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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on January 27, 2012

Registration No. 333-

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

Three Rivers Operating Company Inc.
(Exact name of registrant as specified in its charter)


Delaware	1311	38-3865257
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

1122 South Capital of Texas Highway, Suite 325
Austin, Texas 78746
512-600-3190
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Gabriel L. Ellisor
Chief Financial Officer
Three Rivers Operating Company Inc.
1122 South Capital of Texas Highway, Suite 325
Austin, Texas 78746
512-600-3190
(Name, address, including zip code, and telephone number, including area code, of agent for service)


Copies to:
Charles H. Still, Jr. Bracewell & Giuliani LLP 711 Louisiana Street, Suite 2300 Houston, Texas 77002 (713) 221-3309		David P. Oelman Matthew R. Pacey Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2500 Houston, Texas 77002 (713) 758-2222

Approximate date of commencement of proposed sale to the public:
As soon as practicable after the effective date of this registration statement.

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

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, 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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer o		Accelerated filer o		Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company o

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to Be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee




Common Stock, par value $0.01 per share	$300,000,000	$34,380

(1): Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.
(2): Includes shares of common stock issuable upon exercise of the underwriters' option to purchase additional shares of common stock.

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.

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The information in this prospectus is not complete and may be changed. We and the selling stockholder 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 state where the offer or sale is not permitted.

Subject to Completion
Preliminary Prospectus dated January 27, 2012

P R O S P E C T U S

Shares

Three Rivers Operating Company Inc.

Common Stock

Three Rivers Operating Company Inc. is offering shares of its common stock and the selling stockholder is offering shares of common stock. We will not receive any proceeds from the sale of the common stock by the selling stockholder. This is the initial public offering of our common stock. Prior to this offering, there has been no public market for our common stock. The initial public offering price of the common stock is expected to be between $ and $ per share. We intend to apply to list our common stock on the New York Stock Exchange under the symbol "TROC."

Investing in our common stock involves risks. See "Risk Factors" beginning on page 17.

	Price to Public	Underwriting Discounts and Commissions	Proceeds to Us	Proceeds to Selling Stockholder




Per Share	$	$	$	$

Total	$	$	$	$

To the extent the underwriters sell more than shares of common stock, the underwriters have an option to purchase up to an additional shares of common stock from the selling stockholder at the initial price to the public less the underwriting discount. The underwriters can exercise this option at any time within 30 days from the date of this prospectus.

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

Delivery of the shares of common stock will be made on our about .


Goldman, Sachs & Co.		J.P. Morgan		Credit Suisse

The date of this prospectus is

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TABLE OF CONTENTS


PROSPECTUS SUMMARY			1
RISK FACTORS			17
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			41
USE OF PROCEEDS			43
DIVIDEND POLICY			43
CAPITALIZATION			44
DILUTION			45
SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA			46
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			49
BUSINESS			69
MANAGEMENT			96
EXECUTIVE COMPENSATION			101
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			106
CORPORATE REORGANIZATION			108
PRINCIPAL AND SELLING STOCKHOLDERS			109
DESCRIPTION OF CAPITAL STOCK			111
SHARES ELIGIBLE FOR FUTURE SALE			115
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS TO NON-U.S. HOLDERS			117
UNDERWRITING			121
LEGAL MATTERS			128
EXPERTS			128
WHERE YOU CAN FIND MORE INFORMATION			129
INDEX TO FINANCIAL STATEMENTS			F-1
GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS			A-1

You should rely only on the information contained in this document and any free writing prospectus we provide you. We, the selling stockholder and the underwriters have not authorized anyone to provide you with additional or different information. We, the selling stockholder and the underwriters are offering to sell, and seeking offers to buy, these securities only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of these securities.

Dealer Prospectus Delivery Obligation

Until , all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. 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.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information.

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PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all the information that you should consider before investing in our common stock. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings "Risk Factors," "Cautionary Note Regarding Forward-Looking Statements" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical and pro forma financial statements and the notes thereto included elsewhere in this prospectus. Unless otherwise stated in this prospectus, references to "Three Rivers," "we," "us" or "our company" refer to Three Rivers Operating Company LLC and its subsidiaries prior to the completion of our corporate reorganization, and Three Rivers Operating Company Inc. and its subsidiaries as of the completion of our corporate reorganization and thereafter. References to "Riverstone" refer to Riverstone/Carlyle Global Energy and Power Fund IV, L.P. and affiliated entities, including Riverstone Holdings LLC. Unless otherwise indicated, information presented in this prospectus assumes that the underwriters' option to purchase additional shares of our common stock is not exercised. We have provided definitions for some of the industry terms used in this prospectus in the "Glossary of Selected Oil and Natural Gas Terms."

Overview

We are an independent exploration and production company engaged in the exploration, development, production and acquisition of oil and natural gas in the Permian Basin of West Texas and Southeast New Mexico. Our drilling activity is primarily focused in the Bone Spring formation in New Mexico and the Wolfberry formation in West Texas. Both plays are characterized by high oil and liquids-rich natural gas content, multiple target horizons, long-lived resources, and high drilling success rates. In total we have accumulated 200,598 net acres in the Permian Basin, of which 65.4% is held-by-production, providing a multi-year inventory of 2,863 gross (2,212 net) identified future drilling locations and an additional 266 gross (212 net) identified recompletion opportunities.

Since our inception in March 2010, we have increased our average daily production from 2,834 Boe/day in the month ended April 30, 2010 to 7,961 Boe/day for the three months ended September 30, 2011 through acquisitions and development drilling. For the three months ended September 30, 2011, 61% of our average daily production was oil or liquids volumes. The increase in our production includes the effects of sales of non-core assets that contributed approximately 340 Boe/day of production prior to their sale during the first five months of 2011. Cawley, Gillespie & Associates, Inc., our independent reserve engineers, estimated our net proved reserves to be 73.9 MMBoe as of September 30, 2011, an increase of 14.2% from our estimated pro forma net proved reserves as of December 31, 2010 of 64.7 MMBoe. As of September 30, 2011, 51.4% of our estimated proved reserves were classified as proved developed. As a result of our focus on oil and liquids-rich natural gas opportunities, we have increased the percentage of our estimated net proved reserves that constitute oil and natural gas liquids to 68% as of September 30, 2011 from 54% on a pro forma basis as of December 31, 2010.

Our business is concentrated in the Permian Basin of West Texas and Southeast New Mexico. The Permian Basin is one of the most prolific and largest producing oil and gas natural regions in the United States. We have three core operating areas within the Permian Basin:

•: the Bone Spring formation, which occurs in the Delaware Basin;
•: the Wolfberry, targeting the Spraberry and Wolfcamp formations, which occur primarily in the Midland Basin; and
•: Conventional Permian, where we target conventional Permian Basin oil and natural gas formations primarily in the Central Basin Platform.

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The following table summarizes, for each of our core operating areas, our net acreage as of December 31, 2011, identified drilling locations as of September 30, 2011, estimated total proved reserves and related PV-10 as of September 30, 2011, and average daily production for the nine-month period ended September 30, 2011:

						Identified Drilling Locations(1)

			% of Net Acreage Held-by- Production			Identified Drilling Locations(1)													Average Daily Production (Boe/day)
	Net Acreage		% of Net Acreage Held-by- Production			Gross		Net		% Operated				PV-10(2) (in thousands)		% Proved Developed			Average Daily Production (Boe/day)
Bone Spring		39,732		52.1	%		464		250		64.7	%	4,636	$	56,307		35.9	%		319
Wolfberry		45,227		60.0	%		1,995		1,646		86.2	%	36,254		524,309		33.9	%		3,087
Conventional Permian		115,639		72.1	%		404		316		88.4	%	33,009		401,917		72.8	%		4,471

Total		200,598		65.4	%		2,863		2,212		83.0	%	73,899	$	982,533		51.4	%		7,877

(1): Approximately 17% of our total gross identified drilling locations are attributable to proved undeveloped reserves. For additional information regarding our identified drilling locations, including the processes and criteria we used to identify these drilling locations, see "Business—Our Operations—Identified Drilling Locations." Amounts do not include our 266 gross (212 net) recompletion opportunities.
(2): PV-10 is a non-GAAP financial measure. For additional information about PV-10 and how it differs from the Standardized Measure, see "—Summary Historical Reserve and Operating Data."

Since our inception in March 2010, we have completed two significant, complementary acquisitions of oil and natural gas properties in the Permian Basin. In April 2010 we acquired interests in oil and natural gas properties from Chesapeake Energy Corporation, which we refer to as the Chesapeake Acquired Properties, and in January 2011 we acquired interests in oil and natural gas properties from Samson Resources Company, which we refer to as the Samson Acquired Properties. These acquisitions included complementary and overlapping acreage positions, similar target formations, and jointly-owned wells, which have allowed us to achieve significant post-acquisition operational and cost efficiencies. Together, at the time of each respective acquisition, these purchases consisted of approximately 131,000 net held-by-production acres, 62.4 MMBoe of estimated proved reserves and interests in 1,450 producing wells in the Permian Basin in West Texas and Southeast New Mexico. Following these acquisitions, we have leased an additional approximately 14,707 acres in and around our core operating areas to add scale to our existing properties.

We commenced drilling operations in September 2010. In the nine months ended September 30, 2011, we drilled a total of 23 operated gross wells (of which one was awaiting completion at September 30, 2011), participated in the drilling of 31 additional non-operated gross wells and performed 26 recompletions. As of December 31, 2011, we had a total of three operated rigs running, with two rigs operating in our Wolfberry core area and one rig operating in our Conventional Permian core area.

Our estimated 2011 capital expenditures were approximately $110.1 million, approximately $96.0 million of which was dedicated to drilling, completions and recompletions. During 2011, we drilled a total of 71 gross wells, 36 of which are operated by us. Our total 2012 capital expenditure budget is approximately $266.1 million, $254.2 million of which is dedicated to drilling, completions and recompletions. All of our operated 2012 drilling, completion and recompletion capital expenditure budget is targeted towards oil and liquids-rich natural gas reserves and resource opportunities, with 39% of our drilling, completion and recompletion capital expenditure budget targeting the Bone Spring and 51% targeting the Wolfberry. The following table provides information regarding our estimated

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2011 capital expenditures and our 2012 capital expenditure budget for drilling, completion and recompletion activities and the number of gross identified drilling locations drilled and expected to be drilled in each of our core operating areas:

	Estimated for Year Ended December 31, 2011			Budget for Year Ending December 31, 2012

	(in thousands)			(in thousands)
Bone Spring	$	5,305	4	$	99,978	26
Wolfberry		75,306	89		130,526	151
Conventional Permian		15,418	15		23,732	14

Total	$	96,029	108	$	254,236	191

(1): Represents locations drilled and recompletions performed during the year ended December 31, 2011.
(2): Represents locations expected to be drilled, including operated and non-operated, and recompletions expected to be performed during the year ending December 31, 2012.

The ultimate amount of capital we will expend and the identified drilling locations we will drill may fluctuate materially based on market conditions and the success of our drilling operations as the year progresses. Please read "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" and "Business—Our Operations—Capital Expenditures" for further detail.

Our Strengths

We believe we are well positioned to successfully execute our business strategies and achieve our business objectives because of the following competitive strengths:

Oil-Focused Operations in the Permian Basin. Our operations are 100% focused in the Permian Basin of West Texas and Southeast New Mexico. Our operations are specifically focused on areas of the Permian Basin with proven oil and liquids-rich natural gas reserves and resource opportunities, and all of our operated 2012 capital expenditure budget for drilling, completion and recompletion activities is targeted towards those opportunities. The Permian Basin is one of the most prolific and largest producing oil and natural gas regions in the United States and underlies an area approximately 250 miles wide and 300 miles long, and commercial accumulations of hydrocarbons occur in multiple stratigraphic horizons, at depths ranging from approximately 1,000 feet to over 25,000 feet. The stacked horizons of the Permian Basin allow significant opportunity for multiple completions in a single well bore and the potential for both vertical and horizontal completions. The Permian Basin is the largest oil and natural gas producing basin in the United States based on total proved reserves, according to the most recent Energy Information Administration report regarding the Permian Basin. Reserves in the Permian Basin are generally characterized as long lived, and the basin has substantial existing infrastructure and well-developed network of oilfield service providers, which we believe reduces the risk of production delays and generally lowers commodity price basis differentials. As of December 29, 2011, 479 rigs were operating in the Permian Basin, which represents a 37% increase compared to the prior year, according to Baker Hughes Interactive Rig Counts. We believe this increase is primarily attributable to higher commodity prices and advancements in technology being utilized to exploit stacked pay potential.

Large, Multi-Year Project Inventory in Existing and Emerging Plays. We have assembled a sizable inventory of 2,377 operated and 486 non-operated gross identified future drilling locations and an

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additional 266 gross identified recompletion opportunities targeting multiple well-defined zones. The majority of our locations target the higher impact Bone Spring and the lower risk Wolfberry formations with crude oil as the primary objective for both. We plan to drill or recomplete 191 gross (153 net) locations in 2012, which would represent 6.1% of our 3,129 combined gross identified drilling locations and recompletion opportunities. Our portfolio of drilling locations is based on an extensive dataset of geologic, engineering and operational information and includes stacked horizontal locations targeting the first, second, and third Bone Spring formations and 20-acre infill drilling in the Wolfberry. In addition, we have accumulated leasehold positions that are prospective for recently emerging plays, such as the Wolfcamp Shale, Cline Shale, Avalon Shale, horizontal Yeso, Cisco and Wolfbone, that are not included in the 2,863 gross identified drilling locations and represent incremental opportunities for potential development.

Substantial, Geographically-Focused Leasehold Position with Significant Operational Control and Strategic Flexibility. Our current leasehold position includes 200,598 net acres in the Permian Basin. We are focused on accumulating and maintaining high working interests and operatorship in our properties in order to maximize financial returns and operating efficiency. We have an average working interest of 77% across our portfolio, operate approximately 83% of our 2,863 gross identified drilling locations and have operational control of 75% of the production from our proved developed reserves. As operator, we control the selection of specific drilling locations, timing of development and the drilling and completion techniques utilized to efficiently develop our significant resource base. Additionally, 65.4% of our acreage is held-by-production, providing us with substantial time and optionality in executing our development plan. We expect that the scale and geographic focus of our acreage will enhance operational efficiencies with respect to drilling, production, operating and administrative functions enabling us to continue to reduce our drilling and completion costs. Our geographic focus also allows us to leverage our base of technical expertise and the extensive dataset of geologic, engineering and operational information available to us throughout this region.

Experienced and Incentivized Management Team with Proven Track Record. Our senior management team has extensive expertise and operational experience in the oil and natural gas industry and a track record of successfully executing and integrating acquisitions. Members of management have previously held management positions with major and large independent oil and natural gas companies, including Exxon Mobil Corporation, Texaco Inc., Shell Oil Company, Mobil Corporation, Seagull Energy Corp, Mariner Energy Inc., Mitchell Energy & Development Corp, XTO Energy Inc. and Ocean Energy, Inc. The members of our executive and technical team have an average of more than 29 years of experience in the oil and natural gas industry and significant experience in the Permian Basin. We believe our management and technical team is one of our principal competitive strengths due to our team's vast level of experience and proven track record in the identification and execution of acquisitions and profitable drilling programs. Additionally, we believe our management team's equity interest in us provides substantial incentive to grow the value of our business for the benefit of our stockholders.

Supportive Sponsor with Significant Industry Expertise. Riverstone, our principal owner, has substantial experience as a private equity investor in the energy sector, including upstream oil and natural gas companies, with current or prior investments in Mariner Energy Inc., Kinder Morgan Energy Partners, L.P., Cobalt International Energy, Inc., Buckeye Partners, L.P. and Magellan Midstream Partners, L.P. Riverstone's management has substantial experience in identifying, evaluating, negotiating and financing acquisitions and investments. We believe our relationship with Riverstone will enhance our ability to grow our asset base and cash flow.

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Our Business Strategy

Our strategy is to increase stockholder value by economically and sustainably growing our reserves, production and cash flow. We intend to execute this strategy as follows:

Drill and Develop Our Oil-Focused, Multi-Year Inventory of Drilling Locations and Recompletion Opportunities. We intend to aggressively drill and develop our acreage position to maximize the value of our resource base. We have an inventory of 464 gross (250 net) Bone Spring identified drilling locations, 1,995 gross (1,646 net) Wolfberry identified drilling locations and 404 gross (316 net) Conventional Permian identified drilling locations. Our inventory of identified drilling locations includes stacked horizontal locations targeting the first, second and third Bone Spring formations and infill locations to 20-acre spacing in the Wolfberry. In 2012, subject to market conditions and rig availability, we plan to increase the number of drilling rigs we operate from three to seven and drill approximately 109 gross (98 net) operated wells and recomplete an additional 47 gross (44 net) wells. We believe that we will have the ability to add additional rigs if market conditions and program results warrant.

Balance Capital Allocation Between Our Lower Risk Development Opportunities and Our Higher Impact Drilling Inventory. We believe that our Wolfberry and Conventional Permian project areas possess geologic and reservoir characteristics that make them well suited for production increases through what we believe to be relatively low-risk, repeatable drilling and development programs. We intend to balance these lower risk programs with our higher impact opportunities in our horizontal Bone Spring project area. Our drilling, completion and recompletion capital expenditure budget for 2012 contemplates 39% of our expenditures in the Bone Spring and 51% of our expenditures in the Wolfberry. Our current leasehold position also provides exposure to other recently emerging plays within the basin, such as the Wolfcamp Shale, Cline Shale, Avalon Shale, horizontal Yeso, Cisco and Wolfbone, which we believe provides significant additional upside.

