128

		Total revenue		58,684		151,730		173,314		126,498		181,285


												Nine Months Ended
			Year Ended December 31,									September 30,

			2002			2003			2004			2004			2005

			(in thousands)
Operating income:
	Exploration and production			(4,437	)		10,115			7,818			5,813			(1,156	)
	Drilling and oil field services			3,470			2,845			4,206			4,857			12,975
	Midstream gas services			3,050			2,713			2,636			1,866			3,600
	Other			—			—			(92	)		(55	)		(233	)

		Total operating income		2,083			15,673			14,568			12,481			15,186
	Interest expense			(916	)		(1,105	)		(1,622	)		(1,145	)		(2,938	)
	Other income (expense)			(369	)		960			(298	)		(255	)		(2,144	)

		Income before income taxes	$	798		$	15,528		$	12,648		$	11,081		$	10,104

Production data:
	Gas (Mmcf)			3,909			6,706			6,708			5,079			4,885
	Oil (MBbls)			45			38			37			25			31
	Combined volumes (Mmcfe)			4,182			6,936			6,930			5,229			5,073
	Daily combined volumes (Mcfe/d)			11,456			19,004			18,935			19,152			18,582
Average Prices:
	Natural gas (per Mcf)		$	2.96		$	3.99		$	4.43		$	4.25		$	5.85
	Oil (per Bbl)			27.10			26.62			34.03			30.16			41.72
	Combined (per Mcfe)			3.06			4.01			4.47			4.27			5.89
Drilling and oil field services:
	Number of drilling rigs owned			3			6			10			9			18
	Average number of drilling rigs owned			3.0			4.9			8.0			7.9			13.1
	Average total revenue per rig per day(1)		$	9,549		$	10,207		$	11,322		$	10,658		$	12,550
Midstream gas services:
	Natural gas volume (Mmcf)			12,373			24,253			22,547			17,135			17,807
	Daily natural gas volume (Mcf/d)			33,899			66,447			61,773			62,766			65,227


(1)	Includes revenues for related rental equipment.

We report the results of our operations in the following segments:

Exploration and Production. We aggressively explore for, develop and produce oil and natural gas reserves, with a focus on our proved reserves and extensive undeveloped acreage positions in West Texas and the Piceance Basin. We operate substantially all of our wells in West Texas and the Piceance Basin, but we also participate in drilling operations in the Arkoma and Anadarko Basins, currently as a non-operator. We employ our drilling rigs and other drilling services in the exploration and development of our operated wells and, to a lesser extent, on our non-operated wells.

The primary factors affecting the financial results of our exploration and production segment are the prices we receive for our oil and natural gas production, the quantity of our oil and natural gas production, and changes in the fair value of derivative instruments we use to reduce the volatility of the prices we receive for our oil and natural gas production.

Exploration and production revenues increased to $32.7 million in the nine months ended September 30, 2005 from $26.4 million in nine months ended September 30, 2004, primarily as a result of an increase in the average price we received for the oil and natural gas we produce. The average combined price increased to $5.89 per Mcfe in the 2005 period from $4.27 per Mcfe in 2004, or 38%. This increase was partially offset by a decline in total production, which decreased to 5,073 Mmcfe in 2005 from 5,229 Mmcfe in 2004, or 3.0%. We were operating at the capacity of our gathering systems for most of the 2004 and 2005 period, but we have recently expanded the capacity of our gathering systems, including the construction of the new 31-mile Sabino line, which connects the Pinion Field to the Grey Ranch plant. We anticipate that we will sell increased volumes of natural gas beginning in the first quarter of 2006 as a result of this expansion.

For the nine months ended September 30, 2005, we had a $1.2 million operating loss in our exploration and production segment, compared to a $5.8 million operating income for the same period in 2004. We record the change in the fair value of our derivative instruments in our exploration and production operating results on a quarterly basis, and for the period ended September 30, 2005, the change in the fair value of our derivative agreements resulted in a charge of $8.6 million compared to a gain of $0.4 million in the 2004 period. Future volatility in oil and natural gas prices could have an adverse effect on the operating results of our exploration and production segment.

Exploration and production revenues increased to $35.1 million in 2004 from $32.3 million in 2003 and from $15.5 million in 2002. The increase in 2004 compared to 2003 was primarily due to an increase in the average prices we received for our oil and natural gas production. The increase in 2003 compared to 2002 was primarily due to an increase in production volume to 6,936 Mmcfe in 2003 from 4,182 Mmcfe in 2002 and the increase in average sales prices during the year.

Exploration and production operating income decreased to $7.8 million in 2004 from $10.1 million in 2003, due to a $4.7 million increase in our production expenses which included a $1.2 million increase in dry hole expense and a $1.6 million increase in property taxes partially offset by higher average prices. Exploration and production operating income increased to $10.1 million in 2003 from a $4.4 million operating loss in 2002, which is partially due to a 65.9% increase in our production of oil and natural gas and a 63.9% increase in the average price we received for this production. As a result of changes in the fair value of our derivative instruments, we recognized a $0.2 million charge and a $1.5 million gain in 2003 and 2002, respectively.

As of September 30, 2005, we had 199.5 Bcfe of estimated net proved reserves with a PV-10 of $746.9 million, while at December 31, 2004 we had 148.5 Bcfe of estimated net proved reserves with a PV-10 of $293.5 million. The substantial majority of the increase in the PV-10 was the result of the increase in the end of period price for natural gas that we realized from $5.67 per Mcf of natural gas at December 31, 2004 to $10.50 per Mcf of natural gas at September 30, 2005. To a lesser extent our PV-10 also increased as a result of the increase in our net proved reserves. Estimates of net proved reserves are inherently imprecise. In order to prepare our estimates, we must analyze available geological, geophysical, production and engineering data and project production rates and the timing of development expenditures. The process also requires economic assumptions about matters such as oil and natural gas 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 oil and natural gas prices and other factors, many of which are beyond our control. As a result of these factors, we reduced our previous estimates of net proved reserves by $40.8 million in 2002 and $39.2 million in 2004.

Over the past several years, higher oil and natural gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services and have caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher field costs. Given the inherent volatility of oil and natural gas prices that are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions, which generally are lower than the average sales prices received in 2004 and the nine months ended September 30, 2005. 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, oil and natural gas production from a given well naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling 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. The permitting and approval process has been more difficult in recent years than in the past due to increased activism from environmental and other groups, particularly in the Piceance Basin, and has extended the time it takes us to receive permits.

Drilling and Oil field Services. We drill for our own account in both West Texas and the Piceance Basin through our drilling and oil field services subsidiary, Lariat Services. We also drill wells for other oil and natural gas companies, primarily located in the West Texas region. Our oil field services business conducts operations that complement our drilling services operation. These services include providing pulling units, mud logging, trucking, rental tools, location and road construction and roustabout services to ourselves and to third-parties. Additionally, we provide under-balanced drilling systems only for our own account.

In October 2005, we entered into a joint venture, Larclay, with CWEI, pursuant to which we will jointly acquire 12 newly-constructed rigs to be used primarily for drilling on CWEI’s prospects. CWEI is responsible for financing the purchase of the rigs by the joint venture and may be required to contribute equity or make loans to the joint venture, as needed, if Larclay is unable to finance 100% of the acquisition cost of the rigs, which is expected to be approximately $75 million. We will operate the rigs owned by the joint venture, and after the initial construction and equipping, all operating costs to maintain the equipment will be borne proportionately between us and CWEI. We will have a 50% interest in Larclay, and we expect to account for this joint venture as an equity investment in an unconsolidated subsidiary.

The financial results of our drilling and oil field services segment depend on many factors, particularly the demand for and the price we can charge for our services. We provide drilling services for our own account and for others, generally on a daywork, footage or turnkey contract basis. The majority of our drilling contract revenues are derived from daywork drilling contracts. However, we generally assess the complexity and risk of operations, the on-site drilling conditions, the type of equipment to be used, the anticipated duration of the work to be performed and 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 hour 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.

Footage Contracts. Under a footage contract, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. The risks to us on a footage contract are greater because we assume most of the risks that are associated with drilling operations and that would normally be assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalation and personnel.

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 technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We subcontract for related services, such as the provision of casing crews, cementing and well logging. Generally we do not receive progress payments and are paid only after the well is drilled. We routinely enter into turnkey contracts in areas where our experience and expertise permit us to drill wells more profitably than under a daywork contract.

Drilling and oil field services revenue increased to $55.5 million in the nine month period ending September 30, 2005 from $26.9 million in the nine month period ending September 30, 2004, primarily as a result of an increase in the number of drilling rigs we owned and an increase in the average revenue per rig per day we received. The number of drilling rigs we owned increased 88.9% during the period, and the average rate we received per rig per day increased 17.8% (before intercompany eliminations). Operating

income increased to $13.0 million in the nine month period ending September 30, 2005 from $4.9 million in the nine month period ended September 30, 2004.

Drilling and oil field services revenue increased to $39.2 million in 2004 from $20.0 million in 2003. Operating income increased to $4.2 million in 2004 from $2.8 million in 2003. 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 66.7% and the average revenue we received per rig per day increased 10.9% (before intercompany eliminations).

Drilling and oil field services revenue increased to $20.0 million in 2003 from $10.9 million in 2002 primarily due to an increase in the number of rigs we owned; our rig fleet doubled during the comparison period to six rigs in 2003 from three in 2002. Operating income decreased to $2.8 million in 2003 from $3.5 million in 2002, primarily due to an increase in operating expenses related to the start up of our compression business and a $2.1 million increase in depreciation expenses related to the expansion of our rig fleet and the purchase of related oil field services equipment. The reduction in operating income was partially offset by an increase in drilling revenue.

We believe our ownership of drilling rigs and related oil field services will continue to be a major catalyst of our growth. Except for maintenance and weather downtime, all of our rigs have been operating continuously since the acquisition of our first rig in 1997. Currently, ten of our rigs are working on properties that we operate and 12 of our rigs are drilling on a contract basis for third-parties. By the first quarter of 2007, we expect to increase the size of our drilling fleet to 42 rigs, including the 12 rigs owned by Larclay.

The 10 rigs we expect to add in 2006 and the first quarter of 2007 for our own account have been ordered from Chinese manufacturers for an approximate aggregate purchase price of $52.4 million, which includes the cost of equipping the rigs in the U.S. For the 10 rigs, we expect capital expenditures will be approximately $3.9 million for the remainder of 2005, $43.0 million in 2006 and $4.0 million in the first quarter 2007. We believe this is a lower cost when compared to newly built U.S. manufactured rigs with similar capabilities. We anticipate that the arrival of these units will occur ahead of the bulk of the order backlogs of U.S. manufactured rigs.

Midstream Gas Services. We provide gathering, compression, processing and treating services of natural gas in the TransPecos region of West Texas and the Piceance Basin in northwestern Colorado, primarily through our wholly-owned subsidiary, ROC Gas. Through our gas marketing subsidiary, Integra Energy LLC (“Integra Energy”), we buy and sell natural gas produced from our operated wells as well as third-party operated wells. Gas marketing revenue is our largest revenue component; however, it is a very low margin business. Substantially all of our marketing fees are billed on a per unit basis. Most of the gas we market is sold on a month-to-month basis; however, there are times when we will enter into 4 or 5 month gas sales commitments to manage seasonal market loads, which are priced at the monthly index for that particular area. On a consolidated basis, gas purchases and other costs of sales includes the total value we receive from third-parties for the gas we sell and the amount we pay for gas, which are reported as exploration and production expense.

The primary factors affecting our midstream gas services are the quantity of gas we gather, treat and market and the prices we pay and receive for natural gas.

Midstream gas services revenue increased to $93.1 million in the nine month period ended September 30, 2005 from $73.2 million in the nine month period ended September 30, 2004, or 27.2%. The increase was attributable to an increase in the average natural gas selling price. Operating income increased to $3.6 million in the 2005 period from $1.9 million in the 2004 period, primarily due to an increase in the gathering and plant processing fees we charged to the producer. We have the contractual right to increase these fees from time to time based on certain indexes.

Midstream gas services revenue decreased to $99.0 million in 2004 from $99.5 million in 2003, primarily due to a reduction in the volume of natural gas sold which decreased to 22.1 Bcfe in 2004 from 23.5 Bcfe in 2003. Operating income also decreased to $2.6 million in 2004 from $2.7 million in 2003. The

decline in volume was largely proportionate to our decrease in production for the same comparison period due to the constricted nature of our gathering systems before we expanded the capacity to gather more gas.

Midstream gas services revenue increased to $99.5 million in 2003 from $32.3 million in 2002, primarily due to a 96.0% increase in volume and an increase in the average selling price of natural gas. Operating income decreased to $2.7 million from $3.1 million, primarily as a result of a change in the fair value of our derivative instruments.

CO₂ and Tertiary Oil Recovery Operations. We conduct our CO₂ gathering and tertiary oil recovery operations through PetroSource, a majority-owned subsidiary. Currently most of the oil and natural gas revenue we receive is from the production of natural gas; however, we expect more of our revenue to come from oil after we initiate our CO₂ flood operations. PetroSource gathers CO₂ from natural gas treatment plants located in the Delaware and Val Verde Basins of West Texas. PetroSource treats and transports this CO₂ for use in our and third-parties’ tertiary oil recovery operations.

While it is extremely difficult to accurately forecast future oil and natural gas production, we believe tertiary oil recovery operations will provide significant long-term production growth potential at reasonable rates of return with relatively low risk. The increasing emphasis on CO₂ tertiary oil recovery projects has had, and will continue to have, an impact on our financial condition in the following manner:


	•	there is a significant delay between the initial capital expenditures and the resulting production increases, if any, as tertiary oil recovery operations require the construction of facilities before CO₂ flooding can commence. After the infrastructure is in place, it usually takes an additional eighteen months before the field responds (i.e. oil production commences) to the injection of CO₂;

	•	it is anticipated that PetroSource will not be profitable for the next several years. The anticipated lack of profitability in the initial years is due largely to the significant outlay of capital investment in the CO₂ flood projects and the lag of revenues associated with such expenditures. Thereafter, we will recognize profits only if the tertiary oil recovery efforts are successful; and

	•	our tertiary oil recovery projects are more expensive to operate than conventional oil fields because of the additional cost of injecting and recycling the CO₂ (primarily due to the significant energy requirements to re-compress the CO₂ back into a liquid state for re-injection purposes). If commodity and energy prices increase, our operating expenses in these fields will also increase. Moreover, our overall operating expenses on a per unit basis will likely increase as these operations constitute an increasingly larger percentage of our overall operations.

Other Charges


	*Stock-based Compensation*

We granted restricted stock awards for approximately 1.6 million shares on December 21, 2005. The stock awards with respect to: (i) 153,667 shares vest on the earlier of (x) December 31, 2006 and (y) the expiration of the lock-up agreement entered into by our officers in connection with our December 2005 private placement, (ii) 904,833 shares vest on the earlier of (x) June 30, 2010 and (y) the fourth anniversary of the completion by us of a registered initial public offering and (iii) 493,667 shares vest on the earlier of (x) June 30, 2013 and (y) the seventh anniversary of the completion by us of a registered initial public offering. The issuance of the restricted stock awards will result in our recognition of a non-cash compensation expense, after income tax, of approximately $15.4 million over the vesting periods, subject to reduction in the event of any forfeitures. We intend to accrue compensation expense based on the December and June vesting dates referred to above. In the event that any of the restricted stock awards vest sooner, we will recognize all of the remaining compensation expense associated with such awards in the period in which such vesting occurs.


	*Deferred Financing Fees*

We repaid certain bank loans from the proceeds of our December 2005 private placement, including the outstanding balance of our existing revolving credit facility with Bank of America, N.A. Prior to our December 2005 private placement, we had an interest rate swap agreement outstanding, with a notional amount totaling $25 million, that expires on September 1, 2006. We terminated this agreement in December 2005, and the effect was not material.


	*Public Company Expenses*

In connection with our proposed initial public offering, we filed a registration statement with the SEC. We believe that our general and administrative expenses will increase in connection with the filing of this registration statement. This increase will consist of legal and accounting fees and additional expenses associated with compliance with the Sarbanes-Oxley Act of 2002 and other regulations, including the NYSE listing standards. Following the filing of the registration statement, we anticipate that our ongoing general and administrative expenses will also increase as a result of being a publicly traded company. This increase will be due to the cost of tax return preparations, accounting support services, filing annual and quarterly reports with the SEC, investor relations, directors’ fees, directors’ and officers’ insurance and registrar and transfer agent fees. As a result, we believe that our general and administrative expenses for 2006 will significantly increase. Our consolidated financial statements following the completion of our proposed initial public offering will reflect the impact of these increased expenses and affect the comparability of our financial statements with periods prior to the completion of our proposed initial public offering.


	*Derivative Instruments*

Due to the historical volatility of oil and natural gas prices, we have implemented a hedging strategy aimed at reducing the variability of prices we receive for our production. Currently, we use collars and fixed-price swaps as our mechanisms for hedging commodity prices. We do not designate any of our derivative instruments as hedges for accounting purposes in accordance with SFAS No. 133 — Derivative Instruments and Hedging Activities. As a result, we account for our derivative instruments on a mark-to-market basis, and changes in the fair value of derivative instruments are recognized in earnings. While we believe that the stabilization of prices and protection afforded us by providing a revenue floor for our production is beneficial, this strategy may result in lower revenues than we would have if we were not party to derivative instruments in times of rising natural gas prices. As a result of rising commodities prices, we recognized a charge in the nine months ended September 30, 2005 of approximately $8.6 million. If commodities prices remain at current levels or increase, we will recognize additional charges in future periods.


	*Royalty and Damage Payments*

Prior to September 30, 2005, we owned the surface and minerals on the Longfellow Ranch, including part of the Pinon Field and other fields. We retained the royalty and damage income and paid the surface operating expenses associated with the Longfellow Ranch. On September 30, 2005, we sold these surface and mineral rights, and accordingly we no longer receive the royalty and damage income or pay the surface operating expenses associated with the Longfellow Ranch. For the years 2002, 2003 and 2004, and the nine months ended September 30, 2005, the royalty and damage income was $1.0 million, $1.6 million, $2.0 million and $1.7 million, respectively. The operating expenses related to the Longfellow Ranch (other than operating expenses related to mineral rights) for the same periods were $0.7 million, $1.7 million, $1.3 million and $1.5 million, respectively. These amounts are included in the discontinued operations line of the consolidated financial statements included elsewhere in this prospectus. As part of this transaction, we leased back the undeveloped mineral rights at the same royalty rates we had historically incurred in the area, and the developed mineral rights were assigned to us subject to the existing lease royalty burdens. Future royalty payments will vary depending upon amounts produced and prices received. Our portion of future royalty and damage payments will be reflected as a deduction from our revenues. Please read “Related Party Transactions” for further details. The information reflected in our reserve reports has historically not included royalties associated with the Longfellow Ranch properties.

Results of Operations


	*Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2005*

The financial information with respect to the nine months ended September 30, 2004 and 2005 that is discussed below is unaudited. In the opinion of management, this information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for such periods. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Revenue. Total revenue increased 43.3% to $181.3 million for the nine months ended September 30, 2005 from $126.5 million in the same period in 2004. This increase was due to an increase in oil and natural gas sales, drilling and oil field services revenue and revenue from midstream gas services.


			Nine Months Ended
			September 30,

			2004		2005		$ Change		% Change

			(in thousands)
Revenue:
	Exploration and production		$	22,357	$	29,895	$	7,538		33.7
	Drilling and oil field services			27,853		54,935		27,082		97.2
	Midstream gas services			73,081		92,843		19,762		27.0
	Other			3,207		3,612		405		12.6

		Total Revenue	$	126,498	$	181,285	$	54,787		43.3

Total exploration and production revenues increased $7.5 million to $29.9 million for the nine months ended September 30, 2005 compared to $22.4 million for the same period in 2004, primarily as a result of an increase in the average price we received for our oil and natural gas production. The average price increased to $5.89 per Mcfe in the 2005 period from $4.27 per Mcfe in 2004, or 37.9%. This increase was partially offset by a decline in total production, which decreased to 5,073 Mmcfe in 2005 from 5,229 Mmcfe in 2004, or 3.0%. We were operating at the capacity of our gathering systems for most of the 2004 and 2005 period, but we have recently expanded the capacity of our gathering systems, including the construction of the new 31-mile Sabino line, and anticipate that we will sell increased volumes of natural gas beginning in the first quarter of 2006.

Drilling and oil field services revenue increased 97.2% to $54.9 million for the nine months ended September 30, 2005 from $27.9 million in the same period in 2004, 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 18 (13.1 average) in the 2005 period (before intercompany eliminations) from nine (7.9 average) in the 2004 period, an increase of 65.8%, and the average daily revenue per rig, before considering the effect of the elimination of intercompany usage, increased to $12,550 in the 2005 period from $10,658 in the 2004 period, or 17.8%. Additionally, the revenue from our heavy hauling trucking subsidiary increased $2.8 million during the comparison period due to an expansion of our trucking services, and the revenue from our pulling unit operations increased $2.1 million because of an increase in the demand for these oil field services and an increase in the rate we charge.

Midstream gas services revenue increased 27.0% to $92.8 million for the nine months ended September 30, 2005 from $73.1 million in the same period in 2004, primarily due to an increase in the average price of natural gas. Midstream gas services revenue is primarily affected by the volume of gas gathered, processed and sold; the gathering and plant fees we charge; and the sale price we receive for the gas. Following a review of area gathering fees in May 2005, we recommended and our partners accepted an increase in the gathering fee we charge to $0.10 per Mcf from $0.0656, or 52.4%, in order to match market rates. The plant fee we charge increased in April 2005 to $0.2154 from $0.2092, or 2.96%.

Other revenue increased to $3.6 million for the nine months ended September 30, 2005 from $3.2 million for the same period in 2004. The increase was due to additional administration fees collected

from operating oil and natural gas wells and lease acreage income received, which was primarily due to an increase in the overall number of wells and well locations.

Operating Costs and Expenses. Total operating costs and expenses increased to $166.1 million for the nine months ended September 30, 2005 compared to $114.0 million for the same period in 2004.


			Nine Months Ended
			September 30,

			2004		2005		$ Change		% Change

			(in thousands)
Operating costs and expenses:
	Exploration and production		$	12,975	$	14,323	$	1,348		10.4
	Gas purchases and cost of sales			75,628		114,028		38,400		50.8
	Salaries and wages			14,608		20,415		5,807		39.8
	General and administrative			1,426		2,019		593		41.6
	Depreciation, depletion and amortization			9,380		15,314		5,934		63.3

		Total operating costs and expenses	$	114,017	$	166,099	$	52,082		45.7

Exploration and production expense includes the costs associated with the exploration and production activities conducted by the company, including, but not limited to, lease operating expense, dryhole expense, severance tax, gas marketing and processing cost and geologic and geophysical expense. Exploration and production expense increased $1.3 million for the nine months ended September 30, 2005, or 10.4%, primarily because of an increase in the number of producing properties we own. The number of active wells increased to 288 gross (152.5 net) wells from 254 gross (135.6 net) wells.

Gas purchases and cost of sales increased to $114.0 million for the nine months ended September 30, 2005 from $75.6 million in the same period in 2004 primarily because of an increase in the average natural gas price, which increased 20.7%. The remaining increase was attributable to an increase in gas volume and an overall increase in the cost to gather, treat and transport natural gas.

Salaries and wages increased to $20.4 million for the nine months ended September 30, 2005 from $14.6 million for the same period in 2004, primarily due to an increase in the number of our employees. Total personnel increased to 664 employees for the nine months ended September 30, 2005 from 462 employees for the same period in 2004. Our drilling and oil field services segment, which has the highest average hourly wage, experienced the largest increase in total personnel. In addition to an increase in the total number of employees, our wages have also increased due to the increase in demand for oil field labor.

General and administrative expense increased to $2.0 million for the nine months ended September 30, 2005 from $1.4 million in the same period in 2004, primarily due to a $0.2 million increase in rent expense associated with an increase in our leased office space. Additionally, legal and professional fees increased $0.1 million, which primarily relates to audit and accounting fees.

Depreciation, depletion and amortization expense increased to $15.3 million for the nine months ended September 30, 2005 from $9.4 million in the same period in 2004 primarily due to an increase in depreciation expense recorded in our drilling and oil field services segment, which was due to an increase in our capital expenditures for additional drilling rigs. Drilling and oil field services depreciation, depletion and amortization expense increased to $7.7 million for the nine months ended September 30, 2005 from $4.5 million for the same period in 2004. We calculate depreciation of property and equipment using the straight-line method over the estimated useful lives of the assets, which range from 3 to 25 years. Our drilling rigs and related oil field services equipment are depreciated over an average seven-year useful life. Additionally, depreciation, depletion and amortization expense in our exploration and production segment increased to $5.9 million for the nine months ended September 30, 2005 from $4.0 million for the same period in 2004, primarily due to an increase in the number of wells in which we own an interest.

Other Income (Expense). Total other expense increased to $5.1 million in the nine month period ended September 30, 2005 from $1.4 million in the nine month period ended September 30, 2004. The increase is reflected in the table below.


			Nine Months Ended
			September 30,

			2004			2005			$ Change			% Change

			(in thousands)
Other Income (expense):
	Interest expense, net		$	(1,145	)	$	(2,938	)	$	1,793			156.6
	Minority interest			(135	)		(968	)		833			617.0
	Loss from equity investments			(120	)		(1,176	)		1,056			880.0

		Total other expense	$	(1,400	)	$	(5,082	)	$	3,682			263.0

	Income before income taxes		$	11,081		$	10,104		$	(977	)		(8.8	)
	Income tax expense			3,767			3,435			(332	)		(8.8	)
	Income from discontinued operations, net of tax			386			229			157			(40.7	)

	Net Income		$	7,700		$	6,898		$	802			(10.4	)

Interest expense increased to $2.9 million for the nine months ended September 30, 2005 from $1.1 million for the same period in 2004. This increase was due to the additional debt that we incurred to finance our investment in oil and natural gas properties and oil field services equipment, including the additional drilling rigs. Additionally, our borrowing rate increased to 3.87% at September 30, 2005 from 2.39% at December 31, 2004.

The loss from equity investments increased to $1.2 million for the nine months ended September 30, 2005 from $0.1 million for the same period in 2004 primarily due to our proportionate share of the net loss from our investment in PetroSource.

Income tax expense decreased to $3.4 million for the nine months ended September 30, 2005 from $3.8 million for the same period in 2004, primarily due to a decrease in income before income tax expense, which decreased to $10.1 million in the 2005 period from $11.1 million in the 2004 period. The effective tax rate for 2005 and 2004 was 34%.


	*Year Ended December 31, 2003 Compared to Year Ended December 31, 2004*

Revenue. Total revenue increased to $173.3 million in 2004 from $151.7 million in 2003, which is explained by category below.


			Year Ended
			December 31,

			2003		2004		$ Change			% Change

			(in thousands)
Revenue:
	Exploration and production		$	27,826	$	31,004	$	3,178			11.4
	Drilling and oil field services			20,745		39,417		18,672			90.0
	Midstream gas services			99,313		98,906		(407	)		(0.4	)
	Other			3,846		3,987		141			3.7

		Total Revenue	$	151,730	$	173,314	$	21,584			14.2

Revenue from exploration and production sales increased $3.2 million to $31.0 million in 2004 from $27.8 million in 2003. This increase was due to an increase in the average price we received for the oil and natural gas we produced, which increased to $4.47 per Mcfe in 2004 from $4.01 per Mcfe in 2003.

Drilling and oil field services revenue increased to $39.4 million in 2004 from $20.7 million in 2003, primarily due to an increase in the number of drilling rigs we owned and an increase in the average daily revenue we earned from our rigs. Average daily revenue per rig, before considering the effect of the

elimination of intercompany usage, increased to $11,332 in 2004 from $10,207 in 2003, and our rig fleet increased to 10 (8.0 average) rigs in 2004 from six (4.9 average) rigs in 2003. Revenue from our oil field supply division increased $8 million because this division started operations in 2003, and our air compression rental increased $2 million due to an increase in the number of compressor units in operation.

Midstream gas services revenue decreased to $98.9 million in 2004 from $99.3 million in 2003, primarily due to a 7.0% decrease in the volume of natural gas sales, which was partially offset by an increase in the average sale price. The increase in transportation and processing income was due to an increase in the gross volume of gas transported and processed and to an increase in plant and gathering fees collected by our midstream segment. Additionally, during 2004 we increased the plant fee by 1.9%, to $0.2092 per Mcf, and we increased the gathering fee by 2.3%, to $0.0634 per Mcf.

Other revenue increased 3.7% to $4.0 million in 2004 from $3.8 million in 2003. The increase was due to an increase in the fees and other income collected from operating oil and natural gas wells and conducting related activities. The number of wells we operate increased in 2004 from 2003.

Operating Costs and Expenses. Total operating costs and expenses increased $22.7 million to $158.7 million in 2004 from $136.1 million in 2003, which is explained by category below.


			Year Ended
			December 31,

			2003		2004		$ Change		% Change

			(in thousands)
Operating costs and expenses:
	Exploration and production		$	11,677	$	18,172	$	6,495		55.6
	Gas purchases and cost of sales			99,632		106,045		6,413		6.4
	Salaries and wages			10,699		18,920		8,221		76.8
	General and administrative			1,704		2,198		494		29.0
	Depreciation, depletion and amortization			12,345		13,411		1,066		8.6

		Total operating costs and expenses	$	136,057	$	158,746	$	22,689		16.7

Exploration and production expense increased to $18.2 million in 2004 from $11.7 million in 2003 primarily as a result of an increase in lease operating expense. Lease operating expense increased $3.2 million, primarily due to a $1.5 million increase in property taxes and a $0.5 million increase in gas marketing costs. Generally, our exploration and production expense has increased along with the growth in our exploration and production activities.

Gas purchases and other cost of sales increased to $106.0 million in 2004 from $99.6 million in 2003, or 6.4%, primarily due to a 12.3% increase in the average price of natural gas paid by our marketing company and due to an increase in our oil field services operating expense. Oil field services operating expenses, including fuel, repairs and maintenance, increased $3.7 million, due to an increase in the number of drilling rigs we owned.

Salaries and wages increased 76.8% to $18.9 million in 2004 from $10.7 million in 2003, primarily due to a 38.4% increase in our total number of employees to 497 employees in 2004 from 359 employees in 2003. Our drilling and oil field services segment, which has the highest average hourly wage, experienced the largest increase in total employment.

General and administrative expense increased $0.5 million to $2.2 million in 2004 from $1.7 million in 2003, primarily as a result of a $0.2 million increase in rent expense and a $0.1 million increase in our insurance premiums due to the additional drilling rigs.

Depreciation, depletion and amortization increased to $13.4 million in 2004 from $12.4 million in 2003. This increase was primarily due to an increase in depreciation expense in our drilling and oil field services segment to $5.9 million in 2004 from $3.4 million in 2003, which resulted from our investment in additional drilling rigs and oil field service equipment.

Other Income (Expense). Total other expense increased to $1.9 million in 2004 from $0.1 million in 2003. The increase is discussed in the table below.


			Year Ended
			December 31,

			2003			2004			$ Change			% Change

			(in thousands)
Other Income (expense):
	Interest expense, net		$	(1,105	)	$	(1,622	)	$	517			46.8
	Minority interest			(96	)		(262	)		166			172.9
	Income (loss) from equity investments			1,056			(36	)		1,092			(103.4	)

		Total other expense	$	(145	)	$	(1,920	)	$	1,775			1224.1

	Income before income taxes		$	15,528		$	12,648		$	(2,880	)		(18.5	)
	Income tax expense			5,307			4,321			(986	)		(18.6	)
	Income (loss) from discontinued operations, net of tax			(85	)		451			(536	)		(630.6	)
	Extraordinary gain			—			12,544			12,544			—
	Cumulative effect of accounting change			(1,636	)		—			(1,636	)		(100.0	)

		Net income	$	8,500		$	21,322		$	12,822			150.8

Interest expense increased to $1.6 million in 2004 from $1.1 million in 2003. This increase was due to the additional debt that we incurred to finance our investment in oil and natural gas properties and oil field services equipment, including the additional drilling rigs. Additionally, our borrowing rate increased to 2.39% at December 31, 2004 from 1.11% at December 31, 2003.

The decrease in income equity investments was primarily due to the operating loss recorded on our PetroSource equity investment.

Income tax expense decreased to $4.3 million in 2004 from $5.3 million in 2003 primarily due to a decrease in income before tax, which decreased to $12.6 million in 2004 from $15.5 million in 2003. The effective tax rate for 2004 and 2003 was 34%.

The extraordinary gain was attributable to our purchase of the Foreland Corporation in 2004 and represented the difference between the fair value of assets acquired and the purchase price. The fair value of the assets acquired was $13.8 million and the purchase price was $1.2 million.


	*Year Ended December 31, 2002 Compared to Year Ended December 31, 2003*

Revenue. Total revenue increased 158.6% to $151.7 million in 2003 from $58.7 million in 2002, which is explained by category below.


			Year Ended
			December 31,

			2002		2003		$ Change		% Change

			(in thousands)
Revenue:
	Exploration and production		$	12,807	$	27,826	$	15,019		117.3
	Drilling and oil field services			10,745		20,745		10,000		93.1
	Midstream gas services			32,195		99,313		67,118		208.5
	Other			2,937		3,846		909		30.9

		Total Revenue	$	58,684	$	151,730	$	93,046		158.6

Exploration and production revenues increased to $27.8 million in 2003 from $12.8 million in 2002, primarily due to a 31.0% increase in the average price we received for the oil and natural gas we produced, which increased to $4.01 per Mcfe in 2003 from $3.06 per Mcfe in 2002. Additionally, total production increased 65.9% to 6,936 Mmcfe in 2003 from 4,182 Mmcfe in 2002, due to a 20.2% increase in the number

of gross wells (6.7% net) in which we owned an interest, which in turn was largely due to an increase in the number of wells drilled during 2003, primarily in the Pinon Field.

Drilling and oil field services revenue increased to $20.7 million in 2003 from $10.7 million in 2002, primarily due to an increase in the number of rigs we owned during 2003. In 2003, we owned an average of 4.9 drilling rigs compared to three in 2003, an increase of 63.3%. The average daily revenue generated by our rigs increased 6.9% (before intercompany elimination) to $10,207 in 2003 from $9,549 in 2002. Other related oil field divisions that recognized an increase in revenue included dirt work, which reported a $2.2 million increase, roustabouts, which reported a $1.0 million increase and trucking, which reported a $1.0 million increase in revenue. These related oil field services generally benefit as the level of activity increases, especially drilling activity.

Midstream gas services revenue increased to $99.3 million in 2003 from $32.2 million in 2002, primarily due to a 96% increase in the volume of natural gas sold and an increase in the average selling price. During 2003, we increased the plant fee at Pike’s Peak by 2.6%, to $0.20 per Mcf, and we increased the gathering fee in the Pinon Field by 3.33%, to $0.0620 per Mcf. In addition, we had a 25% plant fee increase at the Pike’s Peak plant which became effective in March 2002.

Other revenue increased 30.9% to $3.8 million in 2003 from $2.9 million in 2002. This increase was due to an increase in the administration fees and other income collected from operating oil and natural gas wells and conducting related activities. The number of wells we operate increased in 2003 from 2002.

Operating Costs and Expenses. Total operating costs and expenses increased to $136.1 million in 2003 from $56.6 million in 2002, which is explained by category below.


			Year Ended
			December 31,

			2002		2003		$ Change			% Change

			(in thousands)
Operating costs and expenses:
	Exploration and production		$	8,791	$	11,677	$	2,886			32.8
	Gas purchases and costs of sale			32,833		99,632		66,799			203.5
	Salaries and wages			6,093		10,699		4,606			75.6
	General and administrative			1,812		1,704		(108	)		(6.0	)
	Depreciation, depletion and amortization			7,072		12,345		5,273			74.6

		Total operating costs and expenses	$	56,601	$	136,057	$	79,456			140.4

Exploration and production expense increased to $11.7 million in 2003 from $8.8 million in 2002 primarily as a result of an increase in lease operating expense, property tax and gas marketing costs.

Gas purchases and cost of sales increased to $99.6 million in 2003 from $32.8 million in 2002 primarily due to a 96.0% increase in the volume of natural gas sold, which was principally a result of our commencement as the sole operator of the Pike’s Peak gas plant in 2003.

Salaries and wages increased along with an increase in our total employment, which increased 77.7% to 359 employees in December 2003 from 202 employees in December 2002. Our drilling and oil field services employment increased 100% to 278 employees at year end 2003 from 139 employees at year end 2002.

General and administrative expense decreased $0.1 million to $1.7 million in 2003 from $1.8 million in 2002. In 2003, we began allocating a portion of our expenses that were recoverable under the terms of operative documents which govern our operations of the properties.

Depreciation, depletion and amortization expense increased to $12.3 million for 2003 from $7.1 million in 2002 due to an increase in capital spending in the drilling and oil field services segment, which increased 96.6% to $13.5 million in 2003 from $6.9 million in 2002 as a result of an increase in our drilling rigs and related equipment. The increase was primarily a result of the addition of approximately 26 (8.39 net) producing wells in the Pinon Field.

Other Income (Expense). Total other expense decreased to $0.1 million in 2003 from $1.3 million in 2002. The decrease is shown in the table below:


			Year Ended
			December 31,

			2002			2003			$ Change			% Change

			(in thousands)
Other Income (expense):
	Interest expense, net		$	(916	)	$	(1,105	)	$	(189	)		20.6
	Minority interest			(673	)		(96	)		577			(85.7	)
	Income from equity investments			304			1,056			752			247.4

		Total other expense	$	(1,285	)	$	(145	)	$	1,140			(88.7	)

	Income before interest expense		$	798		$	15,528		$	14,730			1,845.9
	Income tax expense			289			5,307			5,018			1,736.3
	Income (loss) from discontinued operations, net of tax			1,105			(85	)		(1,190	)		(107.7	)
	Cumulative effect of accounting change			—			(1,636	)		(1,636	)		—

		Net income	$	1,614		$	8,500		$	6,886			426.6

Net interest expense increased to $1.1 million in 2003 from $0.9 million in 2002 due to an increase in our debt, which was partially offset by a decrease in the LIBOR rate to 1.11% at December 31, 2003 from 1.38% at December 31, 2002.

Minority interest increased $0.6 million in 2003 from $(0.7) in 2002 primarily due to an increase in operating income recorded on our Cholla Pipeline, L.P. investment.

The increase in income tax expense was due to an increase in pre-tax income compared to 2002.

As further discussed in Note 1 to our Consolidated Financial Statements, we adopted Financial Accounting Standard No. 143 “Accounting for Asset Retirement Obligations” (FAS 143) on January 1, 2003 and recorded a charge as the cumulative effect of accounting change of $1.6 million, net of tax benefit of $843,000.

Liquidity and Capital Resources


	*Summary*

Our financial condition and liquidity has been dependent on the cash flow we receive from our principal business segments (and our subsidiaries that carry out those operations) and borrowings under our bank credit agreement.

Our cash flow is influenced mainly by the prices that we receive for our oil and natural gas production; the quantity of natural gas we produce; and, to a lesser extent, the quantity of oil we produce; the success of our development and exploration activities; the demand for our drilling rigs and oil field services and the rates we receive therefore; and the margins we obtain from our natural gas and CO₂ gathering and processing contracts. In connection with our amended revolving credit facility, we have agreed not to hedge more than 75% of our projected annual production of proved developed producing oil and natural gas production at any time.

We believe that we have sufficient liquidity through our cash flow from operations; cash flows provided by financing activities, including cash flows from our proposed initial public offering; and borrowing capacity under our revolving credit facility to meet our short-term operating needs, debt service obligations, contingencies and anticipated capital expenditures. The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. As a result we may, from time to time, seek additional financing.

Our capital expenditures by segment are explained in the table below:


								Nine Months Ended
		Year Ended December 31,						September 30,

		2002		2003		2004		2004		2005

		(in thousands)
Capital Expenditures:
	Exploration and production	$	11,297	$	22,868	$	23,660	$	17,191	$	20,042
	Drilling and oil field services		6,855		13,474		22,679		13,892		32,846
	Midstream gas services		1,046		873		2,026		1,649		18,569
	Other		740		4,280		4,116		2,029		4,329

	Total capital expenditures	$	19,938	$	41,495	$	52,481	$	34,761	$	75,786

Our estimated capital expenditures for 2005 were approximately $122 million, of which $75.8 million was spent as of September 30, 2005. We intend to increase our capital expenditures by approximately 89% in 2006 to $230 million. Our 2006 capital expenditures will primarily be related to growing our reserves and production on our existing acreage. To this end, we plan to drill 115 gross wells in West Texas and 40 gross wells in the Piceance Basin, pursue tertiary oil recovery operations and purchase the 10 additional drilling rigs described below and certain related oil field services equipment. As of December 31, 2004, the estimated future development costs relating to the development of proved undeveloped oil and gas reserves for the years 2005 through 2007 are projected to be $17.8 million, $32.2 million and $19.6 million. In addition, we intend to expend even greater amounts on the development of our unproved oil and natural gas reserves.

The majority of our capital expenditures will be discretionary and could be curtailed if our cash flows decline from expected levels; however, we have contracted for the construction and acquisition of 10 new drilling rigs for our own account, which will require capital expenditures of approximately $43 million in 2006 and $4 million in 2007.

We expect to make substantial capital expenditures related to our PetroSource segment primarily for the commencement of our CO₂ flood operations at the Wellman and South Mallet units. We expect to make capital expenditures of $34 million in 2006 in connection with PetroSource. We capitalize a portion of the acquisition cost of CO₂ used in our CO₂ floods as development cost as it is injected.


	*Cash Flows from Continuing Operations*

Our cash flows from continuing operations are as follows:


											Nine Months Ended
		Year Ended December 31,									September 30,

		2002			2003			2004			2004			2005

Cash Flows from Continuing Operations:
	Cash flows provided by operating activities		8,046			27,369			33,013		$	19,127		$	40,638
	Cash flows used in investing activities		(5,629	)		(31,103	)		(53,963	)		(35,142	)		(76,625	)
	Cash flows provided by (used in) financing activities		(2,431	)		3,089			34,700			25,501			30,008

	Net increase (decrease) in cash and cash equivalents		(14	)		(645	)		13,750		$	9,486		$	(5,979	)

Operating Activities. Cash flows provided from continuously operating activities increased $21.5 million to $40.6 for the nine months ended September 30, 2005 from $19.1 million for the nine months ended September 30, 2004. The increase was caused by a $8.6 million charge resulting from a change in the fair value of our derivative instruments, an increase of $5.9 million in depreciation, depletion and amortization expense, a $0.7 million loss on equity investments and an increase of $5.3 million in operating assets and liabilities.

Cash flows provided by operating activities increased $5.6 million to $33.0 million in 2004 from $27.4 million in 2003 primarily due to a $5.4 million change in operating assets and liabilities.

Cash flows provided by operating activities increased $19.4 million to $27.4 million in 2003 from $8.0 million in 2002 primarily due to an $8.1 million increase in income from continuing operations, a $5.3 million increase in depreciation, depletion and amortization expense, a $3.8 million change in deferred income taxes and a $5.6 million change in the gain on the sale of property, plant and equipment, partially offset by a $2.9 million reduction in operating assets and liabilities.

Investing Activities. Capital expenditures increased to $76.6 million in the nine month period ended September 30, 2005 from $35.1 million in the 2004 period. For the nine months ended September 30, 2005, our capital expenditures were $20.0 million in our exploration and production segment, $32.8 million for drilling and oil field services and $18.6 million for midstream gas services.

Capital expenditures increased to $52.5 million in 2004 from $41.5 million in 2003 and $19.9 million in 2002. During the comparison period, exploration and production capital expenditures increased to $23.7 million in 2004 from $22.9 million in 2003 and $11.3 million in 2002 primarily because of the additional wells that were drilled in the Pinon Field in 2004 and 2003. Capital expenditures for drilling and oil field services increased to $22.7 million in 2004 from $13.5 million in 2003 and $6.9 million in 2002 due to an increase in the number of drilling rigs.

Proceeds from the sale of assets decreased to $1.4 million in 2004 from $12.9 million in 2003 and $15.9 million in 2002.

Financing Activities. Our financial condition and liquidity have been dependent on the cash flow we receive from our principal business segments (and our subsidiaries that carry out those operations) and borrowings under our bank credit agreement. Proceeds from borrowing, increased to $33.2 million for the nine months ended September 30, 2005 from $29.4 million for the nine months ended September 30, 2004. Additionally, minority interests increased $8.0 million, primarily due to an increase in investment by our partners in the Sagebrush and Cholla pipeline companies.

Proceeds from borrowings increased to $41.6 million in 2004 from $6.6 million in 2003 and $9.9 million in 2002. Most of our borrowings funded the acquisition of our drilling rigs, our exploration and production activities and the expansion of our gathering and treating assets.

We made principal payments on our debt of $6.8 million in 2004, $2.4 million in 2003 and $12.4 million in 2002. The majority of the principal payments were applied to our revolving credit facility and is further described below.


	*Credit Facilities*

We currently have a $200,000,000 revolving credit facility in place with Bank of America, N.A. The revolving credit facility includes a $20,000,000 sub-limit for letters of credit. Advances under the revolving credit facility are subject to a borrowing base based on our proved developed producing reserves, our proved developed non-producing reserves and proved undeveloped reserves. It is subject to re-determination semi-annually at the sole discretion of the lender based on the reports of independent petroleum engineers in accordance with normal and customary oil and gas lending practices.

The revolving credit facility bears interest at our option at either Eurodollar plus an applicable margin ranging from 1.5% to 2.5% or the Bank of America, N.A. prime rate plus an applicable margin of up to 0.5%. We pay a commitment fee on the unused portion of the borrowing base amount ranging from 0.125% to 0.35% per annum. The revolving credit facility is secured by oil and natural gas properties representing at least 80% of the present discounted value of our proved reserves and by a negative pledge on any of our non-mortgaged properties.

As of February 10, 2006, the borrowing base under our revolving credit facility was $72,000,000 and we had no outstanding balance. For information concerning the effect of changes in interest rates on interest

payments under this revolving credit facility, see, “— Quantitative and Qualitative Disclosures About Market Risk — Interest Rate Risks.”

Our revolving credit facility contains certain financial covenants. We must maintain a minimum tangible net worth equal to $225,000,000 plus the sum of 50% of net income, without deduction for any loss, for each calendar year after December 31, 2005 and the proceeds of any equity offerings. We must also maintain a minimum EBITDA to fixed charge ratio of 2.50:1 and a maximum funded debt to EBITDA ratio of 3.50:1. EBITDA is not intended to represent net income (loss) as defined by generally accepted accounting principles in the United States, or GAAP, and such information should not be considered as an alternative to net income (loss), cash provided by operating activities or any other measure of performance prescribed by generally accepted accounting principles in the United States. As of the date of this prospectus, we are in compliance with all applicable financial covenants.

We have financed a portion of our drilling rig fleet and related oil field services equipment through notes with Merrill Lynch Capital. At January 31, 2006, the aggregate outstanding balance of these credit agreements was $34.2 million, with a fixed interest rate ranging from 7.6375% to 8.248%. The notes have a final maturity date of November 11, 2010, aggregate monthly installments for principal and interest in the amount of $775,298 and are secured by the equipment. The notes have a prepayment penalty in the event we repay the notes prior to maturity.

We have financed the purchase of various vehicles, oil field services equipment and other equipment used in our business and the payment of insurance premiums. The aggregate outstanding balance of this debt as of January 31, 2006 was $1.9 million.

On October 14, 2005, Sagebrush Pipeline, LLC borrowed $3.6 million from Bank of America, N.A. for the purpose of completing the gas processing plant and pipeline in Colorado. This loan matures on October 14, 2006, and the interest rate is LIBOR plus 215 basis points. The aggregate outstanding balance of this loan as of January 31, 2006 was $4.0 million. We have guaranteed this loan, and we could be required to repay this debt in full. As of January 31, 2006, we owned 69.6% of Sagebrush Pipeline, LLC.

In 2003, PetroSource issued $6.5 million in subordinated debt payable quarterly to certain of its shareholders through 2010 with fixed interest of 6.00%, approximately $5.5 million of which is held by Riata Energy, Inc. as of January 31, 2006.


	*Contractual Obligations*

A summary of our contractual obligations as of September 30, 2005 is provided in the following table:


		Payments Due by Year

		2005		2006		2007		2008		2009		After 2009		Total

		(in thousands)
Long-term debt		$	2,598	$	11,279	$	45,728	$	9,584	$	8,957	$	3,183	$	81,329
Interest(1)			724		2,659		2,004		1,374		684		103		7,548
Firm transportation(2)			—		—		79		949		949		7,083		9,060
Operating leases			231		534		208		44		—		—		1,017
Asset retirement obligations(3)			—		—		—		—		—		4,740		4,740

	Total	$	3,553	$	14,472	$	48,019	$	11,951	$	10,590	$	15,109	$	103,694


(1)	Calculated based on the interest rates in effect as of September 30, 2005.

(2)	We entered into a firm transportation agreement with Questar Pipeline Company giving us guaranteed capacity on their pipeline for 10 MmBtu per day at an estimated charge of $949,000 for one year, with a total commitment of $9.1 million.

(3)	This represents our estimate of future asset retirement obligations on an undiscounted basis. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based on numerous factors, including the rate of inflation, changing technology and the political and regulatory environment.

Critical Accounting Policies and Estimates

We follow certain significant accounting policies when preparing our consolidated financial statements. A complete summary of these policies is included in Note 1 of the Notes to Consolidated Financial Statements.

The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Oil and natural gas reserve engineering is a subjective process. It entails estimating underground accumulations of oil and natural gas. These accumulations cannot be measured in an exact manner. The degree of accuracy of these estimates depends on a number of factors, including the quality of available geological and engineering data, the precision of the interpretations of that data and judgment based on experience and training.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firms described above adhere to the same guidelines when reviewing our reserve reports. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas, and natural gas liquids eventually recovered.

Revenues associated with sales of crude oil and natural gas are recorded, net of applicable royalties, discounts and allowances, when title passes to the customer. Revenues derived from crude oil and natural gas production from properties in which we have an interest with other producers are generally recognized on the basis of our net working interest.

We recognize revenues and expenses on daywork contracts daily as the work progresses, since we do not bear the risk of completion of the well. For certain contracts, we receive lump-sum payments for the mobilization of rigs and other drilling equipment. Mobilization revenues earned, and the related direct cost incurred for the mobilization, are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred.

Transportation and processing revenue is recognized when the product is delivered to the customer.

We use the successful efforts method of accounting for oil and natural gas-exploration and production activities. Costs to acquire mineral interests in oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed. We capitalize the cost of the CO₂ used in our CO₂ floods as development cost as it is injected. Capitalized costs of producing oil and natural gas properties are depreciated and depleted by the units-of production method. Unproved oil and natural gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance.

We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure. Impairment of proved properties is required when carrying value exceeds undiscounted future net cash flows based on total proved and risk-adjusted probable and possible reserves. Oil and gas producing properties deemed to be

impaired are written down to their fair value, as determined by discounted future net cash flows based on total proved and risk-adjusted probable and possible reserves or, if available, comparable market values.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized in income. On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Capitalized costs of producing oil and gas properties are depreciated and depleted by the units-of-production method. Under the units-of-production method, acquisition costs of proved properties are based on proved reserves and other capitalized costs of proved properties are based on proved developed reserves.

We evaluate our unproved property investment for impairment based on time or geologic factors in addition to the use of an undiscounted future net cash flow approach. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage are also considered. Impairment expense for unproved oil and gas properties is reported in exploration expense.

Expenditures for maintenance, repairs and minor renewals to maintain plant and equipment are expensed as incurred. Major replacements and renewals are capitalized. When CO₂ is recovered in conjunction with oil production from our CO₂ floods, it is extracted and reinjected, and all of the associated costs are expensed as incurred.

We account for our investments in affiliated companies under the cost or equity method, based on our ability to exercise significant influence. Our investments in affiliated companies are summarized below:


	•	Cholla Pipeline, L.P. Cholla was formed to transport natural gas from the Longfellow and West Ranch areas. We account for this investment under the equity method of accounting because we own more than 20% and we have significant influence but do not control Cholla Pipeline, L.P.

	•	Grey Ranch, L.P. Grey Ranch is primarily engaged in the processing and transportation of gas and natural gas liquids. We account for this investment under the equity method of accounting because we own more than 20% and we have significant influence but do not control Grey Ranch. We contributed a disproportionate amount of capital into the Partnership, amounting to approximately $217,000 and $1,050,000 as of December 31, 2004 and 2003, respectively. The excess amount contributed is being amortized over the average life of the partnership’s long-lived assets.

	•	PetroSource. PetroSource acquires, compresses, transports and sells CO₂ through its CO₂ pipeline and spurs located in West Texas. We have historically accounted for our investment under the equity method of accounting because we have significant influence in its operations but we do not control PetroSource. Upon the closing of the offering, we will purchase an additional interest in PetroSource, and we will consolidate PetroSource into our financial statements.

We have various other investments in other affiliated companies in which we do not have the ability to exercise significant influence, and we account for these investments under the cost method.

Asset Retirement Obligation

On January 1, 2003, we adopted SFAS 143 “Accounting for Asset Retirement Obligation.” SFAS 143 requires us to record the fair value of the liability associated with the retirement of the oil and natural gas properties we own, which require expenditures to plug and abandon the wells when the oil and natural gas reserves in the wells are depleted. These expenditures under SFAS 143 are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). We do not have any assets restricted for the purpose of settling the plugging liabilities.

The following is a reconciliation of the asset retirement obligation for the nine months ended September 30, 2005 and 2004 (in thousands).


	2004		2005

Asset retirement obligation, January 1	$	3,883	$	4,394
Liability incurred upon acquiring and drilling wells		215		174
Accretion of discount expense		102		172

Asset retirement obligation, September 30	$	4,200	$	4,740

New Accounting Pronouncements

In November 2004, the FASB issued Statement on Financial Accounting Standards No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4,” which clarifies the types of costs that should be expensed rather than capitalized as inventory. The provisions of SFAS 151 are effective for years beginning after June 15, 2005. We do not expect this statement to have a material impact on our results of operations or our financial condition.

The FASB issued Statement on Financial Accounting Standards No. 153, “Exchanges of Productive Assets,” in December 2004 that amended APB Opinion No. 29, “Accounting for Nonmonetary Transactions.” SFAS 153 requires that nonmonetary exchanges of similar productive assets are to be accounted for at fair value. Previously these transactions were accounted for at book value of the assets. This statement is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. We do not expect this statement to have a material impact on our results of operations or our financial condition.

In December 2004, the FASB issued SFAS 123R “Share-Based Payment,” which requires that compensation cost relating to share based payments be recognized in our financial statements. SFAS 123R revises SFAS 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share based payments for services provided by employee to employer. We will adopt the provision in 2006.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, “Accounting for Asset Retirement of Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 stated that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. FIN 47 is intended to provide more information about long-lived assets and future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. We do not believe that our financial position, results of operations or cash flows will be impacted by FIN 47.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Under this statement, voluntary changes in accounting principle are required to be applied retrospectively for the direct effects of a change to prior periods’ financial statements, unless such application is impracticable. Retrospective application refers to reflecting a change in accounting principle in the financial statements of prior periods as if the principle had always been used. When retrospective application is determined to be impracticable, this statement requires the new accounting principle to be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective treatment is practicable with a corresponding adjustment to the opening balance of retained earnings. This statement retains the guidance in APB Opinion No. 20 for reporting the corrections of errors and changes in accounting estimates. This statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, with early adoption permitted. Our adoption of this statement will affect our consolidated financial statements for any changes in accounting principle we may make in the future, or new pronouncements we adopt that do not provide transition provisions.

Effects of Inflation

The effect of inflation in the oil and natural gas industry is primarily driven by the prices for oil and natural gas. Increased commodity prices increase demand for contract drilling rigs and services, which supports higher drilling rig activity. This in turn affects the overall demand for our drilling rigs and the dayrates we can obtain for our contract drilling services.

Over the last two years, natural gas and oil prices have been more 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 oil and natural gas.

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*

Due to the historical volatility of oil and natural gas prices, we have entered into derivative arrangements aimed at reducing the variability of prices we receive for our production including collars and fixed-price swaps. These transactions require no cash payment upfront and are settled on a monthly basis. While this strategy may result in our having lower revenues than we would have if we were not party to these derivative arrangements 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 on the final trading day of the month. Settlement for natural gas derivative contracts occurs in the month following the production month. We currently do not enter into derivative arrangements with respect to our oil production, but we may do so in the future if our oil production increases as a result of the initiation of our CO₂ floods.

For the most part, 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.

We have not designated any of our derivative instruments as hedges for accounting purposes. Riata records all derivatives instruments on the balance sheet at fair value. Changes in derivative fair values are recognized in earnings. The income (loss) amount recognized in earnings, included in gas purchases and cost of sales, for the nine months ended September 30, 2005 and December 31, 2004, was approximately $(8.6) million and $1.8 million, respectively.

A hypothetical 10% increase in market commodity prices relative to commodity prices as of September 30, 2005 would result in a loss of $3.8 million under our derivative instruments detailed below. A $0.25 change per Mcf in the price of natural gas would have had a $0.8 million impact on earnings during the nine months ended September 30, 2005.

We have entered into oil and natural gas futures contracts with a bank whereby we purchase, based on a fixed price, notional amounts monthly. The contracts expire on various dates through September 1, 2006.

At September 30, 2005, our open commodity derivatives consisted of the following:


				Fixed		September 30, 2005
Fixed Price Swaps		Quantity		Price		Fair Value

						(in millions)
Natural Gas (MmBtu)
	January 3 — December 1, 2005		92,000		4.85		(0.6	)
	January 3 — December 1, 2005		92,000		4.83		(0.6	)

Total						$	(1.2	)


								September 30, 2005
Costless Collars		Quantity		Floor		Cap		Fair Value

								(in millions)
Natural Gas (MmBtu)
	October 3 — September 1, 2006		3,650,000		6.00		9.25		(8.3	)

Total								$	(8.3	)

These derivatives have not been designated as hedges.


	*Interest Rate Risk*

In addition to commodity price derivative arrangements, we also have entered into derivative transactions to fix the interest rate we pay on a portion of the money we borrow under our credit agreement. Our revolving credit facility is a floating rate agreement based on LIBOR or the prime rate. The swap transactions allow us to pay a fixed rate to the counterparty, and we receive a LIBOR based payment from the counterparty. All of our interest rate derivative instruments are with affiliates of the financial institution that are party to our credit agreement. We have entered into interest rate swap agreements with a bank whereby we receive payments based on a floating one-month LIBOR rate plus 1.25% applied to the notional amounts (totaling $25 million), and we make payments based on a fixed rate of 4.4% applied to the same notional amount.

A hypothetical 10% decrease in market interest rates relative to interest rates as of September 30, 2005 would result in a $0.3 million decrease in the fair value of our interest rate hedging contracts as of September 30, 2005. A 1% change would have had a $0.4 million impact on interest expense and a $0.3 million impact on net income during the nine months ended September 30, 2005.

With respect to any particular swap transaction, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price for the transaction.

BUSINESS

Overview

Riata Energy, Inc. is an oil and natural gas company with its principal focus on exploration and production. We also own and operate drilling rigs and a related oil field services business; gas gathering, marketing and processing facilities; and, through our subsidiary PetroSource, CO₂ treating and transportation facilities and tertiary oil recovery operations. We believe that this vertical integration in our core operating areas is unique to a company of our size and provides us with operational flexibility and an advantageous cost structure. We began our exploration and production operations in 1986 in West Texas with limited acreage and production. To date, we have concentrated our exploration and production activities in West Texas, where we have assembled a large, focused acreage position, and more recently, we have expanded our operations into our largely undeveloped acreage position in the Piceance Basin. As a result of these exploration and production activities, we have grown our average net production to 20.2 Mmcfe per day for September 2005. We also have acreage positions in the Anadarko and Arkoma Basins of Oklahoma. We continually seek to optimize our asset base and believe that our control of all of the components of oil and natural gas exploration and production — acreage, drilling, gathering, transportation and treating — provides us with significant competitive advantages. As of September 30, 2005 after giving effect to our December 2005 acquisitions, our estimated proved reserves were 272 Bcfe. We have assembled an extensive oil and natural gas property base with 326 gross (190.5 net) wells and interests in over 722,590 gross (226,037 net) acres as of September 30, 2005 after giving effect to our December 2005 acquisitions. Our large acreage position provides us with an extensive drilling inventory.

We began our oil field services business in 1986 and expanded this business in 1997 to include drilling with the acquisition of our first rig. We currently operate 20 drilling rigs and have 22 additional rigs on order or under construction with the last delivery scheduled in the first quarter of 2007. Twelve of these new rigs are expected to be owned through Larclay, our 50/50 drilling rig joint venture. Our rig fleet and existing inventory of oil and natural gas prospects provide us with the opportunity to control and accelerate our drilling program.

Our estimated capital expenditures for 2005 were approximately $122 million, of which $75.8 million was spent during the nine months ended September 30, 2005. We intend to increase our capital expenditures by approximately 89% in 2006 to $230 million. Our 2006 capital expenditures will primarily be related to growing our reserves production on our existing acreage. To this end, we plan to drill 115 gross wells in West Texas and 40 gross wells in the Piceance Basin, pursue tertiary oil recovery operations and purchase 10 of the additional drilling rigs described above and certain related oil field service equipment. In addition, we believe we are positioned to take advantage of attractive acquisition opportunities that may arise.

Our Businesses

We conduct and report our business in the following four related segments:


	•	Exploration and Production. We aggressively explore for, develop and produce oil and natural gas reserves, with a focus on our proved reserves and extensive undeveloped acreage positions in West Texas and the Piceance Basin. We are also participating in drilling operations in the Arkoma and Anadarko Basins, currently as a non- operator.

	•	Drilling and Oil Field Services. We drill onshore for our own account in both West Texas and the Piceance Basin through our drilling and oil field services subsidiary, Lariat Services. In addition, we also drill wells for other oil and natural gas companies, primarily in the West Texas region.

	•	Midstream Gas Services. We provide gathering, compression, processing and treating services of natural gas in the TransPecos region of West Texas and the Piceance Basin, primarily through our wholly-owned subsidiary, ROC Gas.

	•	CO₂ and Tertiary Oil Recovery Operations. We conduct our CO₂ gathering and tertiary oil recovery operations through our subsidiary, PetroSource. PetroSource gathers CO₂ from natural gas treatment


		plants located in the Delaware and Val Verde Basins of West Texas. PetroSource treats and transports this CO₂ for use in our and third-parties’ tertiary oil recovery operations.

Our business units are integrated across our business segments. Our drilling and oil field services business supports our exploration and development efforts and gives us greater operational flexibility and a favorable cost structure. Natural gas produced from our West Texas operations is transported and treated for the removal of CO₂ by our midstream gas services business at the Pike’s Peak and Grey Ranch Plants. The CO₂ is captured by PetroSource, our tertiary oil recovery subsidiary, while our natural gas is sold to third-parties. PetroSource transports the CO₂ by pipeline to market for use by us and others in tertiary oil recovery operations. While most of PetroSource’s CO₂ is currently being sold to third-parties, a portion of our CO₂ will be redirected for use in our own CO₂ flood projects as our internal demand increases. In the Piceance Basin, the integration of our exploration and production business and our drilling and oil field services and midstream gas services businesses provide us with flexibility and control over the timing of the exploitation of our significant acreage position.

Our Strategy

The principal elements of our strategy to maximize shareholder value are to:


	•	Grow Through Aggressive Drilling and Exploration on Existing Acreage. We have been one of the most successful finders and developers of natural gas reserves in the Ouachita Overthrust area of West Texas since 1990. We expect to continue to generate long-term reserve and production growth by aggressively developing our sizeable inventory of under-exploited properties in West Texas and developing our large acreage position in the core focus area of the Piceance Basin. We currently own 463,712 gross (166,722 net) leasehold acres in West Texas, where we have identified over 600 drilling locations, and 32,374 gross (15,679 net) leasehold acres in the Piceance Basin. We intend to drill the eastern portion of our Piceance Basin acreage using 20-acre spacing, which is the minimum allowed under current regulations. Based on our current drilling schedule of 155 wells per year, our acreage positions have a substantial drilling inventory with significant resource expansion potential. Beyond our identified locations in West Texas, we have developed over 50 additional prospects in West Texas.

	•	Utilize “Vertigration” to Reduce Costs, Enhance Returns and Maintain Operating Flexibility. We intend to continue to integrate our exploration and production operations with our drilling and oil field services and CO₂ flooding businesses. By controlling our fleet of drilling rigs, gathering and treating assets and supply of necessary CO₂, we are able to better control costs and maintain a high degree of operational flexibility. We also seek opportunities to partner with other energy firms in key projects to maximize the value of our drilling and midstream businesses, thus further reducing costs. We refer to this strategy as “vertigration.”

	•	Pursue Low-Risk, Low-Cost Oil Reserves through CO₂ Flooding. We intend to capitalize on our sizeable CO₂ assets and tertiary oil recovery expertise to enhance oil recovery in mature oil fields in West Texas in which we own or will acquire an interest. We have acquired the Wellman and South Mallet Units, without allocating significant value to the reserves that we expect to recover through CO₂ flooding operations. We also intend to leverage our CO₂ supply and acquire additional mature oil fields suited for CO₂ flooding located in or near our existing West Texas operations. We expect the Wellman and South Mallet Units will require less than 50% of our expected supply of CO₂.

	•	Build Rig Fleet and Pursue Opportunistic Acquisitions. In 2006 and the first quarter of 2007, we expect to add 22 newly-constructed drilling rigs which have been ordered from Chinese manufacturers. We believe these rigs can be placed in the field sooner and at a lower cost than similar domestically manufactured rigs. Of our expected fleet of 42 rigs, 29 rigs will have been constructed since 2004. Given the current scarcity of rigs, we plan to evaluate opportunities to utilize our rigs to earn interests in projects operated by third-parties. We also will continuously evaluate acquisitions and other expansion opportunities for complementary oil field services in our areas of operation.

Competitive Strengths

We have a number of strengths that we believe will help us successfully execute our strategies:


	•	Experienced Management Team Focused on Delivering Long-term Shareholder Value. Our nine corporate officers have a combined 186 years of experience working in or servicing the oil and natural gas industry and have an average age of 45. We focus on long-term growth and value over multiple industry cycles. We believe this strategy, along with the significant ownership position of our management, will allow us to increase long-term shareholder value.

	•	Large Acreage Position with Drilling Inventory. We have a large asset base of over 722,590 gross (226,037 net) leasehold acres as of September 30, 2005 after giving effect to our December 2005 acquisitions. This large acreage position provides us with significant drilling opportunities on both proved and unproved locations. We believe this drilling inventory affords us significant opportunity to grow our reserves. As of September 30, 2005 after giving effect to our December 2005 acquisitions, we had over 600 identified well locations in West Texas and intend to drill the eastern portion of our Piceance Basin acreage using 20-acre spacing, the minimum allowed under current regulations. Under our current business plan, in 2006 we plan to drill 115 wells in West Texas and 40 wells in the Piceance Basin using 17 of our own rigs.

	•	Geographically Concentrated Operations. We focus over 90% of our operations in West Texas and the Piceance Basin in northwestern Colorado. In addition, this geographic concentration positions us to secure additional acreage and allows us to develop our infrastructure to leverage our vertical integration in these areas and establish economies of scale in both drilling and production operations. As a result, we are able to achieve lower production costs and generate increased cash flows from our producing properties.

	•	Vertical Integration of Operations. Our integration of drilling and oil field services and midstream gas services with exploration and development operations provides us with increased efficiency, greater control over our operations, a lower cost structure and the ability to secure additional acreage in our areas of operation.

	•	Large Modern Fleet of Drilling Rigs. We are significantly growing and enhancing our rig fleet with orders for newly built rigs. Many other exploration and development companies are experiencing difficulty in securing drilling rigs. We believe our timely orders of additional rigs have been placed at favorable prices. By controlling a large drilling fleet, we can develop our existing reserves and explore for new reserves. This provides us with a competitive advantage, especially during periods when the supply of rigs is scarce. The anticipated size of our rig fleet by the end of the first quarter of 2007 will allow us to expand our drilling activity using our own rigs.