Optimize Recovery Rates on Our Existing Acreage Through Continuous Evaluation and Early Adoption of Leading Drilling and Completion Technology and Techniques. We focus on maximizing recovery rates by adopting and employing enhanced drilling and completion techniques that have a demonstrated record of success. We continuously evaluate our internal drilling results and monitor the results of other operators to improve our operating practices, and we expect our drilling and completion techniques to continue to evolve. This continued evolution may significantly enhance our ultimate recovery factors and rate of return on invested capital. By adopting and employing the latest, proven techniques, rather than expending capital on experimental or developmental techniques, we believe we will be able to optimize recovery rates on our existing acreage in a cost-efficient manner. We will continue to utilize technology as other leading operators establish optimal drilling and completion methodologies, such as stacked horizontal wells in the Bone Spring play and infill drilling in the Wolfberry.

Evaluate and Pursue Long-Lived, Complementary, Oil-Focused Acquisitions. While our principal strategy will be to continue to develop our inventory of identified drilling locations and recompletion opportunities, we will continue to actively evaluate the acquisition of additional oil-weighted Permian targets that include existing production with a high proportion of operated, low-risk drilling opportunities and a large share of held-by-production acreage. We believe by acquiring assets with high components of held-by-production acreage we can maintain our capital flexibility and limit our lease expirations in challenging commodity price environments. We have an experienced team of engineering and geoscience professionals to identify and evaluate acquisition opportunities, and have successfully integrated our two large acquisitions to date.

Maintain Financial Strength and Flexibility. We expect the proceeds from this offering, internally generated cash flow and borrowings under our revolving credit facility to provide us with the financial resources to pursue our drilling and development program. As of September 30, 2011 and giving effect

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to the completion of this offering, we would have had $ million in borrowing capacity available under our revolving credit facility. We intend to continue to actively manage our exposure to commodity price risk. As part of this strategy, we have entered into a series of hedging arrangements for each year through 2015. For this period, we have entered into hedges with respect to approximately 79% of our anticipated oil production from proved developed producing properties at an average price of $92.31 per Bbl and approximately 51% of our anticipated natural gas production from proved developed producing properties at an average price of $5.38 per MMBtu.

Our Core Project Areas

Our assets are primarily distributed in three core areas of the greater Permian Basin.

Bone Spring. We have approximately 39,732 net acres and an inventory of 464 gross identified drilling locations in the Bone Spring formation in Southeast New Mexico. The Bone Spring trend encompasses the Avalon Shale, the first, second and third Bone Spring formations, and the Wolfcamp Shale. Our Bone Spring drilling locations include 425 horizontal locations and 39 vertical locations. Much of our acreage has multiple horizontal locations. The gross Bone Spring section consists of approximately 2,500 feet of alternating organic rich limestone, sand-to-siltstone and shale, which is found at depths ranging from 6,000 feet to 12,000 feet across the basin. We commenced an operated drilling program in this area in January 2012 and plan to operate two drilling rigs to drill 17 gross (14 net) wells. Our average net daily production in this area for the nine-month period ended September 30, 2011 was approximately 319 Boe/day.

Wolfberry. We have approximately 45,227 net acres and an inventory of 1,995 gross identified drilling locations in the Wolfberry trend. "Wolfberry" refers generally to the combined Spraberry and Wolfcamp formations in the Permian Basin, and our Wolfberry core area encompasses the Dean, Spraberry, Clear Fork, Wolfcamp, Canyon and Strawn intervals. The Wolfberry play encompasses the entire southern Midland Basin. Our primary development in the Wolfberry play is located in Irion County, Texas along the Eastern Shelf where the Wolfcamp and Spraberry formations (4,000-7,000 feet) were deposited during the Permian Era. We operated two drilling rigs, drilled 30 gross (30 net) wells and performed 27 gross (27 net) recompletions in 2011. In 2012, we plan to operate four drilling rigs, drilling 83 gross (77 net) wells and recompleting 43 gross (42 net) wells targeting the Wolfberry. Our average net daily production in this area for the nine-month period ended September 30, 2011 was approximately 3,087 Boe/day.

Conventional Permian. We have approximately 115,639 net acres containing both oil and natural gas resources within our Conventional Permian core area. Of this acreage, we have approximately 38,035 net acres that we consider to be oil-focused. The conventional oil area is primarily located in the Central Basin Platform, and targets multiple objective formations, including the San Andres, Yeso, Queen, Clearfork, and Devonian Sands. Most of the reservoirs in the area are platform carbonates composed of limestone and dolomite. We have identified 247 gross (217 net) potential vertical drilling locations in this area. In 2010, we commenced a drilling program in this area and completed five gross wells. In the fourth quarter of 2011, we drilled an additional seven gross wells in this area. We plan to operate one drilling rig to drill nine gross (seven net) wells and perform four gross (two net) recompletions in 2012. Our average net daily production in this area for the nine-month period ended September 30, 2011 was approximately 1,770 Boe/day. We have approximately 77,604 net acres in our Conventional Permian core area that we consider to be natural gas-focused. The conventional natural gas area is primarily located in Chaves County, New Mexico and Reeves and Pecos Counties, Texas. We have identified 157 gross (99 net) potential vertical drilling locations in this area. Our average net daily production in this area for the nine-month period ended September 30, 2011 was approximately 2,701 Boe/day. Our 2012 capital expenditure budget does not include material expenditures for our conventional natural gas area.

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Our Relationship with Riverstone

Upon completion of this offering, Riverstone will beneficially own % of our outstanding common stock. Riverstone, a global energy- and power-focused private equity firm founded in 2000, has approximately $17 billion of assets under management across six investment funds. Riverstone conducts buyout and growth capital investments in the midstream, exploration and production, energy services, power and renewable sectors of the energy industry. With offices in New York, London and Houston, Riverstone has committed approximately $16 billion to 78 investments in North America, South America, Europe and Asia. Riverstone currently has, and may make in the future, investments in other similar companies that compete with us. See "Certain Relationships and Related Party Transactions—Historical Transactions with Three Rivers Holdings and Riverstone."

Corporate Reorganization

We were recently incorporated pursuant to the laws of the State of Delaware as Three Rivers Operating Company Inc. to become a holding company for Three Rivers Operating Company LLC. Three Rivers Operating Company LLC was formed as a Delaware limited liability company on March 8, 2010. Prior to completion of our corporate reorganization described below, all of the equity interests in Three Rivers Operating Company LLC are owned, directly or indirectly, by Three Rivers Natural Resource Holdings LLC, which we refer to as Three Rivers Holdings. Three Rivers Holdings is owned by Riverstone and members of our management.

Pursuant to the terms of a corporate reorganization that will be completed simultaneously with the closing of this offering, Three Rivers Holdings will contribute all of the outstanding equity interests in Three Rivers Operating Company LLC to its wholly-owned subsidiary Three Rivers Operating Company Inc. in exchange for shares of common stock of Three Rivers Operating Company Inc. As a result of the reorganization, Three Rivers Operating Company LLC will become a wholly-owned subsidiary of Three Rivers Operating Company Inc. For more information on our reorganization and the ownership of our common stock by our principal and selling stockholders, see "Corporate Reorganization" and "Principal and Selling Stockholders."

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The following diagram indicates our ownership structure after giving effect to our reorganization and this offering.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 1122 South Capital of Texas Highway, Suite 325, Austin, Texas 78746, and our telephone number at that address is (512) 600-3190. Our website address is http://www.3rnr.com. Information contained on our website is not incorporated by reference into this prospectus, and you should not consider the information contained on our website to be part of this prospectus.

Risk Factors

An investment in our common stock involves significant risks. Before investing in our common stock, you should carefully consider all the information contained in this prospectus, including the information under the headings "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements."

Conflicts of Interest

An affiliate of J.P. Morgan Securities LLC is lead arranger, Syndication Agent and a lender under our revolving credit facility. Because a portion of the proceeds of this offering will be used to repay indebtedness under our revolving credit facility, a "conflict of interest" under Rule 5121 of the Financial Industry Regulatory Authority, or FINRA, is therefore deemed to exist. Accordingly, this offering is being made in compliance with FINRA Rule 5121. Pursuant to FINRA Rule 5121, a "qualified independent underwriter" meeting certain standards must participate in the preparation of the registration statement of which this prospectus forms a part and must exercise the usual standards of due diligence with respect thereto. has assumed the responsibilities of acting as the qualified independent underwriter in this offering. Please read "Underwriting—Conflicts of Interest."

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The Offering


Issuer		Three Rivers Operating Company Inc.
Common stock offered by us		shares
Common stock offered by the selling stockholder		shares
Common stock to be outstanding after this offering		shares
Option to purchase additional shares		The underwriters have an option to purchase a maximum of additional shares of common stock from the selling stockholder to cover sales by the underwriters of more than shares. The underwriters can exercise this option at any time within 30 days from the date of this prospectus.
Use of proceeds		We expect to receive approximately $ million of net proceeds from the sale of the common stock offered by us, based upon an assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses payable by us. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $ million. We intend to use the net proceeds we receive from this offering to repay outstanding indebtedness under our revolving credit facility. We may reborrow amounts repaid under our revolving credit facility and expect to do so to fund a portion of our development and other capital expenditures. We will not receive any proceeds from the sale of shares by the selling stockholder. See "Use of Proceeds." Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a portion of the proceeds of this offering. See "Use of Proceeds" and "Underwriting—Conflicts of Interest."
Dividend policy		After this offering, we do not anticipate paying cash dividends on our common stock in the foreseeable future. See "Dividend Policy."
Listing		We intend to apply to list our common stock on the New York Stock Exchange under the symbol "TROC."
Risk Factors		See "Risk Factors" beginning on page 17 for a discussion of factors you should consider before deciding to purchase shares of our common stock.

Unless otherwise indicated, all share information contained in this prospectus:

•: assumes the consummation of our corporate reorganization, as described under "Corporate Reorganization;"

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•: assumes that the underwriters' option to purchase additional shares, granted by the selling stockholder, will not be exercised; and
•: does not include shares of common stock reserved for issuance under our long-term incentive plan to be approved by our board of directors and stockholders prior to the completion of this offering.

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Summary Historical and Pro Forma Financial Data

Set forth below are (1) summary historical financial data for the Chesapeake Acquired Properties, as our predecessor, for the years ended December 31, 2008 and 2009 and the period from January 1, 2010 to April 9, 2010 and as of December 31, 2008 and 2009, which have been derived from the audited financial statements of the predecessor included elsewhere in this prospectus; (2) summary consolidated historical financial data for Three Rivers Operating Company LLC for the period from March 8, 2010, the date of inception, to December 31, 2010 and as of December 31, 2010 (successor), which have been derived from the audited consolidated financial statements of Three Rivers Operating Company LLC, included elsewhere in this prospectus; (3) summary unaudited consolidated financial data for Three Rivers Operating Company LLC for the period from March 8, 2010 (Inception), the date of inception, to September 30, 2010 and the nine months ended September 30, 2011 and as of September 30, 2011 (successor), which have been derived from the unaudited consolidated financial statements of Three Rivers Operating Company LLC included elsewhere in this prospectus and which, in the opinion of our management, include all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of this information; and (4) summary unaudited pro forma financial data for Three Rivers Operating Company Inc. for the year ended December 31, 2010, which have been derived from the unaudited pro forma financial statements included elsewhere in this prospectus. Additionally, the historical financial data for the Chesapeake Acquired Properties, the predecessor, reflects full cost accounting for oil and natural gas properties and the historical financial data for Three Rivers Operating Company LLC, the successor, reflects the successful efforts method of accounting for oil and natural gas properties, effective March 8, 2010.

The unaudited pro forma financial data for the year ended December 31, 2010 give effect to the acquisition of the Chesapeake Acquired Properties and the Samson Acquired Properties and our corporate reorganization as if these transactions had taken place on January 1, 2010. Historical statements of revenues and direct operating expenses for the Samson Acquired Properties appear elsewhere in this prospectus and are presented on an audited basis.

The information set forth below should be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical and pro forma financial statements and the notes thereto included elsewhere in this prospectus. The financial data included in

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this prospectus may not be indicative of our future results of operations, financial position and cash flows.

	Predecessor							Three Rivers (Successor)

														Period from March 8, 2010 (Inception) to September 30, 2010 (Unaudited)
	Year Ended December 31,							Period from March 8, 2010 (Inception) to December 31, 2010			Pro Forma Year Ended December 31, 2010 (Unaudited)						Nine Months Ended September 30, 2011 (Unaudited)
	Year Ended December 31,					Period from January 1, 2010 to April 9, 2010
	2008			2009		Period from January 1, 2010 to April 9, 2010
	(in thousands)							(in thousands)
Revenues:
Oil and gas revenues	$	74,878		$	33,244	$	11,406	$	30,219		$	117,897		$	19,560		$	113,653
Expenses:
Lease operating expenses		22,076			18,274		3,152		12,000			27,089			7,870			22,027
Production and ad valorem taxes		6,177			3,128		735		2,852			10,346			1,860			8,839
Depreciation, depletion and amortization		17,887			9,400		2,259		8,072			24,316			5,177			22,706
Gain on the sale of oil and gas properties		—			—		—		—			—			—			(11,079	)
Impairment of oil and gas properties		88,173			—		—		—			—			—			—
Exploration expenses		—			—		—		13			13			4			63
General and administrative expenses		3,398			2,393		723		5,089			8,781			3,755			6,586

Total expenses		137,711			33,195		6,869		28,026			70,545			18,666			49,142

Operating income (loss)		(62,833	)		49		4,537		2,193			47,352			894			64,511
Other income (expense):
Interest expense		—			—		—		(3,399	)		(11,004	)		(2,240	)		(8,103	)
Realized and unrealized gain on commodity derivative instruments		—			—		—		3,893			3,893			9,248			26,903
Interest income		—			—		—		2			2			1			6
Other income		—			—		—		9			9			4			8

Total other income (expense)		—			—		—		505			(7,100	)		7,013			18,814

Income (loss) before taxes		(62,833	)		49		4,537		2,698			40,252			7,907			83,325
Provision for income tax		—			—		—		71			71			53			771

Net income (loss)	$	(62,833	)	$	49	$	4,537	$	2,627		$	40,181		$	7,854		$	82,554

Pro forma income tax expense (Unaudited)									986						2,888			30,439
Pro forma net income (Unaudited)								$	1,712					$	5,019		$	52,886

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	Predecessor				Three Rivers (Successor)

	As of December 31,						As of September 30, 2011 (Unaudited)
	As of December 31,				As of December 31, 2010
	2008		2009		As of December 31, 2010
	(in thousands)				(in thousands)
Balance sheet data:
Cash and cash equivalents	$	—	$	—	$	146,756	$	465
Property and equipment, net		129,343		123,665		212,991		575,104
Total assets		136,584		130,747		406,182		633,030
Long-term debt		—		—		114,500		286,500
Owner's net investment/total members' equity		128,375		122,892		273,342		296,155

	Predecessor									Three Rivers (Successor)

													Period from March 8, 2010 (Inception) to September 30, 2010 (Unaudited)
	Year Ended December 31,									Period from March 8, 2010 (Inception) to December 31, 2010						Nine Months Ended September 30, 2011 (Unaudited)
	Year Ended December 31,						Period from January 1 to April 9, 2010
	2008			2009			Period from January 1 to April 9, 2010
	(in thousands)									(in thousands)
Other financial data:
Net cash provided by operating activities	$	46,925		$	9,073		$	4,058		$	13,517		$	7,794		$	64,510
Net cash used in investing activities		(28,735	)		(3,541	)		(548	)		(249,549	)		(207,553	)		(320,910	)
Net cash provided by (used in) financing activities		(18,190	)		(5,532	)		(3,510	)		382,788			200,975			110,109
EBITDAX (Unaudited)(1)		43,227			9,449			6,796			13,035			7,739			77,152

(1): EBITDAX is a non-GAAP financial measure. For a definition of EBITDAX and a reconciliation of EBITDAX to net income and net cash provided by operating activities, see "—Non-GAAP Financial Measure—EBITDAX" below.

Non-GAAP Financial Measure—EBITDAX

EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion and amortization, exploration expenses, impairment of oil and natural gas properties, unrealized derivative gains and losses and gain on sale of properties. EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.

Management believes EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDAX should not be considered as an alternative to, or more meaningful than, net income from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other

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similarly titled measures of other companies. We believe that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

The following table presents a reconciliation of the non-GAAP financial measure EBITDAX to net income (loss), the most directly comparable GAAP financial measure, for the periods presented.

	Predecessor							Three Rivers (Successor)

											Period from March 8, 2010 (Inception) to September 30, 2010 (Unaudited)
	Year Ended December 31,							Period from March 8, 2010 (Inception) to December 31, 2010						Nine Months Ended September 30, 2011 (Unaudited)
	Year Ended December 31,					Period from January 1 to April 9, 2010
	2008			2009		Period from January 1 to April 9, 2010
	(in thousands)							(in thousands)
EBITDAX reconciliation to net income (loss):
Net income (loss)	$	(62,833	)	$	49	$	4,537	$	2,627		$	7,854		$	82,554
Exploration expenses		—			—		—		13			4			63
Depreciation, depletion and amortization		17,887			9,400		2,259		8,072			5,177			22,706
Impairment of oil and gas properties		88,173			—		—		—			—			—
Change in unrealized gain (loss) on derivative instruments		—			—		—		(1,147	)		(7,589	)		(25,966	)
Gain on sale of properties		—			—		—		—			—			(11,079	)
Interest expense		—			—		—		3,399			2,240			8,103
Income tax		—			—		—		71			53			771

EBITDAX (Unaudited)	$	43,227		$	9,449	$	6,796	$	13,035		$	7,739		$	77,152

The following table presents a reconciliation of the non-GAAP financial measure EBITDAX to the GAAP financial measure, net cash provided by operating activities, for the periods presented.