	•	Conservatively Leveraged Capital Structure. Following the completion of our proposed initial public offering, we will have little debt outstanding and an unused revolving credit facility. This conservative capital structure should allow us to aggressively accelerate our extensive drilling program and to pursue opportunistic acquisitions in our core operating areas.

Exploration and Production

We aggressively explore for, develop and produce natural gas and oil reserves, with a focus on our proved reserves and extensive undeveloped acreage positions in West Texas and the Piceance Basin. We operate substantially all of our wells in West Texas. We are also participating in drilling operations in the Arkoma and Anadarko Basins, currently as a non-operator, and have acreage interests in certain other non-core areas. We employ our drilling rigs and other drilling services in the exploration and development of our operated wells, and to a lesser extent on our non-operated wells. This strategy reduces our exploratory and development costs.

We serve as operator of over 95% of the wells in which we have a working interest. The notable exceptions are the wells on our Barnett and Woodford Shale acreage in Reeves County, Texas and acreage in

Oklahoma. As operator, we select most drilling locations, supervise the drilling and completion of the wells and produce and maintain the wells. In addition to operating most of our wells, we own and operate much of the equipment that is used in the drilling of our wells, including the drilling rigs. Independent contractors provide the equipment and services we do not provide, such as complex logging and completion services. After our natural gas is produced, more than 95% of it is gathered into lines that we operate. A substantial portion of our production in West Texas is produced with large quantities of CO₂ gas. We use this gas in our tertiary oil recovery operations. The high CO₂ gas is treated for the removal of CO₂ at plants in which we either have an ownership interest or operate. In all phases of our business we employ professionals, including engineers and geologists, who work to improve efficiencies, capture margins, increase reserves and lower our operating costs.

The following table identifies certain information concerning our exploration and production business as of September 30, 2005 after giving effect to our December 2005 acquisitions:


																Approximate
		Estimated														No. of Potential
		Net Proved				Productive		Gross			Productive		Net			Drilling
		Reserves		PV-10(1)		Wells (Gross)		Acreage			Wells (Net)		Acreage			Locations

Exploration and Production Opportunities
West Texas			268,717		927,816		302		463,712			179.1		166,722			600
Piceance Basin, Colorado			3,646		16,036		24		32,374			11.3		15,679			(2	)
Arkoma/ Anadarko Basins, Oklahoma			—		—		—		194,398			—		15,187			10

	Total		272,363		943,852		326		690,484	(2)		190.4		197,588	(2)		610


(1)	For a discussion of the reconciliation of the pre-tax PV-10 to Standardized Measure of Discounted Net Cash Flows, see “— Proved Reserves” below.

(2)	Under evaluation.

(3)	Does not include our Missouri and Nevada properties.


	*West Texas*

Since 1986, we have concentrated our drilling efforts on the exploration and development of natural gas reserves in the TransPecos region of West Texas. Our primary focus has been on the reservoirs associated with the geological feature known as the Ouachita Overthrust in Brewster, southern Pecos and Terrell Counties. The Ouachita Overthrust contains numerous oil and natural gas fields, the first of which were discovered in the 1960’s. In the early 1990’s, we initially targeted the Wolfcamp age sandstones that were eroded and deposited north of the Ouachita Overthrust, which resulted in the development of the Pakenham natural gas field. In 1994, after successfully drilling multiple producing wells in the Pakenham Field, we sold most of our interest and purchased surface and mineral interests covering over 200,000 contiguous acres in southern Pecos County, including a portion of the Pinon Field. We began an aggressive exploration and development program in this area, the success of which allowed us to secure a majority position in the leases covering the Pinon Field and to bring in joint venture partners to fund the escalating development in this area that continues to this day. The Pinon Field accounts for approximately 68% of our net proved reserves as of September 30, 2005 after giving effect to our December 2005 acquisitions.

Over the last three years, we have leveraged our knowledge and experience in the Ouachita Overthrust to drill exploration wells to find and develop additional natural gas reserves in nearby areas. This effort has resulted in discoveries in and extensions to the Pinon Field, including the South Pinon, Pinon-Multi-Pay, Sabino, Ocotillo, Verbena, Algerita and Circle Dot Fields. We have also discovered the Sierra Madre, Wolfcamp and Almez Fields in the Val Verde Basin. We are currently drilling eight wells in these fields and intend to drill a total of 109 wells in 2006.

Since 2002, we have also acquired approximately 78,000 gross (30,000 net) leasehold acres in the Ouachita Overthrust that we believe have significant potential for commercial discoveries. We continue to

seek acquisition opportunities for leasehold acreage in the TransPecos region. We are currently conducting seismic survey and geological studies on a substantial portion of these leases. We expect that these surveys and our extensive seismic, gravity, aeromagnetic and well record database will result in the identification of prospects which will be drilled during 2006 and 2007. Technological advances in processing techniques have dramatically improved our ability to structurally interpret the geology of the area. As a result, we have identified over 50 additional exploratory drilling prospects in West Texas.

In 2003, we entered into an agreement to participate in the acquisition of 140,000 leasehold acres in the Delaware Basin of northwestern Pecos County and Reeves County, targeting the Barnett and Woodford shales. We have completed one well in the Woodford shale, and we are in the process of completing a well in the Barnett shale. We anticipate drilling six wells on this leasehold acreage in 2006.


	At September 30, 2005(1)

			Number of							Capital
	Proved		Producing		Proved		2006			Expenditures(2)
	Reserves		Wells		Undeveloped		New
Exploration and Development Areas	(Bcfe)		(Gross)		Locations		Wells(3)			2005		2006

Pinon Field Area		187		160		360		95		$	24.6	$	57.7
Terrell County (KM Field and Circle Dot)		12		11		4		2		$	0.0	$	1.8
Other Pecos County Properties		4		92		3		18		$	1.8	$	2.8
Delaware Basin		0		1		0		6	(4)		—	$	1.0
Terry and Hockley Counties		65		38		n/a		0			—	$	12.5


(1)	The information in this table gives effect to our December 2005 acquisitions.

(2)	In millions. Includes budgeted drilling expenditures as well as exploration and facilities costs for the area and excludes property acquisition costs and exploration costs for other areas.

(3)	Based on 2006 business plan. Subject to change based on numerous factors, including availability of rigs and services, changes in oil and natural gas prices or costs or drilling.

(4)	We expect to have a small non-operating interest in these wells. They are likely to be drilled with third-party rigs and are not included in the 115 wells we plan to drill in 2006.


	*Pinon Field Area*

Pinon Field. The Pinon Field, located in Pecos County, is our most significant producing field. The Pinon Field, including the adjacent South Pinon, Bitterweed, Bitterweed South and Rio Caballos Fields, currently produces primarily from the Dimple limestones, the Tesnus sandstones and the Caballos cherts, each of which are contained as separate reservoirs within distinct imbricate thrust sheets. The most significant producing reservoirs are the Caballos cherts. The initial production in the Pinon Field was from the prolific Upper Caballos chert at an average depth of 5,500 feet and generally contained CO₂ concentrations ranging from 40% to 80% of produced volumes. Through deeper drilling, we subsequently discovered significant production from the Lower Caballos chert at an average depth of 7,300 to 10,000 feet, which generally contained CO₂ concentrations ranging from 1% to 10% of production volumes. We have recently made a significant discovery, the Pinon Multi-Pay, in Devonian age carbonates underlying these thrust sheets. We anticipate that this will be a significant producing target for future drilling. The shallower Dimple limestones and Tesnus sandstones, which generally contain little or no CO₂, have also proven to be commercial secondary objectives of product volumes at depths of 3,500 to 4,750 feet.

As of September 30, 2005 after giving effect to our December 2005 acquisitions, the estimated proved natural gas reserves of the Pinon Field totaled 1.19 Tcfe gross (627 Bcfe net of CO₂), with our net proved reserves totaling 185.0 Bcfe. This field has produced approximately 106 Bcf of natural gas through September 30, 2005 and currently produces in excess of 69 Mmcfe per day of natural gas. 76% of the wells in the field have been drilled since 2000. Net of CO₂, the Caballos chert reservoirs currently produce approximately 68% of the natural gas produced in the field and comprise approximately 77% of the total proved reserves of the field.

Our interests in the Pinon Field currently include approximately 160 producing wells, including 76 Dimple/ Tesnus wells, 26 Upper Caballos wells, 47 Lower Caballos wells, two Devonian wells and nine dual completion, Tesnus/ Caballos wells. In the first nine months of 2005, we have drilled 24 wells (20 development and four exploration) in the Pinon Field. Of these wells, 18 are currently producing, one was a dry hole, five are being tested or are awaiting completion and one is still being drilled. For 2006 we plan to add five more drilling rigs to the field, bringing our total to 12 rigs. We estimate that we will drill approximately 96 development wells in the field during 2006. As of September 30, 2005 after giving effect to our December 2005 acquisitions, we have identified over 600 potential well locations in the Pinon Field, including 360 proved undeveloped drilling locations and an additional 198 probable locations. Our current geologic and seismic studies indicate that the geographic limits of the field could contain additional possible undrilled drilling locations not discussed above, all of which would constitute a significant drilling inventory for the 12 drilling rigs we plan to utilize during 2006 in West Texas.

Longfellow Ranch. The Longfellow Ranch prospect area is generally described as those lands north and east of the previously described Pinon Field. The prospect area consists of 155,584 gross (87,043 net) acres. Our existing seismic database over this prospect indicates numerous undrilled Ouachita Overthrust, Wolfcamp and Paleozoic Basement fault structures. We are currently conducting additional 2-D seismic surveys to refine our exploration prospects. We intend to re-enter old wells during the fourth quarter of 2005 to attempt completion in several prospective formations. This acreage was leased as part of the transaction with Malone Mitchell, 3rd, our Chief Executive Officer, and his family, as described in “Related Party Transactions.”


	*Terrell County*

KM Field. The KM Field is located in north central Terrell County. Production in this field occurs from a variety of formations at various depths, including the Wolfcamp formation at depths of 9,000 to 10,000 feet, Strawn formation at depths of 10,500 to 15,000 feet, Devonian formation, at depths of approximately 16,000 feet; and Ellenburger formation at depths of approximately 18,000 feet. Originally discovered in the 1960’s, the Ellenburger reservoir portion of this field is approximately 11 miles long and confirmed by six wells. We did not begin development of the Ellenburger formation until 2004, due to the high CO₂ content (approximately 76% of production) and deep drilling depth. Shallower reservoirs in this field have little or no CO₂ and have been partially developed. We have drilled one well and re-entered two wells in the Ellenburger formation. Of these wells, one well is currently producing 5,000 Mcfe per day, one well is producing and one well is being evaluated. We currently own 2,706 gross (962 net) acres in this prospect. We intend to drill two additional wells and acquire additional acreage in this prospect in 2006. As of September 30, 2005 after giving effect to our December acquisitions, our estimated net proved natural gas reserves of the KM Field total 12.1 Bcf.

Circle Dot Prospect. The Circle Dot Prospect is located in Terrell County along the frontal edge of the Ouachita Overthrust. We own 30,846 gross (12,774 net) leasehold acres in this exploratory prospect. We have drilled four exploratory wells and are completing one re-entry well targeting natural gas in the Overthrusted Caballos and Tesnus formations at depths of 6,000 to 12,000 feet. One of the wells drilled resulted in a discovery located approximately eight miles from our gathering system. Of the remaining four wells, three were dry holes and one is awaiting further testing. We plan to drill two wells in this discovery in 2006 in order to investigate the extent and magnitude of the discovery. Should the results of this offset drilling confirm that sufficient reserves exist, a pipeline gathering system will be constructed and drilling will accelerate to develop the discovery.


	*Other Pecos County*

Pecos Wolfcamp Prospect. The Pecos Wolfcamp Prospect is located in Pecos County, north of the frontal edge of the Ouachita Overthrust. We own 18,369 gross (7,942 net) leasehold acres in this exploratory play, which encompasses an area of approximately 400 square miles. The prospect targets natural gas reservoirs in the Wolfcamp age marines at depths of 7,000 to 18,000 feet. This geological formation is similar to that of Pakenham Field, which we developed in the 1990’s. We have drilled four exploratory wells and re-entered two wells in this prospect. The first exploratory well drilled resulted in non-commercial production.

Of the remaining wells, two were dry and one is currently being tested. Both re-entry wells were unsuccessful. We have just commenced shooting a 2-D seismic survey covering approximately 130 miles across primary portions and expect to drill four exploratory wells in the prospect in 2006 after evaluating the results of the 2-D seismic survey.

Brooklaw Field. The Brooklaw Field is located in northwestern Pecos County, approximately 25 miles northeast of Fort Stockton. We acquired this property in 1993. Primary production is from the Clearfork formation. We currently own 10,884 gross (9,972 net) acres in the prospect and own 76 gross (72.7 net) active wells. We drilled one well on this prospect in 2005 and intend to divest approximately 70% of our working interest in connection with the acquisition of other producing properties.

Sabino Field. The Sabino Field, which we discovered in October 2003, is located in southern Pecos County approximately 12 miles east of the Pinon Field and two miles west of the Thistle Field. This field produces natural gas and natural gas condensate from the Overthrusted Caballos formation at depths of 4,500 to 6,000 feet. The Sabino Field currently covers approximately 640 acres and contains five producing wells, with one well currently being completed. The north and east boundaries of the field have been defined, with development drilling extending the field to the south and southwest.

In the Sabino Field, we own working interests in one producing well and one completing well and own leaseholds in the field and the adjacent area totaling 4,195 gross (2,126 net) acres. We intend to drill four wells in the Sabino Field in 2006.

Dimple Hills Prospect. The Dimple Hills Prospect is located in Pecos and Brewster Counties, to the west of the Pinon Field area. We own 24,521 gross (8,736 net) leasehold acres in this exploratory prospect targeting natural gas reservoirs in the Ouachita Thrust Belt facies (primarily the Caballos formation). We have not drilled any wells in the prospect. For 2006, we plan to conduct a 2-D swath seismic survey covering approximately 85 miles across the prospect area. We are continuing to acquire leasehold interests in the prospect and would expect to generate several prospective drilling targets from the results of the seismic survey. We expect to drill several exploratory wells in the prospect after the completion of the seismic survey in 2006 or early 2007.


	*Delaware Basin*

Barnett and Woodford Shales Prospects. We own 141,762 gross (8,381 net) leasehold acres in Reeves County, which is located in the Delaware Basin and is the focus of a developing natural gas play targeting the Barnett and Woodford age shale formations at depths of 12,000 to 16,000 feet. In addition to those two formations, we expect to encounter shallow prospective formations in each deep well drilled in this play. We own a small non-operator working interest in a large leasehold block located in the heart of the current industry drilling activity. Our exploratory agreements covering our leasehold allow us to leverage our working interest in the acreage up to a much larger leasehold with an aggressive drilling program should our co-leasehold owners not participate with us in drilling exploratory wells. To date, we have participated in the drilling of two exploratory wells on our leasehold acreage. The first exploratory well resulted in a non-commercial production from the Woodford Shale, but proved that the Barnett and Woodford shales are natural gas productive reservoirs. The second well is currently being completed from a horizontal Barnett shale section. We are also participating in a third test well. We have entered into two AMI agreements with a small portion of our leasehold, each of which requires the drilling of exploratory wells in 2006. We are carefully monitoring the drilling results on our leasehold and the industry drilling results in the area of our leases in order to react aggressively to any important discovery. We expect to drill and participate in four to six exploratory wells in this play in 2006.


	*Terry and Hockley County*

Wellman Unit. The Wellman Unit is part of our tertiary oil recovery operations. The Wellman Field, located in Terry County, 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 82.5 Mmboe to date. We recently began new injections of CO₂, and our planned injections are expected to reach 35.0 Mmcf per day in 2006 and to average 20.0 Mmcf per day over the next 10 years. Current net proved reserves attributable to the Wellman Unit are 8.1 Mmboe. We also own a CO₂ recycling plant at this unit with a capacity of 30 Mmcf per day and 6,680 horsepower of compression, which is sufficient to handle the recycling of the CO₂ that will be produced in association with the production of these reserves.

South Mallet Unit. The South Mallet Unit, located in Hockley County, covers 3,540 gross acres and produces from the San Andres formation from an average depth of 5000 feet, in the Slaughter/ Levelland Field complex. 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 28.0 Mmboe to date. We plan to begin injections of CO₂ in 2006, and we expect to reach injections of approximately 2,000 Mcf per day in 2006. Current net proved reserves attributable to the South Mallet Unit are 2.6 Mmboe.


	*Piceance Basin*

The Piceance Basin in northwestern Colorado is a sedimentary basin consisting of multiple productive sandstone formations in one of the country’s most prolific natural gas regions. We entered the Piceance Basin in 1993 with the purchase of leasehold interests predominantly located on federal lands. We acquired this position in order to utilize the experience we had gained in underbalanced drilling and foam fracture simulations in West Texas. Initially, development of these natural gas reserves was limited due to high drilling costs and complex completion requirements. However, new drilling and completion technologies now enable the successful development of these reserves.

During 2005, we began developing our acreage in the Piceance Basin. Consequently, only a small portion of our acreage is currently under development. As of September 30, 2005 after giving effect to our December 2005 acquisitions, we owned interests in 24 gross (11.8 net) producing wells and held oil and natural gas interests in 32,374 gross (15,679 net) acres. We currently operate two drilling rigs in this area and expect to increase the number of rigs to five by the end of 2006. We intend to drill the eastern portion of our Piceance Basin acreage based on 20-acre spacing and plan to drill 40 wells in 2006 with our own rigs. The western portion of our acreage block remains under evaluation. To date, we have drilled ten MesaVerde wells and are currently drilling two additional wells. Of these ten wells, seven were producing wells, two are waiting to be completed and one has been temporarily abandoned for mechanical reasons. We utilize multiple stage fracture treatments designed and conducted by Schlumberger to complete our MesaVerde wells. Our new wells began production in August 2005.

ExxonMobil owns extensive leasehold acreage located generally east and southwest of our acreage. They have been conducting an ongoing development drilling program for several years in the MesaVerde and Iles formations. Currently they are drilling with two rigs east of our acreage on their Love Ranch and Piceance Creek projects. EnCana Corporation (“EnCana”) owns extensive leasehold acreage located generally south and west of our acreage. They have also been conducting an ongoing development drilling program for several years in the MesaVerde and Iles formations. They operate the Eureka, Figure Four, and Leftfork units. They are currently operating one rig approximately one mile south of our acreage. We have a small interest in their Figure Four Unit. We exchange certain drilling and completion information with EnCana. The Williams Company (“Williams”) operates the Ryan Gulch Unit, which is adjacent to our acreage. Williams is currently operating one rig approximately one mile from our leasehold. We exchange certain drilling and completion data with Williams. ExxonMobil, EnCana and Williams have each released in public announcements the results of their activities and intentions to increase their respective activity levels in our operating area.


	*Oklahoma — Arkoma and Anadarko Basins*

NW Strong City Prospect. The NW Strong City prospect is located in Roger Mills County, Oklahoma and targets the Springer age sand reservoirs at depths of 15,000 to 16,000 feet. We currently own 1,894 gross (1,024 net) leasehold acres in this prospect and are attempting to acquire additional leases. We have identified a prospective Springer sand reservoir on the electric logs in an abandoned well on our leasehold. Based on 160 acre spacing, our current leasehold acreage position could contain as many as 10 gross (3.2 net) Springer sand development locations. Because of the “force pooling” regulations in effect in Oklahoma, it is possible that we can leverage our interest in any wells drilled on our leasehold to greater amounts than currently owned. We also own a small override and reversionary working interest in the NW Cheyenne Prospect operated by a third party in Roger Mills County, Oklahoma. We have not had our interests in these prospects evaluated by independent engineers.

Arkoma Prospect. The Arkoma Prospect consists of 192,504 gross (14,163 net) leasehold and option acres in Pushmataha and Atoka Counties in Oklahoma. The majority of the acreage was acquired from Weyerhauser Corp. We own a non-operating working interest between 6.66% and 7.5% of the leasehold or option and have the right to increase or decrease our interest on a cost basis. We are owed approximately $0.7 million from a portion of the proceeds from the sale of future prospects by the prospect originator. We have a 7.5% working interest in two non-commercial wells which were drilled on the prospect in 2004 and 2005. We intend to take a more active role in originating and proposing wells on this prospect in 2006.


	*Proved Reserves*

The following table presents our estimated net proved oil and natural gas reserves and the present value of our estimated proved reserves as of December 31, 2004 and September 30, 2005. The PV-10 and Standardized Measure shown in the table are not intended to represent the current market value of our estimated market value or our estimated natural gas and oil reserves. DeGolyer & MacNaughton, independent petroleum engineers, prepared reserve estimates for approximately 97% of our proved reserves at December 31, 2004. Our reserves estimates at September 30, 2005 are based upon reserve reports of DeGolyer & MacNaughton at June 30, 2005 that were adjusted, or “rolled forward,” for production through September 30, 2005 and repriced based on oil and gas prices in effect at September 30, 2005. Our pro forma proved reserves also include the proved reserves attributable to PetroSource and the additional West Texas interests that we are acquiring at closing of the offering, which additional reserves are also based on the reserve reports of DeGolyer & MacNaughton prepared at June 30, 2005 and similarly rolled forward to September 30, 2005. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency.


							Pro Forma Nine
	At December 31,						Months Ended
					At September 30,		September 30,
	2003		2004		2005(2)		2005(2)(3)

Estimated Proved Reserve(1)
Natural Gas (Bcf)(4)		121.3		144.5		195.3		203.6
Oil (MBbls)		649.8		682.0		697.8		11,457.0
Total (Bcfe)		125.2		148.5		199.5		272.4
PV-10 (in millions)(5)	$	232.7	$	293.5	$	746.9	$	943.9	(6)
Standardized Measure of Discounted Net Cash Flows (in millions)(7)	$	157.3	$	199.0		n/a		n/a


(1)	In accordance with SEC requirements, 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, 2003, December 31, 2004 and September 30, 2005, which were $5.39 per Mcf of natural gas and $29.25 per barrel of oil at December 31, 2003, $5.67 per Mcf of natural gas and $40.22 per barrel of oil at December 31, 2004 and $10.50 per Mcf of natural gas and $66.90 per barrel of oil at September 30, 2005.

(2)	Excludes reserves of Brooklaw Field and certain Oklahoma properties for which a September 30, 2005 reserve report was unavailable. Proved reserves for these properties as of December 31, 2004 were 2.0 Bcf with an associated Standard Measure of Discounted Net Cash Flows of $1.5 million and an associated PV-10 of $2.2 million.

(3)	Gives pro forma effect to the proved reserves acquired as a result of the acquisition of additional interests in, and resulting consolidation of PetroSource, as a subsidiary of the Company and the other acquisitions described under “Unaudited Pro Forma Condensed Consolidated Financial Statements.”

(4)	Given the nature of our natural gas reserves, a significant amount of our production contains high CO₂ gas. These figures are net of CO₂.

(5)	PV-10 represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, and production, discounted at 10% per annum to reflect timing of future cash flows and using pricing assumptions. PV-10 differs from Standardized Measure of Discounted Net Cash Flows because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represent an estimate of fair market value of our oil and natural gas properties. PV-10 is used by the industry and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.

(6)	Includes the PV-10 associated with the reserves and the future net revenues of PetroSource, which were determined using the prices for natural gas and oil that PetroSource realized as of September 30, 2005, which were $6.76 per Mcf of natural gas and $59.44 per barrel of oil.

(7)	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, production, 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, which was $75.4 million and $94.5 million at December 31, 2003 and 2004, respectively.


	*Production and Price History*

The following table sets forth information regarding net production of oil, natural gas and natural gas liquids and certain price and cost information for each of the periods indicated:


								Nine Months
								Ended
		Year Ended December 31,						September 30,

		2002		2003		2004		2004		2005

Production Data:
	Natural Gas (Mmcfe)		3,909		6,706		6,708		5,079		4,885
	Oil (MmBbls)		45		38		37		25		31
	Combined Volumes (Mmcfe)		4,182		6,936		6,930		5,229		5,073
	Daily Combined Volumes (Mmcfe/d)		11.5		19.0		18.9		19.2		18.6
Production Costs per Unit:
	Production costs per Mcfe(1)	$	2.05	$	1.61	$	2.23	$	1.92	$	1.91
Average Prices:
	Natural Gas (per Mcf)	$	2.96	$	3.99	$	4.43	$	4.25	$	5.85
	Oil (per Bbl)	$	27.10	$	26.62	$	34.03	$	30.16	$	41.72
	Combined (Mcfe)	$	3.06	$	4.01	$	4.47	$	4.27	$	5.89


(1)	Computed using production costs, excluding transportation costs, as defined by the SEC. Production costs include labor, repairs and maintenance, materials, supplies, fuel and power, property taxes, severance taxes and general and administrative expenses directly related to oil and natural gas producing activities. Includes only production attributable to lease hold ownership.

Productive Wells

The following table sets forth information at September 30, 2005, relating to the productive wells in which we owned a working interest as of that date giving effect to our December 2005 acquisitions. 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.


		Natural Gas				Oil

Basin		Gross Wells		Net Wells		Gross Wells		Net Wells

West Texas			193		75.4		109		103.7
Piceance Basin			24		11.3		—		—

	Total		217		86.7		109		103.7

Developed and Undeveloped Acreage

The following table sets forth information at September 30, 2005 after giving effect to our December 2005 acquisitions, relating to our leasehold acreage:


			Developed				Undeveloped
			Acreage(1)				Acreage(2)

Basin			Gross(3)		Net(4)		Gross(3)		Net(4)

West Texas:
		Pinon Field		9,653		3,808		42,613		12,459
		Other		16,444		12,302		388,188		131,340
		PetroSource		6,813		6,813		—		—
Piceance Basin				480		232		31,894		15,447
Other				—		—		226,504		43,637

	Total			33,390		23,154		689,200		202,883


(1)	Developed acres are acres spaced or assigned to productive wells.

(2)	Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

(3)	A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4)	A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Many of the leases comprising the undeveloped 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 September 30, 2005 and after giving effect to our December 2005 acquisitions, the expiration periods of the gross and net acres that are subject to leases in the undeveloped acreage summarized in the above table.


		Undeveloped Acres
		Expiring

Twelve Months Ending		Gross		Net

December 31, 2005			—		—
December 31, 2006			34,584		13,490
December 31, 2007			17,762		1,838
December 31, 2008			238,841		44,255
December 31, 2009 and later			358,653		129,105
Other(1)			39,359		14,195

	Total		689,200		202,883


(1)	Leases remaining in effect until the cessation of development efforts or cessation of production on the developed portion of the particular lease.

Drilling Results

The following table sets forth information with respect to wells 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.


														Nine Months
		Year Ended				Year Ended				Year Ended				Ended
		December 31,				December 31,				December 31,				September 30,
		2002				2003				2004				2005

		Gross		Net		Gross		Net		Gross		Net		Gross		Net

Development:
	Productive		22		7.7		31		9.4		38		12.3		26		8.9
	Dry		—		—		2		0.5		3		1.0		4		1.9
Exploratory:
	Productive		—		—		8		2.9		7		1.9		5		1.3
	Dry		1		0.4		3		1.0		8		2.3		6		2.0
Total:
	Productive		22		7.7		39		12.3		45		14.2		31		10.2
	Dry		1		0.4		5		1.5		11		3.3		10		3.9

From January 1, 2000 through September 30, 2005, we participated in drilling 184 gross (62.0 net) wells, of which 157 were completed as producing, and 27 were dry holes.

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. While most of the natural gas is sold on a month-to-month basis, there are times when we will enter into four or five month natural gas sales commitments to secure seasonal market loads. These commitments are priced at the monthly index for that particular area. During the past year, we have sold natural gas to 18 different purchasers, each of whom is required to provide financial information to ensure creditworthiness.

Our top five natural gas purchasers of our West Texas production for the two years ended September 30, 2005 and each company’s approximate percentage of total sales during that period are listed below:


•	ANP Funding I, LLC	26.5%
•	TXU Portfolio Management Company, LP	18.8%
•	Atmos Energy Corporation	15.6%
•	ETC Marketing, Ltd.	6.1%
•	Astra Power, LLC	6.0%

In the Piceance Basin, we sell natural gas to Enserco Energy, Inc. and Wasatch Energy LLC, which account for approximately 53.3% and 46.7%, respectively, of our sales for the two years ended September 30, 2005. We expect this distribution will change dramatically in the future as more purchasers will be utilized as our natural gas production increases.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling

operations on those properties, we conduct a 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 oil and natural gas industry. However, we have drilled wells in the Piceance Basin, which are subject to litigation that may affect portions of that property. Please read “— Litigation.” Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Drilling and Oil Field Services Operations

We provide drilling and related oil field services to our exploration and production business and to third-parties in both West Texas and the Piceance Basin.

Drilling Operations

We drill for our own account in both West Texas and the Piceance Basin through our drilling and oil field services subsidiary, Lariat Services. In addition, we also drill wells for other oil and natural gas 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 also recently entered into a joint venture, Larclay, with CWEI, where we will jointly acquire 12 newly-constructed rigs to be used for drilling on CWEI’s prospects. We believe that we are one of the largest privately held drilling contractors in the United States on a footage drilled basis. We believe that our ownership of drilling rigs and our related oil field services will continue to be a major catalyst of our growth. Except for maintenance and weather downtime, all of our rigs have been operating continuously since the acquisition of our first rig in 1997. Currently, ten of our rigs are working on properties operated by us. By the end of the first quarter of 2007, we expect to be operating 42 rigs, including the 12 rigs owned by Larclay. Our rig fleet is designed to drill in our specific areas of operation and have average horsepower of 1,000 and average depth capacity of 11,300 feet.

The table below identifies certain information concerning our contract drilling operations:


	Year Ended December 31,									Nine Months Ended
										September 30,
	2002			2003			2004			2005

Number of rigs owned at end of period		3			6			10			18
Average number of rigs owned during the period		3.0			4.9			8.0			13.1
Average number of rigs utilized		3.0			4.9			8.0			13.1
Utilization rate(1)		100	%		100	%		100	%		100	%
Average drilling revenue per day(2)(3)		24,305			42,822			75,969			147,322
Average drilling revenue per rig per day(3)		8,102			8,739			9,496			11,246
Total footage drilled		240,356			317,685			635,684			1,114,741
Number of wells drilled		42			58			159			170


(1)	Utilization rate is determined by dividing the number of drilling rigs used by the average number of rigs owned during period.

(2)	Represents the total revenues from our contract drilling operations divided by the total number of days our drilling rigs were used during the period.

(3)	Does not include revenues for related rental equipment.

We currently have 18 rigs operating in West Texas, eight of which are operating on Riata-owned wells, and two rigs operating in the Piceance Basin, both of which are drilling Riata-owned wells. Including the Larclay rigs, we expect to increase these numbers to approximately 30 in West Texas, seven in the Piceance

Basin and 6 in East Texas and northern Louisiana. The 22 rigs that we expect to add in 2006 and the first quarter of 2007 (including the Larclay rigs) have been ordered from Chinese manufacturers for an aggregate purchase price of approximately $126 million, which includes the cost of equipping the rigs in the U.S. We believe this is a lower cost when compared to U.S. manufactured rigs and anticipate the arrival of these units will occur ahead of the bulk of the large order backlog of U.S. manufactured rigs. Our new rigs will have 1,000 to 2,000 horsepower, with an average depth capacity of 14,250 feet.

The following table shows the distribution of our drilling rigs as of September 30, 2005:


						September 30, 2005

		Third Party		Own Acreage		Utilization			Average Horse
		Contract		Drilling		Rate			Power

Operating Rigs:
	West Texas		11		6		100	%		1,000
	Piceance Basin		—		1		100	%		1,000
	Oklahoma		—		—		—			—

Oil Field Services

Our oil field services business began in 1986 and conducts operations that complement our drilling services operation. These services include providing pulling units, mud logging, trucking, rental tools, location and road construction and roustabout services to ourselves and to third-parties. Less than 10% of our oil field services revenues are from third-parties. We also provide underbalanced drilling systems for our own wells. We continually seek opportunities to add services in development of our integration model. Our expected capital expenditures for 2006 related to our oil field services are $84 million.

Types of Drilling Contracts

We obtain our contracts for drilling oil and natural gas 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.”

Our Customers

We perform approximately 50% of our drilling services in support of our exploration and production business. We also have significant customer relationships with other operators in West Texas, including Henry Petroleum, LP, Mariner Energy, Inc., Encore Operating, LP and Discovery Operating Inc. For the year ended December 31, 2004 and the nine months ended September 30, 2005, we generated revenues of $5.2 million and $2.5 million, respectively, for services performed for third-parties.

In addition, we expect delivery of the first of the 22 rigs from China to our Larclay joint venture in the first quarter of 2006. It is anticipated that Larclay will begin drilling wells in the first quarter of 2006 and that the majority of Larclay’s revenues will be generated by drilling for CWEI.

Midstream Gas Services

We provide gathering, compression, processing and treating services of natural gas in the TransPecos region of West Texas and the Piceance Basin, through ROC Gas, Sagebrush LLC, Integra Energy, Cholla Pipeline, Larco and PSCO₂. Our midstream operations and assets not only serve our exploration and

production business, but also service other oil and natural gas companies. The following tables set forth our primary midstream assets as of September 30, 2005:


	Plant Capacity
ROC Gas Operated Plants	(Mmcf/d)		Average Utilization(2)			Third Party Usage

Pike’s Peak		60		99	%		2	%
Pinon		4		—			—
Grey Ranch(1)		160		24	%		44	%
Sagebrush		50		n/a			n/a
Black Sulfur		3		16	%		—


(1)	The Grey Ranch plant is operated by Sid Richardson Pipeline Company.

(2)	Average utilization for January 2004 through September 2005.


	CO₂Compression
PetroSource Facilities	Capacity (Mmcf/d)		Average Utilization(1)			Third Party Usage

Pike’s Peak		38		62	%		—
Mitchell		31		36	%		—
Grey Ranch		20		49	%		—
Terrell		38		58	%		—
Puckett		11		—			—


(1)	Average utilization for nine months ended September 30, 2005.

West Texas

In Pecos County, we operate and own 57.5% of the Pike’s Peak treatment plant, which has the capacity to treat 60 Mmcf per day of raw natural gas for the removal of CO₂ from natural gas produced in the Pinon Field and nearby areas. We also have a 50% interest in the partnership that leases and operates the Grey Ranch CO₂ treatment plant located in Pecos County, which has the capacity to treat 160 Mmcf per day of raw natural gas. The treating capacities for both the Pike’s Peak and Grey Ranch plants are dependent upon the quality of natural gas being treated. The above numbers for the Pike’s Peak plant are based on a natural gas stream that is about 65% CO₂. The Grey Ranch plant capacity is an estimate of its treating capacity based on a natural gas stream that is about 70% CO₂.

We also operate or own approximately 238 miles of natural gas gathering pipelines and numerous dehydration units. Within the Pinon Field, we operate separate gathering systems for sweet natural gas and produced natural gas containing high percentages of CO_2. In addition to servicing our exploration and production business, these assets also service other oil and natural gas companies.

A portion of our West Texas assets, including the Pike’s Peak plant and approximately 52 miles of pipeline, was acquired from TXU Lone Star in 1998. We have since constructed or acquired more than 186 miles of pipeline, constructed a 4 Mmcf per day amine treating plant in the Pinon field in 2001 and acquired and expanded the only sweet gathering pipeline system within the Brown Bassett field in Terrell County in 2002. In 2003, we entered into a 50% joint venture with Sid Richardson Pipeline Company, whose primary assets are a 10-year lease on the Grey Ranch natural gas treatment plant and a 22-mile pipeline gathering system. Our three 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.

Approximately 45% of the produced natural gas gathered by our midstream assets requires compression from the wellhead to the final sales meter. We began replacing third-party rental compression through our subsidiary, Larco, in 2003. Larco currently owns and operates more than 22,000 horsepower of gas compression. Market based monthly rental fees are charged based on the gross horsepower rating of each unit.


	*Piceance Basin*

Our Piceance Basin system consists of 53 Mmcf per day of processing plants and approximately 40 miles of pipeline gathering systems. We gather and transport our natural gas and third-party natural gas to market delivery points on Questar and Rocky Mountain Natural Gas Pipelines.

Our midstream assets and operations in the Piceance Basin began in 1994 with the acquisition of the Black Sulfur Creek and Fawn Creek pipeline gathering systems and a 600 horsepower compressor from Swift Energy Company and KinderMorgan, Inc. This is a low-pressure 30-mile gathering system that gathers natural gas produced primarily in the eastern production area of our Piceance Basin acreage. A propane refrigeration plant with a capacity of 3 Mmcf per day was added to the system in 2001 to meet the gas pipeline quality specifications of Kinder Morgan’s Rocky Mountain Natural Gas Pipeline. This system currently gathers approximately 500 Mcf per day. In November 2004, we initiated the construction of a 10 mile gathering and plant residue pipeline for the Sagebrush plant, a 50 Mmcf per day plant consisting of an amine treating unit to remove CO₂ and a propane refrigeration plant to reduce the hydrocarbon content — both of which are required to meet the pipeline quality specifications of Questar Pipeline and Colorado Interstate Gas companies. Much of the pipeline gathering system and plant inlet liquid separation equipment was sized for approximately 75 Mmcf per day. The plant residue pipeline is currently connected to Questar and will be connected to Colorado Interstate Gas in the first quarter of 2006. The Sagebrush and Black Sulfur plants are expected to contribute approximately 27% of the total net income from natural gas assets for 2006.

Larco has a 1,230 horsepower compressor at the Sagebrush Plant for inlet gas compression. Larco will rent the compressor for a market-based monthly rental fee and will supply additional rental compression as production increases. Larco will also provide contract mechanical labor for the Sagebrush Plant equipment, including the two 635 horsepower propane refrigeration compressors. The requirement for additional compression for the Sagebrush Plant gathering system is approximately 160 horsepower per one Mmcf per day of natural gas production.

Capital Expenditures

The growth of our midstream assets is primarily 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. Capital requirements for pipeline expansions and associated compression in 2006 is approximately $6 million for West Texas only. We have budgeted up to an additional $13.9 million in 2006 for targeted acquisitions of strategic treatment plants and pipeline systems located in Pecos County.

Larco plans to construct an overhaul shop in the second quarter of 2006 in the West Texas area to facilitate the refurbishment of used compressors. The shop will also contain warehouse space for Larco to build and maintain inventory of parts and supplies for its compressors. Larco plans to aggressively pursue the acquisition of additional compressors in the first quarter of 2006. The inventory is necessary due to the general shortage and long lead time of high quality natural gas compressors within the industry. Capital expenditures required for the shop and additional compression will be approximately $5.0 million in 2006.

The Sagebrush plant is expected to require approximately $3.7 million in capital investment in 2006 for the expansion of its pipeline gathering system.

Marketing

Through Integra Energy, our subsidiary, we buy and sell the natural gas and oil production from Riata-operated wells and third-party operated wells. Through Integra Energy, we will purchase and sell residue gas from the Sagebrush plant and Black Sulfur plant under contract arrangements described above and manage any firm transportation contracted for on the Questar and Colorado Interstate Gas pipelines. We also manage transportation agreements on intrastate and interstate pipelines to gain access to higher-priced markets and to facilitate direct sales to end-users. 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 F.E.R.C. 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. At present, we do not have any firm transportation agreements.

We have subscribed for 10 MmBtu per day of firm transportation capacity commencing in 2007 on Questar in response to its open season. We will acquire additional firm transportation in the future as needs and availability dictate.

CO₂ Tertiary Oil Recovery Operations — PetroSource

Our CO₂ gathering and tertiary oil recovery operations are conducted through PetroSource. We currently hold a 86.5% ownership interest in PetroSource. PetroSource has invested heavily in its CO₂ pipeline and compression assets. PetroSource owns 231 miles of CO₂ pipelines in West Texas with 71,800 horsepower of owned and leased CO₂ compression. In addition, PetroSource has exclusive long-term supply contracts to gather CO₂ from natural gas treatment plants in West Texas and is the sole gatherer of CO₂ from the four natural gas treatment plants located in the Delaware and Val Verde Basins of West Texas. The primary use of our CO₂ supply is for use 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 waterflooding, 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 unrecovered. 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 product. 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 two West Texas waterfloods, the Wellman and South Mallet Units, for the purpose of implementing tertiary oil recovery operations utilizing CO₂ injection. For a discussion of our tertiary reserves and production at the units, please read “— Exploration and Production Operations — West Texas.” 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.

As of September 30, 2005, PetroSource had approximately 75 Mmcf per day of CO₂ in available supply. We currently sell the majority of this supply to Occidental Permian Ltd. and Pure Resources L.P. We believe our current tertiary oil recovery properties will require a maximum of 45 Mmcf of CO₂ per day over the next five years. We intend to increase our supply of CO₂ in order to provide sufficient capacity as our tertiary oil recovery operations expand and we seek additional third-party purchasers. We expect the supply of CO₂ to increase as additional natural gas reserves with a high CO₂ content are developed in the region. In addition, we intend to increase the capacity of our CO₂ treating, gathering and transportation assets. We are currently

refurbishing an additional compressor unit at the Grey Ranch plant at a cost of approximately $1.2 million. The unit is expected to be operational by March 2006 and will provide an additional 6,350 horsepower and 16 Mmcf per day of capacity to our system. An additional unit of same size will be refurbished for approximately $1.4 million in mid-2006.

In addition to gathering CO₂ for use in tertiary oil recovery operations, our CO₂ assets can create another economic benefit by generating Emissions Reduction Credits (“ERCs”). In recent years there has been a global effort to reach consensus on the reduction of emissions of greenhouse gases such as CO₂, including the adoption of the Kyoto Protocol. Although the United States is not party to the Kyoto Protocol, we are well positioned to benefit from the developing market for trading ERCs. We currently capture approximately 1.5 million tons of CO₂ per year. Since that CO₂ would otherwise escape into the atmosphere, the resulting capture of CO₂ generates ERCs that can be sold to parties either needing or desiring to offset their own CO₂ emissions. We have historically sold a portion of our ERCs; however, this market is still in its infancy and has not been a material source of income. In the coming years, we expect ERCs to become a greater source of income.

Other

We are engaged in certain ancillary operations in order to attract and retain employees to isolated regions of West Texas, including a family entertainment complex and a casual dining restaurant in Fort Stockton, Texas scheduled for completion in the fourth quarter of 2006. Total capital expenditures for these operations in 2006 will be approximately $6 million. We anticipate that these businesses will be self-sustaining and profitable following completion. We also make small investments in other non-energy business. From January 1, 2000 through September 30, 2005, the aggregate amount of these investments was approximately $2 million.

Competition

We believe that our leasehold acreage position, oil field service businesses, midstream assets, CO₂ supply and technical and operational capabilities generally enable us to compete effectively. However, the oil and natural gas industry is intensely competitive, and we face competition in each of our business segments.

We believe our geographic concentration of operations and vertigration model 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 oil and natural gas 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 oil and natural gas 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.

We believe our supply of CO₂, focus on small to mid-sized acquisitions and technical expertise enable us to compete effectively in our PetroSource business segment. However, we face the same competitive pressures in this segment 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 oil and natural gas operations in certain areas of the Piceance Basin. 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 various stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:


	•	require the acquisition of various permits before drilling commences;

	•	require the installation of expensive pollution control equipment;

	•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling production, transportation and processing activities;

	•	suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas;

	•	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 oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.

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 even 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.

The following is a summary of some of the existing laws, rules, and regulations to which our business operations are subject.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we generate wastes that may fall within CERCLA’s definition of hazardous substances. Therefore, governmental agencies or third-parties could seek to hold us responsible under CERCLA for all or part of the costs to clean up a site at which such 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 federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our operating expenses, which could have a material adverse effect on our results of operations and financial position.

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, 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 may require us to reduce emissions at existing facilities. As a result, we may be required to incur increased capital and operating costs. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

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. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay our development of oil and natural gas projects.

Other Laws and Regulations

In February 2005, the Kyoto Protocol to the United Nations Framework Convention on Climate Change entered into force. Pursuant to the Protocol, adopting countries are required to implement national programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming. The Bush administration has indicated it will not support ratification of the Protocol, and Congress has not actively considered recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the United States for legislation that requires reductions in greenhouse gas emissions, and some states, although not those in which we currently operate, have already adopted legislation addressing greenhouse gas emissions from certain greenhouse gas emission sources, primarily power plants. The oil and natural gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions would likely adversely impact our future operations, results of operations and financial condition. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

New and more stringent laws and regulations concerning the security of industrial facilities, including oil and natural gas facilities could be adopted in the future. Our operations may in the future be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.


	Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities, including Native American tribes. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Drilling and Production

Our operations are subject to various types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribes, in which we operate also regulate one or more of the following:


	•	the location of wells;

	•	the method of drilling and casing wells;


	•	the rates of production or “allowables;”

	•	the surface use and restoration of properties upon which wells are drilled and other third-parties;

	•	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 oil and natural gas 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 oil and natural gas 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.

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 recently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what affect, 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, non-discriminatory 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 instate 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, 2005, we have 855 full-time employees and 81 part-time employees, including 29 geologists, geophysicists, petroleum engineers and land and regulatory professionals. Of our 936 employees, 76 are located at our headquarters in Amarillo and 860 are in our field offices.

Offices

We currently lease approximately 21,223 square feet of office space in Amarillo, Texas at 701 S. Taylor Street, where our principal offices are located. The leases for our Amarillo office expire between April 2006 and December 2007. PetroSource currently leases approximately 3,529 square feet in Midland, Texas. The PetroSource lease expires in December 2008. In Fort Stockton, Texas, we own over 5,000 square feet of office space and 40,000 square feet of shop space. We also own 4,358 square feet of office space and 6,240 square feet of shop space in Odessa, Texas, which serves as the headquarters of Lariat Services. In addition, we have a field office located in Terry County, Texas and Rifle, Colorado. We believe that our office facilities are adequate for our current needs and that additional office space can be obtained if necessary.

Legal Proceedings

On May 18, 2004, we commenced a civil action seeking declaratory judgment against Elliot Roosevelt, Jr., E.R. Family Limited Partnership and Ceres Resource Partners, L.P. in the District Court of Dallas County, Texas, 101st Judicial District, Riata Energy, Inc. and Riata Piceance, LLC v. Elliot Roosevelt, Jr. et al, Cause No. 92.717-C. This suit seeks a declaratory judgment relating to the rights of the parties in and to certain leases in a defined area of mutual interest in the Piceance Basin pursuant to an acquisition agreement entered into in 1989. If this declaratory judgment is not found in our favor, the other parties involved could be entitled to up to a 25% working interest in 8,000 acres in the western portion of our Piceance Basin acreage and a 12¹/2% to 25% net profits or reversionary interest in all of our Piceance Basin acreage. Trial has been scheduled for April 2006.

On April 16, 2002, ConocoPhillips Company (“ConocoPhillips”) commenced a civil suit against us in the District Court of Pecos County, Texas, 112th Judicial District, ConocoPhillips Company (Successor by Merger to Conoco, Inc.) v. Riata Energy, Inc. et al, Cause No. 9,846. The complaint alleges that ConocoPhillips is entitled to 12.5% of the proceeds from production of certain of our lease properties in Pecos County. We believe that at most, ConocoPhillips is entitled to a 5.0% overriding royalty interest on production from wells we have drilled and completed on these leases since April 30, 1998 and that they were to bear the costs of transportation, processing and marketing associated with such wells. Conoco is claiming damages of $17.8 million, plus interest and attorneys fees. We have not taken any of the disputed interest as income. As of October 31, 2005, we had approximately $14.0 million recorded as an accrual related to this lawsuit. This accrual represents the 12.5% of the proceeds from production in which ConocoPhillips claims an interest. We have retained counsel and are engaged in mediation regarding this matter.

On April 29, 2005, Harvey E. Yates Company (“Heyco”), filed a trespass to try title suit against us in the District Court for Pecos County, Texas, 112th Judicial District, Harvey E. Yates Company v. Riata Energy, Inc., Cause No. 10376. HeyCo seeks title to an 8.33% working interest in a lease covering three sections of land and a 3.33% working interest in a lease covering 1¹/2 sections of land, each located in West Texas, as well as unspecified damages based on production attributable to these working interests. Heyco’s claims stem from the alleged failure of our predecessors in title to assign Heyco the disputed working interest in 1994. We believe that we have record title to the interest claimed by Heyco. Further, we believe Heyco’s claims are barred by the four year statute of limitations, which we believe ran in 1998. If Heyco prevails, any recovery would not have a material impact on our proved reserves. We are currently in the preliminary stages of discovery.

We are subject to other claims in the ordinary course of business. However, we believe that the ultimate resolution of the above mentioned claims and other current legal proceedings will not have a material adverse effect on our financial condition or results of operation.

MANAGEMENT

The following table sets forth information regarding our executive officers, our directors and other key employees as of February 10, 2006.


Name	Age		Position

Malone Mitchell, 3rd		44	President, Chief Executive Officer and Chairman of the Board
John Gaines		45	Chief Financial Officer
Barbara Pope		50	Vice President, Accounting
James Follis		41	Vice President, Operations
Dan Jordan		49	Vice President, Business, Director
Matthew McCann		37	Vice President, Legal
Todd Dutton		51	Chief Operating Officer, Riata
Greg West		45	Chief Operating Officer, PetroSource
Monte Bell		44	Chief Operating Officer, Gas Systems
Bill Gilliland		68	Director
Kurt G. Keene		42	Director
Ira A. Post		57	Director
Michael Harvey		58	Director

Malone Mitchell, 3rd, (President, Chief Executive Officer and Chairman) has served as our President, Chief Executive Officer and Chairman since 1989. Mr. Mitchell joined Riata as operations manager at its inception in 1984. Mr. Mitchell holds a Bachelor of Science degree in Agriculture from Oklahoma State University. Mr. Mitchell is the brother-in-law of Ms. Pope, our Vice President, Accounting.

John Gaines (Chief Financial Officer) has served as our Chief Financial Officer of Riata since September 2005. Prior to this, Mr. Gaines served as the Chief Financial Officer for PetroSource beginning in May 2004. During this time, Mr. Gaines was also employed by Gillco Investments, L.P., a private company in Amarillo, Texas. From December 2001 through April 2004, Mr. Gaines was the Director of Internal Audit for VT, Inc. in Shawnee Mission, Kansas, which is the nation’s largest privately-owned franchised auto dealership group. From June 1996 to October 2001, Mr. Gaines was a District Controller for AutoNation, Inc. and served as Chief Financial Officer, Treasurer and Director of its predecessor, Cross-Continent Auto Retailers, Inc. Mr. Gaines holds a Bachelor of Arts degree in Economics and Business Administration from Westminster College.

Barbara Pope (Vice President, Accounting) has served as our Vice President, Accounting since August 2000. Prior to this, Ms. Pope worked for us in various accounting capacities, beginning in September 1997. Ms. Pope holds a Bachelor of Science degree from Oklahoma State University. Ms. Pope is the sister-in-law of Mr. Mitchell, our Chief Executive Officer.

James Follis (Vice President, Operations) has served as our Vice President, Operations since October 2005 and has served as General Manager of our drilling program since June 1995. Mr. Follis has been employed by us in various capacities since June 1990.

Dan Jordan (Vice President, Business and Director) was appointed Vice President, Business in October 2005 and appointed as a director of Riata in December 2005. Mr. Jordan also has served as a director of PetroSource since May 2004 and served as a Vice President and director of Symbol Underbalanced Air Services and Larco from August 2003 to September 2005. Prior to joining Riata, Mr. Jordan founded Jordan Drilling Fluids, Inc. and served as its Chairman, President and Chief Executive Officer from March 1984 to July 2005. Mr. Jordan sold Jordan Drilling Fluids, Inc. and its wholly owned subsidiary, Anchor Drilling Fluids USA Inc., in August 2005. At that time, Anchor Drilling Fluids USA Inc. was the largest privately held domestic drilling fluids firm.

Matthew McCann (Vice President, Legal) has served as our Vice President, Legal since October 2005. Prior to this, he served as our General Counsel beginning in April 2001. Prior to joining Riata, Mr. McCann

practiced law with the Amarillo law firm of Sprouse, Smith & Rowley, P.C. from August 1995 to April 2001. Mr. McCann holds a Bachelor of Science in Business Administration from the University of Vermont and a Doctorate of Jurisprudence from the University of Oklahoma College of Law.

Todd Dutton (Chief Operating Officer, Riata) was appointed our Chief Operating Officer, Riata in June 2005. Mr. Dutton served as a Vice President of BEREXCO Inc., a privately owned oil and gas producer, from January 1984 to May 2005. Mr. Dutton has over 27 years of experience in exploration land activities and exploration economics. Mr. Dutton earned his Bachelor of Business Administration degree in Petroleum Land Management from the University of Oklahoma and holds a certification from the American Association of Professional Landmen as a Certified Professional Landman.

Greg West (Chief Operating Officer, PetroSource) has served as Chief Operating Officer of PetroSource since January 2004. Prior to this, Mr. West worked for Texaco and then ChevronTexaco for 17 years and was responsible for operations and asset development of Northern Permian Basin waterflood and CO₂ flood assets as well as management of the Delaware Basin gas assets. Mr. West earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University.

Monte Bell (Chief Operating Officer, Gas Systems) has served as our Chief Operating Officer, Gas Systems since July 2001. Mr. Bell has worked for us in various capacities related to our midstream business since 2000. Mr. Bell has served as a director for PetroSource since November 2003. He has over twenty years of experience in the natural gas industry and previously worked for KN Energy, KinderMorgan, Inc., Oneok Gas Marketing and Southwestern Public Service Company. Mr. Bell obtained a Bachelor of Science degree in Chemical Engineering from Texas Tech University and a Master of Science degree in Engineering Management from the University of Colorado.

Bill Gilliland (Director) was appointed as a director on January 7, 2006. Mr. Gilliland has served as managing partner of several personal and family investment partnerships, including Gillco Energy, L.P. and Gillco Investments, L.P., since April 1999. Prior to this, Mr. Gilliland was the founder, chief executive officer, president and chairman of Cross-Continent Auto Retailers, Inc. Mr. Gilliland holds a Bachelor of Business Administration from North Texas State University.

Kurt G. Keene (Director) was appointed as a director on January 7, 2006. Mr. Keene has served as a Managing Director of RSTW, a private equity firm, since 1995. Prior to this, Mr. Keene worked for Ernst & Young LLP where he began his career in 1986 and where last he served as a Senior Manager performing audit accounting and advisory services. Mr. Keene graduated with a B.B.A. in Accounting from the University of Texas in 1986.

Ira A. Post (Director) was appointed as a director on January 7, 2006. Mr. Post has been a principal of HPL&S Inc., an employee benefit consulting firm, since 1978. Prior to joining HPL&S, Inc., Mr. Post served as a tax attorney with a Chicago-based law firm. Mr. Post is a member of the Chicago, Illinois and American Bar Associations and is also a Certified Public Accountant. He has held numerous teaching positions in the areas of law and taxation in such programs as the Becker C.P.A. Review, the Masters of Science in Taxation at DePaul University, the Masters of Law in Taxation at DePaul University College of Law and the Continuing Professional Education Program of the Illinois C.P.A. Foundation. Mr. Post obtained a Bachelor of Arts in Accounting from DePaul University and a Doctorate of Jurisprudence from DePaul University College of Law.

Michael Harvey (Director) was appointed as a director on January 7, 2006. Mr. Harvey is chairman, president and chief executive officer of MBC Interests, Inc, a family owned company. Prior to forming MBC Interest Inc., he served as chairman, president and chief executive officer of Gryphon Exploration Company from it’s inception in October 2000 until it was sold to Woodside Petroleum in September 2005. Prior to founding Gryphon Exploration Company, he was president, chief executive officer and a director of Cheniere Energy, Inc. Mr. Harvey has over 33 years experience in the oil and natural gas industry, primarily in building and managing exploration and production companies. He also serves on the board of directors of Cymraec Resources, Inc, as non executive chairman. Cymraec is a privately owned onshore Gulf Coast exploration and production company based in Houston, Texas. Mr. Harvey also serves on the board of

directors of Scorpion Offshore Corporation as head of the audit committee. Scorpion is a Norwegian publicly traded offshore drilling contractor based in Houston, Texas. Mr. Harvey is a 1969 graduate of Texas A&M University, receiving his degree in Finance. He subsequently was commissioned as an officer in the U.S. Army and served as a helicopter pilot in Vietnam. Upon discharge from the U.S. Army, he attended the University of Texas as a special student, studying Petroleum Engineering and graduate level business. He also serves on the Finance Advisory Board of the Mays School of Business at Texas A&M University.

Board of Directors

Our board of directors currently consists of six members, including three independent directors — Messrs. Keene, Post and Harvey. The listing requirements of the NYSE require that our board of directors be composed of a majority of independent directors within one year of the listing of our common stock on the NYSE. Accordingly, we intend to appoint one additional independent director to our board of directors prior to or shortly following the effectiveness of this registration statement.

Our articles of incorporation and bylaws provide for a classified board of directors consisting of three classes of directors, each serving staggered three-year terms. As a result, shareholders will elect a portion of our board of directors each year. The current classification of our directors is as follows:


	•	Class I — Messrs. Mitchell and Jordan;

	•	Class II — Messrs. Gilliland and Post; and

	•	Class III — Messrs. Keene and Harvey.

Class I directors’ terms will expire at the annual meeting of shareholders to be held in 2006, Class II directors’ terms will expire at the annual meeting of shareholders to be held in 2007 and Class III directors’ terms will expire at the annual meeting of shareholders to be held in 2008. At each annual meeting of shareholders, the successors to directors whose terms will then expire will be elected to serve from the time of election until the third annual meeting following election. The division of our board of directors into three classes with staggered terms may delay or prevent a change of our management or a change in control. See “Description of Capital Stock — Anti-Takeover Effects of Provisions of Texas Law, Our Articles of Incorporation and Bylaws — Classified Board; Renewal of Directors.”

In addition, our bylaws provide that the authorized number of directors, which shall constitute the whole board of directors, may be changed by resolution duly adopted by the board of directors. Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of the total number of directors. Vacancies and newly created directorships may be filled by the affirmative vote of a majority of our directors then in office, even if less than a quorum.


	*Committees of the Board*

Audit Committee. We expect to establish an audit committee prior to the effectiveness of this registration statement. We anticipate that the audit committee will consist of three directors, each of whom will be independent under the rules of the SEC. As required by the rules of the SEC and listing standards of the NYSE, the audit committee will consist solely of independent directors. This committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements. Upon formation of the audit committee, we expect to adopt an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.

Compensation Committee. We expect to establish a compensation committee prior to the effectiveness of this registration statement. We anticipate that the compensation committee will consist of three directors,

each of whom will be “independent” under the rules of the SEC. As required by the rules of the SEC and listing standards of the NYSE, a majority of the compensation committee will be independent directors. This committee will establish salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee will also administer our incentive compensation and benefit plans. Upon formation of the compensation committee, we expect to adopt a compensation committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.

Nominating and Corporate Governance Committee. We expect to establish a nominating and corporate governance committee shortly after the effectiveness of this registration statement. We anticipate that the nominating and corporate governance committee will consist of Mr. Mitchell and two additional directors. As required by the rules of the SEC and listing standards of the NYSE, the nominating and corporate governance committee will consist of a majority of independent directors. This committee will identify, evaluate and recommend qualified nominees to serve on our board of directors, develop and oversee our internal corporate governance processes and maintain a management succession plan. Upon formation of the nominating and corporate governance committee, we expect to adopt a nominating and corporate governance committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.


	*Indemnification*

We intend to maintain directors’ and officers’ liability insurance. Our articles of incorporation and bylaws include provisions limiting the liability of directors and officers and indemnifying them under certain circumstances. We expect to enter into indemnification agreements with our officers and directors to provide our officers and directors with additional assurances in a manner consistent with Texas law.


	*Compensation Committee Interlocks and Insider Participation*

None of our executive officers serves as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our board of directors or compensation committee.


	*Director Compensation*

Directors who are our employees do not receive a retainer or fees for service on the board or any committees. We pay non-employee members of the board for their service as directors. Directors who are not employees will receive an annual fee of $30,000. In addition, the chairman of each committee will receive the following annual fees: audit committee — $15,000; compensation committee — $7,500; and nominating and corporate governance committee — $7,500. Directors who are not employees will receive a fee of $1,000 for each board meeting attended in person and a fee of $250 for attendance at a board meeting held telephonically. For committee meetings, directors who are not employees will receive a fee of $500 for each committee meeting attended in person and a fee of $250 for attendance at a committee meeting held telephonically. In addition, each non-employee director will receive a stock grant of 1,818 shares of our common stock, which will vest three years from the date of such grant. Directors are reimbursed for reasonable out-of-pocket expenses incurred in attending meetings of the board or committees and for other reasonable expenses related to the performance of their duties as directors.


	*Web Access*

We will provide access through our website at www.riataenergy.net to current information relating to governance, including a copy of each board committee charter, our Code of Conduct, our corporate governance guidelines and other matters impacting our governance principles. You may also contact our chief financial officer for paper copies of these documents free of charge once they have been adopted.

Executive Compensation and Other Information

The following table sets forth the compensation of our chief executive officer and each of our other most highly compensated executive officers serving as of December 31, 2005 for the most recent fiscal year.


										Long-Term
		Annual Compensation								Compensation

								Other Annual		Restricted Stock
Name and Principal Position		Year		Salary		Cash Bonus		Compensation(1)		Awards

Malone Mitchell, 3rd
	Chief Executive Officer		2005	$	580,210	$	—	$	11,118	$	—
James Follis
	Vice President, Operations		2005	$	94,627	$	238,472	$	62,592	$	1,240,000
Greg West
	Chief Operating Officer, PetroSource		2005	$	119,279		—	$	27,189	$	1,325,000
Monte Bell
	Chief Operating Officer, Gas Systems		2005	$	133,269	$	—	$	49,371	$	1,550,000
Todd Dutton
	Chief Operating Officer, Riata		2005	$	103,158	$	50,000	$	37,615	$	1,650,000


(1)	Includes contributions to 401(k) plans and employee drilling participation allowances.


	*Indemnification Agreements*

We will enter into indemnification agreements with each of our directors and executive officers. These agreements will require us, among other things, to indemnify our directors and officers against certain liabilities that may arise by reason of their status or service as directors or officers, to advance their expenses incurred as a result of a proceeding as to which they may be indemnified and to cover them under any directors’ and officers’ liability insurance policy we choose, in our discretion, to maintain. These indemnification agreements are intended to provide indemnification rights to the fullest extent permitted under applicable indemnification rights statutes in the State of Texas and will be in addition to any other rights that the indemnitee may have under our articles of incorporation, bylaws and applicable law.


	*Description of Stock Plan*

Scope. Our board of directors and shareholders have approved our Stock Plan (the “Plan”). The Plan authorizes the granting of stock options to purchase common stock, stock appreciation rights, restricted stock, phantom stock and other stock-based awards to our employees, directors and consultants. In addition, the Plan authorizes cash-denominated awards that may be settled in cash, stock or any combination thereof. The purpose of the Plan is to attract, retain and provide incentives to our officers, other associates, directors and consultants and to thereby increase overall shareholder value.

The Plan authorizes 7,074,252 shares of common stock to be used for awards. As of December 31, 2005, 1,552,167 shares had been awarded as restricted stock subject to vesting periods of one, four and seven years, and 5,522,085 shares were available to be used for future awards. If an award made under the Plan expires, terminates or is forfeited, canceled, settled in cash without issuance of shares of common stock covered by the award, or if award shares are used to pay for other award shares, those shares will be available for future awards under the Plan. We have not made any awards under the Plan to date.

Eligibility. Our employees, directors and consultants may be selected by the compensation committee to receive awards under the Plan. In the discretion of the compensation committee, an eligible person may receive an award in the form of a stock option, stock appreciation right, restricted stock award, phantom stock, other stock-based award or any combination thereof, including a cash-based award, and more than one award may be granted to an eligible person.

Stock Options. The Plan authorizes the award of both non-qualified and incentive stock options (“ISO”). Under the Plan and pursuant to awards made thereunder, common stock may be purchased at a fixed exercise price during a specified time. Unless otherwise provided in the award agreement, the exercise price of each share of common stock covered by a stock option shall not be less than the fair market value of the common stock on the date of the grant of such stock option, and one-third (¹/3) of the shares covered by the stock option shall become exercisable on the first anniversary of its grant and an additional one-third (¹/3) of such shares shall become exercisable on each of the second and third anniversaries of its grant. A limited number of options and SARs may be granted with an exercise price below fair market value on the date of grant, but not less than 75% of fair market value.

Under the Plan an ISO may be exercised at any time during the exercise period established by the compensation committee, except that (i) no ISO may be exercised more than three months after employment with us terminates by reason other than death or disability and (ii) no ISO may be exercised more than one year after employment with us terminates by reason of death or disability. The aggregate fair market value (determined at the time of the award) of the common stock with respect to which ISOs are exercisable for the first time by any employee during any calendar year may not exceed $100,000. The term of each ISO is determined by the compensation committee, but in no event may such term exceed 10 years from the date of grant (or five years in the case of ISOs granted to shareholders owning 10% or more of our outstanding shares of common stock). The exercise price of ISOs cannot be less than the fair market value of the common stock on the date of the grant (or 110% of the fair market value of the common stock on the date of grant in the case of ISOs granted to shareholders owning 10% or more of our outstanding shares of common stock). The exercise price of options may be paid in cash, in shares of common stock through a cashless exercise program with previously owned common stock or by such other methods as the compensation committee deems appropriate.

Stock Appreciation Rights. The Plan authorizes the grant of stock appreciation rights (“SARs”). The SARs may be granted either separately or in tandem with options. An SAR entitles the holder to receive an amount equal to the excess of the fair market value of a share of common stock at the time of exercise of the SAR over the option exercise price or other specified amount (or deemed option price in the event of an SAR that is not granted in tandem with an option), multiplied by the number of shares of common stock subject to the option or deemed option as to which the SAR is being exercised (subject to the terms and conditions of the option or deemed option). An SAR may be exercised at any time when the option or deemed option to which it related may be exercised and will terminate no later than the date on which the right to exercise the tandem option (or deemed option) terminates (or is deemed to terminate).

Restricted Stock. Restricted stock awards are grants of common stock made to eligible persons subject to restrictions, terms and conditions as established by the compensation committee. An eligible person will become the holder of shares of restricted stock free of all restrictions if he or she complies with all restrictions, terms and conditions. Otherwise, the shares will be forfeited. The eligible persons will not have the right to vote the shares of restricted stock until all restrictions, terms and conditions are satisfied.

Other Stock Based Awards. The compensation committee may grant other stock based awards, upon such terms as it may elect.

Dollar-Denominated Awards. The compensation committee may grant an award in terms of a specific dollar amount on such terms as it may elect. Upon the vesting of such award, the award earned may be paid in cash, stock or any combination thereof as the compensation committee may choose.

Adjustments. In the event of any changes in the outstanding shares of common stock by reason of any stock dividend, split, spinoff, recapitalization, merger, consolidation, combination, exchange of shares or other similar change, the aggregate number of shares with respect to which awards may be made under the Plan, and the terms and the number of shares of any outstanding option, restricted stock or other stock-based award, may be equitably adjusted by the compensation committee in its sole discretion.

the then outstanding common stock entitled to vote generally in the election of directors, changes in the composition of the board of directors, shareholder approval of certain significant corporate transactions such as a reorganization, merger, consolidation, sale of assets or the liquidation or dissolution of the company, all outstanding awards (other than the grants of seven year restricted stock) vest and become immediately exercisable and cease to be subject to the risk of forfeiture.

Administration. The Plan is administered by the board of directors or, if directed by the board of directors, the compensation committee of the board of directors or another committee designated by the board of directors (in each event, the “compensation committee”). The compensation committee makes determinations with respect to the participation of employees, directors and consultants in the Plan and, except as otherwise required by law or the Plan, the grant terms of awards, including vesting schedules, retirement and termination rights, payment alternatives such as cash, stock, contingent award or other means of payment consistent with the purposes of the Plan, and such other terms and conditions as the board or the compensation committee deems appropriate. The compensation committee has the authority at any time to provide for the conditions and circumstances under which awards shall be forfeited. The compensation committee has the authority to accelerate the vesting of any award and the time at which any award becomes exercisable.