	Predecessor							Three Rivers (Successor)

											Period from March 8, 2010 (Inception) to September 30, 2010 (Unaudited)
	Year Ended December 31,							Period from March 8, 2010 (Inception) to December 31, 2010						Nine Months Ended September 30, 2011 (Unaudited)
	Year Ended December 31,					Period from January 1 to April 9, 2010
	2008			2009		Period from January 1 to April 9, 2010
	(in thousands)							(in thousands)
EBITDAX reconciliation to net cash provided by operating activities:
Net cash provided by operating activities	$	46,925		$	9,073	$	4,058	$	13,517		$	7,794		$	64,510
Interest expense		—			—		—		3,399			2,240			8,103
Exploration expenses		—			—		—		13			4			63
Debt financing cost amortization and other		—			—		—		(449	)		(273	)		(923	)
Income tax		—			—		—		71			53			771
Changes in working capital		(3,698	)		376		2,738		(3,516	)		(2,079	)		4,628

EBITDAX (Unaudited)	$	43,227		$	9,449	$	6,796	$	13,035		$	7,739		$	77,152

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Summary Historical Reserve and Operating Data

The following table presents summary data with respect to our estimated net proved oil and natural gas reserves as of September 30, 2011. For additional information regarding our reserves, see "Business—Our Operations—Estimated Proved Reserves." The reserve estimates at September 30, 2011 are based on a report prepared by Cawley, Gillespie & Associates, Inc., independent reserve engineers. Reserve estimates were prepared consistent with the rules and regulations of the Securities and Exchange Commission, or the SEC, regarding oil and natural gas reserve reporting.

	September 30, 2011

Reserve Data(1):
Estimated proved reserves:
Oil & natural gas liquids (MBbl)		50,003
Natural gas (MMcf)		143,380
Total estimated proved reserves (MBoe)		73,899
Proved developed (MBoe)		37,956
Percent developed		51	%
Proved undeveloped (MBoe)		35,943
PV-10 (in thousands)(2)	$	982,533
Standardized Measure (in thousands)(3)	$	982,533

(1): Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $94.50/Bbl for oil and $4.17/MMBtu for natural gas at September 30, 2011. These prices were adjusted by lease for crude quality, transportation charges, BTU content and gravity corrections.
(2): PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. However, our PV-10 and our Standardized Measure are equivalent because, as of September 30, 2011, we were a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to our equity holders. However, simultaneously with the closing of this offering, we will effect a corporate restructuring that will result in Three Rivers Operating Company Inc. becoming a holding company for Three Rivers Operating Company LLC. As a result, we will be treated as a taxable entity for federal income tax purposes. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
(3): Standardized Measure represents the present value of estimated future net cash inflows from proved oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses (if applicable), discounted at 10% per annum to reflect timing of future cash flows. Following our corporate reorganization, we will be treated as a taxable entity for federal income tax purposes. Future calculations of Standardized Measure will include the effects of income taxes on future net revenues. Assuming our corporate reorganization had occurred on September 30, 2011, we estimate that income taxes would have reduced our Standardized

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Measure to $626.9 million as of September 30, 2011. For further discussion of income taxes, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Other Income (Expense)—Income Tax Expense."

The following table sets forth summary data with respect to our production results, average sales prices and production costs on a historical basis for the periods presented:

	Predecessor						Three Rivers (Successor)

	Year Ended December 31,						Period from March 8, 2010 (Inception) to December 31, 2010		Period from March 8, 2010 (Inception) to September 30, 2010
											Nine Months Ended September 30, 2011
					January 1 to April 9, 2010
	2008		2009		January 1 to April 9, 2010
Net production volumes:
Oil (Bbl)		359,370		330,734		78,029		224,758		143,249		825,885
Natural Gas (Mcf)		5,439,334		4,225,255		1,073,621		2,662,231		1,834,972		5,281,878
Natural Gas Liquids (Bbl)		—		—		531		114,275		48,937		444,143

Total (Boe)		1,265,926		1,034,943		257,497		782,738		498,015		2,150,341
Average daily production volumes:
Oil (Bbl)		985		906		867		818		783		3,025
Natural Gas (Mcf)		14,902		11,576		11,929		9,681		10,027		19,347
Natural Gas Liquids (Bbl)		—		—		6		416		267		1,627

Total (Boe)		3,468		2,835		2,861		2,847		2,721		7,877
Average prices:
Oil, without derivatives (Bbl)	$	96.89	$	56.12	$	73.38	$	75.67	$	74.40	$	91.13
Natural Gas, without derivatives (Mcf)	$	7.36	$	3.48	$	5.27	$	3.55	$	3.78	$	3.54
Natural Gas Liquids (Bbl)	$	—	$	—	$	33.90	$	32.96	$	40.32	$	44.33
Total, without derivatives (Boe)	$	59.15	$	32.12	$	44.30	$	38.61	$	39.28	$	52.85
Operating costs and expenses per Boe:
Lease operating expenses	$	17.44	$	17.66	$	12.24	$	15.33	$	15.80	$	10.24
Production and ad valorem taxes	$	4.88	$	3.02	$	2.85	$	3.64	$	3.73	$	4.11
Depreciation, depletion and amortization	$	14.13	$	9.08	$	8.77	$	10.31	$	10.40	$	10.56
General and administrative expenses	$	2.68	$	2.31	$	2.81	$	6.50	$	7.54	$	3.06

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RISK FACTORS

An investment in our common stock involves significant risks. You should carefully consider the risks described below together with the other information set forth in this prospectus before making an investment decision. Our business, financial condition or results of operations could be materially adversely affected by any of these risks. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

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

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil and natural gas heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

•: worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
•: the actions of the Organization of Petroleum Exporting Countries, or OPEC;
•: the price and quantity of imports of foreign oil and natural gas, including liquefied natural gas;
•: political conditions in or hostilities in oil-producing and natural gas-producing regions, including current conflicts in the Middle East and conditions in Africa, South America and Russia;
•: the level of global oil and natural gas exploration and production;
•: the level of global oil and natural gas inventories;
•: prevailing prices on local oil and natural gas price indexes in the areas in which we operate;
•: localized supply and demand fundamentals and transportation availability;
•: weather conditions and natural disasters;
•: domestic and foreign governmental regulations;
•: speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
•: price and availability of competitors' supplies of oil and natural gas;
•: technological advances affecting energy consumption; and
•: the price and availability of alternative fuels.

Lower oil and natural gas prices will reduce our cash flows, our borrowing ability and the present value of our reserves. See also "—Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves." A substantial or extended decline in oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically and may affect the quantities of our proved reserves. See also "—The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves."

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 future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration

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and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see "—Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves." Our cost of drilling, completing and operating wells is often uncertain before drilling commences. In addition, the application of new techniques, such as high-graded stimulation designs and horizontal completions, some of which we have not previously employed, may make it more difficult to accurately estimate these costs. Overruns in budgeted expenditures are common risks that can make a particular project uneconomic. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

•: increases in the costs of, shortages of or delays in obtaining equipment and qualified personnel;
•: facility or equipment malfunctions;
•: unexpected drilling conditions;
•: pressure or irregularities in geological formations;
•: adverse weather conditions;
•: reductions in oil and natural gas prices;
•: delays imposed by or resulting from compliance with permitting and other regulatory requirements;
•: proximity to and capacity of transportation facilities;
•: title problems; and
•: limitations in the market for oil and natural gas.

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

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this prospectus. See "Business—Our Operations—Estimated Proved Reserves" for information about our estimated oil and natural gas reserves and the PV-10 and Standardized Measure of discounted future net revenues as of December 31, 2010 and September 30, 2011.

In order to prepare estimates of our proved reserves, Cawley, Gillespie & Associates, Inc., our independent reserve engineers, must project production rates and the timing of development expenditures as well as analyze available geological, geophysical, production and engineering data. Although data in the Permian Basin is abundant, 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 as of December 31, 2010 and September 30, 2011 contained in this prospectus is prepared by our 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 will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of

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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. Due to the limited production history of our undeveloped acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. As required by SEC rules and regulations, we based the estimated discounted future net revenues from proved reserves as of December 31, 2010 and September 30, 2011 on the unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions as well as operating and development costs being incurred at the end of the reporting period. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and gas production because of seasonal price fluctuations or other varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and gas properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the ten percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Therefore, the estimates of discounted future net cash flows, Standardized Measure or PV-10 in this prospectus should not be construed as accurate estimates of the current market value of our proved reserves. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:

•: actual prices we receive for oil and natural gas;
•: actual cost of development and production expenditures;
•: the amount and timing of actual production; and
•: changes in governmental regulations or taxation.

Actual future prices and costs may differ materially from those used in the present value estimates included in this prospectus. If oil prices declined by $1.00 per Bbl, then our PV-10 as of September 30, 2011 would decrease approximately $16.6 million. If natural gas prices declined by $0.10 per Mcf, then our PV-10 as of September 30, 2011 would decrease approximately $5.0 million.

Our business is difficult to evaluate because we have a limited operating history.

In considering whether to invest in our common stock, you should consider that there is only limited historical financial and operating information available on which to base your evaluation of our performance. We were formed in March 2010 and we had no operations until we acquired the Chesapeake Acquired Properties in April 2010 and, as a result, we have a limited operating history. We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. New companies must develop successful business relationships, establish operating procedures, hire staff, install management information and other systems, establish facilities and obtain licenses, as well as take other measures necessary to conduct their intended business activities. We may not be successful in implementing our business strategies or in completing the development of the infrastructure necessary to conduct our business as planned. In the event that our development plan is not completed or is delayed, our operating results will be adversely affected and our operations will differ materially from the activities described in this prospectus. As a result of industry factors or factors relating specifically to us, we may

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have to change our methods of conducting business, which may have a material adverse effect on our results of operations and financial condition.

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves.

Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash flows used in investing activities relating to capital and developmental expenditures were $11.2 million excluding acquisitions for the period from March 8, 2010 (Inception) to December 31, 2010. Our estimated 2011 capital expenditures were approximately $110.1 million, approximately $96.0 million of which was dedicated to drilling, completions and recompletions. Our capital expenditure budget for 2012 is approximately $266.1 million, with $254.2 million allocated for drilling and completions. To date, our capital expenditures have been financed with capital contributions from Riverstone, borrowings under our revolving credit facility and net cash provided by operating activities. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.

A significant improvement in product prices could result in an increase in our capital expenditures as we increase production to bring more oil and natural gas to market. We intend to finance our future capital expenditures primarily through cash flows provided by operating activities, borrowings under our revolving credit facility and net proceeds from this offering; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or additional equity securities or the sale of non-strategic assets. The issuance of additional debt may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.

Our cash flows provided by operating activities 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 our oil and natural gas are sold;
•: the costs of developing and producing our oil and natural gas reserves;
•: our ability to acquire, locate and produce new reserves;
•: the ability and willingness of our banks to lend; and
•: our ability to access the equity and debt capital markets.

If the borrowing base under our revolving credit facility or our revenues decrease as a result of lower oil or 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. 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 cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.

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If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. In addition, prolonged low gas prices may require us to write down the carrying value of some of our natural gas properties. Such write-downs may result in a decrease in the amount available under our revolving credit facility. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our ability to borrow under our revolving credit facility and our results of operations for the periods in which such charges are taken.

We will not be the operator on all of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

As of September 30, 2011, we were the operator on approximately 83% of our gross identified drilling locations. Although we seek to be the operator of our identified drilling locations, as we carry out our exploration and development programs in the future, we may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of our locations being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

•: the timing and amount of capital expenditures;
•: the operator's expertise and financial resources;
•: the approval of other participants in drilling wells;
•: the selection of technology; and
•: the rate of production of reserves, if any.

This limited ability to exercise control over the operations of some of our drilling locations may cause a material adverse effect on our results of operations and financial condition.

Our producing properties are located exclusively in the Permian Basin of West Texas and Southeast New Mexico, making us vulnerable to risks associated with operating in one major geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

Our producing properties in our core operating areas are geographically concentrated in the Permian Basin of West Texas and Southeast New Mexico. At September 30, 2011, all of our proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, or interruption of the processing or transportation of oil, natural gas or natural gas liquids.

Our business depends on oil and natural gas gathering and transportation facilities, most of which are owned by third parties.

The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of gathering, processing and pipeline systems owned by third parties. The

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unavailability of, or lack of, available capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance, of development plans for properties. We generally do not purchase firm transportation on third party facilities and, therefore, the transportation of our production is generally interruptible in nature and lower in priority to those having firm transportation arrangements. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport our oil and natural gas.

The disruption of third-party facilities due to maintenance and/or weather could also negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored by third party owners or operators, or what prices will be charged. A total shut-in of production resulting from the acts or omissions of third party transportation providers, or circumstances affecting third party transportation facilities, could materially affect us due to a lack of cash flow, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flow.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

Approximately 49% of our total proved reserves were classified as proved undeveloped as of September 30, 2011. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations, and development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. 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 and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

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. Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future oil and natural gas reserves and production, and therefore our cash flows 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, exploit, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

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

Market conditions or the unavailability of satisfactory oil and natural gas 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 due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines or gathering system capacity. If our production becomes shut-in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

•: environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;
•: abnormally pressured formations;
•: mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
•: fires, explosions and ruptures of pipelines;
•: personal injuries and death; and
•: natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

•: injury or loss of life;
•: damage to and destruction of property, natural resources or equipment;
•: pollution or other environmental damage;
•: regulatory investigations or penalties;
•: suspension of our operations; or
•: repair or remediation costs.

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

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

We describe some of our drilling locations and our plans to explore those drilling locations in this prospectus. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Ultimately, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

Our identified drilling locations are scheduled to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our identified drilling locations.

Our management has identified and scheduled drilling locations as an estimate of our future multi-year drilling activities on our existing acreage. As of September 30, 2011, only 17% of our 2,863 gross identified drilling locations were attributed to proved undeveloped reserves. All of our drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, availability of drilling services and equipment, lease expirations, gathering system, marketing and pipeline transportation constraints, oil and natural gas prices, drilling and production costs, drilling results and other factors. Additionally, several of our identified drilling locations are on our held-by-production acreage, the leases on which expire if, prior to expiration of the initial term of such leases, we do not meet the production levels in the leases to hold the acreage. Because of these uncertainties and the potential for losing held-by-production acreage where we have insufficient production to hold the acreage, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. Pursuant to SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. The SEC rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of December 31, 2011, we had leases representing 12,985 net acres expiring in

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2012, 19,041 net acres expiring in 2013, 11,913 net acres expiring in 2014 and 25,435 net acres expiring thereafter. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing, or fracking, processes. Historically, we have been able to purchase water from local land owners for use in our operations. According to the Lower Colorado River Authority, during 2011, Texas has experienced the lowest inflows of water of any year in recorded history. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing in order to protect local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the timing, cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our oil and natural gas exploration and production 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 experience delays in receiving such permits, approvals and certificates. In particular, we have experienced long lead-times in receiving permits from the State of New Mexico. Additionally, some of our acreage coincides with potash mining operations, particularly in Lea and Eddy Counties in New Mexico, which imposes heightened permitting requirements for us to conduct our drilling operations. Delays in permitting could result in delays in development of our reserves, which could adversely affect the quantities of our proved reserves and related PV-10 value. We may incur substantial costs in order to maintain compliance with 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. Such costs could have a material adverse effect on our business, financial condition and results of operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

See "Business—Regulation of the Oil and Natural Gas Industry" for a further description of the laws and regulations that affect us.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.

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As a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the Endangered Species Act. The law prohibits the harming of endangered or threatened species, provides for habitat protection, and imposes stringent penalties for noncompliance. One of the species being considered for listing pursuant to the settlement is the Dunes Sagebrush Lizard. Some of our operations are located in or near areas that may potentially be designated as Dunes Sagebrush Lizard habitat. If the lizard is classified as an endangered species, our operations in any area that is designated as the lizard's habitat may be limited, delayed or, in some circumstances, prohibited, and we may be required to comply with expensive mitigation measures intended to protect the lizard and its habitat. Under the September 9, 2011 settlement, the U.S. Fish and Wildlife Service is required to begin issuing decisions with respect to the 250 candidate species by the end of 2011. In December 2011, the U.S. Fish and Wildlife Service announced that it would delay its decision on whether to list the Dunes Sagebrush Lizard as an endangered species for six months to provide for additional time to study the issue. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

Our operations are subject to environmental and operational safety laws and regulations that may expose us to significant costs and liabilities.

Our oil and natural gas exploration and production operations are subject to stringent and complex federal, state and local laws and regulations governing health and safety aspects of our operations, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of permits before conducting drilling or underground injection activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and wastes, because of air emissions and waste water discharges related to our operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures

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to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.

Climate change laws and regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA have allowed the agency to proceed with the adoption and implementation of regulations restricting emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Among other things, EPA regulations now require specified large greenhouse gas emitters in the United States including companies in the energy industry to annually report those emissions. Additionally, starting in 2011, new sources or modifications of existing sources of significant quantities of greenhouse gas emissions are required to obtain permits—and to use best available control technology to control those emissions—pursuant to the Clean Air Act as a prerequisite to the development of that emissions source. While these regulations have not to date materially affected our company, such regulations may over time require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce.

Additionally, the U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane, that are understood to contribute to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that smaller sources could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

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Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. We routinely apply hydraulic-fracturing techniques in many of our U.S. onshore oil and natural-gas drilling and completion programs. The process is typically regulated by state oil and natural-gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process.

Certain states, including Texas, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas (RCT) and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic-fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands.

Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the U.S. Securities and Exchange Commission to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural-gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency's estimates regarding natural-gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate hydraulic fracturing activities.

Further, on July 28, 2011, the EPA issued proposed rules that would subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New

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Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs. The EPA proposed rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion (REC) techniques developed in EPA's Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (MACT) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. We are currently researching the effect these proposed rules could have on our business. Final action on the proposed rules is expected no later than February 28, 2012.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.

New regulations, proposed regulations and proposed modifications to existing regulations under the Clean Air Act, if implemented, could result in increased compliance costs.

On August 23, 2011, the EPA proposed regulations focused on reducing emissions of certain air pollutants by the oil and natural gas industry, including volatile organic compounds, sulfur dioxide and certain air toxics. The regulations, if adopted as proposed, would impose the first federal air emissions standards for wells that are hydraulically fractured. These requirements include the use of "green" well completion technologies to capture natural gas emissions that currently escape to the atmosphere during well development, reducing emissions of volatile organic compound by nearly ninety-five percent. The EPA accepted public comments on the proposed rule and is required to finalize and publish the rule by April 3, 2012. If adopted as proposed, this rule could increase the cost of drilling and completing wells and of producing and transporting oil and natural gas. At this point, however, we cannot reasonably predict what applicable requirements may eventually be adopted respecting this proposed rule or the ultimate cost to comply with such requirements.

These new regulations and proposals, when finalized, and any other new regulations requiring the installation of more sophisticated pollution control equipment or the adoption of other environmental protection measures, could have a material adverse impact on our business, financial condition, results of operations and cash flows.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, obtaining gathering, processing and pipeline transportation services, marketing oil and natural gas and securing equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of

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unsuccessful drilling attempts, sustained periods of volatility in financial and commodity markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel in the Permian Basin region has increased over the past few years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

The loss of senior management or technical personnel could adversely affect our operations.

To a large extent, we depend on the services of our senior management and technical personnel who have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production, and developing and executing acquisition, financing and hedging strategies. Our ability to hire and retain senior management and technical personnel is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could negatively impact our ability to execute our business strategy. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

Changes in the differential between benchmark prices of oil and natural gas and the reference or regional index price used to price our actual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.

The reference or regional index prices that we use to price our oil and natural gas sales sometimes reflect a discount to the relevant benchmark prices. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict oil and natural gas differentials. Changes in differentials between the benchmark price for oil and natural gas and the reference or regional index price we reference in our sales contracts could have a material adverse effect on our results of operations and financial condition.

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

To achieve more predictable cash flows 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 fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:

•: production is less than the volume covered by the derivative instruments;
•: the counter-party to the derivative instrument defaults on its contract obligations; or
•: there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.

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In addition, our commodity derivative transactions expose us to credit risk in the event of default by our counterparties that are lenders in our credit facilities. Further deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. A default under any of these agreements could negatively impact our financial performance.

The adoption of derivatives legislation by Congress, and implementation of that legislation by Federal agencies, could have an adverse impact on our ability to hedge risks associated with our business.

On July 21, 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Reform Act, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation requires the Commodities Futures Trading Commission, or the CFTC, and the SEC to promulgate rules and regulations implementing the new legislation, which they are expected to continue to do through the end of 2011 and at least through the first quarter of 2012. From late 2010 and continuing to the present date, the CFTC has introduced dozens of proposed rules coming out of the Dodd-Frank Reform Act, and has promulgated numerous final rules based on those proposals. The effect of the proposed rules and any additional regulations on our business is currently uncertain, but it is increasingly clear that the costs of derivatives-based hedging for commodities will likely increase for all market participants. Of particular concern, the Dodd-Frank Reform Act does not explicitly exempt end users (such as us) from the requirements to post margin in connection with hedging activities. While several senators have indicated that it was not the intent of the Act to require margin from end users, the exemption is not in the Act. While rules proposed by the CFTC and federal banking regulators appear to allow for non-cash collateral and certain exemptions from margin for end users, the rules are not final and uncertainty remains. The new requirements to be enacted, to the extent applicable to us or our derivatives counterparties, may result in increased costs and cash collateral requirements for the types of derivative instruments we use to hedge and otherwise manage our financial and commercial risks related to fluctuations in natural gas, oil and NGL commodity prices. In addition, final rules promulgated by the CFTC imposing federally-mandated position limits cover a wide range of derivatives positions, including non-exchange traded bilateral swaps related to commodities including oil and natural gas. These position limit rules are likely to increase regulatory monitoring and compliance costs for all market participants, even where a given trading entity is not in danger of breaching position limits. These and other regulatory developments stemming from the Dodd-Frank Reform Act, including stringent new reporting requirements for derivatives positions and detailed criteria that must be satisfied to continue to enter into uncleared swap transactions, could have a material impact on our derivatives trading and hedging activities in the form of increased transaction costs and compliance responsibilities. Any of the foregoing consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

Declining general economic, business or industry conditions could have a material adverse effect on our results of operations.

Concerns over the worldwide economic outlook, geopolitical issues, the availability and cost of credit and the United States mortgage and real estate markets contributed to increased volatility and diminished expectations for the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment resulted in a worldwide recession during the second half of 2008 and 2009. While the worldwide economic outlook has improved, concerns about global economic growth could have a significant adverse effect on global financial markets and commodity prices. If the economic climate in the United States or abroad were to deteriorate, demand for petroleum products could diminish, which could depress the prices at which we could sell our oil and natural gas and ultimately decrease our revenue and profitability.

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Increased costs of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Our revolving credit facility contains covenants that may inhibit our ability to make certain investments, incur additional indebtedness or engage in certain other transactions, which could adversely affect our ability to meet our future goals.

Our revolving credit facility includes covenants that, among other things, restrict:

•: our investments, loans and advances and the payment of dividends and other restricted payments;
•: our incurrence of additional indebtedness;
•: the granting of liens, other than liens created pursuant to the revolving credit facility and certain permitted liens;
•: mergers, consolidations and sales of all or a substantial part of our business or properties;
•: the hedging, forward sale or swap of our production of oil or natural gas or other commodities;
•: the sale of assets (other than production sold in the ordinary course of business); and
•: our capital expenditures.

Our revolving credit facility contains certain financial covenants. For example, our revolving credit facility requires us to maintain a minimum ratio of current assets to current liabilities of 1.0 to 1.0, a maximum ratio of total debt to EBITDAX of 4.0 to 1.0, and a minimum ratio of EBITDAX to interest expense of 2.5 to 1.0. All of these restrictive covenants may restrict our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our revolving credit facility may be impacted by changes in economic or business conditions, results of operations or events beyond our control. The breach of any of these covenants could result in a default under our revolving credit facility, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under our revolving credit facility, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders could proceed against their collateral. If the indebtedness under our revolving credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.

Our future level of indebtedness may increase and reduce our financial flexibility.

Upon the completion of this offering, we expect to have an immaterial amount of outstanding indebtedness and a borrowing capacity of $ million under our revolving credit facility, subject to periodic redetermination. In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

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Our future level of indebtedness could affect our operations in several ways, including the following:

•: a significant portion of our cash flows could be used to service our indebtedness;
•: a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
•: the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;
•: a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
•: our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
•: a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and
•: a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate expenses or other purposes.

A high level of indebtedness would increase the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness will depend on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

We regularly evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

•: recoverable reserves;
•: future oil and natural gas prices and their appropriate differentials;
•: development and operating costs; and
•: potential environmental and other liabilities.

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The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis.

Significant acquisitions and other strategic transactions may involve other risks, including:

•: diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
•: challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;
•: difficulty associated with coordinating geographically separate organizations; and
•: challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be lower than we expect.

The success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations into our existing operations. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and natural gas industry conditions, or by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

Prior to the drilling of an oil or gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work

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entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.

The proposed American Jobs Act of 2011 includes potential legislation that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain U.S. federal income tax benefits currently available to oil and gas exploration and production companies. Such proposed changes include, but are not limited to, (1) the repeal of the percentage depletion allowance for oil and gas properties; (2) the elimination of current deductions for intangible drilling and development costs; (3) the elimination of the deduction for certain U.S. production activities; and (4) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether all or any such changes will be enacted or, if enacted, how soon such changes would be effective.

The passage of any legislation as a result of these proposals or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change, as well as any changes to or the imposition of new state or local taxes (including the imposition of, or increase in, production, severance or similar taxes), could negatively affect our financial condition and results of operations.

Risks Relating to the Offering and our Common Stock

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active liquid trading market for our common stock may not develop and our stock price may be volatile.

Prior to this offering, our common stock was not traded on any market. An active and liquid trading market for our common stock may not develop or be maintained after this offering. Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors' purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a decline in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated between us, the selling stockholder and representatives of the underwriters, based on numerous factors which we discuss in the "Underwriting" section of this prospectus, and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in the offering.

The following factors could affect our stock price:

•: our operating and financial performance and drilling results, including reserve estimates;
•: quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;
•: strategic actions by our competitors;

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•: changes in revenue or earnings estimates, publication of reports or changes or withdrawals of research coverage by equity research analysts;
•: speculation in the press or investment community;
•: sales of our common stock by us, the selling stockholder or our other stockholders, or the perception that such sales may occur;
•: changes in accounting principles;
•: additions or departures of key management personnel;
•: actions by our stockholders;
•: general market conditions, including fluctuations in commodity prices; and
•: domestic and international economic, legal and regulatory factors unrelated to our performance.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company's securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management's attention and resources and harm our business, operating results and financial condition.

Purchasers of common stock in this offering will experience immediate and substantial dilution of $ per share.

Based on an assumed initial public offering price of $ per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $ per share in the pro forma net tangible book value per share of our common stock from the initial public offering price, and our pro forma net tangible book value as of September 30, 2011 after giving effect to this offering would be $ per share. See "Dilution" for a complete description of the calculation of net tangible book value.

Because we are a relatively small company, the requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we will need to comply with certain laws, regulations and requirements, including corporate governance provisions of the Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the New York Stock Exchange, or the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

•: institute a more comprehensive compliance function;
•: design, establish, evaluate and maintain a system of internal control over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;
•: comply with rules promulgated by the NYSE;

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•: prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
•: establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;
•: involve and retain to a greater degree outside counsel and accountants in the above activities; and
•: establish an investor relations function.

We have material weaknesses in our internal control over financial reporting. If one or more material weaknesses persist or if we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

Prior to the completion of this offering, we have been a private company with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address our internal control over financial reporting. This lack of adequate accounting resources contributed to audit adjustments to the financial statements for the year ended December 31, 2010 and review adjustments for the nine months ended September 30, 2011 and the period from March 8, 2010 (Inception) to September 30, 2010. In connection with our audit for the year ended December 31, 2010 and review for the nine months ended September 30, 2011 and the period from March 8, 2010 (Inception) to September 30, 2010, our independent registered public accounting firm identified and communicated to us material weaknesses, including a material weakness related to not having adequate staffing levels which resulted in effective review and supervision by individuals with financial reporting oversight roles.

The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare our financial statements. This material weakness contributed to material audit adjustments to the depletion, asset retirement obligations, lease operating expense accruals and capital accruals accounts. In addition, our lack of adequate staffing levels resulted in the following individual material weaknesses:

•: our failure to design and operate effective controls to ensure the completeness and accuracy of the inputs with respect to depletion and asset retirement obligation calculations for the year ended December 31, 2010 and the nine months ended September 30, 2011 and the period from March 8, 2010 (Inception) to September 30, 2010; and
•: our failure to design and operate effective controls over the completeness of the lease operating expenses and capital accruals for the year ended December 31, 2010 and the nine months ended September 30, 2011 and the period from March 8, 2010 (Inception) to September 30, 2010.

Each of the material weaknesses described above could result in a misstatement of our accounts or disclosures that would result in a material misstatement of our annual or interim consolidated financial statements that would not be prevented or detected. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to remediate the material weaknesses described above or avoid potential future material weaknesses.

If, after this offering, we are unable to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act, or our internal controls over financial reporting are not effective, the reliability of our financial statements may be questioned, and our share price may suffer.

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will be required to comply with the SEC's rules implementing Section 302 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective controls, or any difficulties encountered in our implementation or improvement of our internal controls over financial reporting could result in material misstatements that are not prevented or detected on a timely basis, which could potentially subject us to sanctions or investigations by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.

We do not intend to pay dividends on our common stock and, consequently, your only opportunity to achieve a return on your investment is if the price of our stock appreciates.

We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our revolving credit facility places certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if the market price of our common stock appreciates, which may not occur, and you sell your shares at a profit. There is no guarantee that the price of our common stock that will prevail in the market after this offering will ever exceed the price that you pay.

Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public offerings or otherwise issue additional shares of common stock or convertible securities. Assuming no exercise of the underwriters' option to purchase additional shares, after the completion of this offering, we will have outstanding shares of common stock. This number includes shares that we and the selling stockholder are selling in this offering, which may be resold immediately in the public market. Following the completion of this offering, Three Rivers Holdings will beneficially own shares, or % of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to a lock-up agreement with the underwriters described in "Underwriting," but may be sold into the market in the future. We expect that Three Rivers Holdings will be a party to a registration rights agreement with us that will require us to effect the registration of its shares in certain circumstances no earlier than 180 days after the date of this prospectus.

As soon as practicable after this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our long-term incentive plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under our registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an

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acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

Our amended and restated certificate of incorporation and amended and restated bylaws contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to and desirable by our stockholders, including:

•: a classified board of directors, so that only approximately one-third of our directors are elected each year;
•: limitations on the removal of directors;
•: limitations on the ability of our stockholders to call special meetings; and
•: advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

The concentration of our capital stock ownership by our largest stockholder will limit your ability to influence corporate matters.

Upon completion of this offering, we anticipate that Three Rivers Holdings will initially own approximately % of our outstanding common stock. Riverstone will continue to own a substantial majority of the equity and control of Three Rivers Holdings. Consequently, Riverstone will continue to have control over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Riverstone, including its portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Riverstone is a private equity firm in the business of making investments in entities primarily in the energy industry. As a result, Riverstone's existing and future portfolio companies may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor. Further, while we expect that Riverstone will continue to provide us with several significant benefits, including strategic guidance and financial expertise from professionals with a successful track record of investing in energy assets, Riverstone is under no obligation to provide us with any such services.

We have also renounced our interest in certain business opportunities. Please read "—Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects" below.

Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects.

Our amended and restated certificate of incorporation provides that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in, or in being offered an opportunity to

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participate in, any business opportunity that may be from time to time presented to Riverstone or any of its officers, directors, agents, shareholders, members or partners (other than us and our subsidiaries) or business opportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so, and no such person shall be liable to us for breach of any fiduciary or other duty, as a director or officer or controlling stockholder or otherwise, by reason of the fact that such person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us unless, in the case of any such person who is our director or officer, any such business opportunity is expressly offered to such director or officer solely in his or her capacity as our director or officer. Riverstone does not have a formal policy regarding business opportunities presented to the investment funds managed or advised by it and their respective portfolio companies. However, it is generally Riverstone's practice that any such funds may pursue or direct to a portfolio company any business opportunity that is presented both to such fund and any portfolio company of any such funds but do not pursue business opportunities presented to an employee of an affiliate of Riverstone solely in his or her capacity as a director of a portfolio company of any such fund.

As a result, Riverstone may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which it has invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunities. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to Riverstone could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. See "Description of Capital Stock—Corporate Opportunity."

We will be a "controlled company" within the meaning of the NYSE rules and, as a result, will qualify for and will rely on exemptions from certain corporate governance requirements.

Because Three Rivers Holdings will own a majority of our outstanding common stock following the completion of this offering, we will be a "controlled company" as that term is set forth in Section 303A of the NYSE Listed Company Manual. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a "controlled company" and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

•: a majority of our board of directors consist of independent directors;
•: we have a nominating and corporate governance committee composed entirely of independent directors, with a written charter addressing the committee's purpose and responsibilities;
•: we have a compensation committee composed entirely of independent directors, with a written charter addressing the committee's purpose and responsibilities; and
•: we conduct an annual performance evaluation of the nominating and corporate governance committee and compensation committee.

These requirements will not apply to us as long as we remain a "controlled company." Following this offering, we expect to utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. Three Rivers Holdings' significant ownership interest could adversely affect investors' perceptions of our corporate governance.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "may," "continue," "predict," "potential," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include statements about our:

•: estimated future reserves and the present value thereof;
•: cash flows and liquidity;
•: business and financial strategy, budget, projections and operating results;
•: oil and natural gas realized prices;
•: timing and amount of future production of oil and natural gas;
•: availability of drilling and production equipment;
•: availability of oil field labor;
•: amount, nature and timing of capital expenditures, including future development costs;
•: availability and terms of capital;
•: drilling of wells;
•: competition;
•: marketing of oil and natural gas;
•: exploitation or property acquisitions;
•: costs of exploiting and developing our properties and conducting other operations;
•: general economic and business conditions;
•: effectiveness of our risk management activities;
•: environmental and other liabilities;
•: counterparty credit risk;
•: governmental regulation and taxation of the oil and natural gas industry;
•: developments in oil-producing and natural gas-producing countries and regions; and
•: plans, objectives, expectations and intentions contained in this prospectus that are not historical.