Termination and Amendment. The board may at any time terminate the Plan or from time to time make such modifications or amendments of the Plan as it may deem advisable; provided, however, that the board shall not make any amendments to the Plan which require shareholder approval under applicable law, rule or regulation unless approved by the requisite vote of our shareholders. No termination, modification or amendment of the Plan may adversely affect the rights conferred by an award without the consent of the recipient thereof.


	*Employee Participation Plan*

Scope. We have adopted an Employee Participation Plan (the “Plan”) that allows certain employees to participate in the drilling of oil and natural gas wells in which we have an interest. It is our intention to limit participation to 5% of our interest in a well. The purpose of the plan is to associate the interest of our employees with the shareholders, maintain competitive compensation levels and provide an incentive for employees to continue employment with us. Participation in the Plan is on a prospect by prospect basis prior to drilling rather than on a well by well basis.

Eligibility. Our employees may be selected to participate in the Plan (“Participants”). Each Participant receives a monthly allowance as determined by us ranging from $2,000 to $6,000 per month. The monthly allowance is an amount a Participant is credited with each month that may be used for the satisfaction of the Participant’s share of costs incurred attributable to the Participant’s interest in acquiring, drilling, completing and operating wells. Amounts established as a monthly allowance need not be fully utilized each month and may be accumulated for future use, but may not be accumulated for more than an eleven (11) month period. The Participant’s interest in a project is subject to the terms of all operating or other agreements applicable to the project. To the extent a Participant’s monthly allowance, including any previously accumulated but unused amount, is insufficient to satisfy a Participant’s monthly obligations, the Participant must pay us such deficiency. When a Participant’s employment with us ceases, we have the right to purchase the proved developed reserves attributable to the Participant’s interest or make an assignment to the Participant of such interest. Under certain circumstances, a Participant’s interest may be forfeited to us. The aggregate cost to the company is approximately $1 million per year.

Change of Control. Upon a change in control, which is defined in the Plan to include certain third-party acquisitions of 50% or more of our then outstanding common stock or the combined voting power of the then outstanding common stock entitled to vote generally in the election of directors, changes in the composition of the board of directors, shareholder approval of certain significant corporate transactions such as a reorganization, merger, consolidation, sale of assets or the liquidation or dissolution of us, all outstanding awards vest and become immediately exercisable and cease to be subject to the risk of forfeiture.

Administration. The Plan is administered by our President or a committee designated by the President (together the “Committee”). The Committee makes determinations with respect to the participation of the employees in the Plan, the designation of projects in which the employees can participate, and such other terms and conditions as the Committee deems appropriate. The Committee has the authority at any time to allow or disallow employees from participation in the Plan, to increase or decrease the amount an employee has to invest and to make such other determinations in its discretion as it deems appropriate.

Termination and Amendment. The Committee may at any time terminate the Plan or from time to time make such modifications or amendments of the Plan as it may deem advisable. No termination, modification or amendment of the Plan may adversely affect the interest already earned by a Participant.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information with respect to the beneficial ownership of our common stock as of December 31, 2005 by:


	•	each shareholder known by us to be the beneficial owner of more than 5% of the outstanding shares of our common stock;

	•	our current directors;

	•	our five most highly compensated executive officers; and

	•	all of our directors and executive officers as a group.

For purposes of this table, beneficial ownership is determined in accordance with Rule 13d-3 promulgated under the Securities Exchange Act of 1934. The following table includes shares of restricted stock of the company held by our executive officers and directors over which they have voting power but no investment power. The following percentage information is calculated based on 73,154,130 shares of common stock that were outstanding as of February 10, 2006. Unless otherwise indicated in the footnotes to this table and subject to community property laws where applicable, we believe that each of the shareholders named in this table has sole voting and investment power with respect to the shares indicated as beneficially owned. Unless otherwise indicated, the address of each individual listed below is c/o Riata Energy, Inc., 701 S. Taylor, Suite 390, Amarillo, Texas 79101.


		Number of
		Shares
		Beneficially			Percentage of Class
Name of Beneficial Owner		Owned			Beneficially Owned

Malone Mitchell, 3rd			49,106,325	(1)		67.1
James Follis			93,213	(2)		*
Dan Jordan			1,663,333	(3)		2.3
Greg West			88,333	(2)		*
Monte Bell			108,667	(2)		*
Todd Dutton			—			*
Bill Gilliland			1,384,677	(4)		1.9
Kurt G. Keene			—			*
Ira A. Post			—			*
Michael Harvey			—			*
	Directors and officers as a group (13 persons)		53,249,694	(5)		72.8


*	Less than 1%


(1)	Includes 211,173 shares of common stock held by Mr. Mitchell’s minor children for which he has voting and dispositive power.

(2)	Consists of shares of restricted stock vesting on a one, four and seven-year vesting schedule.

(3)	Includes 103,333 shares of restricted stock vesting on a one, four and seven-year vesting schedule.

(4)	Includes 1,384,677 shares held by Gillco Energy, L.P. for which Mr. Gilliland has voting and dispositive power. Does not include 21,323 shares held by Gillco Energy, L.P. for which Mr. Gilliland has disclaimed beneficial ownership.

(5)	Includes 598,666 shares of restricted stock vesting on a one, four and seven year vesting schedule.

SELLING SHAREHOLDERS

No shareholder may offer or sell shares of our common stock under this prospectus unless such shareholder has notified us of his or her intention to sell shares of our common stock and this prospectus has been declared effective by the SEC and remains effective at the time such selling shareholder offers or sells such shares. We are required to amend this prospectus to reflect material developments in our business, financial position and results of operations. Each time we file an amendment to this prospectus with the SEC, it must first be declared effective prior to the offer or sale of shares of our common stock by the selling shareholders.

The common stock covered by this prospectus is to be offered for the account of the selling shareholders in the following table. The selling shareholders may from time to time sell all, some or none of the shares of common stock offered by this prospectus.

The following table, which we have prepared based on information provided to us by the applicable selling shareholder, sets forth the name, the number of shares of common stock beneficially owned by the selling shareholders intending to sell our common stock and the number of shares of common stock to be offered. Unless set forth below, none of the selling shareholders selling in connection with the prospectus has held any position or office with, been employed by, or otherwise has had a material relationship with us or any of our affiliates during the three years prior to the date of the prospectus.

Number of

Shares

Percentage of Shares

Beneficially

Beneficially Owned

Owned

Number of

Owned

Prior to

Shares

After

Prior to

After

Name of Beneficial Owner

Offering

Being Offered

Offering

Amaranth LLC(1)

327,868

Pioneer Funds — U.S. Small Company(2)

59,000

Pioneer Small Cap Value Fund(2)

304,500

Pioneer Small Cap Value II VTC Portfolio(2)

19,000

Pioneer Small Cap Value VTC Portfolio(2)

17,500

Total:

* Less than 1%.


(1)	Amaranth Advisors L.L.C., the trading advisor for Amaranth LLC, exercises voting and dispositive powers with respect to the shares held by Amaranth LLC. Nicholas M. Maounis is the managing member.

(2)	Pioneer Investment Management, Inc. (“PIM”), the investment advisor to such selling shareholder has or shares voting and dispositive with respect to the shares held by such selling shareholder. PIM is a privately held company, the sole shareholder of which is Pioneer Investment Management Company USA Inc. (“PIMUSA”). The sole shareholder of PIMUSA is a private Italian company named Pioneer Global Asset Management S.p.A. (“PGAM”). the parent company of PGAM is UniCreditio Italiano S.p.A, a publicly traded Italian bank.

We prepared this table based on the information supplied to us by the selling shareholders named in the table, and we have not sought to verify such information.

The selling shareholders listed in the above table may have sold or transferred, in transactions exempt from the registration requirements of the Securities Act, some or all of the shares of our common stock since the date on which the information in the above table was provided to us. Information about the selling shareholders may change over time.

Because the selling shareholders may offer all or some of their shares of our common stock from time to time, we cannot estimate the number of shares of our common stock that will be held by the selling shareholders upon the termination of any particular offering by such selling shareholder. Please refer to “Plan of Distribution.”

PLAN OF DISTRIBUTION

We are registering the common stock covered by this prospectus to permit selling shareholders to conduct public secondary trading of these shares from time to time after the date of this prospectus. In connection with our December 2005 private placement, we entered into a Registration Rights Agreement with the selling shareholders, pursuant to which we agreed to, among other things, bear all expenses, other than brokers’ or underwriters’ discounts and commissions, in connection with the registration and sale of the common stock covered by this prospectus. We will not receive any of the proceeds of the sale of the common stock offered by this prospectus. The aggregate proceeds to the selling shareholders from the sale of the common stock will be the purchase price of the common stock less any discounts and commissions. A selling shareholder reserves the right to accept and, together with their agents, to reject, any proposed purchases of common stock to be made directly or through agents.

The common stock offered by this prospectus may be sold from time to time to purchasers:


	•	directly by the selling shareholders and their successors, which includes their donees, pledgees or transferees or their successors-in-interest, or

	•	through underwriters, broker-dealers or agents, who may receive compensation in the form of discounts, commissions or agent’s commissions from the selling shareholders or the purchasers of the common stock. These discounts, concessions or commissions may be in excess of those customary in the types of transactions involved.

The selling shareholders and any underwriters, broker-dealers or agents who participate in the sale or distribution of the common stock may be deemed to be “underwriters” within the meaning of the Securities Act. The selling shareholders identified as registered broker-dealers in the selling shareholders table above (under “Selling Shareholders”) are deemed to be underwriters. As a result, any profits on the sale of the common stock by such selling shareholders and any discounts, commissions or agent’s commissions or concessions received by any such broker-dealer or agents may be deemed to be underwriting discounts and commissions under the Securities Act. Selling shareholders who are deemed to be “underwriters” within the meaning of Section 2(11) of the Securities Act will be subject to prospectus delivery requirements of the Securities Act. Underwriters are subject to certain statutory liabilities, including, but not limited to, Sections 11, 12 and 17 of the Securities Act.

The common stock may be sold in one or more transactions at:


	•	fixed prices;

	•	prevailing market prices at the time of sale;

	•	prices related to such prevailing market prices;

	•	varying prices determined at the time of sale; or

	•	negotiated prices.

These sales may be effected in one or more transactions:


	•	on any national securities exchange or quotation on which the common stock may be listed or quoted at the time of the sale;

	•	in the over-the-counter market;

	•	in transactions other than on such exchanges or services or in the over-the-counter market;

	•	through the writing of options (including the issuance by the selling shareholders of derivative securities), whether the options or such other derivative securities are listed on an options exchange or otherwise;

	•	through the settlement of short sales; or

	•	through any combination of the foregoing.

These transactions may include block transactions or crosses. Crosses are transactions in which the same broker acts as an agent on both sides of the trade.

In connection with the sales of the common stock, the selling shareholders may enter into hedging transactions with broker-dealers or other financial institutions which in turn may:


	•	engage in short sales of the common stock in the course of hedging their positions;

	•	sell the common stock short and deliver the common stock to close out short positions;

	•	loan or pledge the common stock to broker-dealers or other financial institutions that in turn may sell the common stock;

	•	enter into option or other transactions with broker-dealers or other financial institutions that require the delivery to the broker-dealer or other financial institution of the common stock, which the broker-dealer or other financial institution may resell under the prospectus; or

	•	enter into transactions in which a broker-dealer makes purchases as a principal for resale for its own account or through other types of transactions.

To our knowledge, there are currently no plans, arrangements or understandings between any selling shareholders and any underwriter, broker-dealer or agent regarding the sale of the common stock by the selling shareholders.

We intend to apply to list our common stock on NYSE under the symbol REI. However, we can give no assurances as to the development of liquidity or any trading market for the common stock.

There can be no assurance that any selling shareholder will sell any or all of the common stock under this prospectus. Further, we cannot assure you that any such selling shareholder will not transfer, devise or gift the common stock by other means not described in this prospectus. In addition, any common stock covered by this prospectus that qualifies for sale under Rule 144 or Rule 144A of the Securities Act may be sold under Rule 144 or Rule 144A rather than under this prospectus. The common stock covered by this prospectus may also be sold to non-U.S. persons outside the U.S. in accordance with Regulation S under the Securities Act rather than under this prospectus. The common stock may be sold in some states only through registered or licensed brokers or dealers. In addition, in some states the common stock may not be sold unless it has been registered or qualified for sale or an exemption from registration or qualification is available and complied with.

The selling shareholders and any other person participating in the sale of the common stock will be subject to the Exchange Act. The Exchange Act rules include, without limitation, Regulation M, which may limit the timing of purchases and sales of any of the common stock by the selling shareholders and any other such person. In addition, Regulation M may restrict the ability of any person engaged in the distribution of the common stock to engage in market-making activities with respect to the particular common stock being distributed. This may affect the marketability of the common stock and the ability of any person or entity to engage in market-making activities with respect to the common stock.

We have agreed to indemnify the selling shareholders against certain liabilities, including liabilities under the Securities Act.

We have agreed to pay substantially all of the expenses incidental to the registration, offering and sale of the common stock to the public, including the payment of federal securities law and state blue sky registration fees, except that we will not bear any underwriting discounts or commissions or transfer taxes relating to the sale of shares of our common stock.

RELATED PARTY TRANSACTIONS

The following is a discussion of transactions between us and our officers, directors and beneficial owners of more than 5% of our common stock.

Mr. Mitchell, our Chief Executive Officer, and his family, on September 30, 2005, traded 2.5% of our then outstanding common stock to us for our 100% interest in Longfellow Ranch Partners, LP (“Longfellow”). Longfellow owns surface and/or minerals or royalty under a significant amount of our exploration and development lands in West Texas, including the Longfellow Ranch. We have oil and natural gas leaseholds that cover all of Longfellow’s minerals. Under the leases, we will pay Longfellow royalties, based on production. The lease is for a seven-year primary term, with the option of extending the primary term another three years by paying a market value bonus. The lease royalty is 20% for wells completed before 2009, escalating to 25% in 2012. At the end of the primary term, the lease will break into approximately 3,000-acre tracts, and each tract will be subject to a 120-day continuous development clause. We also have an agreement with Longfellow for use of the surface of the Longfellow Ranch. Under this agreement, we pay Longfellow fees, pursuant to a set schedule, for use of the surface for our oil and natural gas operations and for damages and rights of way. We believe the rates are equivalent to, or less than, the rates paid to other landowners in the area. Because the Mitchell family only recently acquired Longfellow, there has not been any meaningful royalty or damage payments made to date. However, we expect substantial payments to be made. For 2002, 2003, 2004 and the nine months ended September 30, 2005, income (loss) from Longfellow’s operations were $366,000, ($128,000), $683,000 and $638,000, respectively. These numbers included, among other things, royalties, damages and agricultural operations on the lands, minerals and royalties now indirectly owned by the Mitchell family. In addition, to his involvement with Longfellow, Mr. Mitchell owns small working interests in some of our wells and a small interest in our Cholla Pipeline. For the years 2002, 2003, 2004 and the nine months ended September 30, 2005, we paid Mr. Mitchell $60,000, $134,000, $147,000 and $146,000, respectively. Any material transaction with family members of Mr. Mitchell will be approved by a committee consisting of independent directors.

Mr. Jordan, a director and Vice President, Business, has participated in projects since 2000. As part of our December 2005 acquisitions, we acquired Mr. Jordan’s interests in our Piceance Basin Project, West Texas undeveloped acreage and Larco for 1,418,182 shares of common stock. Mr. Jordan currently owns working interests in much of our production in West Texas, a small interest in our marketing company, and a 12.5% interest in PetroSource. For the years 2002, 2003, 2004 and the nine months ended September 30, 2005, we recognized the capital contributions from Mr. Jordan of $593,000, $4,274,000, $1,353,000 and $4,377,000, respectively. For the same periods, we paid Mr. Jordan $242,000, $1,509,000, $1,532,000 and $1,455,000, respectively. From August 2002 until Mr. Jordan became Vice President, Business in October 2005, he received consulting fees from Larco of $40,000 per month.

Mr. Gilliland, a director, assisted us in the acquisition of the PetroSource assets and owned an approximate 18.8% interest through Gillco Energy, L.P. Through that same entity, he has also participated in our Piceance Basin Project, and various drilling projects in Missouri and Nevada. As part of our December 2005 acquisitions, we acquired ownership interests in PetroSource, our Piceance Basin acreage and our Missouri and Nevada acreage from Gillco Energy, L.P. for 1,406,000 shares of common stock. Mr. Gaines worked for Mr. Gilliland before he became our CFO.

Mr. McCann, Vice President, Legal, as part of our December 2005 acquisitions, sold his interest in PetroSource to us for $135,000 in cash. In addition he owns small working interests in most of our wells drilled since 2001, an interest in Cholla Pipeline and an interest in Sagebrush Pipeline, LLC. Excluding PetroSource, for 2002, 2003, 2004 and the nine months ended September 30, 2005, we recognized capital contributions from Mr. McCann of $15,000, $36,000, $192,000 and $210,000, respectively, and we paid Mr. McCann $21,000, $88,000, $143,000 and $113,000, respectively. Mr. McCann also owns a small interest in a business in which we own a minority interest and owned a small interest in a business in which we owned a minority interest. That business was sold in 2005.

Mr. Follis, Vice President, Operations, as part of our December 2005 acquisitions, sold his interest in PetroSource to us for $144,000 worth of common stock. In addition, he owns small working interests in most

of our wells drilled, an interest in Cholla Pipeline and an interest in Sagebrush Pipeline, LLC. Excluding PetroSource, for 2002, 2003, 2004 and the nine months ended September 30, 2005, we recognized capital contributions from Mr. Follis of $21,000, $35,000, $61,000 and $19,000, respectively, and we paid Mr. Follis $57,000, $233,000, $206,000 and $156,000, respectively.

Mrs. Pope, Vice President, Accounting, as part of our December 2005 acquisitions, sold her interest in PetroSource to us for $31,000 in cash. In addition she owns small working interests in most of our wells drilled since 2003, an interest in Cholla Pipeline and an interest in Sagebrush Pipeline, LLC. Excluding PetroSource, for 2002, 2003, 2004 and the nine months ended September 30, 2005, we recognized capital contributions from Mrs. Pope of $41,000, $1,000, $14,000 and $8,000, respectively, and we paid Mrs. Pope $2,000, $33,000, $48,000 and $39,000, respectively.

Mr. Bell, Chief Operating Officer, Gas, as part of our December 2005 acquisitions, sold his interest in PetroSource to us for $80,000 worth of common stock and $106,000 in cash. In addition, he owns small working interests in most of our wells drilled since 2003, a 5% interest in Integra Energy, a 5% interest in our Brown Basset gathering system, and an interest in Sagebrush Pipeline, LLC. Excluding PetroSource, for 2002, 2003, 2004 and the nine months ended September 30, 2005, we recognized capital contributions from Mr. Bell of $26,000, $3,000, $50,000 and $33,000, respectively, and we paid Mr. Bell $4,000, $35,000, $66,000 and $52,000, respectively.

DESCRIPTION OF CAPITAL STOCK

Our authorized capital stock will consist of 400,000,000 shares of common stock, par value $0.001 per share, and 50,000,000 shares of preferred stock, no par value. As of the date of this prospectus, we have outstanding shares of common stock and no outstanding shares of preferred stock. We have no outstanding options to purchase common stock, however, we have granted restricted stock awards for approximately shares.

Common Stock

Subject to any special voting rights of any series of preferred stock that we may issue in the future, each share of common stock has one vote on all matters voted on by our shareholders, including the election of our directors. Because holders of common stock do not have cumulative voting rights, the holders of a majority of the shares of common stock can elect all of the members of the board of directors standing for election, subject to the rights, powers and preferences of any outstanding series of preferred stock.

No share of common stock affords any preemptive rights or is convertible, redeemable, assessable or entitled to the benefits of any sinking or repurchase fund. Holders of common stock will be entitled to dividends in the amounts and at the times declared by our board of directors in its discretion out of funds legally available for the payment of dividends.

Holders of common stock will share equally in our assets on liquidation after payment or provision for all liabilities and any preferential liquidation rights of any preferred stock then outstanding. All outstanding shares of common stock are fully paid and non-assessable.

Preferred Stock

At the direction of our board, we may issue shares of preferred stock from time to time. Our board of directors may, without any action by holders of the common stock:


	•	adopt resolutions to issue preferred stock in one or more classes or series;

	•	fix or change the number of shares constituting any class or series of preferred stock; and

	•	establish or change the rights of the holders of any class or series of preferred stock.

The rights of any class or series of preferred stock may include, among others:


	•	general or special voting rights;

	•	preferential liquidation or preemptive rights;

	•	preferential cumulative or noncumulative dividend rights;

	•	redemption or put rights; and

	•	conversion or exchange rights.

We may issue shares of, or rights to purchase, preferred stock the terms of which might:


	•	adversely affect voting or other rights evidenced by, or amounts otherwise payable with respect to, the common stock;

	•	discourage an unsolicited proposal to acquire us; or

	•	facilitate a particular business combination involving us.

Any of these actions could discourage a transaction that some or a majority of our shareholders might believe to be in their best interests or in which our shareholders might receive a premium for their stock over its then market price.

Anti-Takeover Provisions of Texas Law, Our Articles of Incorporation and Bylaws

The provisions of Texas law and our articles of incorporation and bylaws we summarize below may have an anti-takeover effect and may delay, defer or prevent a tender offer or takeover attempt that a shareholder might consider in his or her best interest, including those attempts that might result in a premium over the market price for the common stock.

Business Combinations Under Texas Law

We are a Texas corporation and, upon completion of the offering, will be subject to Part Thirteen of the Texas Business Corporation Act, known as the “Business Combination Law.” In general, this law will prevent us from engaging in a business combination with an affiliated shareholder, or any affiliate or associate of an affiliated shareholder, for a three-year period after the date such person became an affiliated shareholder, unless:


	•	our board of directors approves the acquisition of shares that causes such person to become an affiliated shareholder before the date such person becomes an affiliated shareholder,

	•	our board of directors approves the business combination before the date such person becomes an affiliated shareholder, or

	•	holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder or its affiliates or associates approve the business combination within six months after the date such person becomes an affiliated shareholder.

Under this law, any person that owns or has owned 20% or more of our voting shares during the preceding three-year period is an “affiliated shareholder.” The law defines “business combination” generally as including:


	•	mergers, share exchanges or conversions involving an affiliated shareholder,

	•	dispositions of assets involving an affiliated shareholder:


	—	having an aggregate value equal to 10% or more of the market value of our assets,

	—	having an aggregate value equal to 10% or more of the market value of our outstanding common stock, or

	—	representing 10% or more of our earning power or net income,


	•	issuances or transfers of securities by us to an affiliated shareholder other than on a pro rata basis,

	•	plans or agreements relating to our liquidation or dissolution involving an affiliated shareholder,

	•	reclassifications, recapitalizations, mergers or other transactions that would have the effect of increasing an affiliated shareholder’s percentage ownership of our outstanding voting stock, and

	•	the receipt of tax, guarantee, pledge, loan or other financial benefits by an affiliated shareholder other than proportionally as one of our shareholders.

Written Consent of Shareholders

Our articles of incorporation provide that any action by our shareholders must be taken at an annual or special meeting of shareholders. Special meetings of the shareholders may be called only by holders of not less than 50% of all the shares entitled to vote.

Advance Notice Procedure for Shareholder Proposals

Our bylaws establish an advance notice procedure for the nomination of candidates for election as directors as well as for shareholder proposals to be considered at annual meetings of shareholders. In general,

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notice of intent to nominate a director must contain specific information concerning the person to be nominated and must be delivered to or mailed and received at our principal executive offices as follows:


	•	With respect to an election to be held at the annual meeting of shareholders, not less than 90 days nor more than 120 days prior to the first anniversary date of the preceding year’s annual meeting of shareholders.

	•	With respect to an election to be held at a special meeting of shareholders for the election of directors, not earlier than the close of business on the 120th day prior to the special meeting and not later than the close of business on the later of the 90th day prior to the special meeting or the 10th day following the day on which public disclosure is first made of the date of the special meeting.

Notice of shareholders’ intent to raise business at an annual meeting must be delivered to or mailed and received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary date of the preceding year’s annual meeting of shareholders. These procedures may operate to limit the ability of shareholders to bring business before a shareholders meeting, including with respect to the nomination of directors or considering any transaction that could result in a change of control.

Classified Board; Removal of Director

Our bylaws provide that the members of our board of directors are divided into three classes as nearly equal as possible. Each class is elected for a three-year term. At each annual meeting of shareholders, approximately one-third of the members of the board of directors are elected for a three-year term and the other directors remain in office until their three-year terms expire. Furthermore, our bylaws provide that neither any director nor the board of directors may be removed without cause, and that any removal for cause would require the affirmative vote of the holders of at least a majority of the voting power of the outstanding capital stock entitled to vote for the election of directors. Thus, control of the board of directors cannot be changed in one year without removing the directors for cause as described above; rather, at least two annual meetings must be held before a majority of the members of the board of directors could be changed.

Limitation of Liability of Directors

Our articles of incorporation provide that no director shall be personally liable to us or our shareholders for monetary damages for breach of fiduciary duty as a director, except for liability as follows:


	•	for any breach of the director’s duty of loyalty to us or our shareholders;

	•	for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

	•	for an act or omission for which the liability of a director is expressly provided by an applicable statute; and

	•	for any transaction from which the director derived an improper personal benefit.

The effect of these provisions is to eliminate our rights and the rights of our shareholders, through derivative suits on our behalf, to recover monetary damages against a director for a breach of fiduciary duty as a director, including breaches resulting from grossly negligent behavior, except in the situations described above.

Transfer Agent and Registrar

The transfer agent and registrar of our common stock is American Stock Transfer & Trust Company.

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CERTAIN U.S. TAX CONSEQUENCES TO NON-U.S. HOLDERS

The following is a general discussion of the principal U.S. federal income and estate tax consequences of the ownership and disposition of our common stock by a non-U.S. holder. As used in this discussion, the term “non-U.S. holder” means a beneficial owner of our common stock that is not, for U.S. federal income tax purposes:


	•	an individual who is a citizen or resident of the United States;

	•	a corporation or partnership (including any entity treated as a corporation or partnership for U.S. federal income tax purposes) created or organized in or under the laws of the United States, or of any political subdivision of the United States (unless, in the case of a partnership, U.S. Treasury Regulations are adopted which provide otherwise);

	•	an estate whose income is subject to U.S. federal income taxation regardless of its source; or

	•	a trust, if a U.S. court is able to exercise primary supervision over the administration of the trust and one or more United States persons have authority to control all substantial decisions of the trust, or if it has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a United States person.

An individual may be treated as a resident of the United States in any calendar year for U.S. federal income tax purposes, instead of a nonresident, by, among other ways, being present in the United States for at least 31 days in that calendar year and for an aggregate of at least 183 days during a three-year period ending in the current calendar year. For purposes of the 183-day calculation, all of the days present in the current year, one-third of the days present in the immediately preceding year and one-sixth of the days present in the second preceding year are counted. Residents are taxed for U.S. federal income tax purposes as if they were U.S. citizens. This discussion does not consider:


	•	U.S. state or local or non-U.S. tax consequences;

	•	all aspects of U.S. federal income and estate taxes or specific facts and circumstances that may be relevant to a particular non-U.S. holder’s tax position, including the fact that in the case of a non-U.S. holder that is an entity treated as a partnership for U.S. federal income tax purposes, the U.S. tax consequences of holding and disposing of our common stock may be affected by certain determinations made at the partner level;

	•	the tax consequences for the shareholders, partners or beneficiaries of a non-U.S. holder;

	•	special tax rules that may apply to particular non-U.S. holders, such as financial institutions, insurance companies, tax-exempt organizations, U.S. expatriates, broker-dealers, and traders in securities; or

	•	special tax rules that may apply to a non-U.S. holder that holds our common stock as part of a “straddle,” “hedge,” “conversion transaction,” “synthetic security” or other integrated investment.

The following discussion is based on provisions of the U.S. Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed U.S. Treasury Regulations and administrative and judicial interpretations, all as of the date of this prospectus, and all of which are subject to change, retroactively or prospectively. The following summary assumes that a non-U.S. holder holds our common stock as a capital asset. Each non-U.S. holder should consult a tax advisor regarding the U.S. federal, state, local and non-U.S. income and other tax consequences of acquiring, holding and disposing of shares of our common stock.

Distributions on Common Stock

We do not expect to pay any cash distributions on our common stock in the foreseeable future; however, in the event that we do make such cash distributions, these distributions generally will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Any amount paid in excess of such earnings and profits

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generally will be treated as a recovery of tax basis, to the extent thereof, and then gain from sale. See “Disposition of Common Stock,” below, for additional discussion of the federal income tax treatment of distributions in excess of earnings and profits. Distributions paid to non-U.S. holders of our common stock that are not effectively connected with the non-U.S. holder’s conduct of a U.S. trade or business generally will be subject to U.S. withholding tax at a 30% rate, or if a tax treaty applies, a lower rate specified by the treaty. Non-U.S. holders should consult their tax advisors regarding their entitlement to benefits under a relevant income tax treaty.

Dividends that are effectively connected with a non-U.S. holder’s conduct of a trade or business in the United States and, if an income tax treaty applies, are attributable to a permanent establishment in the United States, are taxed on a net income basis at the regular graduated rates and in the manner applicable to United States persons. In that case, we will not have to withhold U.S. federal withholding tax if the non-U.S. holder complies with applicable certification and disclosure requirements. In addition, a “branch profits tax” may be imposed at a 30% rate, or a lower rate under an applicable income tax treaty, on dividends received by a foreign corporation that are effectively connected with its conduct of a trade or business in the United States.

A non-U.S. holder that claims the benefit of an applicable income tax treaty generally will be required to satisfy applicable certification and other requirements. However,


	•	in the case of common stock held by a foreign partnership, the certification requirement will generally be applied to the partners of the partnership and the partnership will be required to provide certain information;

	•	in the case of common stock held by a foreign trust, the certification requirement will generally be applied to the trust or the beneficial owners of the trust depending on whether the trust is a “foreign complex trust,” “foreign simple trust” or “foreign grantor trust” as defined in the U.S. Treasury Regulations; and

	•	look-through rules will apply for tiered partnerships, foreign simple trusts and foreign grantor trusts.

A non-U.S. holder that is a foreign partnership or a foreign trust is urged to consult its own tax advisor regarding its status under these U.S. Treasury Regulations and the certification requirements applicable to it.

A non-U.S. holder that is eligible for a reduced rate of U.S. federal withholding tax under an income tax treaty may obtain a refund or credit of any excess amounts withheld by filing an appropriate claim for refund with the U.S. Internal Revenue Service.

Disposition of Common Stock

We believe that we are a United States real property holding corporation. Generally, a corporation is a United States real property holding corporation if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. Notwithstanding our status as a United States real property holding corporation, a non-U.S. holder of our common stock generally will not be subject to U.S. federal income tax on gain recognized on a disposition of our common stock unless:


	•	the gain is effectively connected with the non-U.S. holder’s conduct of a trade or business in the United States and, if an income tax treaty applies, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States; in these cases, the gain will be taxed on a net income basis at the rates and in the manner applicable to United States persons, and if the non-U.S. holder is a foreign corporation, the branch profits tax described above may also apply;

	•	the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of the disposition and meets other requirements; or

	•	our common stock is not considered to be “regularly traded on an established securities market,” within the meaning of section 897 of the Code and the applicable Treasury Regulations, at some time during the calendar year in which the sale or other disposition occurs, or the non-U.S. holder actually

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		or constructively owns more than five percent of our common stock at any time during the shorter of the five-year period ending on the date of disposition or the period that the non-U.S. holder held our common stock.

It is likely that our common stock will not be considered “regularly traded on an established securities market” prior to the effectiveness of the registration statement governing the resale of such stock. In addition, even after the registration statement becomes effective, it is possible that our common stock will not be considered regularly traded if it is not regularly quoted by brokers or dealers making a market in our common stock. If our common stock is not considered to be “regularly traded on an established securities market,” a non-U.S. holder may be subject to withholding tax on any proceeds from a disposition of such stock at a 10% rate and the non-U.S. holder generally will be subject to tax on its net gain derived from the disposition at the regular U.S. federal income tax rates applicable to U.S. persons (subject to a credit for any tax withheld). If the non-U.S. holder subject to tax in this manner is a foreign corporation, the additional “branch profits tax” described above may also apply.

Similarly, if we make any distribution to a non-U.S. holder in excess of our current and accumulated earnings and profits, the distribution will be subject to withholding of tax, and the non-U.S. holder generally will be taxed on its net gain, if any, derived from the receipt of the distribution at the regular U.S. federal income tax rates applicable to U.S. persons (subject to a credit for any tax withheld). If the non-U.S. holder subject to tax in this manner is a foreign corporation, the additional “branch profits tax” described above may also apply. Non-United States holders should consult their own tax advisors with respect to the application of the foregoing rules.

U.S. Federal Estate Tax

Common stock owned or treated as owned by an individual who is a non-U.S. holder for U.S. federal estate tax purposes at the time of death will be included in the individual’s gross estate for U.S. federal estate tax purposes, unless an applicable estate tax or other treaty provides otherwise, and therefore may be subject to U.S. federal estate tax.

Information Reporting and Backup Withholding Tax

Generally, we must report annually to any non-U.S. holder and the U.S. Internal Revenue Service the amount of any dividends paid to such holder, the holder’s name and address, and the amount, if any, of tax withheld. Copies of the information returns reporting those dividends and amounts withheld also may be made available to the tax authorities in the country in which the non-U.S. holder resides under the provisions of any applicable tax treaty or exchange of information agreement.

In addition to information reporting requirements, dividends paid to a non-U.S. holder may be subject to U.S. backup withholding tax. A non-U.S. holder generally will be exempt from this backup withholding tax, however, if such holder properly provides a Form W-8BEN certifying that such holder is a non-U.S. person or otherwise establishes an exemption and we do not know or have reason to know that the holder is a U.S. person.