All forward-looking statements speak only as of the date of this prospectus. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, objectives, expectations and intentions reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, objectives, expectations or intentions will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk Factors" and "Management's Discussion and Analysis of

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Financial Condition and Results of Operations" and elsewhere in this prospectus. These factors include risks related to:

•: variations in the market demand for, and prices of, oil and natural gas;
•: uncertainties about our estimated quantities of oil and natural gas reserves;
•: the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our revolving credit facility;
•: general economic and business conditions;
•: failure to realize expected value creation from property acquisitions;
•: uncertainties about our ability to replace reserves and economically develop our current reserves;
•: risks related to the concentration of our operations in the Permian Basin;
•: drilling results;
•: potential financial losses or earnings reductions from our commodity price risk management programs;
•: potential adoption of new governmental regulations; and
•: our ability to satisfy future cash obligations and environmental costs.

These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $ million from the sale of the common stock offered by us, assuming an initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus) and after deducting estimated expenses payable by us and underwriting discounts and commissions. An increase or decrease in the initial public offering price of $1.00 per share of common stock would cause the net proceeds that we will receive from this offering, after deducting estimated expenses payable by us and underwriting discounts and commissions, to increase or decrease by approximately $ million.

We intend to use the net proceeds from this offering to repay outstanding borrowings under our revolving credit facility, of which $286.5 million was outstanding as of September 30, 2011. Our revolving credit facility matures on April 9, 2014 and bears interest at a variable rate, which was approximately 3.2% as of September 30, 2011. The borrowings to be repaid were incurred to fund our acquisitions of the Chesapeake Acquired Properties and the Samson Acquired Properties and to fund exploration, development and other capital expenditures. We may reborrow amounts repaid under our revolving credit facility and expect to do so to fund a portion of our development and other capital expenditures.

We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholder. We will pay all expenses related to this offering, other than underwriting discounts and commissions related to the shares sold by the selling stockholder. We expect that Riverstone and certain members of our senior management will indirectly receive proceeds from the sale of shares by the selling stockholder as a result of the distribution of proceeds by the selling stockholder to its members.

Affiliates of certain of the underwriters are lenders under our revolving credit facility and will receive a portion of the proceeds of this offering. Accordingly, this offering is being made in compliance with Rule 5121 of FINRA. See "Underwriting—Conflicts of Interest."

DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, our revolving credit facility places certain restrictions on our ability to pay cash distributions.

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CAPITALIZATION

The following table sets forth the capitalization as of September 30, 2011 of:

•: Three Rivers Operating Company LLC on an actual basis; and
•: Three Rivers Operating Company Inc. on an as adjusted basis giving effect to (1) our corporate reorganization that will occur simultaneously with the closing of this offering as described under "Corporate Reorganization" and (2) this offering and the application of the net proceeds as set forth under "Use of Proceeds."

You should read the following table in conjunction with "Use of Proceeds," "Selected Historical and Pro Forma Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our historical consolidated financial statements and unaudited pro forma financial information and related notes thereto appearing elsewhere in this prospectus.

	As of September 30, 2011

	Actual		As Adjusted
	(in thousands)
	(Unaudited)
Cash and cash equivalents	$	465	$

Long-term debt, including current maturities
Revolving credit facility(1)	$	286,500

Total debt		286,500
Members'/stockholders' equity
Capital contributions		271,066
Common stock, par value $0.01 per share; shares authorized, issued and outstanding, as adjusted		—
Preferred stock, par value $0.01 per share; shares authorized, no shares issued and outstanding, as adjusted		—		—
Additional paid-in capital		—
Accumulated earnings(2)		25,089

Total members'/stockholders' equity		296,155

Total capitalization	$	582,655	$

(1): The borrowing base under our revolving credit facility is currently set at $355 million, subject to periodic redetermination. We intend to use the net proceeds of this offering to repay outstanding borrowings under the revolving credit facility. See "Use of Proceeds." As of January 20, 2012, we had approximately $298.0 million of outstanding borrowings under our revolving credit facility.
(2): In connection with our corporate reorganization, an estimated net deferred tax liability of approximately $ will be established for differences between the book and tax basis of our assets and liabilities and a corresponding expense will be recorded to net income from operations.

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DILUTION

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of September 30, 2011, after giving pro forma effect to our corporate reorganization as described under "Corporate Reorganization," was approximately $ million, or $ per share of common stock. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering, after giving effect to our corporate reorganization. After giving effect to our corporate reorganization and the sale of the shares in this offering and assuming the receipt of the estimated net proceeds (after deducting estimated discounts and expenses of this offering), our adjusted pro forma net tangible book value as of September 30, 2011 would have been approximately $ million, or $ per share. This represents an immediate increase in the net tangible book value of $ per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $ per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:


Assumed initial public offering price per share		$
Pro forma net tangible book value per share as of September 30, 2011 (after giving effect to our corporate reorganization)
Increase per share attributable to new investors in this offering	$

As adjusted pro forma net tangible book value per share after giving effect to our corporate reorganization and this offering

Dilution in pro forma net tangible book value per share to new investors in this offering		$

The following table summarizes, on an as adjusted pro forma basis as of September 30, 2011, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $ , which is the midpoint of the range of the initial public offering prices set forth on the cover page of this prospectus, calculated before deduction of estimated underwriting discounts and commissions:

	Shares Acquired(1)			Total Consideration

	Shares Acquired(1)			Total Consideration			Average Price Per Share
	Number	Percent		Amount	Percent		Average Price Per Share
Existing stockholders			%	$		%	$
New investors			%			%

Total			%	$		%	$

(1): The number of shares disclosed for the existing stockholders includes shares being sold by the selling stockholder in this offering. The number of shares disclosed for the new investors does not include the shares being purchased by the new investors from the selling stockholder in this offering.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

Set forth below are (1) selected historical financial data for the Chesapeake Acquired Properties, as our predecessor, for the years ended December 31, 2008 and 2009 and the period from January 1, 2010 to April 9, 2010 and as of December 31, 2008 and 2009, which have been derived from the audited financial statements of the predecessor included elsewhere in this prospectus; (2) selected consolidated historical financial data for Three Rivers Operating Company LLC for the period from March 8, 2010, the date of inception, to December 31, 2010 and as of December 31, 2010 (successor), which have been derived from the audited consolidated financial statements of Three Rivers Operating Company LLC, included elsewhere in this prospectus; (3) selected unaudited consolidated financial data for Three Rivers Operating Company LLC for the period from March 8, 2010 (Inception), the date of inception, to September 30, 2010 and the nine months ended September 30, 2011 and as of September 30, 2011 (successor), which have been derived from the unaudited consolidated financial statements of Three Rivers Operating Company LLC included elsewhere in this prospectus and which, in the opinion of our management, include all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of this information; and (4) selected unaudited pro forma financial data for Three Rivers Operating Company Inc. for the year ended December 31, 2010, which have been derived from the unaudited pro forma financial statements included elsewhere in this prospectus. Additionally, the historical financial data for the Chesapeake Acquired Properties, the predecessor, reflects full cost accounting for oil and natural gas properties and the historical financial data for Three Rivers Operating Company LLC, the successor, reflects the successful efforts method of accounting for oil and natural gas properties, effective March 8, 2010.

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this prospectus may not be indicative of our future results of operations, financial position and cash flows.

	Predecessor							Three Rivers (Successor)

														Period from March 8, 2010 (Inception) to September 30, 2010 (Unaudited)
	Year Ended December 31,							Period from March 8, 2010 (Inception) to December 31, 2010			Pro Forma Year Ended December 31, 2010 (Unaudited)						Nine Months Ended September 30, 2011 (Unaudited)
	Year Ended December 31,					Period from January 1, 2010 to April 9, 2010
	2008			2009		Period from January 1, 2010 to April 9, 2010
	(in thousands)							(in thousands)
Revenues:
Oil and gas revenues	$	74,878		$	33,244	$	11,406	$	30,219		$	117,897		$	19,560		$	113,653
Expenses:
Lease operating expenses		22,076			18,274		3,152		12,000			27,089			7,870			22,027
Production and ad valorem taxes		6,177			3,128		735		2,852			10,346			1,860			8,839
Depreciation, depletion and amortization		17,887			9,400		2,259		8,072			24,316			5,177			22,706
Gain on the sale of oil and gas properties		—			—		—		—			—			—			(11,079	)
Impairment of oil and gas properties		88,173			—		—		—			—			—			—
Exploration expenses		—			—		—		13			13			4			63
General and administrative expenses		3,398			2,393		723		5,089			8,781			3,755			6,586

Total expenses		137,711			33,195		6,869		28,026			70,545			18,666			49,142

Operating income (loss)		(62,833	)		49		4,537		2,193			47,352			894			64,511
Other income (expense):
Interest expense		—			—		—		(3,399	)		(11,004	)		(2,240	)		(8,103	)
Realized and unrealized gain on commodity derivative instruments		—			—		—		3,893			3,893			9,248			26,903
Interest income		—			—		—		2			2			1			6
Other income		—			—		—		9			9			4			8

Total other income (expense)		—			—		—		505			(7,100	)		7,013			18,814

Income (loss) before taxes		(62,833	)		49		4,537		2,698			40,252			7,907			83,325
Provision for income tax		—			—		—		71			71			53			771

Net income (loss)	$	(62,833	)	$	49	$	4,537	$	2,627		$	40,181		$	7,854		$	82,554

Pro forma income tax expense (Unaudited)									986						2,888			30,439
Pro forma net income (Unaudited)								$	1,712					$	5,019		$	52,886

	Predecessor				Three Rivers (Successor)

	As of December 31,						As of September 30, 2011 (Unaudited)
	As of December 31,				As of December 31, 2010
	2008		2009		As of December 31, 2010
	(in thousands)				(in thousands)
Balance sheet data:
Cash and cash equivalents	$	—	$	—	$	146,756	$	465
Property and equipment, net		129,343		123,665		212,991		575,104
Total assets		136,584		130,747		406,182		633,030
Long-term debt		—		—		114,500		286,500
Owner's net investment/total members' equity		128,375		122,892		273,342		296,155

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	Predecessor									Three Rivers (Successor)

										Period from March 8, 2010 (Inception) to December 31, 2010			Period from March 8, 2010 (Inception) to September 30, 2010 (Unaudited)
	Year Ended December 31,															Nine Months Ended September 30, 2011 (Unaudited)
	Year Ended December 31,						Period from January 1 to April 9, 2010
	2008			2009			Period from January 1 to April 9, 2010
	(in thousands)									(in thousands)
Other financial data:
Net cash provided by operating activities	$	46,925		$	9,073		$	4,058		$	13,517		$	7,794		$	64,510
Net cash used in investing activities		(28,735	)		(3,541	)		(548	)		(249,549	)		(207,553	)		(320,910	)
Net cash provided by (used in) financing activities		(18,190	)		(5,532	)		(3,510	)		382,788			200,975			110,109
EBITDAX (Unaudited)(1)		43,227			9,449			6,796			13,035			7,739			77,152

(1): EBITDAX is a non-GAAP financial measure. For a definition of EBITDAX and a reconciliation of EBITDAX to our net income and net cash provided by operating activities, see "Prospectus Summary—Non-GAAP Financial Measure—EBITDAX."

Set forth below is unaudited financial data regarding our predecessor's revenues and direct operating expenses for the years ended December 31, 2006 and 2007. The financial data regarding revenues and direct operating expenses are not indicative of the financial condition or results of operations of the Chesapeake Acquired Properties or of Three Rivers and are not comparable to the selected financial data presented above for the Chesapeake Acquired Properties or Three Rivers due to the omission of various operating expenses. Prior to our acquisition, Chesapeake Energy Corporation did not account for the Chesapeake Acquired Properties as a separate business unit. As such, certain costs, such as depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expense and interest expense, were not allocated to the Chesapeake Acquired Properties.

	Year Ended December 31,

	2006		2007
	(in thousands)
	(Unaudited)
Oil and gas revenues	$	61,900	$	59,649

Direct operating expenses	$	25,851	$	26,405

Excess of revenues over direct operating expenses	$	36,049	$	33,244

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the carve out financial statements for the Chesapeake Acquired Properties, as our predecessor, and related notes appearing elsewhere in this prospectus. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. See "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements."

Overview

Since our inception in March 2010, we have completed two significant, complementary acquisitions of oil and natural gas properties in the Permian Basin. In April 2010 we acquired interests in oil and natural gas properties from Chesapeake Energy Corporation, which we refer to as the Chesapeake Acquired Properties, and in January 2011 we acquired interests in oil and natural gas properties from Samson Resources Company, which we refer to as the Samson Acquired Properties. These acquisitions included complementary and overlapping acreage positions, similar target formations, and jointly-owned wells, which have allowed us to achieve significant post-acquisition operational and cost efficiencies. Together, at the time of each respective acquisition, these purchases consisted of approximately 131,000 net held-by-production acres, 62.4 MMBoe of estimated proved reserves and interests in 1,450 producing wells in the Permian Basin in West Texas and Southeast New Mexico. We funded the purchase price for the acquisitions with capital contributions from Riverstone and borrowings under our revolving credit facility. Following these acquisitions, we have leased an additional approximately 14,707 acres in and around our core operating areas to add scale to our existing properties

Because of our recent significant acquisitions in 2010 and 2011, our discussion and analysis of our historical financial condition and results of operations for the periods discussed below may not necessarily be comparable with or applicable to our future results of operations. Additionally the Chesapeake Acquired Properties, our predecessor, used the full cost method of accounting for oil and natural gas activities and Three Rivers Operating LLC, as successor, adopted the successful efforts method of accounting for our oil and natural gas properties. See "—Critical Accounting Policies and Estimates—Successful Efforts Method of Accounting vs. Full Cost Method of Accounting" below for further discussion of the effect of each accounting method on the financial statements.

Our acquisition of the Chesapeake Acquired Properties was completed on April 9, 2010. The Chesapeake Acquired Properties constitute our accounting predecessor. Information about historical results for periods prior to April 9, 2010 relates to results of the Chesapeake Acquired Properties, as predecessor.

Our historical results include the Chesapeake Acquired Properties beginning on April 9, 2010 and include the Samson Acquired Properties beginning on January 7, 2011, the date of acquisition. The unaudited pro forma financial information and related notes included elsewhere in this prospectus give

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pro forma effect to the acquisitions of the Chesapeake Acquired Properties and the Samson Acquired Properties as if each had been completed on January 1, 2010.

Our 2010 and 2011 operations focused on evaluating and developing our asset base, optimizing our acreage positions and evaluating potential acquisitions. At September 30, 2011, based on the reserve report prepared by our independent reserve engineers, we had 73.9 MMBoe of estimated net proved reserves with a PV-10 of $982.5 million. Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas without giving effect to derivative transactions, and were based on the unweighted arithmetic average first-day-of-the-month prices for the prior twelve months. The unweighted arithmetic average prices were $94.50/Bbl for oil and $4.17/MMBtu for natural gas at September 30, 2011 and $79.43/Bbl for oil and $4.37/MMBtu for natural gas at December 31, 2010. These prices were adjusted by lease for crude quality, transportation charges, BTU content and gravity corrections.

Factors That Significantly Affect Our Results

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices have historically been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas that we can economically produce and our ability to access capital.

We generally hedge a significant portion of our expected future oil and natural gas production to reduce our exposure to fluctuations in commodity prices. See "—Hedging" for a discussion of our hedging and open hedge positions.

Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves, acquiring more reserves than we produce, and implementing secondary recovery techniques. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus on costs necessary to produce our reserves as well as the costs necessary to add reserves through drilling and acquisitions. Our ability to make capital expenditures to increase production from our existing reserves and to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost-effective manner and to timely obtain drilling permits and regulatory approvals.

As described above in "—Overview," the acquisitions of the Chesapeake Acquired Properties and the Samson Acquired Properties have been the two most significant events in the development of our company since its formation. One of our core strategies is to continue to actively evaluate the acquisition of additional oil-weighted Permian targets that include existing production with a high proportion of operated, low-risk drilling opportunities and a large share of held-by-production acreage. We believe by acquiring assets with high components of held-by-production acreage we can maintain our capital flexibility and limit our lease expirations in challenging commodity price environments. As with our historical acquisitions, any future acquisitions could have a substantial impact on our results of operations. In addition, funding future acquisitions may require us to incur additional indebtedness or issue additional equity.

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Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the period from March 8, 2010 (Inception) through December 31, 2010 or the nine months ended September 30, 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas of operations.

Sources of Our Revenue

Our revenues are derived from the sale of oil and natural gas within the continental United States and do not include the effects of derivatives. For the nine months ended September 30, 2011, our revenues were comprised of sales of approximately 66.2% oil, 16.5% natural gas and 17.3% natural gas liquids. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices which have historically been volatile. In 2009, prices were approximately $39.00 per Bbl and $3.00 per MMBtu compared to approximately $80.00 per Bbl and $4.40 per MMBtu in 2010. In the first nine months of 2011, West Texas Intermediate, or WTI, prices have been in a range between $85.00 and $110.00 per Bbl and wellhead natural gas market prices have been in a range between $3.90 and $4.27 per MMBtu. However, during the three months ended December 31, 2011, gas prices were generally lower, ranging between $2.99 and $4.05 per MMBtu.

NYMEX WTI futures prices are widely-used benchmarks in the pricing of oil and natural gas liquids, and NYMEX Henry Hub futures prices are used as benchmarks in the pricing of natural gas. The prices realized for our products compared to the NYMEX benchmark prices (or pricing differentials) tend to be comparable to the differentials of other producers in the Permian Basin. The differentials of Permian Basin producers are relatively constant as a result of, among other things, the Permian Basin's mature midstream infrastructure and proximity to major consuming and refining markets. For the year ended December 31, 2010, our average oil differential to the NYMEX WTI price was approximately $4.17 per Bbl and our average natural gas differential to the NYMEX Henry Hub price was approximately $0.56 per Mcf. For the nine months ended September 30, 2011, our average oil differential to the NYMEX WTI price was approximately $4.35 per Bbl and our average natural gas differential to the NYMEX Henry Hub price was approximately $0.63 per Mcf.

Hedging

Due to the inherent volatility in oil and natural gas prices, we use commodity derivative instruments, such as collars, swaps, puts and basis swaps to hedge price risk associated with a significant portion of our anticipated oil and natural gas production. By removing some of the price volatility associated with future production, we expect to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. We have not elected hedge accounting on these derivatives and, therefore, the unrealized gains and losses on open positions are reflected currently in earnings. At each period end, we estimate the fair value of our commodity derivatives and recognize an unrealized gain or loss.

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Our open hedge positions as of September 30, 2011 were as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total

Oil Swaps(1)
2011
Volume (Bbl)		—		—		—		151,800		151,800
Price per Bbl		—		—		—	$	91.30	$	91.30
2012
Volume (Bbl)		137,700		137,700		131,700		131,700		538.800
Price per Bbl	$	91.76	$	91.76	$	91.72	$	91.72	$	91.74
2013
Volume (Bbl)		138,600		138,600		138,600		138,600		554,400
Price per Bbl	$	92.51	$	92.51	$	92.51	$	92.51	$	92.51
2014
Volume (Bbl)		108,900		108,900		108,900		108,900		435,600
Price per Bbl	$	90.80	$	90.80	$	90.80	$	90.80	$	90.80
2015
Volume (Bbl)		102,000		102,000		102,000		102,000		408,000
Price per Bbl	$	91.62	$	91.62	$	91.62	$	91.62	$	91.62
Oil Collars(1)
2011
Volume (Bbl)		—		—		—		52,200		52,200
Floor Price per Bbl		—		—		—	$	100.00	$	100.00
Ceiling Price per Bbl		—		—		—	$	117.00	$	117.00
2012
Volume (Bbl)		29,100		29,100		29,100		29,100		116,400
Floor Price per Bbl	$	100.00	$	100.00	$	100.00	$	100.00	$	100.00
Ceiling Price per Bbl	$	112.40	$	112.40	$	112.40	$	112.40	$	112.40

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total

Natural Gas Swaps(2)
2011
Volume (MMBtu)		—		—		—		808,800		808,800
Price per MMBtu		—		—		—	$	5.26	$	5.26
2012
Volume (MMBtu)		786,300		786,300		744,000		684,000		3,000,600
Price per MMBtu	$	5.26	$	5.26	$	5.26	$	5.31	$	5.27
2013
Volume (MMBtu)		684,000		684,000		684,000		684,000		2,736,000
Price per MMBtu	$	5.31	$	5.31	$	5.31	$	5.31	$	5.31
2014
Volume (MMBtu)		609,000		609,000		609,000		609,000		2,436,000
Price per MMBtu	$	5.53	$	5.53	$	5.53	$	5.53	$	5.53
2015
Volume (MMBtu)		555,000		555,000		555,000		555,000		2,220,000
Price per MMBtu	$	5.48	$	5.48	$	5.48	$	5.48	$	5.48

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	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total

Natural Gas Basis Swaps(2)
2011
Volume (MMBtu)		—			—			—			495,000			495,000
Price per MMBtu		—			—			—		$	(0.17	)	$	(0.17	)
2012
Volume (MMBtu)		904,500			904,500			904,500			904,500			3,618,000
Price per MMBtu	$	(0.19	)	$	(0.19	)	$	(0.19	)	$	(0.19	)	$	(0.19	)
2013
Volume (MMBtu)		792,000			792,000			792,000			792,000			3,168,000
Price per MMBtu	$	(0.22	)	$	(0.22	)	$	(0.22	)	$	(0.22	)	$	(0.22	)
2014
Volume (MMBtu)		714,000			714,000			714,000			714,000			2,856,000
Price per MMBtu	$	(0.24	)	$	(0.24	)	$	(0.24	)	$	(0.24	)	$	(0.24	)
2015
Volume (MMBtu)		648,000			648,000			648,000			648,000			2,592,000
Price per MMBtu	$	(0.25	)	$	(0.25	)	$	(0.25	)	$	(0.25	)	$	(0.25	)

(1): The oil derivatives are settled based on the month's average daily NYMEX price of West Texas Intermediate Light Sweet Crude Oil.
(2): The natural gas derivatives are settled based on NYMEX gas futures. Natural gas basis swaps are based off of the differential between NYMEX gas futures and El Paso Permian and WAHA gas price indices.

Principal Components of Our Cost Structure

Lease Operating Expenses. Lease operating expenses include the daily costs incurred to bring crude oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs include field personnel compensation, utilities, maintenance, and repair expenses related to our oil and natural gas properties.

Production and Ad Valorem Taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices or at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. Ad valorem taxes are property taxes assessed based on a flat rate per natural gas equivalent produced.

Workover Expenses. Workover expenses include the costs of major remedial operation on any completed wells to restore, maintain, or improve the wells' production. Because the amount of workover expenses is closely correlated to the level of workover activity, which is not regularly scheduled, workover expenses are not necessarily comparable from period-to-period. Workover expenses are included in lease operating expenses in the presentation of our financial results.

Exploration Expenses. Costs related to exploratory wells that do not find proved reserves are charged as exploration expenses. These costs include costs for geological and geophysical studies, including seismic data, rights of access to properties and costs of carrying and retaining undeveloped properties, such as delay rentals. As with workover expenses, the amount of exploration expenses is non-recurring, and may not necessarily be comparable from period-to-period. Chesapeake Acquired Properties, our predecessor, used the full cost method of accounting for oil and natural gas activities and Three Rivers Operating LLC, as successor, adopted the successful efforts method of accounting for our oil and natural gas properties. See "—Critical Accounting Policies and Estimates—Successful

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Efforts Method of Accounting vs. Full Cost Method of Accounting" for further discussion of the effect of each accounting method on the financial statements.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas. Chesapeake Acquired Properties, our predecessor, used the full cost method of accounting for oil and natural gas activities and Three Rivers Operating LLC, as successor, adopted the successful efforts method of accounting for our oil and natural gas properties. See "—Critical Accounting Policies and Estimates—Successful Efforts Method of Accounting vs. Full Cost Method of Accounting" for further discussion of the effect of each accounting method on the financial statements.

General and Administrative Expenses. General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other professional fees and legal compliance costs.

Interest Expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our revolving credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We include interest paid to the lenders under our revolving credit facility in interest expense. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense.

Other Income (Expense)

Commodity Derivative Income (Expense). We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of oil and natural gas. We recognize unrealized gains and losses associated with our open commodity derivative contracts as commodity prices and commodity derivative contracts change. The commodity derivative contracts we have in place are not classified as hedges for accounting purposes. Consequently, these commodity derivative contracts are marked-to-market each month with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market commodity derivative contracts in our consolidated statement of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

Interest Income. This represents the interest received on our cash and cash equivalents.

Income Tax Expense. Prior to the completion of this offering and our corporate reorganization, we have been a limited liability company not subject to entity level federal income tax. Accordingly, no provision for federal or state corporate income taxes has been provided for the period from March 8, 2010, the date of our inception, to December 31, 2010, the period from March 8, 2010 to September 30, 2010, or the nine months ended September 30, 2011, because taxable income is allocated directly to our equity holders. Simultaneously with the closing of this offering, we will reorganize as a corporation that will be subject to federal and state entity-level taxation.

Our income tax expense in our historical financial statements results from the enactment of state income tax laws by the State of Texas that apply to entities organized as partnerships or limited liability companies. In connection with our corporate reorganization, an estimated net deferred tax liability of approximately $ will be established for differences between the book and tax basis of our assets and liabilities and a corresponding expense will be recorded to net income from operations.

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Results of Operations

The following table summarizes our historical production and financial data for the periods indicated.

	Predecessor							Three Rivers (Successor)

											Period from March 8, 2010 (Inception) to September 30, 2010 (Unaudited)
								Period from March 8, 2010 (Inception) to December 31, 2010						Nine Months Ended September 30, 2011 (Unaudited)
	Year Ended December 31,					Period from January 1 to April 9, 2010
	2008			2009		Period from January 1 to April 9, 2010
Net production volumes:
Oil (Bbls)		359,370			330,734		78,029		224,758			143,249			825,885
Natural Gas (Mcf)		5,439,334			4,225,255		1,073,621		2,662,231			1,834,972			5,281,878
Natural Gas Liquids (Bbls)		—			—		531		114,275			48,937			444,143

Total (Boe)		1,265,926			1,034,943		257,497		782,738			498,015			2,150,341
Average daily production volumes:
Oil (Bbl)		985			906		867		818			783			3,025
Natural Gas (Mcf)		14,902			11,576		11,929		9,681			10,027			19,347
Natural Gas Liquids (Bbls)		—			—		6		416			267			1,627

Total (Boe)		3,468			2,835		2,861		2,847			2,721			7,877
Average sales prices:
Oil, without derivatives (Bbl)	$	96.89		$	56.12	$	73.38	$	75.67		$	74.40		$	91.13
Natural gas, without derivatives (Mcf)	$	7.36		$	3.48	$	5.27	$	3.55		$	3.78		$	3.54
Natural Gas Liquids (Bbls)	$	—		$	—	$	33.90	$	32.96		$	40.32		$	44.33
Total, without derivatives (Boe)	$	59.15		$	32.12	$	44.30	$	38.61		$	39.28		$	52.85
Operating results (in thousands):
Revenues:
Oil	$	34,820		$	18,561	$	5,726	$	17,008		$	10,658		$	75,260
Natural Gas		40,058			14,683		5,662		9,445			6,929			18,704
Natural Gas Liquids		—			—		18		3,766			1,973			19,689

Total oil and gas revenues		74,878			33,244		11,406		30,219			19,560			113,653
Expenses:
Lease operating expenses		22,076			18,274		3,152		12,000			7,870			22,027
Production and ad valorem taxes		6,177			3,128		735		2,852			1,860			8,839
Depreciation, depletion and amortization		17,887			9,400		2,259		8,072			5,177			22,706
Gain on sale of oil and gas properties		—			—		—		—			—			(11,079	)
Impairment of oil and gas properties		88,173			—		—		—			—			—
Exploration expenses		—			—		—		13			4			63
General and administrative expenses		3,398			2,393		723		5,089			3,755			6,586

Total expenses	$	137,711		$	33,195	$	6,869	$	28,026		$	18,666		$	49,142

Operating income (loss)		(62,833	)		49		4,537		2,193			894			64,511
Other income (expense):
Interest expense		—			—		—		(3,399	)		(2,240	)		(8,103	)
Realized and unrealized gain on commodity derivative instruments		—			—		—		3,893			9,248			26,903
Interest income		—			—		—		2			1			6
Other income		—			—		—		9			4			8

Total other income		—			—		—		505			7,013			18,814

Income (loss) before taxes		(62,833	)		49		4,537		2,698			7,907			83,325
Provision for income tax		—			—		—		71			53			771

Net income (loss)	$	(62,833	)	$	49	$	4,537	$	2,627		$	7,854		$	82,554

Pro forma income tax expense (Unaudited)									986			2,888			30,439

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	Predecessor						Three Rivers (Successor)

									Period from March 8, 2010 (Inception) to September 30, 2010 (Unaudited)
							Period from March 8, 2010 (Inception) to December 31, 2010				Nine Months Ended September 30, 2011 (Unaudited)
	Year Ended December 31,				Period from January 1 to April 9, 2010
	2008		2009		Period from January 1 to April 9, 2010
Pro forma net income (loss) (Unaudited)							$	1,712	$	5,019	$	52,886
Expenses (per Boe of production):
Lease operating expenses	$	17.44	$	17.66	$	12.24	$	15.33	$	15.80	$	10.24
Production and ad valorem taxes	$	4.88	$	3.02	$	2.85	$	3.64	$	3.73	$	4.11
Depreciation, depletion and amortization	$	14.13	$	9.08	$	8.77	$	10.31	$	10.40	$	10.56
General and administrative expenses	$	2.68	$	2.31	$	2.81	$	6.50	$	7.54	$	3.06

Nine Months Ended September 30, 2011 Compared to the Period from March 8, 2010 (Inception) to September 30, 2010

Oil and Natural Gas Revenues. Our total oil and natural gas sales revenues increased by $94.1 million, or 481%, to $113.7 million during the nine months ended September 30, 2011 compared to the period from inception to September 30, 2010. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold, and average sales prices received for those volumes. Average daily production sold increased by 5,156 Boe per day, or 189%, to 7,877 Boe per day during the nine months ended September 30, 2011 compared to the period from inception to September 30, 2010. The increase in average daily production sold is primarily due to the addition of the Samson Acquired Properties in January 2011 and successful drilling and recompletion activity in our Wolfberry core area, as well as a full nine months of operations. For the nine-month period ended September 30, 2011, average oil sales prices, without derivatives, increased by $16.73 per barrel, or 22%, to an average of $91.13 per barrel compared to the period from inception to September 30, 2010; average gas prices, without derivatives, declined by $0.24 per Mcf, or 6%, to an average of $3.54 per Mcf compared to the period from inception to September 30, 2010; and average natural gas liquids prices increased by $4.01 per barrel, or 10%, to an average of $44.33 per barrel compared to the period from inception to September 30, 2010.

Lease Operating Expenses. Lease operating expenses increased $14.2 million for the nine months ended September 30, 2011 compared to the period from inception to September 30, 2010. This increase was primarily due to the higher number of producing wells after the addition of the Samson Acquired Properties in January 2011 as well as a full nine months of operations. Lease operating expenses on a per-unit basis decreased by 35% to $10.24 per Boe as the Samson Acquired Properties generally had lower overall per-unit expenses than the Chesapeake Acquired Properties, principally due to the fact that the Chesapeake Acquired Properties were more mature and had lower production rates on a per-well basis.

Production and Ad Valorem Taxes. Production taxes for the nine-month period ended September 30, 2011 increased by $7.0 million to $8.8 million compared to the period from inception to September 30, 2010, as a result of the addition of the Samson Acquired Properties as well as a full nine months of operations. Our production taxes for the nine months ended September 30, 2011 and the period from inception to September 30, 2010 were 7.8% and 9.5%, respectively, as a percentage of total oil and gas revenues.

Depreciation, Depletion and Amortization (DD&A). DD&A increased $17.5 million for the nine months ended September 30, 2011 compared to the period from inception to September 30, 2010. This increase is primarily the result of the addition of the Samson Acquired Properties in January 2011 as well as a full nine months of operations. On a per unit basis, DD&A was relatively unchanged,

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increasing only $0.16 per Boe principally as a result of a 332% increase in total net production volumes.

Exploration Expenses. Exploration expenses of $63 thousand for the nine months ended September 30, 2011 were primarily comprised of geoscience costs. For the period from inception to September 30, 2010, we had exploration expenses of $4 thousand. This increase was primarily due to the increased acreage after the addition of the Samson Acquired Properties in January 2011 as well as a full nine months of operations.

General and Administrative Expenses. Our general and administrative expenses increased to $6.6 million for the nine month period ended September 30, 2011 from $3.8 million for the period from inception to September 30, 2010. The increase was primarily due to the increased staffing levels resulting from hiring of staff from the date of our inception and throughout 2010 and as a result of operating the Samson Acquired Properties beginning in January 2011, as well as a full nine months of operations. On a per unit basis, general and administrative expenses were $3.06 per Boe for the nine month period ended September 30, 2011 compared to $7.54 per Boe for the period from inception to September 30, 2010, primarily because of the significantly greater production as a result of the acquisition of the Samson Acquired Properties as well as production from new drills with minimal addition of staff.

Gain on Sale of Oil and Gas Properties. In the nine-month period ended September 30, 2011, we divested certain non-core, predominantly non-operated, properties in a series of transactions for total consideration of $59 million. We recorded a gain of $11.1 million as a result of these asset sales.

Realized and Unrealized Gain on Commodity Derivative Instruments. As a result of our derivative activities, for the period ended September 30, 2011, we incurred cash settlement gains of $2.5 million from natural gas hedges, and cash settlement losses of $1.6 million for oil hedges, for a net cash gain of $937 thousand. Net cash settlements for the period from inception to September 30, 2010 resulted in a gain of $1.7 million due to cash settlement gains of $1.5 million and $143 thousand for oil hedges and natural gas hedges, respectively. In addition, as a result of changes in commodity prices, we recognized $26.0 million of unrealized mark-to-market non-cash derivative gain in the nine-month period ended September 30, 2011, and a $7.6 million unrealized mark-to-market non-cash derivative gain during the period from inception to September 30, 2010.

Interest Expense. Interest expense increased $5.9 million, or 262%, for the nine months ended September 30, 2011 compared to the period from inception to September 30, 2010, due to a higher average outstanding debt balance in the nine months ended September 30, 2011 as a direct result of the incurrence of additional indebtedness to fund the purchase of the Samson Acquired Properties in January 2011.