The gross proceeds from the disposition of our common stock may be subject to information reporting and backup withholding. If a non-U.S. holder sells shares of our common stock outside the United States through a non-U.S. office of a non-U.S. broker and the sales proceeds are paid to such holder outside the United States, then the U.S. backup withholding and information reporting requirements generally will not apply to that payment. However, U.S. information reporting, but not backup withholding, generally will apply

104

to a payment of sales proceeds, even if that payment is made outside the United States, if the non-U.S. holder sells shares of our common stock through a non-U.S. office of a broker that:


	•	is a United States person;

	•	derives 50% or more of its gross income in specific periods from the conduct of a trade or business in the United States;

	•	is a “controlled foreign corporation” for U.S. federal tax purposes; or

	•	is a foreign partnership, if at any time during its tax year:


	—	one or more of its partners are United States persons who in the aggregate hold more than 50% of the income or capital interests in the partnership; or

	—	the foreign partnership is engaged in a U.S. trade or business,

unless the broker has documentary evidence in its files that the holder is not a U.S. person and certain other conditions are met, or the holder otherwise establishes an exemption.

If a non-U.S. holder receives payments of the proceeds of a sale of our common stock to or through a U.S. office of a broker, the payment will be subject to both U.S. backup withholding and information reporting unless such holder properly provides a Form W-8BEN certifying that such holder is not a U.S. person or otherwise establishes an exemption, and we do not know or have reason to know that such holder is a U.S. person.

A non-U.S. holder generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed such holder’s U.S. federal income tax liability by timely filing a properly completed claim for refund with the U.S. Internal Revenue Service.

LEGAL MATTERS

The validity of the shares offered hereby will be passed upon for us by Vinson & Elkins L.L.P.

EXPERTS

The financial statements of Riata Energy, Inc. as of December 31, 2004 and 2003 and for each of the three years in the period ended December 31, 2004 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 financial statements of PetroSource Energy Company as of December 31, 2004 and for the year ended December 31, 2004 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 information included in this prospectus regarding estimated quantities of proved reserves, the future net revenues from those reserves and their present value is based, in part, on estimates of the proved reserves and present values of proved reserves as of December 31, 2003 and 2004 and September 30, 2005, in each case prepared or derived from estimates prepared by DeGolyer & MacNaughton, independent petroleum engineers, for our West Texas properties (excluding the Brooklaw Field). DeGolyer & MacNaughton also prepared our September 30, 2005 Piceance Basin reserve report. Michael Harper & Associates prepared our reports for Brooklaw Field, certain Oklahoma properties and the Piceance Basin for December 31, 2003 and 2004. These estimates are included in this prospectus in reliance upon the authority of the firm as experts in these matters.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act with respect to the common stock being sold in this offering. This prospectus, which forms part of the registration statement, does not contain all of the information set forth in the registration statement and the exhibits and

105

schedules to the registration statement. For further information with respect to us and our common stock being sold in this offering, we refer you to the registration statement and the exhibits and schedules filed as a part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other document are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit and is qualified in all respects by the filed exhibit. The registration statement, including exhibits and schedules filed, may be inspected without charge at the Public Reference Room of the SEC at 100 F Street, NE, Washington, D.C. 20549, and copies of all or any part of it may be obtained from that office after payment of fees prescribed by the SEC. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. The other information we file with the SEC is not part of the registration statement of which this prospectus forms a part.

Following the effectiveness of this registration statement, we will file annual, quarterly and current reports, proxy statements and other information with the SEC. We intend to make these filings available on our website at http://www.riataenergy.net once the offering is completed. Information on, or accessible through, this website is not a part of, and is not incorporated into, this prospectus. In addition, we will provide copies of our filings free of charge to our stockholders upon request.

106

INDEX TO FINANCIAL STATEMENTS


Riata Energy, Inc. Audited Financial Statements
	Report of Independent Registered Public Accounting Firm	F-2
	Consolidated Balance Sheets as of December 31, 2003 and 2004	F-3
	Consolidated Statements of Operations for the Years Ended December 31, 2002, 2003, and 2004	F-4
	Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2002, 2003, and 2004	F-5
	Consolidated Statements of Cash Flow for the Years Ended December 31, 2002, 2003, and 2004	F-6
	Notes to Consolidated Financial Statements	F-7

Riata Energy, Inc. Unaudited Financial Statements
	Condensed Consolidated Balance Sheets as of December 31, 2004, and September 30, 2005	F-27
	Condensed Consolidated Statements of Operations for the Nine Months Ended September 30, 2004 and 2005	F-28
	Condensed Consolidated Statements of Cash Flow for the Nine Months Ended September 30, 2004 and 2005	F-29
	Notes to Condensed Consolidated Financial Statements	F-30

PetroSource Energy Company Audited Financial Statements
	Report of Independent Registered Public Accounting Firm	F-38
	Consolidated Balance Sheet as of December 31, 2004	F-39
	Consolidated Statement of Operations for the Year Ended December 31, 2004	F-40
	Consolidated Statement of Stockholders’ Equity for the Year Ended December 31, 2004	F-41
	Consolidated Statement of Cash Flows for the Year Ended December 31, 2004	F-42
	Notes to Consolidated Financial Statements	F-43

PetroSource Energy Company Unaudited Financial Statements
	Condensed Consolidated Balance Sheets as of December 31, 2004 and September 30, 2005	F-49
	Condensed Consolidated Statements of Operations for the Nine Months Ended September 30, 2004 and 2005	F-50
	Condensed Consolidated Statements of Cash Flow for the Nine Months Ended September 30, 2004 and 2005	F-51
	Notes to Condensed Consolidated Financial Statements	F-52

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

and Stockholders of Riata Energy, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Riata Energy, Inc. and its subsidiaries (the “Company”) at December 31, 2003 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, 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 auditing 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.

As described in Note 1 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003.

PricewaterhouseCoopers LLP

December 5, 2005, except for Note 19 as to which date is December 19, 2005

Houston, Texas

F-2

Riata Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(in thousands except per share amounts)


				As of December 31,

				2003		2004

ASSETS
Current assets:
	Cash and cash equivalents			$	176	$	12,973
	Accounts receivable, net:
		Trade			27,345		33,436
		Related parties			1,018		1,116
	Inventories				1,079		1,560
	Held for sale				—		14
	Deferred income taxes				11		442
	Other current assets				1,389		1,975

			Total current assets		31,018		51,516
Property, plant and equipment, net					60,841		99,188
Intangibles, net					—		214
Investments					4,592		5,281
Held for sale					20,882		22,504
Deferred income taxes					—		2,184
Other assets					963		500

			Total assets	$	118,296	$	181,387


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Current maturities of long-term debt			$	19,933	$	3,202
	Accounts payable:
		Trade			31,400		41,180
		Related parties			339		3,757
	Accrued expenses				12,861		14,269
	Derivative contracts				2,097		689

			Total current liabilities		66,630		63,097
Long-term debt					4,807		56,318
Derivative contracts					542		147
Asset retirement obligation					3,883		4,394
Held for sale					6,366		6,366
Deferred income taxes					6,507		—

			Total liabilities		88,735		130,322

Commitments and contingencies (Note 13)
Minority interest					1,710		1,894
Stockholders’ equity:
	Preferred stock, no par; 500,000 shares authorized; 1,000 shares issued and outstanding in 2003 and 2004				23		23
	Common stock, $0.001 par value, 400,000,000 shares authorized; 56,312,400 shares issued and outstanding in 2003 and 2004*				200		200
	Retained earnings				27,628		48,948

			Total stockholders’ equity		27,851		49,171

			Total liabilities and stockholders’ equity	$	118,296	$	181,387


*	Restated to reflect a 281.562 for 1 stock split effected in December 2005

The accompanying notes are an integral part of these consolidated financial statements.

F-3

Riata Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(in thousands except per share amounts)


			Years Ended December 31,

			2002			2003			2004

Revenues:
	Exploration and production		$	12,807		$	27,826		$	31,004
	Drilling and oil field service			10,745			20,745			39,417
	Midstream gas services			32,195			99,313			98,906
	Other			2,937			3,846			3,987

		Total revenues		58,684			151,730			173,314
Expenses:
	Exploration and production			8,791			11,677			18,172
	Gas purchases and cost of sales			32,833			99,632			106,045
	Salaries and wages			6,093			10,699			18,920
	General and administrative			1,812			1,704			2,198
	Depreciation, depletion and amortization			7,072			12,345			13,411

		Total expenses		56,601			136,057			158,746

	Income from operations			2,083			15,673			14,568

Other income (expense):
	Interest expense, net			(916	)		(1,105	)		(1,622	)
	Minority interest			(673	)		(96	)		(262	)
	Income (loss) from equity investments			304			1,056			(36	)

		Total other expense		(1,285	)		(145	)		(1,920	)
		Income before income tax expense		798			15,528			12,648
Income tax expense				289			5,307			4,321

		Income from continuing operations		509			10,221			8,327
Income (loss) from discontinued operations (net of tax benefit (expense) of $(632), $43 and $(232) in 2002, 2003 and 2004, respectively)				1,105			(85	)		451

Income before extraordinary gain and cumulative effect of change in accounting principle				1,614			10,136			8,778
Extraordinary gain on Foreland acquisition				—			—			12,544
Cumulative effect of change in accounting principle, net of tax benefit of $843				—			(1,636	)		—

		Net income	$	1,614		$	8,500		$	21,322

Basic and Diluted Earnings Per Share*:
		Income from continuing operations	$	0.01		$	0.18		$	0.15
		Income (loss) from discontinued operations, net of income tax		0.02			—			0.01
		Extraordinary gain on Foreland acquisition		—			—			0.22
		Cumulative effect of change in accounting principle, net of income tax		—			(0.03	)		—

		Basic and diluted income per share	$	0.03		$	0.15		$	0.38

Weighted average number of shares outstanding*:
		Basic		56,312			56,312			56,312

		Diluted		56,312			56,312			56,312


*	Restated to reflect a 281.562 for 1 stock split effected in December 2005.

The accompanying notes are an integral part of these consolidated financial statements.

F-4

Riata Energy, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity

(in thousands)


	Preferred Stock				Common Stock*
									Retained
	Shares		Amount		Shares		Amount		Earnings			Total

Balance, January 1, 2002		1	$	23		56,312	$	200	$	18,568		$	18,791
Net income		—		—		—		—		1,614			1,614
Dividends on preferred stock		—		—		—		—		(2	)		(2	)

Balance, December 31, 2002		1		23		56,312		200		20,180			20,403
Net income		—		—		—		—		8,500			8,500
Dividends on preferred stock		—		—		—		—		(2	)		(2	)
Dividends on common stock		—		—		—		—		(1,050	)		(1,050	)

Balance, December 31, 2003		1		23		56,312		200		27,628			27,851
Net income		—		—		—		—		21,322			21,322
Dividends on preferred stock		—		—		—		—		(2	)		(2	)

Balance, December 31, 2004		1	$	23		56,312	$	200	$	48,948		$	49,171


*	Restated to reflect a 281.562 for 1 stock split effected in December 2005.

The accompanying notes are an integral part of these consolidated financial statements.

F-5

Riata Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(in thousands)


				Years Ended December 31,

				2002			2003			2004

CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income			$	1,614		$	8,500		$	21,322
	Income (loss) from discontinued operations, net of tax				1,105			(85	)		451

	Income from continuing operations				509			8,585			20,871
	Adjustments to reconcile net income to net cash provided by operating activities:
		Cumulative effect adjustments from change in accounting for asset retirement obligations			—			1,636			—
		Depreciation, depletion and amortization			7,072			12,345			13,411
		Deferred income taxes			289			4,124			4,321
		Extraordinary gain			—			—			(12,544	)
		Loss (gain) on change in fair value of derivatives			1,459			(157	)		(1,803	)
		Gain on sale of property, plant and equipment			(6,912	)		(1,284	)		(210	)
		Loss (gain) from equity investments, net of distributions			(78	)		(149	)		1,066
		Minority interests			673			96			262
		Changes in operating assets and liabilities increasing (decreasing) cash:
			Receivables		(8,825	)		(9,286	)		(6,189	)
			Inventories		514			(805	)		(481	)
			Other current assets		(271	)		(168	)		(584	)
			Other assets		—			(963	)		324
			Accounts payable		11,949			9,992			13,162
			Accrued expenses and other		1,667			3,403			1,407

	Net cash provided by operating activities by continuing operations				8,046			27,369			33,013
	Net cash provided by operating activities by discontinued operations				1,938			186			978

	Net cash provided by operating activities				9,984			27,555			33,991

CASH FLOWS FROM INVESTING ACTIVITIES:
		Capital expenditures for property, plant and equipment			(19,938	)		(41,495	)		(52,481	)
		Proceeds from sale of assets			15,866			12,895			1,443
		Contributions on equity investments			(1,513	)		(2,650	)		(1,976	)
		Acquisition of asset, net of cash acquired			—			—			(1,169	)
		Return of investment			(44	)		147			220

	Net cash used in investing activities for continuing operations				(5,629	)		(31,103	)		(53,963	)
	Net cash used in investing activities for discontinued operations				(66	)		(1,241	)		(1,931	)

	Net cash used in investing activities				(5,695	)		(32,344	)		(55,894	)

CASH FLOWS FROM FINANCING ACTIVITIES:
		Proceeds from borrowings			9,906			6,561			41,620
		Repayments of borrowings			(12,411	)		(2,370	)		(6,840	)
		Dividends paid-preferred			(2	)		(2	)		(2	)
		Dividends paid-common			—			(1,050	)		—
		Minority interests contributions (distributions)			76			(50	)		(78	)

	Net cash provided by (used in) financing activities for continuing operations				(2,431	)		3,089			34,700
	Net cash provided by (used in) financing activities for discontinued operations				—			—			—

	Net cash provided by (used in) financing activities				(2,431	)		3,089			34,700

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS					1,858			(1,700	)		12,797
CASH AND CASH EQUIVALENTS, beginning of year					18			1,876			176

CASH AND CASH EQUIVALENTS, end of year				$	1,876		$	176		$	12,973

Supplemental Disclosure of Cash Flow Information:
	Cash paid during the year for interest			$	1,731		$	1,278		$	2,024
	Cash paid during the year for income taxes			$	—		$	300		$	—

The accompanying notes are an integral part of these consolidated financial statements.

F-6

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements


1.	Summary of Significant Accounting Policies

Nature of Business. Riata Energy, Inc. and its subsidiaries (“Riata” or the “Company”) was incorporated in 1984 in the state of Texas. Riata is an oil and gas company with its principal focus on exploration, development and production related to oil and gas activities. Riata also owns and operates drilling rigs and provides related oil field services; and midstream gas services operations. Riata’s primary exploration, development and production areas are concentrated in West Texas and the Rocky Mountain region of northwestern Colorado. Riata also has additional unproved acreage in the Anadarko and Arkoma Basins of Oklahoma. Riata’s current contract drilling operations are focused primarily in the natural gas producing provinces of the Permian Basin and the Rocky Mountain regions. The majority of its contract drilling and exploration and production activities are oriented toward drilling for and producing natural gas. Riata’s midstream gas services operations consists of four natural gas treatment plants, 11 active gathering systems and 238 miles of pipeline.

Principles of Consolidation. The consolidated financial statements include the accounts of Riata Energy, Inc. and its wholly owned or majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

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 exploration and development activities, prevailing commodity process, operating cost and other factors. These revisions may be material and could materially affect our future depletion, depreciation and amortization and impairment 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 very 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.

Accounts Receivable, net. The Company has receivables for sales of oil, gas and natural gas liquids, as well as receivables related to the exploration and extraction services for oil, gas and natural gas liquids. Management has established an allowance for doubtful accounts. The allowance is evaluated by management and is based on 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.

F-7

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Inventories. Inventories consist of oil field service supplies and are stated at the lower of cost or market with cost determined on an average cost basis.

Revenue Recognition. Revenues from the sales of oil and natural gas are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable.

We recognize revenues and costs on daywork contracts daily as services are performed. For certain contracts, we receive lump-sum payments for the mobilization of rigs and other drilling equipment. Mobilization revenues earned and the related direct cost incurred for the mobilization are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred.

Transportation and processing revenue is recognized when the product is delivered to the customer and, if applicable, title has passed.

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.

Oil and Gas Operations. The Company uses the successful efforts method of accounting for oil and gas-exploration, development and production activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.

The Company evaluates its oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure. Impairment of proved properties is required when carrying value exceeds undiscounted future net cash flows based on total proved and risk-adjusted probable and possible reserves. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows based on total proved and risk-adjusted probable and possible reserves or, if available, comparable market values.

The Company evaluates its unproved property investment for impairment based on time or geologic factors in addition to the use of an undiscounted future net cash flow approach. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage are also considered. Impairment expense for unproved oil and gas properties is reported in exploration expense.

F-8

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

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 25 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. On January 1, 2003 the company adopted Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). FAS 143 establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-lived assets. 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 under FAS 143 are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). The Company does not have any assets restricted for the purpose of settling the plugging liabilities. ARO is recorded as a liability at its estimated present value at the asset’s inception, with the offsetting charge to property cost. Periodic accretion expense of the estimated liability is recorded in the statement of income.

The ARO primarily represents the present value of the costs the Company estimates it will incur 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 the ARO by calculating the present value of estimated expenses related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. Inherent in the present value calculation rates, 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 ARO liability, a corresponding adjustment is made to the related asset.

As of January 1, 2003, adoption date of FAS 143, the Company recorded a long-term liability of approximately $3.6 million, an increase in property costs of approximately $2.4 million, an increase in accumulated depreciation, depletion and amortization of $1.2 million and a cumulative effect of accounting change loss, net of $843,000 of tax, of approximately $1.6 million. Pro forma amounts assuming retroactive application of change in accounting principle for 2002 make net income $0.8 million in 2002 with basic and

F-9

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

diluted earnings per share of $0.01. The following is a reconciliation of the asset retirement obligation for the years ended December 31, (in thousands).


	2003		2004

Asset retirement obligation, January 1	$	3,624	$	3,883
Liability incurred upon acquiring and drilling wells		136		372
Accretion of discount expense		123		139

Asset retirement obligation, December 31	$	3,883	$	4,394

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.

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.

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 futures contracts.

The Company recognizes all of its derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship, and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, the Company designates the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. For derivative instruments not designated as hedging instruments, the gain or loss is recognized in current earnings during the period of change. None of the Company’s derivatives were designated as hedging instruments during 2002, 2003 and 2004.

Recently Issued Accounting Pronouncements. In November 2004, the Financial Accounting Standards Board (“FASB”) issued Statement on Financial Accounting Standards No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4”, which clarifies the types of costs that should be expensed rather than capitalized as inventory. The provisions of FAS 151 are effective for years beginning after June 15, 2005. The Company does not expect this statement to have a material impact on its results of operations or its financial condition.

In December 2004, the FASB issued FAS 123R “Shares Based Payment”, which requires that compensation cost relating to share based payments be recognized in the Company’s financial statements. SFAS 123R revises SFAS 123, “Accounting for Stock-Based Compensation”, and focuses on accounting for share based payments for services provided by employee to employer. The Company will adopt the provision in 2006.

The FASB issued Statement on Financial Accounting Standards No. 153, “Exchanges of Productive Assets”, in December 2004 that amended Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions”. FAS 153 requires that nonmonetary exchanges of similar productive assets are to be accounted for at fair value. Previously these transactions were accounted for at book value of the assets. This statement is effective for nonmonetary transactions occurring in fiscal periods beginning after

F-10

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

June 15, 2005. The Company does not expect this statement to have a material impact on its results of operations or its financial condition.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3”. Under this statement, voluntary changes in accounting principle are required to be applied retrospectively for the direct effects of a change to prior periods’ financial statements, unless such application is impracticable. Retrospective application refers to reflecting a change in accounting principle in the financial statements of prior periods as if the principle had always been used. When retrospective application is determined to be impracticable, this statement requires the new accounting principle to be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective treatment is practicable with a corresponding adjustment to the opening balance of retained earnings. This statement retains the guidance in APB Opinion No. 20 for reporting the corrections of errors and changes in accounting estimates. This statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, with early adoption permitted. The Company’s adoption of this statement will affect its consolidated financial statements for any changes in accounting principle it may make in the future, or new pronouncements it adopts that do not provide transition provisions.


2.	Acquisitions

On December 6, 2004, the Company purchased Foreland Corporation for a total purchase price of $13,750,000, net of cash acquired of approximately $1,169,000 and the assumption of $37,000 in liabilities. The purchase price was allocated as follows:


Bonds	$	75,000
Deferred tax assets — net operating losses		13,675,000

The difference between the fair value of assets acquired and the purchase price resulted in negative goodwill and was recognized as an extraordinary gain during the year ended December 31, 2004. The deferred tax assets are subject to full limitation under IRC Section 382 if the Company has a greater than 50% change of ownership in the two years following the date of the purchase.


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 exchange of shares were transferred at its historical basis and reflected as a treasury share transaction.

The land and agriculture operations are presented as discontinued operations, net of income taxes in the Consolidated Statements of Operations and the land and agriculture assets are shown as separate line items in the Consolidated Balance Sheets.

In August 2002, the Company sold substantially all the assets of an oil and gas service company. These operations are presented as discontinued operations for the year ended 2002.

F-11

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

The following table summarizes net revenue and net income (loss) from discontinued operations for the years ended December 31, 2002, 2003 and 2004 (in thousands):


	2002			2003			2004

Revenues	$	1,030		$	1,591		$	1,968
Operating income (expenses)		707			(1,719	)		(1,285	)

Income (loss) from discontinued operations		1,737			(128	)		683
Income tax benefit (expense)		(632	)		43			(232	)

Net income (loss) from discontinued operations	$	1,105		$	(85	)	$	451

The following table summarizes the assets for sale at December 31, 2003 and 2004 (in thousands):


			December 31,

			2003		2004

Assets:
	Current		$	—	$	14
	Property, plant and equipment			20,882		22,504

		Total assets	$	20,882	$	22,518

Liabilities:
	Current		$	—	$	—
	Deferred income taxes			6,366		6,366

		Total liabilities	$	6,366	$	6,366


4.	Accounts Receivable

A summary of accounts receivable is as follows (in thousands):


		December 31,

		2003			2004

Trade — oil and gas service		$	114		$	2,666
Oil and gas sales			10,473			11,506
Joint interest billing			17,360			20,338

			27,947			34,510
Less allowance for doubtful accounts			(602	)		(1,074	)

	Total accounts receivable, net	$	27,345		$	33,436

The following tables show the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2002, 2003 and 2004.


			Additions		Additions
	Balance at		Charged to		Charged to					Balance at
	Beginning of		Costs and		Other					End of
Allowance for Doubtful Accounts	Period		Expenses		Accounts		Deductions(1)			Period

Year ended December 31, 2002	$	564	$	458	$	—	$	(37	)	$	985
Year ended December 31, 2003	$	985	$	158	$	—	$	(541	)	$	602
Year ended December 31, 2004	$	602	$	761	$	—	$	(289	)	$	1,074


(1)	Deductions represent the write-off of receivables.

Bad debt expense for the years ended December 31, 2002, 2003 and 2004, was approximately $458,000, $158,000 and $761,000, respectively.

F-12

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)


5.	Property, Plant and Equipment

Property, plant and equipment consist of the following (in thousands):


				December 31,
		Estimated
		Useful Life		2003			2004

Land				$	572		$	798
Oil and gas properties					51,530			74,615
Equipment			3 — 10		43,223			65,894
Buildings and structures			7 — 25		2,715			1,927
Construction in progress					—			490
Other property and equipment			3 — 7		413			415

					98,453			144,139
Less accumulated depreciation, depletion and amortization					(37,612	)		(44,951	)

	Property, plant and equipment, net			$	60,841		$	99,188


6.	Investment in Affiliated Companies

The significant equity investments consisted of the following as of December 31 (in thousands):


	%
	Ownership
Investment	2004		2003		2004

Cholla Pipeline, L.P.		45%	$	1,627	$	1,462
Grey Ranch Plant, L.P.		50%		901		807
PetroSource Energy Company		17%		1,546		2,038

Summarized unaudited financial information for Cholla Pipeline, Grey Ranch, and the financial information for PetroSource Energy, our significant equity investments, are reported below (in thousands; amounts represent 100% of investee financial information):

Cholla Pipeline, L.P. Cholla was formed to transport natural gas from the Pinon field. The Company accounts for this investment under the equity method of accounting because it owns more than 20% and has significant influence but does not control Cholla Pipeline, L.P.


			2003		2004

			(in thousands)
Balance Sheet:
	Current assets		$	365	$	75
	Noncurrent assets			3,374		3,251

		Total assets	$	3,739	$	3,326

	Current liabilities		$	82	$	77
	Partners’ capital			3,657		3,249

		Total liabilities and partners’ capital	$	3,739	$	3,326


			2002			2003		2004

			(in thousands)
Income Statement:
	Revenues		$	1,017		$	1,999	$	1,847
	Costs and expenses			1,150			364		392

		Net income (loss)	$	(133	)	$	1,635	$	1,455

F-13

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

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. The Company accounts for this investment under the equity method of accounting because it owns more than 20% and has significant influence but does not control Grey Ranch, L.P. The Company contributed a disproportionate amount of capital into the Partnership, amounting to approximately $1,050,000 and $217,000 as of December 31, 2003 and 2004, respectively. The excess amount contributed is being amortized over the average life of the partnership’s long-lived assets.


			2003		2004

			(in thousands)
Balance Sheet:
	Current assets		$	107	$	286
	Noncurrent assets			1,367		1,157

		Total assets	$	1,474	$	1,443

	Current liabilities		$	130	$	263
	Partners’ capital			1,344		1,180

		Total liabilities and partners’ capital	$	1,474	$	1,443


			2003			2004

			(in thousands)
Income Statement:
	Revenues		$	424		$	795
	Costs and expenses			723			1,344

		Net loss	$	(299	)	$	(549	)

PetroSource Energy Company. PetroSource acquires, compresses, transports and sells CO₂ through its CO₂ pipeline and spurs located in West Texas. The Company accounts for this investment under the equity method of accounting because it has significant influence in its operations but does not control PetroSource Energy Company. PetroSource commenced operations in the fourth quarter of 2003.


			2003			2004

			(in thousands)
Balance Sheet:
	Current assets		$	455		$	5,889
	Noncurrent assets			26,766			41,635

		Total assets	$	27,221		$	47,524

	Current liabilities		$	399		$	5,907
	Noncurrent liabilities			18,324			29,626
	Owners’ equity			8,498			11,991

		Total liabilities and owners’ equity	$	27,221		$	47,524

Income Statement:
	Revenues		$	115		$	8,451
	Costs and expenses			185			10,929

		Net loss	$	(70	)	$	(2,478	)

The Company has various investments in other affiliated companies in which it does not have the ability to exercise significant influence and accounts for the investments under the cost method. The carrying value

F-14

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

of these other investments was approximately $518,000 and $974,000 as of December 31, 2003 and 2004, respectively.


7.	Long-Term Debt

Long-term obligations consist of the following at December 31:


		2003		2004

		(in thousands)
Revolver note payable to bank with a commitment not to exceed $46,000; interest at three-month LIBOR rate plus 2.15% per annum (3.1% at December 31, 2004); with a maturity date of December 31, 2007; collateralized by oil and gas properties and certain real property		$	17,045	$	45,264
Note payable to bank; interest at prime rate (4.00% at December 31, 2004); with a maturity date of December 16, 2007; collateralized by equipment and certain other assets; monthly payments of $95,841			3,916		2,981
Note payable to bank; interest at prime rate (5.25% at December 31, 2004); with a maturity date of March 31, 2010; collateralized by equipment and certain other assets; monthly payments of $166,667			—		8,964
Other note payables; various interest rates; various monthly payments ranging from $1 to $64; various maturity dates ranging from February 22, 2005 to December 31, 2007			3,779		2,311

	Total debt		24,740		59,520
Less: Current maturities of long-term debt			19,933		3,202

Long-term debt		$	4,807	$	56,318

Aggregate maturities of long-term debt during the next five years are as follows (in thousands):


Years ended:
	2005		$	3,202
	2006			3,623
	2007			48,313
	2008			2,000
	2009			2,000
	Thereafter			382

		Total debt	$	59,520

The revolver and notes payable contain affirmative and negative covenants, including the maintenance of certain financial ratios, restrictions on sales, leases or other dispositions of property and restrictions on other indebtedness. Events of default under the revolver and notes payable include cross-defaults to all material indebtedness, including each of those financings. As of December 31, 2004, the Company was in compliance with these covenants.


8.	Derivatives

The Company entered into interest rate swap agreements with a bank whereby the Company receives payments based on a floating one-month LIBOR rate plus 2.15% applied to notional amounts (totaling $12,000,000) and makes payments based on a fixed interest rate of 4.4% applied to the same notional amount. The Company has also entered into oil and gas futures contracts with a bank whereby the Company purchases, based on a fixed price, notional amounts monthly. The contracts expire on various dates through September 1, 2005.

F-15

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

At December 31, 2004, the Company’s open commodity derivatives consisted of the following:

Swaps

Weighted Avg.

Period

Commodity

Notional

Fix Price

Receive Fixed/ Pay Variable Jan-05 — Dec-05

Natural Gas

730,000 MMBtu

4.85

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. The income (loss) amount recognized in earnings, as of December 31, 2002, 2003 and 2004, is approximately $1,459,000, $(157,000) and $1,803,000, respectively.


9.	Drilling Advances

The Company received drilling advances from joint interest owners with a remaining balance of approximately $2,500,000 and $3,200,000 at December 31, 2003 and 2004, respectively. Such amounts are included in accrued expenses. These advances are applied towards payments of drilling costs to be incurred.


10.	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. The Company makes matching contributions at the rate of $.50 for every $1.00 of employee deferrals on the first 6.0% of deferred wages (maximum 3.0% matching). For 2002, 2003 and 2004, retirement plan expense was approximately $60,000, $94,000 and $200,000, respectively.


11.	Income Taxes

Significant components of the Company’s deferred tax assets (liabilities) as of December 31 are as follows:


				2003			2004

				(in thousands)
Deferred tax assets (liabilities):
	Current:
		Accrued liabilities		$	—		$	80
		Other			11			362

			Total current deferred tax assets	$	11		$	442

	Noncurrent:
		Property, plant and equipment		$	(9,351	)	$	(12,608	)
		Net operating loss carryforwards			—			12,602
		Other			2,844			2,190

			Total noncurrent deferred tax assets (liabilities)	$	(6,507	)	$	2,184

The provision for income taxes from continuing operations consisted of the following components:


		2002		2003		2004

		(in thousands)
Current		$	—	$	340	$	—
Deferred			289		4,967		4,321

	Total provision for income taxes	$	289	$	5,307	$	4,321

F-16

Riata 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 year ended December 31:


		2002		2003		2004

		(in thousands)
Computed at federal statutory rates		$	271	$	5,280	$	4,300
Nondeductible expenses			18		27		21

	Total provision for income taxes	$	289	$	5,307	$	4,321

As of December 31, 2004, the Company has accumulated approximately $37,064,000 in estimated regular tax net operating loss carryforwards, of which approximately $1,300,000 will expire in 2005. The Company, as of December 31, 2004, has approximately $266,000 of alternative minimum tax credits that do not expire. Based on the Company’s projections of future taxable income, the Company believes that the net operating loss carryforwards are more likely than not to be realized.


12.	Earnings per Share

Basic earnings per share is calculated by dividing net income to common stock by the weighted-average number of shares of common stock outstanding during the period. There are no potential dilutive securities issued. Diluted earnings per share assumes the conversion of all potentially dilutive securities and is calculated by dividing net income to common stock, before the effect of preferred dividends, by the sum of the weighted-average number of shares of common stock outstanding plus all potentially dilutive securities.


13.	Commitments and Contingencies

The Company has obligations under noncancelable operating leases primarily for the use of office space and equipment. Total rent expense under operating leases for the years ended December 31, 2002, 2003 and 2004, was approximately $0, $149,000 and $800,000, respectively.

Future minimum lease payments under noncancelable operating leases (with initial lease terms in excess of one year) as of December 31, 2004, are as follows (in thousands):


Years ended:
	2005	$	503
	2006		291
	2007		102

		$	896

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 other than that specifically identified below, which individually or in the aggregate, could have a material effect on the financial condition, operations and/or cash flows of the Company.

Litigation with Conoco, Inc. The Company is a defendant in a lawsuit brought by Conoco, Inc. for alleged unpaid overriding royalties on production by the Company on certain leases in Pecos County, Texas. Conoco, Inc. alleges that it is entitled to 12.5% of the proceeds from production and the Company alleges that Conoco, Inc., at most, is only entitled to a 5.0% overriding royalty on production. At December 31, 2004, the Company had approximately $10,400,000 recorded as an accrual related to this lawsuit which represents the 12.5% of the proceeds from the production on those properties. This amount is included in accrued expenses on the Company’s consolidated balance sheet. The Company intends to vigorously defend its position.

F-17

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

Roosevelt Litigation. This suit seeks a declaratory judgment relating to the rights of the parties in and to certain leases in a defined area of mutual interest in the Piceance Basin pursuant to an acquisition agreement entered into in 1989. If this declaratory judgment is not found in the Company’s favor, the other parties involved could be entitled to up to a 25% working interest in 8,000 acres in the western portion of the Company’s Piceance Basin acreage and a 12¹/2% to 25% net profits or reversionary interest in all of the Company’s Piceance Basin acreage. Trial has been scheduled for April 2006.

Yates Litigation. The Company is a defendant in where the plaintiff, Harvey E. Yates Company (“HeyCo”), seeks title to an 8.33% working interest in a lease covering three sections of land and a 3.33% working interest in a lease covering 1¹/2 sections of land, each located in West Texas, as well as unspecified damages based on production attributable to these working interests. The Company has denied all liability in this suit and has alleged, among other defenses, that the claims are barred by the statute of limitations. The Company is currently in the preliminary stages of discovery.

The Company is subject to other claims in the ordinary course of business. However, the Company believes that the ultimate resolution of the above mentioned claims and other current legal proceedings will not have a material adverse effect on its results of operations or its financial condition.