Period from March 8, 2010 (Inception) to December 31, 2010

Oil and Natural Gas Revenues. Our total oil and natural gas sales revenues were $30.2 million during the period from inception to December 31, 2010. Total production was 783 MBoe for this period, or 2,847 Boe per day. Average realized prices for oil, without derivatives, natural gas, without derivatives, and natural gas liquids were $75.67, $3.55, and $32.96, respectively.

Lease Operating Expenses. Lease operating expenses for the period from inception to December 31, 2010 were $12.0 million. On a per unit basis, lease operating expenses for the period were $15.33 per Boe.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the period from inception to December 31, 2010 were $2.9 million, or 9.4% of total revenues, excluding the effects of our commodity hedging activities.

Depreciation, Depletion and Amortization (DD&A). DD&A was $8.1 million for the period from inception to December 31, 2010. On a per unit basis, DD&A for the period was $10.31 per Boe.

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Exploration Expenses. Exploration expenses were $13 thousand from inception to December 31, 2010 and were primarily comprised of geophysical data purchases.

General and Administrative Expenses. General and administrative expenses were $5.1 million for the period from inception to December 31, 2010. On a per unit basis, general and administrative expenses for the period were $6.50 per Boe.

Realized and Unrealized Gain on Commodity Derivative Instruments. Derivative settlements for the period from inception to December 31, 2010 were $1.8 million for oil related hedging activities and $900 thousand from natural gas hedging activities. Net derivative settlements for the period were $2.7 million. In addition, as a result of changes in commodity prices, we recognized $1.1 million of unrealized mark-to-market non-cash derivative gain in the period from inception to December 31, 2010.

Interest Expense. Interest expense was $3.4 million for the period from inception to December 31, 2010. On a per unit basis, our interest expense for the period was $4.34 per Boe.

Period from January 1, 2010 to April 9, 2010 (Results of Predecessor)

Oil and Natural Gas Revenues. Total oil and natural gas sales revenues were $11.4 million during the period from January 1, 2010 to April 9, 2010. Total production was 258 MBoe for this period, or 2,861 Boe per day. Average sales prices for oil, without derivatives, natural gas, without derivatives, and natural gas liquids were $73.38, $5.27, and $33.90, respectively.

Lease Operating Expenses. Lease operating expenses for the period from January 1, 2010 to April 9, 2010 were $3.2 million. On a per unit basis, lease operating expenses for the period were $12.24 per Boe.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the period from January 1, 2010 to April 9, 2010 were $735 thousand, or 6.4% of total revenues, excluding the effects of any commodity hedging activities.

Depreciation, Depletion and Amortization (DD&A). DD&A was $2.3 million for the period from January 1, 2010 to April 9, 2010. On a per unit basis, DD&A for the period was $8.77 per Boe.

General and Administrative Expenses. General and administrative expenses were $723 thousand for the period from January 1, 2010 to April 9, 2010. On a per unit basis, general and administrative expenses for the period were $2.81 per Boe.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008 (Results of Predecessor)

Oil and Natural Gas Revenues. Our total oil and natural gas sales revenues decreased by $41.6 million, or 56%, to $33.2 million during the year ended December 31, 2009 as compared to the year ended December 31, 2008. Total production for this period was 1,035 MBoe, down from 1,266 MBoe for the prior year. Total average daily production volumes decreased by 633 Boe per day, or 18%, to 2,835 Boe per day during the year ended December 31, 2009 as compared to the year ended December 31, 2008. The decrease in average daily production sold was due both to natural production declines and Chesapeake's decision to largely suspend development operations on these properties pending disposition. The revenue decrease was also attributable to lower oil and natural gas sales prices during the year ended December 31, 2009. Average oil sales prices, without derivatives, declined by $40.77 per barrel, or 42%, to an average of $56.12 per barrel for the year ended December 31, 2009, as compared to the year ended December 31, 2008. Average natural gas prices, without derivatives, declined by $3.88 per Mcf, or 53%, to an average of $3.48 per Mcf for the year ended December 31, 2009, as compared to the year ended December 31, 2008.

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Lease Operating Expenses. Lease operating expenses decreased $3.8 million during the year ended December 31, 2009, as compared to the year ended December 31, 2008. This decrease was largely the result of lower production volumes. Lease operating expenses on a per unit basis increased to $17.66 per Boe for the year ended December 31, 2009 compared to $17.44 per Boe for the year ended December 31, 2008.

Production and Ad Valorem Taxes. Production and ad valorem taxes during the year ended December 31, 2009 as compared to the year ended December 31, 2008, decreased 49% to $3.1 million, principally as a result of lower production levels and commodity prices. Production and ad valorem taxes during the years ended December 31, 2009 and December 31, 2008, were 9.4% and 8.2%, respectively, as a percentage of total oil and natural gas revenues.

Depreciation, Depletion and Amortization (DD&A). DD&A decreased $8.5 million during the year ended December 31, 2009 as compared to the year ended December 31, 2008 as a result of lower production volumes. On a per unit basis, DD&A decreased to $9.08 per Boe.

General and Administrative Expenses. General and administrative expenses decreased to $2.4 million during the year ended December 31, 2009, as compared to the year ended December 31, 2008. On a per unit basis, general and administrative expenses were $2.31 per Boe during the year ended December 31, 2009, as compared to $2.68 per Boe during the year ended December 31, 2008.

Impairment Expense. Impairment charges were recorded for the year ended December 31, 2008 of $88.2 million as a result of lower commodity prices at year end.

Liquidity and Capital Resources

Our primary sources of liquidity from inception, March 8, 2010, to date have been capital contributions from Riverstone, borrowings under our revolving credit facility and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. We continually monitor potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Our total 2010 capital and developmental expenditures were $11.2 million excluding acquisitions. Our estimated capital expenditures for 2011, excluding the acquisition of the Samson Acquired Properties, were approximately $110.1 million, with approximately $96.0 million allocated for drilling and completion operations, of which $68.8 million had been spent as of September 30, 2011. Our capital expenditure budget for 2012 is approximately $266.1 million, with $254.2 million allocated for drilling and completion operations. We expect to have $ million in available borrowing capacity under our revolving credit facility, after we apply the proceeds of this offering, which we believe, together with cash flows from operations, will be sufficient to fund our 2012 capital expenditure budget. However, because the operated wells funded by our 2012 drilling plans represent only a small percentage of our identified drilling locations, we will be required to generate or raise significant amounts of additional capital to develop our entire inventory of identified drilling locations if we elect to do so.

Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, timing of regulatory approvals, availability of rigs, success or lack of success

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in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

We actively review acquisition opportunities on an ongoing basis. Our ability to make significant additional acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all. Our 2012 capital expenditure budget includes $10 million for acquisition of additional leasehold acreage.

We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. See "—Hedging" and "—Quantitative and Qualitative Disclosures About Market Risk."

Senior Secured Revolving Credit Facility

We have a $600.0 million senior secured revolving credit facility with a syndicate of banks, with a borrowing base of $355.0 million as of September 30, 2011. The revolving credit facility is collateralized by substantially all our assets and matures on April 9, 2014.

As of September 30, 2011 and January 20, 2012, we had $286.5 million and $298.0 million, respectively, in outstanding borrowings under our revolving credit facility. The revolving credit facility provides for interest rates plus an applicable margin to be determined based on LIBOR or a bank base rate, at our election. LIBOR borrowings bear interest at LIBOR plus 2.00% to 3.00%, and base rate borrowings bear interest at the bank prime rate plus 1.00% to 2.00%. The revolving credit facility provides for commitment fees of 0.5% based on borrowing base utilization.

The borrowing base is subject to semi-annual redeterminations on May 15th and November 15th of each year. The revolving credit facility restricts, among other items, the payment of dividends, incurrence of indebtedness, sale of assets, loans, certain investments and mergers. The revolving credit facility also contains certain financial covenants, which require the maintenance of a minimum ratio of current assets to current liabilities of 1.0 to 1.0, a maximum ratio of total debt to EBITDAX of 4.0 to 1.0, and a minimum ratio of EBITDAX to interest expense of 2.5 to 1.0, each as defined in the credit agreement governing the facility. Management believes we were in compliance with all covenants under the revolving credit facility as of September 30, 2011.

The revolving credit facility describes customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the facility to be immediately due and payable. We believe that we are in compliance with the terms of our revolving credit facility.

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Cash Flows

Cash flows for our predecessor and Three Rivers Operating Company LLC are presented for the periods shown below:

	Predecessor									Three Rivers (Successor)

													Period from March 8, 2010 (Inception) to September 30, 2010 (Unaudited)
	Year Ended December 31,									Period from March 8, 2010 (Inception) to December 31, 2010						Nine Months Ended September 30, 2011 (Unaudited)
	Year Ended December 31,						January 1 to April 9, 2010
	2008			2009			January 1 to April 9, 2010
	(in thousands)									(in thousands)
Net cash provided by operating activities	$	46,925		$	9,073		$	4,058		$	13,517		$	7,794		$	64,510
Net cash used in investing activities		(28,735	)		(3,541	)		(548	)		(249,549	)		(207,553	)		(320,910	)
Net cash provided by (used in) financing activities		(18,190	)		(5,532	)		(3,510	)		382,788			200,975			110,109

Net change in cash	$	—		$	—		$	—		$	146,756		$	1,216		$	(146,291	)

Cash flows provided by operating activities

Net cash provided by operating activities was approximately $64.5 million for the nine-month period ending September 30, 2011 and $7.8 million for the period from inception to September 30, 2010. The increase of $56.7 million was largely due to an increase in revenue as a result of the purchase of the Samson Acquired Properties in January 2011 and from successful drilling and recompletion activities from our Wolfberry properties.

Net cash provided by operating activities from inception to December 31, 2010 was $13.5 million and net cash from operating activities of our predecessor for the period from January 1, 2010 to April 9, 2010 was $4.1 million.

Net cash provided by operating activities of our predecessor was $9.1 million in 2009 compared to net cash provided by operating activities of $46.9 million in 2008. The decrease in net cash provided by operating activities in 2009 compared to 2008 was a result of lower commodity prices realized on both oil and natural gas revenues.

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and natural gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see "—Quantitative and Qualitative Disclosures About Market Risk" below.

Cash flows used in investing activities

Net cash used in investing activities for the nine months ended September 30, 2011 was $320.9 million, which included $310.2 million for the acquisition of the Samson Acquired Properties and additions to oil and gas properties of $68.8 million, offset by the sale of $58.8 million of non-core, predominantly non-operated, assets. Net cash used in investing activities for the period from inception to September 30, 2010 was $207.6 million, which included $202.8 million for the acquisition of the Chesapeake Acquired Properties in April 2010.

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Net cash used in investing activities for the period from inception to December 31, 2010 was $249.5 million, comprised of $11.2 million of development capital expenditures, $202.8 million for the acquisition of the Chesapeake Acquired Properties, and a $34.0 million deposit made to Samson Resources Company as part of our acquisition of the Samson Acquired Properties.

Net cash used in investing activities was $548 thousand for our accounting predecessor for the period from January 1 to April 9, 2010, due largely to the fact that Chesapeake had substantially ceased new investment in the Chesapeake Acquired Properties after January 1, 2010, the effective date of our agreement to acquire those properties.

During the year ended December 31, 2009, net cash used in investing activities decreased to $3.5 million from $28.7 million during the year ended December 31, 2008 driven by lower capital expenditures by our predecessor.

Cash flows provided by financing activities

Net cash provided by financing activities was $110.1 million for the nine months ended September 30, 2011, comprised of an increase of $172.0 million in net long term debt partially offset by $60.1 million of distributions to our equity holders from the proceeds of the aforementioned non-core asset sale. For the period from inception to September 30, 2010, net cash provided by financing activities was $201.0 million, which included initial capital contributions from Riverstone prior to transactional costs of $97.7 million as well as net borrowings under our revolving credit facility of $107.5 million primarily to support the purchase of the Chesapeake Acquired Properties.

During the period from inception to December 31, 2010, net cash provided by financing activities was $382.8 million, including net capital contributions of $270.7 million from Riverstone and a net long term debt increase of $114.5 million.

For our predecessor, net cash provided by financing activities represents the change in net investment amount, which is comprised of the difference between net cash provided by operating activities less net cash used in investing activities. For the period from January 1, 2010 to April 9, 2010, the net decrease in investment of our predecessor was $3.5 million. During the periods ended December 31, 2009 and 2008, the decrease in investment of our predecessor was $5.5 million and $18.2 million, respectively. These decreases were due largely to the fact that Chesapeake had largely suspended development operations on the Chesapeake Acquired Properties as it sought to divest these properties.

Obligations and Commitments

We have the following contractual obligations and commitments as of December 31, 2010:

	Payments Due By Period

	Total		2011		2012 to 2013		2014 to 2015		2016 & Beyond
	(in thousands)
Senior secured revolving line of credit(1)	$	114,500	$	—	$	—	$	114,500	$	—
Real estate rental payments(2)		663		183		451		29		—
Asset retirement obligations(3)		4,145		32		1,699		250		2,164

Total contractual obligations	$	119,308	$	215	$	2,150	$	114,779	$	2,164

(1): Amount excludes interest on our revolving credit facility because both the amount borrowed and applicable interest rate is variable. See "—Liquidity and Capital Resources—Senior Secured Revolving Credit Facility" and Note 7 to the consolidated financial statements of Three Rivers

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Operating Company LLC. As of September 30, 2011, we had borrowings of $286.5 million outstanding under our revolving credit facility.

(2): See Note 10 to the consolidated financial statements of Three Rivers Operating Company LLC for a description of our lease obligations.
(3): These amounts represent our estimate of future asset retirement obligations on a discounted 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 upon numerous factors.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and from assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 to our consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Successful Efforts Method of Accounting vs. Full Cost Method of Accounting

SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in oil and natural gas exploration, development, and production. Two methods are prescribed: the successful efforts method and the full cost method of accounting for oil and natural gas properties. In accounting for the oil and natural gas exploration and production business, Chesapeake Acquired Properties, our predecessor, used the full cost method to account for its oil and natural gas properties. However, Three Rivers Operating LLC, as successor, adopted the successful efforts method of accounting for oil and natural gas properties. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and natural gas properties are generally calculated on a field basis versus the "full cost" pool basis. Under the full cost method, all costs incurred in exploring for, acquiring and developing oil and natural gas reserves are capitalized to a full cost pool, whether or not the activities to which they apply are successful. Also the full cost method capitalizes internal costs that can be directly identified with acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. Additionally, gain or loss is generally recognized on all sales of oil and natural gas properties under the successful efforts method whereas under the full cost method, gains or losses are included in the full cost pool unless the entire pool is sold. Under the full cost method, unevaluated costs are excluded from the full cost pool and are periodically evaluated for impairment rather than amortized. Upon evaluation, these costs are transferred to the full cost pool and amortized. Under the successful efforts method, these costs are included in undeveloped leasehold cost or expensed

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depending on the nature of the expenditure. As a result, full cost companies will differ from companies that apply the successful efforts method since they generally will reflect a higher level of capitalized costs as well as a higher depreciation, depletion and amortization rate on oil and natural gas properties.

Under the full cost accounting method for oil and natural gas properties, the net capitalized cost of oil and natural gas properties may not exceed a "ceiling limit" which is based upon the present value of estimated future net cash flows from proved reserves, including cash flow hedges, discounted at 10%, plus the lower of cost or fair market value of unproved properties and the cost of properties not being amortized, less income taxes. If net capitalized costs of oil and natural gas properties exceed the ceiling limit, a company using the full cost method of accounting must charge the amount of the excess to earnings as an impairment charge. This charge does not impact cash flow from operating activities, but would reduce stockholders' equity and earnings. The risk that a company using the full cost method will be required to write down the carrying value of oil and natural gas properties increases when natural gas and crude oil prices are depressed or volatile. In addition, write-down of proved oil and natural gas properties may occur if a company using the full cost method experiences substantial downward adjustments to its estimated proved reserves or if purchasers cancel long-term contracts for its natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling applicable in the subsequent period. Based on the ceiling limitation calculation, an $88.2 million impairment was recorded for the predecessor period ended December 31, 2008. See "—Results of Operations—Year Ended December 31, 2009 Compared to Year Ended December 31, 2008 (Results of Predecessor)" for further information pertaining to the impairment charge. Under the successful efforts method of accounting for oil and natural gas properties followed by Three Rivers Operating LLC, we review our oil and natural gas properties periodically (at least annually) to determine if impairment of such properties was necessary. Property impairments may occur if a field discovers lower than anticipated reserves, reservoirs produce below original estimates or if commodity prices fall below a level that significantly affects anticipated future cash flows on the property. Proved oil and natural gas property values are reviewed when circumstances suggest the need for such a review and, if required, the proved properties are written down to their estimated fair market value based on proved reserves and other market factors. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the current period. Management assesses the undeveloped acreage, leasehold, geological and geophysical (seismic) costs and related capitalized interest to determine if any expenses should be impaired, reclassified to proved properties or classified as a dry hole and recorded as expense in the statement of operations.

Oil and natural gas reserve quantities and standardized measure of future net revenue

Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the SEC has recently adopted rules which allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this prospectus. The SEC's revised rules define proved oil and gas reserves as those quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence within a reasonable time. Our independent engineers and technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent production levels and other technical information about each field. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The

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accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

Revenue recognition

Revenue from our interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership and collectability are reasonably assured. Substantially all of our production is sold to purchasers under short-term (less than 12 month) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, we sell the majority of production soon after it is produced at various locations. As a result, we maintain a minimum amount of product inventory in storage.