14.	Stockholders’ Equity

Preferred stockholders are entitled to receive annual dividends. Dividend rates vary as to the class of preferred stock owned. Dividends are cumulative and are paid on a semi-annual basis. No dividends were in arrears at December 31, 2003 and 2004. The preferred stockholders receive preference in the event of a liquidation and have no voting rights.

Class A Preferred Stock. Receives annual dividends of 8% of the stated value and has designations, preferences, rights and qualifications as authorized by the Board of Directors. At December 31, 2002, 2003 and 2004, there were 600 Class A shares outstanding, respectively.

Class B Preferred Stock. Receives annual dividends of 9% of the stated value and has designations, preferences, rights and qualifications as authorized by the Board of Directors. At December 31, 2002, 2003 and 2004, there were 400 Class B shares outstanding, respectively.


15.	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 revolving lines of credit and the notes payable approximates fair value because their interest rates are based on fair value indexes.


16.	Related Party Transactions

F-18

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

field service supplies. Following is a summary of significant transactions with such related parties as of and for the year ended December 31:


	2002		2003		2004

	(in thousands)
Sales to related parties	$	155	$	—	$	306

Receivables from related parties for services rendered	$	2,230	$	434	$	1,116

Payables to related parties for services rendered	$	2,912	$	1,239	$	3,757

Purchases of services from related parties	$	1,971	$	4,896	$	9,556


17.	Subsequent Events

In February 2005, the Company obtained a line of credit of approximately $37,500,000 from a financial institution. The line of credit will be used to purchase additional equipment.

Additionally, in May 2005, the Company increased its current revolver borrowing base with a financial institution from approximately $46,000,000 to $55,000,000. The original line of credit terms remain the same. The proceeds will be used for production and drilling equipment.


18.	Industry Segment Information

Riata has three business segments: Exploration and Production, Drilling and Oil Field Services and Midstream Gas Services, representing its three 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 and the Midstream Gas Services segment is engaged in the purchasing, gathering, processing and treating of natural gas.

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 Riata’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 our segments is shown in the following table (in thousands):


			2002		2003		2004

			(in thousands)
Revenues:
	Exploration and production		$	17,356	$	33,256	$	36,721
	Elimination of inter-segment revenue			1,817		971		1,662

	Exploration and production, net of inter-segment revenue			15,539		32,285		35,059

	Drilling and oil field services			19,278		32,252		59,179
	Elimination of inter-segment revenue			8,390		12,282		19,968

	Drilling and oil field services, net of inter-segment revenue			10,888		19,970		39,211

	Midstream gas services			44,153		128,441		132,158
	Elimination of inter-segment revenue			11,896		28,966		33,114

	Midstream gas services, net of inter-segment revenue			32,257		99,475		99,044

		Total revenues	$	58,684	$	151,730	$	173,314

F-19

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)


			2002			2003			2004

			(in thousands)
	Exploration and production		$	(4,437	)	$	10,115		$	7,818
	Drilling and oil field services			3,470			2,845			4,206
	Midstream gas services			3,050			2,713			2,636
	Other			—			—			(92	)

		Total operating income(1)		2,083			15,673			14,568
	Interest expense			(916	)		(1,105	)		(1,622	)
	Other income (expense) — net			(369	)		960			(298	)

		Income before income taxes	$	798		$	15,528		$	12,648

Identifiable Asset(2):
	Exploration and production		$	52,909		$	66,620		$	110,114
	Drilling and oil field services			17,715			20,387			35,807
	Midstream gas services			11,738			23,953			25,208

		Total identifiable assets		82,362			110,960			171,129
	Corporate assets			3,101			7,336			10,258

		Total assets	$	85,463		$	118,296		$	181,387

Capital Expenditures:
	Exploration and production		$	11,297		$	22,868		$	23,660
	Drilling and oil field services			6,855			13,474			22,679
	Midstream gas services			1,046			873			2,026
	Other			740			4,280			4,116

		Total capital expenditures	$	19,938		$	41,495		$	52,481

Depreciation, Depletion and Amortization:
	Exploration and production			5,160			7,501			5,648
	Drilling and oil field services			1,300			3,402			5,932
	Midstream gas services			302			1,009			1,270
	Other			310			433			561

		Total depreciation, depletion and amortization	$	7,072		$	12,345		$	13,411


(1)	Operating income is total operating revenues less operating expenses, depreciation, depletion and amortization and does not include non-operating revenues, general corporate expenses, interest expense or income taxes.

(2)	Identifiable assets are those used in Riata’s operations in each industry segment. Corporate assets are principally cash and cash equivalents, corporate leasehold improvements, furniture and equipment.


19.	Stock Split

On December 19, 2005, the Company entered into 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 four hundred million (400,000,000) shares of common stock with a par value of $0.001 per share.


20.	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

F-20

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

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.

Our capitalized costs consisted of the following (in thousands):

Capitalized Costs Related to Oil and Gas Producing Activities


	December 31,

Consolidated Companies(a)	2002			2003			2004

Wells and equipment, facilities and other	$	45,099		$	61,586		$	83,358
Leasehold		11,399			12,121			12,285

Total proved oil and gas properties		56,498			73,707			95,643
Accumulated depreciation and depletion		(15,035	)		(21,973	)		(27,480	)

Net capitalized costs	$	41,463		$	51,734		$	68,163

Wells and equipment, facilities and other	$	138		$	2,489		$	1,137
Unproved leasehold		1,004			2,785			4,392

Total unproved oil and gas properties	$	1,142		$	5,274		$	5,529


(a)	Amounts relate to Riata and Consolidated Subsidiaries. Includes capitalized asset retirement costs and associated accumulated depreciation.


		2002		2003		2004

Acquisitions of properties
	Unproved	$	4,234	$	3,513	$	1,631
Exploration			341		2,883		1,375
Development			5,443		15,477		21,912

Total cost incurred		$	10,018	$	21,873	$	24,918


(a)	Amounts relate to Riata and Consolidated Subsidiaries.

Our results of operations from oil and gas producing activities for each of the years 2002, 2003 and 2004 are shown in the following table:

Results of Operations for Oil and Gas Producing Activities


			Consolidated
			Companies(a)

			(in thousands)
For the Year Ended December 31, 2002
Revenues			$	12,796
Expenses:
	Production costs			8,588
	Exploration cost			203
	Depreciation, depletion and amortization expenses			5,160

		Total expenses		13,951

Loss before income taxes				(1,155	)
Income tax benefit				393

Results of operations for oil and gas producing activities			$	(762	)

F-21

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)


			Consolidated
			Companies(a)

			(in thousands)
For the Year Ended December 31, 2003
Revenues			$	27,807
Expenses:
	Production costs			11,145
	Exploration cost			532
	Depreciation, depletion and amortization expenses			7,501

		Total expenses		19,178

Income before income taxes				8,629
Provision for income taxes				2,934

Results of operations for oil and gas producing activities			$	5,695

For the Year Ended December 31, 2004
Revenues			$	30,976
Expenses:
	Production costs			15,446
	Exploration cost			2,726
	Depreciation, depletion and amortization expenses			5,648

		Total expenses		23,820

Income before income taxes				7,156
Provision for income taxes				2,433

Results of operations for oil and gas producing activities			$	4,723


(a)	Amounts relate to Riata and Consolidated Subsidiaries.

Operating statistics from our oil and gas producing activities for each of the years 2002, 2003 and 2004 are shown in the following table:

Results of Operations for Oil and Gas Producing Activities — Unit Prices and Costs


			Year Ended December 31,

			2002		2003		2004

Consolidated Companies(a)
	Production costs per Mmbtue(b)(c)(d)		$	2.05	$	1.61	$	2.23
	Crude oil production (Bbl/d)			124		105		101
	Natural gas production (Mmbtue/d)(d)			10,709		18,374		18,327
	Average sales prices:
		Crude oil price per Bbl	$	27.10	$	26.62	$	34.03
		Natural gas price per Mcf	$	2.96	$	3.99	$	4.43


(a)	Amounts relate to Riata and Consolidated Subsidiaries.

(b)	Computed using production costs, excluding transportation costs, as defined by the Securities and Exchange Commission. Natural gas volumes were converted to barrels of oil equivalent (BOE) using a conversion factor of six mcf of natural gas to one barrel of oil.

(c)	Production costs include labor, repairs and maintenance, materials, supplies, fuel and power, property taxes, severance taxes, and general and administrative expenses directly related to oil and gas producing activities.

(d)	Includes only production attributable to leasehold ownership.

F-22

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)

The table below represents our estimate of proved crude oil and natural gas reserves based upon our evaluation of pertinent geological and engineering data in accordance with United States Securities and Exchange Commission regulations. Estimates of proved reserves have been prepared by our team of reservoir engineers and geoscience professionals and are reviewed by members of our senior management with professional training in petroleum engineering to ensure that we consistently apply rigorous professional standards and the reserve definitions prescribed by the United States Securities and Exchange Commission.

Netherland, Sewell and Associates, Inc., DeGolyer and MacNaughton and Harper and Associates, Inc., independent oil and gas consultants, have reviewed the estimates of proved reserves of natural gas and crude oil that we have attributed to our net interest in oil and gas properties as of December 31, 2002, 2003 and 2004. Based upon their review of more than 99% of our reserve estimates, it is their judgment that the estimates are reasonable in the aggregate.

We believe 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 becomes 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.

Reserve Quantity Information


		Consolidated
		Companies(a)

		Crude Oil			Nat. Gas
		(MBbls)			(MMcf)(b)

Proved developed and undeveloped reserves:
As of December 31, 2001			276			57,668
	Revisions of previous estimates		108			(22,796	)
	Extensions and discoveries		14			13,620
	Production		(45	)		(3,909	)

As of December 31, 2002			353			44,583
	Revisions of previous estimates		334			2,994
	Extensions and discoveries		—			80,385
	Production		(38	)		(6,706	)

As of December 31, 2003			649			121,256
	Revisions of previous estimates		70			(18,955	)
	Extensions and discoveries		—			48,859
	Production		(37	)		(6,708	)

As of December 31, 2004			682			144,452

F-23

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)


	Consolidated
	Companies(a)

	Crude Oil		Nat. Gas
	(MBbls)		(MMcf)(b)

Proved developed reserves:
As of December 31, 2001		276		22,977
As of December 31, 2002		351		28,001
As of December 31, 2003		327		48,513
As of December 31, 2004		231		50,981


(a)	Amounts relate to Riata and Consolidated Subsidiaries.

(b)	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 underly the computation of the standardized measure of discounted cash flows may be summarized as follows:


	•	the standardized measure includes our 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;

	•	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


			Consolidated
			Companies(a)

			(in thousands)
As of December 31, 2002
	Future cash inflows from production		$	212,739
	Future production costs			(56,192	)
	Future development costs(b)			(9,851	)
	Future income tax expenses			(49,877	)

		Undiscounted future net cash flows		96,819
	10% annual discount			(30,531	)

		Standardized measure of discounted future net cash flows	$	66,288

F-24

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)


			Consolidated
			Companies(a)

			(in thousands)
As of December 31, 2003
	Future cash inflows from production		$	667,123
	Future production costs			(206,041	)
	Future development costs(b)			(38,535	)
	Future income tax expenses			(143,665	)

		Undiscounted future net cash flows		278,882
	10% annual discount			(121,583	)

		Standardized measure of discounted future net cash flows	$	157,299

As of December 31, 2004
	Future cash inflows from production		$	843,647
	Future production costs			(227,257	)
	Future development costs(b)			(77,588	)
	Future income tax expenses			(183,193	)

		Undiscounted future net cash flows		355,609
	10% annual discount			(156,647	)

		Standardized measure of discounted future net cash flows	$	198,962


(a)	Amounts relate to Riata and Consolidated Subsidiaries.

(b)	Includes abandonment costs.

The following table represents our estimate of changes in the standardized measure of discounted future net cash flows from proved reserves:

Changes in the Standardized Measure of Discounted Future Net Cash Flows From

Proved Oil and Gas Reserves


			Consolidated
			Companies(a)

			(in thousands)
Present value as of January 1, 2002			$	29,138
	Changes during the year:
		Revenues less production and other costs		(4,208	)
		Net changes in prices, production and other costs		45,630
		Development costs incurred		5,443
		Net changes in future development costs		5,609
		Extensions and discoveries		35,152
		Revisions of previous quantity estimates		(40,841	)
		Accretion of discount		4,429
		Net change in income taxes		(19,138	)
		Timing differences and other(b)		5,074

	Net change for the year			37,150

F-25

Riata Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements — (Continued)


			Consolidated
			Companies(a)

			(in thousands)
Present value as of December 31, 2002			$	66,288
	Changes during the year:
		Revenues less production and other costs		(16,662	)
		Net changes in prices, production and other costs		(4,116	)
		Development costs incurred		15,477
		Net changes in future development costs		(8,701	)
		Extensions and discoveries		152,884
		Revisions of previous quantity estimates		11,250
		Accretion of discount		11,068
		Net change in income taxes		(46,883	)
		Timing differences and other(b)		(23,306	)

	Net change for the year			91,011

Present value as of December 31, 2003			$	157,299
	Changes during the year:
		Revenues less production and other costs		(15,530	)
		Net changes in prices, production and other costs		4,157
		Development costs incurred		21,912
		Net changes in future development costs		(16,360	)
		Extensions and discoveries		105,603
		Revisions of previous quantity estimates		(39,205	)
		Accretion of discount		25,244
		Net change in income taxes		(20,720	)
		Timing differences and other(b)		(23,438	)

	Net change for the year			41,663

Present value as of December 31, 2004			$	198,962


(a)	Amounts relate to Riata and Consolidated Subsidiaries.

(b)	The changes in timing differences and other are related to revisions in the Company’s estimated time of production and development.

F-26

Riata Energy, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

(in thousands)


				December 31,		September 30,
				2004		2005

ASSETS
Current assets:
	Cash and cash equivalents			$	12,973	$	5,868
	Accounts receivable, net:
		Trade			33,436		52,086
		Related parties			1,116		1,673
	Inventories				1,560		2,653
	Held for sale				14		—
	Deferred income taxes				442		563
	Other current assets				1,975		2,872

			Total current assets		51,516		65,715
Property, plant and equipment, net					99,188		160,673
Intangibles, net					214		50
Investments					5,281		5,413
Held for sale					22,504		—
Deferred income taxes					2,184		—
Derivative contracts					—		72
Other assets					500		312

			Total assets	$	181,387	$	232,235


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Current maturities of long-term debt			$	3,202	$	9,226
	Accounts payable
		Trade			41,180		53,145
		Related party			3,757		47
	Accrued expenses				14,269		32,185
	Derivative contracts				689		9,509

			Total current liabilities		63,097		104,112
Long-term debt					56,318		72,103
Derivative contracts					147		—
Asset retirement obligation					4,394		4,740
Held for sale					6,366		—
Deferred income taxes					—		1,490

			Total liabilities		130,322		182,445

Commitments and contingencies (Note 9)
Minority interest					1,894		11,062
Stockholders’ equity:
	Preferred stock				23		—
	Common stock				200		196
	Additional paid-in capital				—		22
	Retained earnings				48,948		55,845
	Treasury stock, at cost				—		(17,335	)

			Total stockholders’ equity		49,171		38,728

			Total liabilities and stockholders’ equity	$	181,387	$	232,235

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-27

Riata Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(unaudited)

(in thousands except per share amounts)


			Nine Months Ended
			September 30,

			2004			2005

Revenues:
	Exploration and production		$	22,357		$	29,895
	Drilling and oil field service			27,853			54,935
	Midstream gas services			73,081			92,843
	Other			3,207			3,612

		Total revenues		126,498			181,285
Expenses:
	Exploration and production			12,975			14,323
	Gas purchases and cost of sales			75,628			114,028
	Salaries and wages			14,608			20,415
	General and administrative			1,426			2,019
	Depreciation, depletion and amortization			9,380			15,314

		Total expenses		114,017			166,099

	Income from operations			12,481			15,186

Other expense:
	Interest expense, net			(1,145	)		(2,938	)
	Minority interest			(135	)		(968	)
	Loss from equity investments			(120	)		(1,176	)

		Total other expense		(1,400	)		(5,082	)
		Income before income tax expense		11,081			10,104
Income tax expense				3,767			3,435

		Income from continuing operations		7,314			6,669
Income from discontinued operations (net of tax expense of $199 and $118 in 2004 and 2005, respectively)				386			229

		Net income	$	7,700		$	6,898

Basic and Diluted Earnings Per Share:
		Income from continuing operations	$	0.13		$	0.12
		Income from discontinued operations, net of income tax		0.01			—

		Net income	$	0.14		$	0.12

Weighted average number of shares outstanding:
		Basic		56,312			56,312

		Diluted		56,312			56,312


*	Restated to reflect a 281.562 for 1 stock split effected in December 2005.

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-28

Riata Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(unaudited)

(in thousands)


			Nine Months Ended
			September 30,

			2004			2005

CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by operating activities by continuing operations			$	19,127		$	40,638
Net cash provided by operating activities by discontinued operations				860			347

Net cash provided by operating activities				19,987			40,985

CASH FLOWS FROM INVESTING ACTIVITIES:
		Discontinued operations — capital expenditures		(847	)		(1,473	)
		Capital expenditures for property, plant and equipment		(34,761	)		(75,786	)
		Contributions on equity investments		(573	)		(1,132	)
		Acquisition of asset, net of cash acquired		36			—
		Return of investment		156			293

Net cash used in investing activities for continuing operations				(35,142	)		(76,625	)
Net cash used in investing activities for discontinued operations				(847	)		(1,473	)

Net cash used in investing activities				(35,989	)		(78,098	)

CASH FLOWS FROM FINANCING ACTIVITIES:
		Proceeds from borrowings		29,411			33,179
		Repayments of borrowings		(4,106	)		(11,370	)
		Dividends paid-preferred		(1	)		(1	)
		Minority interests contributions		197			8,200

Net cash provided by financing activities for continuing operations				25,501			30,008
Net cash provided by financing activities for discontinued operations				—			—

Net cash provided by financing activities				25,501			30,008

Net increase (decrease) in cash and cash equivalents				9,499			(7,105	)
Cash and cash equivalents:
	Beginning of period			176			12,973

	End of period		$	9,675		$	5,868

Supplemental Disclosure of Cash Flow Information:
	Cash paid during the period for interest		$	1,375		$	3,208
	Cash paid during the period for income taxes		$	—		$	—
Supplemental Disclosure of Noncash Investing and Financing Activities:
	Assets disposed in exchange for common stock		$	—		$	(17,335	)

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-29

Riata Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (unaudited)


1.	Basis of Presentation

The consolidated balance sheet of Riata Energy, Inc. and its subsidiaries (collectively, the “Company”) at December 31, 2004 was derived from the Company’s audited consolidated financial statements as of that date. The condensed consolidated balance sheet at September 30, 2005 and the condensed consolidated statements of operations for the nine months ended September 30, 2004 and 2005, and the condensed consolidated statements of cash flows for the nine months ended September 30, 2004 and 2005, were prepared by the Company. In the opinion of management all adjustments, consisting of normal recurring adjustments, necessary to state fairly the condensed consolidated financial position, results of operations and cash flows were recorded. The results of operations for the nine months ended September 30, 2005 are not necessarily indicative of the operating results for a full year or of future operations.

Certain information and footnote disclosures normally included in financial statements presented in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. The accompanying condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto contained in the Company’s annual audit for the year ended December 31, 2004.

The Company acquired an additional 12% interest in its equity investment, Cholla Pipeline. The operations of Cholla were consolidated as of June 2005. As of September 30, 2005, the Company’s interest in Cholla increased to 57%. Cholla owns a 4% interest in PetroSource Energy Company. Upon consolidation our ownership increased to 22.4% in PetroSource Energy Company. During the nine months ended September 30, 2005, the Company acquired an additional 44% equity ownership in Sagebrush Pipeline LLC for $5.3 million.

The condensed consolidated financial statements include the accounts of Riata Energy, Inc. and its wholly owned or majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.


2.	Significant Accounting Policies

Riata has not changed its accounting policies since December 31, 2004. For a description of those policies, refer to Note 1 of the 2004 consolidated financial statements.


3.	Asset Retirement Obligation

On January 1, 2003 the Company adopted Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). FAS 143 establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-lived assets. 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 under FAS 143 are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). The Company does not have any assets restricted for the purpose of settling the plugging liabilities. A reconciliation of the beginning and

F-30

Riata Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (unaudited) — (Continued)

ending aggregate carrying amount of our asset retirement obligations for each of the nine month periods ended September 30, 2004 and 2005 is as follows (in thousands):


	Nine Months Ended
	September 30,

	2004		2005

Asset retirement obligation, January 1	$	3,883	$	4,394
Liability incurred upon acquiring and drilling wells		215		174
Accretion of discount expense		102		172

Asset retirement obligation, September 30	$	4,200	$	4,740


4.	Long-Term Debt

Long-term obligations consist of the following at December 31, 2004 and September 30, 2005 (in thousands):


		December 31,		September 30,
		2004		2005

Revolver note payable to bank with a commitment not to exceed $55,000; interest at three-month LIBOR rate plus 2.15% per annum (6.56% at September 30, 2005); with a maturity date of December 31, 2007; collateralized by oil and gas properties and certain real property		$	45,264	$	35,485
Notes payable to bank; interest rates ranging from 7.64% to 8.25%; various maturity dates ranging from October 1, 2005 through November 1, 2010; collateralized by equipment and certain other assets			—		35,380
Note payable to bank; interest at prime rate (4.00% at September 30, 2005); with a maturity date of July 20, 2010; collateralized by equipment and certain other assets; monthly payments of $166,667			2,981		5,603
Note payable to bank; interest at prime rate (5.25% at September 30, 2005); with a maturity date of March 31, 2010; collateralized by equipment and certain other assets; monthly payments of $166,667			8,964		—
Other note payables; various interest rates; various monthly payments ranging from $1 to $134; various maturity dates ranging from December 22, 2005 to February 10, 2009			2,311		4,861

	Total debt		59,520		81,329
Less: Current maturities of long-term debt			3,202		9,226

Long-term debt		$	56,318	$	72,103

The revolver and notes payable contain affirmative and negative covenants, including the maintenance of certain financial ratios, restrictions on sales, leases or other dispositions of property and restrictions on other indebtedness. Events of default under the revolver and notes payable include cross-defaults to all material indebtedness, including each of those financings. As of September 30, 2005, the Company was in compliance with these covenants.

F-31

Riata Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (unaudited) — (Continued)


5.	Stockholders’ Equity

Common Stock and Preferred Stock

The following table presents information regarding Riata’s common stock:


	December 31,		September 30,
	2004		2005

Shares authorized		1,000,000		1,000,000
Shares outstanding at end of period		56,312,400		55,179,165
Shares held in treasury		—		1,414,849

Riata is authorized to issue 500,000 shares of preferred stock, no par value, of which 1,000 shares were outstanding as of December 31, 2004 and no shares were outstanding as of September 30, 2005.

On September 23, 2005, the preferred stock was converted into common stock.


6.	Discontinued Operations

On September 30, 2005, the Company exchanged 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 exchange of shares were transferred at historical basis and reflected as a treasury share transaction.

The land and agriculture operations are presented as discontinued operations, net of income taxes in the Condensed Consolidated Statements of Operations and the land and agriculture assets and liabilities are shown as separate line items in the Condensed Consolidated Balance Sheets.

The following table summarizes net revenue and net income from discontinued operations as follows (in thousands):


	Nine Months Ended
	September 30,

	2004			2005

Revenues	$	1,429		$	1,683
Operating expenses		(844	)		(1,336	)

Income from discontinued operations		585			347
Income tax expense		199			118

Net income from discontinued operations	$	386		$	229

The following table summarizes the major assets for sale at December 31, 2004 (in thousands):


			December 31,
			2004

Assets:
	Current		$	14
	Property, plant and equipment			22,504

		Total assets	$	22,518

Liabilities:
	Current		$	—
	Deferred income taxes			6,366

		Total liabilities	$	6,366

F-32

Riata Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (unaudited) — (Continued)


7.	Derivative Financial Instruments

The Company entered into interest rate swap agreements with a bank whereby the Company receives payments based on a floating one-month LIBOR rate plus 2.15% applied to notional amounts (totaling $25,000,000) and makes payments based on a fixed interest rate of 4.4% applied to the same notional amount. The Company has also entered into oil and gas futures contracts with a bank whereby the Company purchases, based on a fixed price, notional amounts monthly. The contracts expire on various dates through September 1, 2006.

At September 30, 2005, the Company’s open commodity derivatives consisted of the following:

Swaps and collars

Weighted Avg.

Period

Commodity

Notional

Fix Price

Receive Fixed/ Pay Variable Jan-05 — Dec-05

Natural Gas

184,000 MMBtu

4.84

Sales Oct-05 — Sept-06

Natural Gas

3,650,000 MMBtu

9.25

Purchases Oct-05 — Sept-06

Natural Gas

3,650,000 MMBtu

6.00

These derivatives have not been designated as hedges because they are for forecasted sales of commodities in the Company’s normal course of business.

The Company records all derivatives on the balance sheet at fair value. Changes in derivative fair values are recognized in earnings. The income (loss) recognized in earnings, included in gas purchases and cost of sales, for the nine months ended September 30, 2004 and 2005, is approximately $427,000 and $(8,601,000), respectively.


8.	Earnings per Share

Basic earnings per share (“EPS”) is calculated by dividing net income to common stock by the weighted-average number of shares of common stock outstanding during the period. No dilution for any potentially dilutive securities is included. Diluted EPS assumes the conversion of all potentially dilutive securities and is calculated by dividing net income to common stock, before the effect of preferred dividends, by the sum of the weighted-average number of shares of common stock outstanding plus all potentially dilutive securities.


9.	Commitments and Contingencies

Litigation with Conoco, Inc. The Company is a defendant in a lawsuit brought by Conoco, Inc. for alleged unpaid overriding royalties on production by the Company on certain leases in Pecos County, Texas. Conoco, Inc. alleges that it is entitled to 12.5% of the proceeds from production and the Company alleges that Conoco, Inc., at most, is only entitled to a 5.0% overriding royalty on production. At September 30, 2005, the Company had approximately $13,473,000 recorded as an accrual related to this lawsuit which represents the 12.5% of the proceeds from the production on those properties. This amount is included in accrued expenses on the Company’s consolidated balance sheet. The Company intends to vigorously defend its position.

F-33

Riata Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (unaudited) — (Continued)


10.	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 nine month period ended September 30:


	2004		2005

	(in thousands)
Sales to related parties	$	213	$	2,078

Purchases of services from related parties	$	3,763	$	3,147

Following is a summary of significant transactions with related parties as of December 31, 2004 and September 30, 2005:


	December 31,		September 30,
	2004		2005

	(in thousands)
Receivables from related parties for services rendered	$	1,116	$	1,673

Payables to related parties for services rendered	$	3,757	$	47


11.	Recently Issued Accounting Pronouncements

In November 2004, the Financial Accounting Standards Board (“FASB”) issued Statement on Financial Accounting Standards No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4,” which clarifies the types of costs that should be expensed rather than capitalized as inventory. The provisions of FAS 151 are effective for years beginning after June 15, 2005. The Company does not expect this statement to have a material impact on its results of operations or its financial condition.

The FASB issued Statement on Financial Accounting Standards No. 153, “Exchanges of Productive Assets,” in December 2004 that amended Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions.” FAS 153 requires that nonmonetary exchanges of similar productive assets are to be accounted for at fair value. Previously these transactions were accounted for at book value of the assets. This statement is effective for nonmonetary transactions occurring in fiscal periods beginning after

F-34

Riata Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (unaudited) — (Continued)

June 15, 2005. The Company does not expect this statement to have a material impact on its results of operations or its financial condition.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3”. Under this statement, voluntary changes in accounting principle are required to be applied retrospectively for the direct effects of a change to prior periods’ financial statements, unless such application is impracticable. Retrospective application refers to reflecting a change in accounting principle in the financial statements of prior periods as if the principle had always been used. When retrospective application is determined to be impracticable, this statement requires the new accounting principle to be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective treatment is practicable with a corresponding adjustment to the opening balance of retained earnings. This statement retains the guidance in APB Opinion No. 20 for reporting the corrections of errors and changes in accounting estimates. This statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, with early adoption permitted. The Company’s adoption of this statement will affect its consolidated financial statements for any changes in accounting principle it may make in the future, or new pronouncements it adopts that do not provide transition provisions.


12.	Industry Segment Information

Riata has three business segments: Exploration and Production, Drilling and Oil field Services and Midstream Gas Services, representing its three 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 and the Midstream Gas Services segment is engaged in the purchasing, gathering, processing and treating of natural gas.

Management evaluates the performance of Riata’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 our segments is shown in the following table (in thousands):


			Nine Months Ended
			September 30,

			2004			2005

Revenues:
	Exploration and production		$	27,642		$	34,530
	Elimination of inter-segment revenue			(1,227	)		(1,825	)

	Exploration and production, net of inter-segment revenue			26,415			32,705

	Drilling and oil field services			43,318			74,130
	Elimination of inter-segment revenue			(16,394	)		(18,678	)

	Drilling and oil field services, net of inter-segment revenue			26,924			55,452

	Midstream gas services			96,925			124,845
	Elimination of inter-segment revenue			(23,766	)		(31,717	)

	Midstream gas services, net of inter-segment revenue			73,159			93,128

		Total revenues	$	126,498		$	181,285

F-35

Riata Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (unaudited) — (Continued)


			Nine Months Ended
			September 30,

			2004			2005

	Exploration and production		$	5,813		$	(1,156	)
	Drilling and oil field services			4,857			12,975
	Midstream gas services			1,866			3,600
	Other			(55	)		(233	)

		Total operating income(1)		12,481			15,186
	Interest expense			(1,145	)		(2,938	)
	Other income (expense) — net			(255	)		(2,144	)

		Income before income taxes	$	11,081		$	10,104

Capital Expenditures:
	Exploration and production		$	17,191		$	20,042
	Drilling and oil field services			13,892			32,846
	Midstream gas services			1,649			18,569
	Other			2,029			4,329

		Total capital expenditures	$	34,761		$	75,786

Depreciation, Depletion and Amortization:
	Exploration and production		$	4,062		$	5,923
	Drilling and oil field services			4,521			7,694
	Midstream gas services			307			1,098
	Other			490			599

		Total depreciation, depletion and amortization	$	9,380		$	15,314


			December 31,		September 30,
			2004		2005

Identifiable Assets(2):
	Exploration and production		$	110,114	$	100,514
	Drilling and oil field services			35,807		73,694
	Midstream gas services			25,208		49,337

		Total identifiable assets		171,129		223,545
	Corporate assets			10,258		8,690

		Total assets	$	181,387	$	232,235


(1)	Operating income is total operating revenues less operating expenses, depreciation, depletion and amortization does not include non-operating revenues, general corporate expenses, interest expense or income taxes.

(2)	Identifiable assets are those used in Riata’s operations in each industry segment. Corporate assets are principally cash and cash equivalents, corporate leasehold improvements, furniture and equipment.


13.	Stock Split

On December 15, 2005, the Company entered into 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 four hundred million (400,000,000) shares of common stock with a par value of $0.001 per share.

F-36

Riata Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (unaudited) — (Continued)


14.	Subsequent Events

The Company recently sold 12.7 million shares in a private placement and received net proceeds from this sale of approximately $175.7 million after deducting the initial purchasers’ discount of $13.4 and offering expenses of approximately $2.0 million. Approximately $105.5 million of the proceeds of our initial public offering were used to repay outstanding bank debt and finance our December 2005 acquisitions described below.

Contemporaneously with the closing of the private placement, we closed a number of acquisitions. These transactions included;


	•	The acquisition of additional equity interests in PetroSource, our CO₂ and tertiary oil recovery subsidiary, to increase our ownership interest from 22.4% to 86.5%, resulting in the consolidation of PetroSource in our financial statements;

	•	The acquisition from an executive officer and director of the remaining 50% equity interest in our compression services subsidiary, Larco, resulting in it becoming a wholly-owned subsidiary;

	•	The acquisition from an executive officer and director of approximately 7,400 net acres of additional leasehold interest in West Texas in properties in which the Company previously held interests;

	•	The acquisition of approximately 2,503 net acres of additional leasehold interest in property in the Piceance Basin in which we previously held interests; and

	•	The acquisition from a director of additional working interests in Missouri and Nevada leases in which we previously held interests.

The acquisitions were financed with approximately $15.9 million in cash and the issuance of 3,508,335 shares of our common stock with an aggregate value of approximately $52.6 million.

Additionally, the Company granted restricted stock awards of 1.6 million shares which vest after one, four and seven years. The issuance of the restricted stock will result in our recognition of compensation expense, after income tax, of approximately $15.5 million over the respective vesting periods.

On December 22, 2005, the Company acquired certain interests in several oil and natural gas properties in West Texas from Carl E. Gungoll Exploration, LLC and certain other parties in exchange for consideration of 174,833 shares of common stock and $5.5 million in cash.

F-37

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders of

PetroSource Energy Company

In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of operations, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of PetroSource Energy Company (the “Company”) as of December 31, 2004, and the results of its operations and its cash flows for the year then ended 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 audit. We conducted our audit of these statements in accordance with auditing 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 audit provides a reasonable basis for our opinion.

PricewaterhouseCoopers LLP

May 31, 2005

Houston, Texas

F-38

PetroSource Energy Company

Consolidated Balance Sheet

(in thousands except per share data)


			December 31,
			2004

ASSETS
Current assets
	Cash and cash equivalents		$	4,220
	Accounts receivable, net			1,441
	Other current assets			228

		Total current assets		5,889
Property, plant and equipment, net				41,398
Other assets				237

		Total assets	$	47,524


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
	Current maturities of long-term debt		$	3,915
	Accounts payable			1,329
	Accrued liabilities			317
	Interest payable			346

		Total current liabilities		5,907
Long-term debt				29,626

		Total liabilities		35,533

Stockholders’ equity
	Common stock, par value $.01 — 1,000,000 shares authorized, 145,425 shares issued and outstanding			1
	Treasury stock at cost, 1,000 shares			(102	)
	Additional paid in capital			14,641
	Retained deficit			(2,549	)

		Total stockholders’ equity		11,991

		Total liabilities and stockholders’ equity	$	47,524

The accompanying notes are an integral part of these consolidated financial statements.

F-39

PetroSource Energy Company

Consolidated Statement of Operations

(in thousands)


	Year Ended
	December 31,
	2004

Revenues
Carbon dioxide sales	$	7,451
Oil and natural gas sales		166
Services		624
Other		210

		8,451

Operating costs
Gas purchases		4,562
Operations and maintenance		2,354
Depreciation, depletion and amortization		1,734
General and administration		1,051

		9,701

Operating loss		(1,250	)
Other income (expense)
Interest expense		(1,426	)
Income from equity investments		243

Loss before income tax		(2,433	)
Deferred income tax expense		(45	)

Net loss	$	(2,478	)

The accompanying notes are an integral part of these consolidated financial statements.

F-40

PetroSource Energy Company

Consolidated Statement of Stockholders’ Equity

(in thousands)


								Common
			Treasury					Stock
	Common		Stock, at			Paid in		Subscription			Retained
	Stock		Cost			Capital		Receivable			Deficit			Total

Balance, January 1, 2004	$	1	$	—		$	12,099	$	(3,531	)	$	(71	)	$	8,498
Sale of common stock		—		—			2,380		—			—			2,380
Stock issued as consideration for accrued interest		—		—			162		—			—			162
Payment of subscription receivable		—		—			—		3,531			—			3,531
Treasury stock acquired		—		(102	)		—		—			—			(102	)
Net loss		—		—			—		—			(2,478	)		(2,478	)

Balance, December 31, 2004	$	1	$	(102	)	$	14,641	$	—		$	(2,549	)	$	11,991

The accompanying notes are an integral part of these consolidated financial statements.

F-41

PetroSource Energy Company

Consolidated Statement of Cash Flows

(in thousands)


				Year Ended
				December 31,
				2004

Cash flows from operating activities
	Net loss			$	(2,478	)
	Adjustments to reconcile net loss to net cash used in operating activities:
		Loss on disposal of equipment			331
		Depreciation, depletion and amortization expense			1,734
		Debt issuance cost			56
		Deferred income taxes			45
	Changes in operating assets and liabilities increasing (decreasing) cash:
			Accounts receivable		381
			Accounts payable		(539	)
			Other current assets		184
			Accrued expenses		(147	)
			Interest payable		259

			Net cash used in operating activities		(174	)

	Cash flows from investing activities
		Additions to property, plant and equipment			(13,488	)
		Return of investment			1,707
		Acquisition of assets net of cash acquired			(5,010	)

			Net cash used in investing activities		(16,791	)

	Cash flows from financing activities
		Payment of subscription receivable			3,531
		Sale of common stock			2,380
		Proceeds from issuance of long-term debt			15,079
		Purchase of treasury stock			(102	)

			Net cash provided by financing activities		20,888

			Net increase in cash		3,923
	Cash
	Beginning of period				297

	End of period			$	4,220

The accompanying notes are an integral part of these consolidated financial statements.

F-42

PetroSource Energy Company

Notes to Consolidated Financial Statements


1.	Organization and Business

PetroSource Energy Company (the “Company”) was organized effective September 12, 2003. On October 31, 2003, the Company’s wholly owned subsidiary, PetroSource Energy Management Company, purchased the 2% general partner interest and the Company purchased the 98% limited partner interest in PSCO₂, L.P. from an unrelated party for a total consideration of $22.8 million. PSCO₂, L.P.’s only activity is its ownership of the partnership interests in Petro Source Carbon Company (“PSCC”), a CO₂ processing and distribution company. PSCO₂, L.P. accounted for its investment of 78% in PSCC on the equity method until June 1, 2004, because of the significant participating rights granted to the other partner. Effective June 1, 2004, the Company acquired the remaining interest in PSCC (Note 7).

The Company, through its wholly owned subsidiary, PSCC, effective June 1, 2004, acquires, compresses, transports and sells CO₂ through its CO₂ pipeline and spurs located in west Texas. In addition, effective in November 2004, the Company is engaged in the production and development of oil and gas activities located in the U.S.


2.	Summary of Significant Accounting Policies


	*Basis of Presentation*

The accompanying financial statements present the consolidated financial position, results of operations and cash flows of the Company in accordance with accounting principles generally accepted in the United States of America. All intercompany balances and transactions have been eliminated.


	*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 those estimates.


	*Cash and Cash Equivalents*

The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.


	*Property, Plant and Equipment*

Property, plant and equipment are stated at cost except for proved oil and gas properties and depreciated using the straight line method of accounting, with estimated economic lives ranging from 5 to 25 years. However, two pipelines contributed to the Company for a total of $3.4 million (Note 6) were idle awaiting interconnection with the pipeline owned by PSCC, as of December 31, 2003. During 2004, these pipelines were connected but have not been put in use. Therefore, no depreciation was taken in 2004 on the two pipelines. A review for the impairment of property, plant and equipment is performed whenever events or changes in circumstance indicate the carrying amount of an asset may not be recoverable. An impairment loss is recognized when estimated future cash flows expected to result from our use of the asset and its eventual disposition is less than the carrying amount.

Expenditures for renewals and betterments are capitalized while repairs and maintenance are charged to expense as incurred. The cost and accumulated depreciation of assets sold or otherwise disposed of are removed from the accounts and any gain or loss is reflected in the statements of income.

F-43

PetroSource Energy Company

Notes to Consolidated Financial Statements — (Continued)

Oil and Gas Operations

Oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method costs that are incurred to acquired leasehold and subsequent development costs are capitalized. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical and costs, and costs of certain nonproducing leasehold costs are expensed as incurred. The capitalized costs of the proved oil and gas properties are depreciated and depleted by the units-of-production method. Other equipment is depreciated over the estimated useful lives of the assets which is seven years.

A gain on the sale of property, plant and equipment used in our oil and gas producing activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation or the market value if the asset is being held for sale, and the sales proceeds received. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset.

Income Taxes

The Company records deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, using the regular tax rate expected to be in effect when the taxes are actually paid or recovered. The Company records net deferred tax assets related to the recognition of future tax benefits, to the extent that realization of such benefits is considered more likely than not to occur.

Revenue Recognition

Substantially all revenues are derived from the sale of CO₂. Revenue is recognized when the product is delivered to the customer. The Company recognized service fees as revenue when the related service is provided.

Revenues from the sale of oil and natural gas liquids production are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable.

Fair Value of Financial Instruments

For cash and cash equivalents, accounts receivable and accounts payable, the carrying amount approximates fair value because of the short maturity of those instruments. The fair value of the Company’s debt approximates market since the debt carries either a floating rate at current interest rate indexes or our fixed rate debt as approximates fair value.

Concentrations of Credit Risk

The Company maintains its cash in bank deposit accounts that, at times, exceed federally insured limits. Management believes that the financial strength of the financial institutions holding such deposits minimizes the credit risk of such deposits.

A significant portion of the Company’s receivables are from oil and gas companies. Although collection of these receivable could be influenced by economic factors affecting the oil and gas industry, the risk of significant loss is considered remote. In 2004, the Company received the majority of its revenue from two

F-44

PetroSource Energy Company

Notes to Consolidated Financial Statements — (Continued)

customers. For the year ended December 31, 2004, two customers accounted for approximately 13% and 75% of total revenues, respectively.

Derivatives

The Company records all derivatives on the balance sheet at fair value. Changes in derivative fair values is recognized in earnings. The amount recognized in earnings is not significant.

Other Current Assets

Prepaid expenses and other current assets includes prepayments for insurance and inventory purchases, manufacturing supplies and other current assets.


3.	Related Party Transactions

The following is a list of related party transactions for the year ended December 31, 2004 (in thousands):


Petro Source Carbon Company
Management fees received	$	555
Marketing fees received		69
Company shareholders
Interest accrued		135
Long-term notes payable (Note 5)		6,540
Interest paid (cash)		130
Interest paid (stock)		162
Riata Energy and its subsidiaries
Administrative fees received		169
Payment of operating expenses		106
Payment for fuel and gas		308
Management fees		247
Overhead expenses		94
Accounts receivable		176
Accounts payable		175

Petro Source Carbon Company was consolidated as of June 1, 2004 (Note 7) amounts disclosed are from the period of January 1, 2004, through May 31, 2004. Riata owns 16.623% of PetroSource Energy Company.


4.	Investment in Unconsolidated Subsidiary — Petro Source Carbon Company

Summarized financial information of PSCC for the period from January 1, 2004 to May 31, 2004 (See Note 1), is as follows (in thousands). The financial statements were consolidated as of June 1, 2004:


Revenues	$	5,211
Net income		316

The Company’s equity in:


Net income		$	243

F-45

PetroSource Energy Company

Notes to Consolidated Financial Statements — (Continued)


5.	Long-Term Debt

Following is a summary of the note payable and long-term debt at December 31, 2004 (in thousands):


Bank note payable due quarterly with interest at one month LIBOR plus 2.5% through 2007 3.61% as of December 31, 2004 collateralized by the assets of the Company	$	26,902
Subordinated debt payable to the shareholders due quarterly through 2010 with a fixed interest rate of 6%		6,540
Other		99

		33,541
Less: Current maturities		3,915

	$	29,626

Following are maturities of long-term debt as of December 31, 2004 (in thousands):


2005	$	3,915
2006		4,778
2007		21,111
2008		934
2009		934
Thereafter		1,869

	$	33,541


6.	Contributed Assets

The shareholders contributed $9,700,000 at the inception of the Company of which $3,531,998 was a subscription receivable as of December 31, 2003. In 2004 the subscription was paid. In addition, in 2003 two pipelines valued at $3,400,000 using an independent valuation were contributed to the Company by two different shareholders. For the contributed pipelines, the shareholders received $2,400,000 in stock and $1,000,000 in subordinated debt.


7.	Acquisitions

As of June 1, 2004, PSCO₂ acquired the remaining 22% of PSCC for a total consideration of $4.3 million from BP America Production Company. PetroSource Energy Company accounts for its investment in PSCO₂, LP on a consolidated basis.

F-46

PetroSource Energy Company

Notes to Consolidated Financial Statements — (Continued)

has consolidated PSCC effective June 1, 2004. PSCC balance sheet as of June 1, 2004, after purchase price adjustments, was as follows (in thousands):


Assets
Cash and cash equivalents		$	2,820
Accounts receivable			1,750
Prepaid expense and other assets			230
Property, plant and equipment			23,093

	Total assets	$	27,893


Liabilities and Partner Capital
Accounts payable and accrued liabilities		$	2,182
Long-term debt			138
Partner capital			25,573

	Total liabilities and partner capital	$	27,893

On November 1, 2004, the Company purchased from Raven Resources, L.L.C., Miranda Energy Corporation and Shenandoah Petroleum Corporation certain oil and gas properties and other assets for $3.6 million in cash. The Company’s allocation of the purchase price to assets acquired and liabilities assumed is preliminary, pending final purchase price adjustments that may be necessary following an analysis of the asset retirement obligations. The preliminary purchase price was allocated to oil and gas properties and other assets amounting to $3,540,000 and $94,845, respectively.


8.	Property, Plant and Equipment

Property, plant and equipment consisted of the following (in thousands):


		Estimated		December 31,
		Useful Life		2004

Pipelines			7 — 20 years	$	20,734
Buildings			7 — 25 years		358
Office equipment, furniture and fixtures, and vehicles			3 — 7 years		197
Compressor stations and other equipment			5 — 15 years		18,169
Proved oil and gas properties					3,457
Leasehold improvements			5 — 7 years		152

					43,067
Less: Accumulated depreciation, depletion and amortization					1,669

	Property, plant and equipment, net			$	41,398


9.	Long-Term Obligations

The Company has obligations under noncancelable operating leases primarily for the use of office space and compressor stations. Total rent expense under operating leases for the year ended December 31, 2004 was approximately $174,000.

F-47

PetroSource Energy Company

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, 2004, are as follows (in thousands):


Year Ending		Operating
December 31		Leases

2005		$	162
2006			162
2007			162
2008			162
2009			118
Thereafter			894

	Future minimum lease payments	$	1,660


10.	Income Taxes

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The tax effects of significant items comprising the Company’s net deferred tax assets (liabilities) as of December 31, 2004, are as follows (in thousands):


Net operating loss carryforward	$	993
Equipment		79
Unrealized loss on futures contracts		5
Valuation allowance		(1,077	)

Net deferred tax asset	$	—

The provision for income taxes from continuing operations consisted of the following components (in thousands):


Current		$	—
Deferred			45

	Total provision for income taxes	$	45


Computed at federal statutory rates		$	(827	)
Change in valuation allowance			872

	Total provision for income taxes	$	45

Management has determined that a full valuation allowance is necessary to reduce the net deferred tax assets to zero as it is not likely that such assets are realizable.


11.	Supplemental Disclosure of Cash Flow Information

Cash paid for interest during the year ended December 31, 2004, was approximately $986,000.


	*Noncash Activities*

The Company paid in the form of additional common stock approximately $162,000 of accrued interest from subordinated debt holders in 2004.


12.	Subsequent Events

On March 4, 2005, the Company converted to a Limited Partnership. The Company’s tax attributes including net operating losses will not carryover to the new entity. The Company obtained a line of credit in March 2005 amounting to $6,900,000. The Company borrowed approximately $5,200,000 to purchase the oil and gas properties in March 2005. The line of credit is due March 2006.

F-48

PetroSource Energy Company

Condensed Consolidated Balance Sheets

(in thousands)

(unaudited)


			December 31,			September 30,
			2004			2005

ASSETS
Current assets
	Cash and cash equivalents		$	4,220		$	66
	Accounts receivable			1,441			4,543
	Prepaid expenses and other assets			228			123

		Total current assets		5,889			4,732
Property, plant and equipment, net				41,398			48,833
Other assets				237			417

		Total assets	$	47,524		$	53,982


LIABILITIES AND STOCKHOLDERS’ EQUITY AND PARTNERS’ CAPITAL
Current liabilities
	Current maturities of long-term debt		$	3,915		$	9,759
	Accounts payable			1,329			801
	Accrued liabilities			317			1,109
	Interest payable			346			688

		Total current liabilities		5,907			12,357
Asset retirement obligation				—			2,429
Long-term debt				29,626			27,678

		Total liabilities		35,533			42,464

Stockholders’ equity and partners’ capital
	Common stock, par value $.01 — 1,000,000 shares authorized, 145,425 and 121,000 shares issued and outstanding, respectively			1			—
	Treasury stock at cost, 1,000 shares			(102	)		—
	Additional paid in capital			14,641			—
	Retained deficit			(2,549	)		—
	Partner’s capital			—			11,518

		Total stockholders’ equity and partners’ capital		11,991			11,518

		Total liabilities and stockholders’ equity and partners’ capital	$	47,524		$	53,982

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-49

PetroSource Energy Company

Condensed Consolidated Statements of Operations

(in thousands)

(unaudited)


	Nine Months Ended
	September 30,

	2004			2005

Revenues
Carbon dioxide sales	$	4,110		$	11,914
Exploration and production		—			1,280
Services		547			215
Other		72			—

		4,729			13,409

Operating costs
Exploration and production		—			931
Gas purchases		2,545			5,644
Operations and maintenance		1,828			4,228
Depreciation, depletion and amortization		985			2,760
General and administration		624			988

		5,982			14,551

Operating loss		(1,253	)		(1,142	)
Other income (expense)
Interest expense		(1,066	)		(1,530	)
Income from equity investment		243			—

Loss before income tax		(2,076	)		(2,672	)
Deferred income tax expense		(45	)		—

Net loss	$	(2,121	)	$	(2,672	)

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-50

PetroSource Energy Company

Condensed Consolidated Statements of Cash Flows

(in thousands)

(unaudited)


		Nine Months Ended
		September 30,

		2004			2005

Cash flows from operating activities
	Net cash used in operating activities	$	(160	)	$	(2,483	)

Cash flows from investing activities
Additions to property, plant and equipment			(8,824	)		(2,104	)
Return of investment			1,707			—
Acquisition of assets net of cash acquired			(5,010	)		(5,663	)

	Net cash used in investing activities		(12,127	)		(7,767	)

Cash flows from financing activities
Payment of subscription receivable			3,531			—
Contributions from partners			—			2,200
Proceeds from issuance of long-term debt			15,056			5,844
Purchase of treasury stock			(102	)		—
Principal payment			—			(1,948	)

	Net cash provided by financing activities		18,485			6,096

	Net increase (decrease) in cash		6,198			(4,154	)
Cash
Beginning of period			297			4,220

End of period		$	6,495		$	66

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-51

PetroSource Energy Company

Notes to Condensed Consolidated Financial Statements (unaudited)


1.	Summary of Significant Accounting Policies

The consolidated balance sheet of PetroSource Energy Company (“PetroSource”) and its subsidiaries (collectively, the “Company”) at December 31, 2004 was derived from the Company’s audited consolidated financial statements as of that date. The consolidated balance sheet at September 30, 2005 and the consolidated statements of operations for the nine months ended September 30, 2004 and 2005, and the consolidated statements of cash flows for the nine months ended September 30, 2004 and 2005, were prepared by the Company and are unaudited. In the opinion of management all adjustments, consisting of normal recurring adjustments, necessary to fairly state the consolidated financial position, results of operations and cash flows were recorded. The results of operations for the nine months ended September 30, 2005 are not necessarily indicative of the operating results for a full year or of future operations.

Certain information and footnote disclosures normally included in financial statements presented in accordance with accounting principles generally accepted in the United States of America were omitted. The accompanying consolidated financial statements should be read in conjunction with the financial statements and notes thereto contained in the Company’s audited financial statements. All intercompany balances and transactions have been eliminated.

Income Taxes

Prior to March 4, 2005, the Company recorded deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, using the regular tax rate expected to be in effect when the taxes are actually paid or recovered. The Company recorded deferred tax assets related to the recognition of future tax benefits, to the extent that realization of such benefits was considered more likely than not to occur.

On March 4, 2005, the Company converted to a Limited Partnership. The Company’s tax attributes including net operating losses will not carryover to the new entity.

The Company is not a taxable entity for federal tax purposes. As such, the Company does not pay federal income taxes. The Company’s taxable income or loss, which may vary substantially from net income or net loss we report in our consolidated statement of income, is includable in the federal tax return of each partner.

Estimates

Recently Issued Accounting Pronouncements

F-52

PetroSource Energy Company

Notes to Condensed Consolidated Financial Statements (unaudited) — (Continued)

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3”. Under this statement, voluntary changes in accounting principle are required to be applied retrospectively for the direct effects of a change to prior periods’ financial statements, unless such application is impracticable. Retrospective application refers to reflecting a change in accounting principle in the financial statements of prior periods as if the principle had always been used. When retrospective application is determined to be impracticable, this statement requires the new accounting principle to be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective treatment is practicable with a corresponding adjustment to the opening balance of retained earnings. This statement retains the guidance in APB Opinion No. 20 for reporting the corrections of errors and changes in accounting estimates. This statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, with early adoption permitted. The Company’s adoption of this statement will effect its consolidated financial statements for any changes in accounting principle it may make in the future, or new pronouncements it adopts that do not provide transition provisions.


2.	Related Party Transactions

The following is a list of related party transactions for the nine months ended September 30, 2004 and 2005 (in thousands):


	2004		2005

Petro Source Carbon Company
Management fees received	$	113	$	—
Marketing fees received		69		—
Company shareholders
Interest accrued		196		429
Long-term notes payable		6,540		6,540
Interest paid (cash)		130		—
Riata Energy and its subsidiaries
Administrative fees received		—		255
Payment of operating expenses		106		—
Payment for fuel and gas		—		1,339
Management fees		247		—
Overhead expenses		123		58
Accounts receivable		17		41
Accounts payable		48		390

Petro Source Carbon Company was consolidated as of June 1, 2004 (Note 7). Amounts disclosed are for the period from January 1, 2004 through May 31, 2004.


3.	Asset Retirement Obligations

The Company accounts for its legal obligations associated with the retirement of long-lived assets pursuant to Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). SFAS No. 143 provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.

SFAS No. 143 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. Under SFAS No. 143, the fair value of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time the assets are installed

F-53

PetroSource Energy Company

Notes to Condensed Consolidated Financial Statements (unaudited) — (Continued)

or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities will be accreted for the change in their present value and the initial capitalized costs will be depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service.

In our Oil and Gas Business, we are required to plug and abandon oil and gas wells that have been removed from service and to remove our surface wellhead equipment. As of September 30, 2005, we have recognized asset retirement obligations in the aggregate amounts of $2.4 million relating to these requirements at existing Oil & Gas Properties.


	Nine Months
	Ended
	September 30,
	2005

Asset retirement obligation, January 1	$	—
Liability incurred upon acquiring and drilling wells		2,312
Accretion expense		117

Asset retirement obligation, September 30	$	2,429


4.	Investment in Unconsolidated Subsidiary — Petro Source Carbon Company

Summarized financial information of PSCC for the period from January 1, 2004 to May 31, 2004 (in thousands) is as follows:


	2004

Revenues	$	5,211
Net income		316

The Company’s equity in:


	2004

Net income	$	243


5.	Long-Term Debt

Following is a summary of the note payable and long-term debt at December 31, 2004 and September 30, 2005 (in thousands):


	December 31,		September 30,
	2004		2005

Bank note payable due quarterly with interest at one month LIBOR plus 2.5% through 2007, 3.61% as of December 31, 2004, collateralized by the assets of the Company	$	26,902	$	24,981
Subordinated debt payable to the shareholders due quarterly through 2010 with a fixed interest rate of 6%		6,540		6,540
Bank note payable with interest at one month prime rate floating, due in March 2006		—		5,877
Other		99		39

		33,541		37,437
Less: Current maturities		3,915		9,759

	$	29,626	$	27,678

F-54

PetroSource Energy Company

Notes to Condensed Consolidated Financial Statements (unaudited) — (Continued)


6.	Derivative Financial Instruments

The Company has two interest rate swap agreements with a bank in the amounts of $6 million and $5.6 million whereby the Company receives payments based on a floating three-month LIBOR rate plus a fixed of rate of 2.25%, applied to notional amounts and makes payments based on a fixed interest rate of 3.49% and 3.38%, respectively, applied to the same notional amount.

The Company records all derivatives on the balance sheet at fair value. Changes in derivative fair values are recognized in earnings. The income (loss) recognized in earnings is included in interest expense, for the nine months ended September 30, 2004 and 2005, is approximately ($125,000) and $219,000, respectively.


7.	Acquisitions

As of June 1, 2004, PSCO₂ acquired the remaining 22% of PSCC for a total consideration of $4.3 million from BP America Production Company. Beginning June 1, 2004, PetroSource Energy Company consolidated its investment in PSCO₂, LP.

Prior to June 1, 2004, the investment in PSCC was accounted for as an equity investment because of the significant participating rights granted to the other partner. Since the Company acquired the additional 22% it has consolidated PSCC effective June 1, 2004. PSCC balance sheet as of June 1, 2004, after purchase price adjustments, was as follows (in thousands):


Assets
Cash and cash equivalents		$	2,820
Accounts receivable			1,750
Prepaid expense and other assets			230
Property, plant and equipment			23,093

	Total assets	$	27,893


Liabilities and Partner Capital
Accounts payable and accrued liabilities		$	2,182
Long-term debt			138
Partner capital			25,573

	Total liabilities and partner capital	$	27,893

On November 1, 2004, the Company purchased from Raven Resources, L.L.C., Miranda Energy Corporation and Shenandoah Petroleum Corporation certain oil and gas properties and other assets for $3.6 million in cash. The Company’s allocation of the purchase price to assets acquired and liabilities assumed is preliminary, pending final purchase price adjustments that may be necessary following an analysis of the asset retirement obligations. The purchase price was allocated to oil and gas properties and other assets amounting to $3,540,000 and $94,845, respectively.

In February 2005, the Company paid approximately $5,900,000 to purchase the Wellman unit, which includes a CO₂ processing facility and oil and gas properties.


8.	Supplemental Disclosure of Cash Flow Information

Cash paid for interest during the nine months ended September 30, 2004 and 2005 was approximately $676,000 and $1,441,000, respectively.

F-55

Appendix A

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas 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.

AMI. Area of mutual interest.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this prospectus in reference to crude oil or other liquid hydrocarbons.

Bcf. Billion cubic feet of natural gas.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well. A well drilled into a proved natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Environmental Assessment (EA). An environmental assessment, a study that can be required pursuant to federal law prior to drilling a well.

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.

Identified drilling locations. Total gross locations specifically identified and scheduled by management as an estimation of the Company’s multi-year drilling activities on existing acreage. The Company’s actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

A-1

Location Construction. The use of dirt equipment to construct oil field roads and locations for oil and natural gas wells.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. Thousand cubic feet of natural gas.

Mcf/d. Mcf per day.

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MmBbls. Million barrels of crude oil or other liquid hydrocarbons.

Mmboe. Million barrels of oil equivalent.

MBtu. Thousand British Thermal Units.

MmBtu. Million British Thermal Units.

Mmcf. Million cubic feet of natural gas.

Mmcf/d. Mmcf per day.

Mmcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Mmcfe/d. Mmcfe per day.

Mudlogging. Mudlogging is the process of examining and logging the cuttings from a well as it is being drilled. Geologists and engineers use this information in analyzing what zones in the well should be tested and completed.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Present value of future net revenues (PV-10). The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation and without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization. PV-10 is calculated using an annual discount rate of 10%.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved 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.

A-2

Pulling Units. Pulling units are used in connection with completions and workover operations.

PV-10. See “Present value of future net revenues.”

Rental Tools. A variety of rental tools and equipment, ranging from trash trailers to blow out preventors to sand separators, for use in the oil field.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Roustabout Services. The provision of manpower to assist in conducting oil field operations.

Standardized Measure. 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.

Stratigraphic play. An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.

Structural play. An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.

Trucking. The provision of trucks to move our drilling rigs from one well location to another and to deliver water and equipment to the field.

Underbalanced Drilling Systems. The use of an “underbalanced” drilling system lightens the hydrostatic pressure of the drilling fluid column so that it is less than the pressure of the formation. When drilling “underbalanced,” it is possible to drill wells faster than with traditional drilling fluids.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

A-3

________________________________________________________________________________

Shares

Riata Energy, Inc.

Common Stock

Prospectus

, 2006

Until , 2006 all dealers that buy, sell or trade the common stock may be required to deliver a prospectus, regardless of whether they are participating in this offering. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS


ITEM 13.	*Other Expenses of Issuance and Distribution*

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the NASD filing fee and the NYSE filing fee, the amounts set forth below are estimates:


Securities and Exchange Commission registration fee		$	29,540
NYSE listing fee			*
Legal fees and expenses			*
Accounting fees and expenses			*
Transfer agent and registrar fees			*
Miscellaneous			*

	TOTAL	$	*


*	To be completed by amendment.


ITEM 14.	*Indemnification of Directors and Officers*

Article 2.02.A.(16) and Article 2.02-1 of the Texas Business Corporation Act and Article VI of the Amended and Restated Bylaws of Riata Energy, Inc. (the “Company”) provide the Company with broad powers and authority to indemnify its directors and officers and to purchase and maintain insurance for such purposes. Pursuant to such statutory and Bylaw provisions, the Company has purchased insurance against certain costs of indemnification that may be incurred by it and by its officers and directors.

Additionally, Article X of the Company’s Restated Articles of Incorporation provides that a director of the Company is not liable to the Company for monetary damages for any act or omission in the director’s capacity as director, except that Article X does not eliminate or limit the liability of a director for (i) breaches of such director’s duty of loyalty to the Company and its shareholders, (ii) acts or omissions not in good faith or which involve intentional misconduct or knowing violation of law, (iii) transactions from which a director receives an improper benefit, irrespective of whether the benefit resulted from an action taken within the scope of the director’s office, (iv) acts or omissions for which liability is specifically provided by statute and (v) acts relating to unlawful stock repurchases or payments of dividends.

Article X also provides that any subsequent amendments to Texas statutes that further limit the liability of directors will inure to the benefit of the directors, without any further action by shareholders. Any repeal or modification of Article X shall not adversely affect any right of protection of a director of the Company existing at the time of the repeal or modification.


ITEM 15.	*Recent Sales of Unregistered Securities*

During the past three years, we have issued unregistered securities to a limited number of persons, as described below:

On December 22, 2005, we acquired certain interests in several oil and natural gas properties in West Texas from Carl E. Gungoll Exploration, LLC and certain other parties in exchange for consideration of 174,833 shares of our common stock and additional cash. This transaction did not involve any underwriter or a public offering, and we believe this transaction was exempt from registration requirements pursuant to

II-1

Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”), and Regulation D promulgated thereunder. Each of the recipients of these securities represented their status as an “accredited investor” (within the meaning of Rule 501(a) under the Securities Act).

On December 21, 2005, we acquired ownership interests in a variety of entities in which we previously held interests, as well as additional leasehold and working interests in oil and natural gas properties in the Piceance Basin in exchange for consideration of 3,508,335 shares of our common stock and additional cash. This transaction did not involve any underwriter or a public offering, and we believe this transaction was exempt from registration requirements pursuant to Section 4(2) of the Securities Act and Regulation D promulgated thereunder. Each of the recipients of these securities represented their status as an “accredited investor” (within the meaning of Rule 501(a) under the Securities Act).

We sold 12,500,000 shares of our common stock on December 21, 2005 and an additional 239,630 shares of our common stock on January 9, 2006 in a private placement to Banc of America Securities LLC and Goldman, Sachs & Co. who resold those shares to certain eligible investors. This transaction did not involve a public offering, and we believe this transaction was exempt from registration requirements pursuant to Section 4(2) of the Securities Act.

On December 21, 2005, we granted restricted stock awards consisting of an aggregate of 1,552,167 shares of our common stock. This transaction did not involve any underwriter or a public offering, and we believe this transaction was exempt from registration requirements pursuant to Securities and Exchange Commission Rule 701 under the Securities Act.


ITEM 16.	*Exhibits and Financial Statement Schedules*


	a.	Exhibits:


3	.1*	—	Restated Articles of Incorporation
3	.2*	—	Amended and Restated Bylaws
4	.1**	—	Specimen Stock Certificate representing common stock
4	.2*	—	Resale Registration Rights Agreement, dated December 21, 2005, by and between Riata Energy, Inc. and Banc of America Securities LLC
5	.1**	—	Opinion of Vinson & Elkins L.L.P.
10	.1**	—	401(k) Plan of Riata Energy, Inc.
10	.2*	—	2005 Stock Plan of Riata Energy, Inc.
10	.3*	—	Employee Participation Plan of Riata Energy, Inc.
10	.4*	—	First Amended and Restated Master Credit Agreement dated January 12, 2006 by and among Riata Energy, Inc., certain guarantors party thereto and Bank of America, N.A.
10	.5**	—	Form of Indemnification Agreement
21	.1*	—	Subsidiaries of Riata Energy, Inc.
23	.1*	—	Consent of PricewaterhouseCoopers LLP (Riata)
23	.2*	—	Consent of PricewaterhouseCoopers LLP (PetroSource)
23	.3*	—	Consent of Michael Harper & Associates
23	.4*	—	Consent of DeGolyer & MacNaughton
23	.5**	—	Consent of Vinson & Elkins L.L.P. (Contained in Exhibit 5.1)
24	.1	—	Power of Attorney (included on signature page)


*	Filed herewith

**	To be filed by amendment


	b.	Financial Statement Schedules

None

II-2


ITEM 17.	*Undertakings*

(a) The undersigned registrant hereby undertakes:

(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 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 Securities and Exchange Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

	(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.

(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.

(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(5) That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities: The undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:


	(i) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

	(ii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

	(iii) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

II-3


	(iv) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

(b) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

II-4

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 Amarillo, in the State of Texas, on February 10, 2006.


	RIATA ENERGY, INC.


	By:	/s/ Malone Mitchell, 3rd



	Name: Malone Mitchell, 3rd


	Title:	President, Chief Executive Officer


	And Chairman

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Malone Mitchell, 3rd and Dan Jordan, 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		Date


/s/ Malone Mitchell, 3rd Malone Mitchell, 3rd	President, Chief Executive Officer and Chairman (Principal Executive Officer)	February 10, 2006

/s/ John Gaines John Gaines	Chief Financial Officer (Principal Financial Officer)	February 10, 2006

/s/ Dan Jordan Dan Jordan	Vice President, Operations and Director	February 10, 2006

/s/ Barbara Pope Barbara Pope	Vice President, Accounting (Principal Accounting Officer)	February 10, 2006

/s/ Bill Gilliland Bill Gilliland	Director	February 10, 2006

/s/ Kurt G. Keene Kurt G. Keene	Director	February 10, 2006

/s/ Ira A. Post Ira A. Post	Director	February 10, 2006

/s/ Michael Harvey Michael Harvey	Director	February 10, 2006

II-5

EXHIBIT INDEX


Exhibit
Number				Description

	3	.1*	—	Restated Articles of Incorporation
	3	.2*	—	Amended and Restated Bylaws
	4	.1**	—	Specimen Stock Certificate representing common stock
	4	.2*	—	Resale Registration Rights Agreement, dated December 21, 2005, by and between Riata Energy, Inc. and Banc of America Securities LLC
	5	.1**	—	Opinion of Vinson & Elkins L.L.P.
	10	.1**	—	401(k) Plan of Riata Energy, Inc.
	10	.2*	—	2005 Stock Plan of Riata Energy, Inc.
	10	.3*	—	Employee Participation Plan of Riata Energy, Inc.
	10	.4*	—	First Amended and Restated Master Credit Agreement dated January 12, 2006 by and among Riata Energy, Inc., certain guarantors party thereto and Bank of America, N.A.
	10	.5**	—	Form of Indemnification Agreement
	21	.1*	—	Subsidiaries of Riata Energy, Inc.
	23	.1*	—	Consent of PricewaterhouseCoopers LLP (Riata)
	23	.2*	—	Consent of PricewaterhouseCoopers LLP (PetroSource)
	23	.3*	—	Consent of Michael Harper & Associates
	23	.4*	—	Consent of DeGolyer & MacNaughton
	23	.5**	—	Consent of Vinson & Elkins L.L.P. (Contained in Exhibit 5.1)
	24	.1	—	Power of Attorney (included on signature page)


*	Filed herewith

**	To be filed by amendment