Impairment of proved properties

We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.

Impairment of unproved properties

We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and record impairment expense for any decline in value. The assessment of unproved properties to determine any possible impairment requires managerial judgment.

Asset retirement obligations

In accordance with the Financial Accounting Standard Board's, or FASB, authoritative guidance on asset retirement obligations, or ARO, we record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized

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cost is depreciated using the unit-of-production method. The accretion expense is recorded as a component of DD&A in our consolidated statement of operations.

We determine ARO by calculating the present value of estimated cash flows related to the liability. Estimating 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 fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment must be made to the related asset.

Derivatives

We record all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. We have not designated any derivative instruments as hedges for accounting purposes and we do not enter into such instruments for speculative trading purposes. Realized gains and realized losses from the settlement of commodity derivative instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled commodity derivative instruments are reported under Other Income (Expense) in our consolidated statement of operations.

Recent Accounting Pronouncements

Fair Value. In February 2010, the FASB enhanced existing authoritative guidance on certain disclosure requirements and added two new disclosure requirements related to fair value measurements. The guidance requires a gross presentation of activities within the Level 3 roll forward and adds a new requirement to disclose details of significant transfers in and out of Level 1 and 2 measurements and the reasons for the transfers. The new disclosures are required for all companies that are required to provide disclosures about recurring and nonrecurring fair value measurements and are required effective as of the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We do not expect the adoption of this guidance to have a significant impact on our financial position, cash flows or results of operations.

Oil and Gas Reporting Requirements. In December 2008, the SEC released the final rule, "Modernization of Oil and Gas Reporting," which adopts revisions to the SEC's oil and gas reporting disclosure requirements. The disclosure requirements under this final rule require reporting of oil and gas reserves using the unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months rather than year-end prices, and the use of new technologies to determine proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies are allowed, but not required, to disclose probable and possible reserves in SEC filings. In addition, companies are required to report the independence and qualifications of their reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. In January 2010, the FASB issued authoritative guidance on oil and gas reserve estimation and disclosure, aligning its requirements with the SEC's final rule. We have presented and applied this new guidance for the year ended December 31, 2010.

Disclosures about Derivative Instruments and Hedging Activities. In March 2008, the FASB issued authoritative guidance related to disclosures about derivative instruments and hedging activities. The guidance requires disclosures previously required only for the annual financial statements to be disclosed in interim financial statements. This guidance is intended to improve financial reporting about derivative instruments and hedging activities by requiring companies to enhance disclosure about how these instruments and activities affect their financial position, performance and cash flows and to

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improve the transparency of the location and amounts of derivative instruments in a company's financial statements and how they are accounted for. This guidance was effective for us beginning January 1, 2009. The adoption of this guidance did not have a significant impact on our consolidated financial position, results of operations or cash flows.

Internal Controls and Procedures

•: our failure to design and operate effective controls to ensure the completeness and accuracy of the inputs with respect to depletion and asset retirement obligation calculations for the year ended December 31, 2010 and the nine months ended September 30, 2011 and the period from March 8, 2010 (Inception) to September 30, 2010; and
•: our failure to design and operate effective controls over the completeness of the lease operating expenses and capital accruals for the year ended December 31, 2010 and the nine months ended September 30, 2011 and the period from March 8, 2010 (Inception) to September 30, 2010.

Although remediation efforts are still in progress, we have taken steps to address the material weaknesses described above. In early 2011, we hired a Controller, a financial accounting manager and more support staff to strengthen the accounting department. In addition, the accounting function responsibility was transferred from an outsourced provider to in-house operations. During 2012, we expect to implement a comprehensive review of our internal control over financial reporting which will include our overall control environment, and the formalization of our review and approval processes.

We are not currently required to comply with the SEC's rules related to Section 404 of the Sarbanes-Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC's rules implementing Section 302 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to upgrade our systems, implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

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Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC unless it is determined we are a non-accelerated filer, in which case our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control. When, and if, it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed or operating. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.

Commodity price exposure. We are exposed to market risk as the prices of oil and natural gas fluctuate as a result of changes in supply and demand and other factors. Due to the inherent volatility in oil and gas prices, we use commodity derivative instruments, such as collars, swaps, puts and basis swaps to hedge price risk associated with a significant portion of our anticipated oil and gas production. By removing a majority of the price volatility associated with future production, we expect to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. We have not elected hedge accounting on these derivatives, and, therefore, the unrealized gains and losses on open positions are reflected currently in earnings. At each period end, we estimate the fair value of our commodity derivatives and recognize an unrealized gain or loss. We expect to enter into derivative instruments in the future to cover a significant portion of our future production.

For information regarding our open hedge positions as of September 30, 2011, see "—Hedging."

Interest rate risk. At December 31, 2010, we had indebtedness outstanding under our revolving credit facility of $114.5 million, which bore interest at floating rates. The weighted-average annual interest rate incurred on this indebtedness for the period from March 8, 2010 (Inception) to December 31, 2010 was approximately 3.4%. A 1.0% increase in each of the average LIBOR and federal funds rate for the period from March 8, 2010 (Inception) to December 31, 2010 would have resulted in an estimated $1.1 million increase in interest expense for the period from March 8, 2010 (Inception) to December 31, 2010. At September 30, 2011, we had indebtedness outstanding under our revolving credit facility of $286.5 million, which bore interest at floating rates. The weighted average annual interest rate incurred on this indebtedness for the nine months ended September 30, 2011 was approximately 3.2%.

We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expenses related to existing debt. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases of properties on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with a few significant customers. See "Business—Our Principal Customers" for further detail about our significant customers. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements.

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BUSINESS

Overview

Our business is concentrated in the Permian Basin of West Texas and Southeast New Mexico. The Permian Basin is one of the most prolific and largest producing oil and natural gas regions in the United States. We have three core operating areas within the Permian Basin:

•: the Bone Spring formation, which occurs in the Delaware Basin;
•: the Wolfberry, targeting the Spraberry and Wolfcamp formations, which occur primarily in the Midland Basin; and
•: Conventional Permian, where we target conventional Permian Basin oil and natural gas formations primarily in the Central Basin Platform.

The following table summarizes, for each of our core operating areas, our net acreage as of December 31, 2011, identified drilling locations as of September 30, 2011, estimated total proved

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reserves and related PV-10 as of September 30, 2011, and average daily production for the nine-month period ended September 30, 2011:

						Identified Drilling Locations(1)

													Estimated Total Proved Reserves (MBoe)
			% of Net Acreage Held-by- Production																	Average Daily Production (Boe/day)
	Net Acreage		% of Net Acreage Held-by- Production			Gross		Net		% Operated					PV-10(2) (in thousands)		% Proved Developed			Average Daily Production (Boe/day)
Bone Spring		39,732		52.1	%		464		250		64.7	%		4,636	$	56,307		35.9	%		319
Wolfberry		45,227		60.0	%		1,995		1,646		86.2	%		36,254		524,309		33.9	%		3,087
Conventional Permian		115,639		72.1	%		404		316		88.4	%		33,009		401,917		72.8	%		4,471

Total		200,598		65.4	%		2,863		2,212		83.0	%		73,899	$	982,533		51.4	%		7,877

(1): Approximately 17% of our total gross identified drilling locations are attributable to proved undeveloped reserves. For additional information regarding our identified drilling locations, including the processes and criteria we used to identify these drilling locations, see "—Our Operations—Identified Drilling Locations." Amounts do not include our 266 gross (212 net) recompletion opportunities.
(2): PV-10 is a non-GAAP financial measure. For additional information about PV-10 and how it differs from the Standardized Measure, see "Prospectus Summary—Summary Historical Reserve and Operating Data."

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recompletion activities and the number of gross locations, including recompletions, drilled and expected to be drilled in each of our core operating areas:

	Estimated for Year Ended December 31, 2011			Budget for Year Ending December 31, 2012

	(in thousands)			(in thousands)
Bone Spring	$	5,305	4	$	99,978	26
Wolfberry		75,306	89		130,526	151
Conventional Permian		15,418	15		23,732	14

Total	$	96,029	108	$	254,236	191

(1): Represents locations drilled and recompletions performed during the year ended December 31, 2011.
(2): Represents locations expected to be drilled, including operated and non-operated, and recompletions expected to be performed during the year ending December 31, 2012.

The ultimate amount of capital we will expend and the identified drilling locations we will drill may fluctuate materially based on market conditions and the success of our drilling operations as the year progresses. Please read "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" and "—Our Operations—Capital Expenditures" for further detail.

Our Strengths

We believe we are well positioned to successfully execute our business strategies and achieve our business objectives because of the following competitive strengths:

Large, Multi-Year Project Inventory in Existing and Emerging Plays. We have assembled a sizable inventory of 2,377 operated and 486 non-operated gross identified future drilling locations and an additional 266 gross identified recompletion opportunities targeting multiple well-defined zones. The

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majority of our locations target the higher impact Bone Spring and the lower risk Wolfberry formations with crude oil as the primary objective for both. We plan to drill or recomplete 191 gross (153 net) locations in 2012, which would represent 6.1% of our 3,129 combined gross identified drilling locations and recompletion opportunities. Our portfolio of drilling locations is based on an extensive dataset of geologic, engineering and operational information and includes stacked horizontal locations targeting the first, second, and third Bone Spring formations and 20-acre infill drilling in the Wolfberry. In addition, we have accumulated leasehold positions that are prospective for recently emerging plays, such as the Wolfcamp Shale, Cline Shale, Avalon Shale, horizontal Yeso, Cisco and Wolfbone, that are not included in the 2,863 gross identified drilling locations and represent incremental opportunities for potential development.

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Our Business Strategy

Our strategy is to increase stockholder value by economically and sustainably growing our reserves, production and cash flow. We intend to execute this strategy as follows:

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Our Core Project Areas

Our assets are primarily distributed in three core areas of the greater Permian Basin.

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Our Operations

Identified Drilling Locations

As of September 30, 2011 we have identified a total of 2,863 gross identified drilling locations, all of which are in our core operating areas in the Permian Basin. Approximately 17% of our gross identified drilling locations are attributable to proved undeveloped reserves. All three areas share some of the same technical metrics that we use to define a location. The drilling locations in each of our core operating areas have been identified based on our review of structure and net isopach maps, as well as production data from offsetting wells. We have internally generated this production data based on our evaluation of an extensive geological and engineering database. Information incorporated into this process includes both our own proprietary information as well as publicly available industry data. Specifically, open hole logging data, production statistics from operated and non-operated wells, and petrophysical data from cores taken from wellbores has provided the technical basis from which we identified the potential locations. These data have allowed us to determine areas for each reservoir that may produce commercial quantities of hydrocarbons and the viability of the potential locations.

In addition, we consider the potential locations in the Bone Spring and the Wolfberry to be characterized as a resource play. Resource plays contain continuous hydrocarbon systems that are regional in extent and have a repeatable statistical distribution of estimated ultimate recoveries, or EURs. Our acreage in the Bone Spring and the Wolfberry is surrounded in all directions by economic wells and logs that exhibit adequate net pay potential.

The Bone Spring resource play in New Mexico is developed by using horizontal wells targeting individual sand or shale formations and contains 464 gross identified drilling locations. These locations are spaced on 160 acres and in some instances include multiple wells per 160 acres targeting different formations within the Bone Spring interval. We anticipate that in the Bone Spring area we will drill 39 operated locations in 2012 and 2013, subject to commodity pricing and the continued success of our existing drilling program.

The Wolfberry resource play in Texas is comprised of multiple producing formations and contains 1,995 gross identified drilling locations. Based on our currently projected capital budget, we estimate that in 2012 and 2013 we will drill approximately 215 operated Wolfberry locations. The timing of the potential Wolfberry locations will be influenced by several factors, including commodity prices, capital requirements, Texas Railroad commission well-spacing requirements, and the continuation of positive results from the program.

We consider the potential locations in the Conventional Permian as representative of a conventional drilling program. As a result, the reservoirs in the Conventional Permian locations are not regional in extent. These reservoirs are localized and are identified by nearby production and location specific isopach maps.

Our gross identified drilling locations in the Conventional Permian area consists of 404 gross vertical wells in Texas and New Mexico. These wells typically target one or two stacked reservoirs, and are in highly developed areas. We anticipate drilling 84 operated locations in 2012 and 2013.

Estimated Proved Reserves

Unless otherwise specifically identified in this prospectus, the summary data with respect to estimated proved reserves presented below has been prepared by Cawley, Gillespie & Associates, Inc., our independent reserve engineering firm, in accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities.

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For a discussion of some of the risks associated with estimating reserves, see "Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves."

The table below summarizes our estimated proved reserves and related PV-10 and Standardized Measure as of December 31, 2010 on an actual basis and on a pro forma basis including the Samson Acquired Properties and as of September 30, 2011.

	December 31, 2010

	Three Rivers			Samson Acquired Properties			Pro Forma			September 30, 2011
Reserve Data(1):
Estimated proved reserves:
Oil & natural gas liquids (MBbl)		15,674			19,176			34,850			50,003
Natural gas (MMcf)		87,370			91,688			179,058			143,380
Total estimated proved reserves (MBoe)		30,235			34,458			64,693			73,899
Proved developed (MBoe)		18,389			16,660			35,049			37,956
Percent developed		61	%		48	%		54	%		51	%
Proved undeveloped (MBoe)		11,846			17,798			29,644			35,943
PV-10 (in thousands)(2)	$	352,396		$	372,072		$	724,468		$	982,533
Standardized measure (in thousands)(3)	$	352,396		$	372,072		$	724,468		$	982,533

(1): Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $79.43/Bbl for oil and $4.37/MMBtu for natural gas at December 31, 2010 and $94.50/Bbl for oil and $4.17/MMBtu for natural gas at September 30, 2011. These prices were adjusted by lease for crude quality, transportation charges, BTU content and gravity corrections.
(2): PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. However, our PV-10 and our Standardized Measure are equivalent because, as of September 30, 2011, we were a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to our equity holders. However, simultaneously with the closing of this offering, we will effect a corporate restructuring that will result in Three Rivers Operating Company Inc. becoming a holding company for Three Rivers Operating Company LLC. As a result, we will be treated as a taxable entity for federal income tax purposes. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
(3): Standardized Measure represents the present value of estimated future net cash inflows from proved oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses (if applicable), discounted at 10% per annum to reflect timing of future cash flows. Following our corporate reorganization, we will be treated as a taxable entity for federal income tax purposes. Future calculations of Standardized Measure will include the effects of income taxes on future net revenues. Assuming our corporate reorganization

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had occurred on September 30, 2011, we estimate that income taxes would have reduced our Standardized Measure to $626.9 million as of September 30, 2011. For further discussion of income taxes, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Other Income (Expense)—Income Tax Expense."

The table below summarizes our estimated proved reserves as of September 30, 2011 for each of our core operating areas:



Bone Spring	4,636	35.9	%
Wolfberry	36,254	33.9	%
Conventional Permian	33,009	72.8	%

Total	73,899	51.4	%

The following table sets forth the estimated future net revenues, excluding derivatives contracts, from proved reserves, the PV-10 and Standardized Measure, and the expected benchmark prices used in projecting net revenues as of December 31, 2010 on an actual basis and on a pro forma basis including the Samson Acquired Properties and as of September 30, 2011:

	December 31, 2010

	Three Rivers		Samson Acquired Properties		Pro Forma		September 30, 2011
Future net revenues, excluding derivatives contracts (in thousands)	$	1,355,112	$	1,945,616	$	3,300,728	$	2,412,429
Present value of future net revenues:
Before income tax (PV-10) (in thousands)		352,396		372,072		724,468		982,533
After income tax (Standardized Measure) (in thousands)(1)		352,396		372,072		724,468		982,533
Benchmark oil price(2) ($/Bbl)	$	79.43	$	79.43	$	79.43	$	94.50
Benchmark gas price(2) ($/MMBtu)	$	4.37	$	4.37	$	4.37	$	4.17

(1): Standardized Measure represents the present value of estimated future net cash inflows from proved oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses (if applicable), discounted at 10% per annum to reflect timing of future cash flows. Following our corporate reorganization, we will be treated as a taxable entity for federal income tax purposes. Future calculations of Standardized Measure will include the effects of income taxes on future net revenues. Assuming our corporate reorganization had occurred on September 30, 2011, we estimate that income taxes would have reduced our Standardized Measure to $626.9 as of September 30, 2011. For further discussion of income taxes, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Other Income (Expense)—Income Tax Expense."
(2): Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $79.43/Bbl for oil and $4.37/MMBtu for natural gas at December 31, 2010 and $94.50/Bbl for oil and $4.17/MMBtu for natural gas at September 30, 2011. These prices were adjusted by lease for crude quality, transportation charges, BTU content and gravity corrections.

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Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Future operating costs, production and ad valorem taxes, and capital costs were based on current costs as of each period-end, with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, neither PV-10 nor the Standardized Measure should be construed as the current market value of the proved oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (1) anticipated future changes in natural gas and oil prices, production and development costs, (2) an allowance for return on investment, (3) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (4) other business risk. See "Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves."

Proved undeveloped reserves

Our estimated proved undeveloped reserves as of December 31, 2010 were 11.8 MMBoe, all of which were attributable to the Chesapeake Acquired Properties, which we acquired in April 2010. Our estimated proved undeveloped reserves increased to 35.9 MMBoe at September 30, 2011, primarily as a result of the acquisition of proved undeveloped reserves associated with the Samson Acquired Properties, which we acquired in January 2011. On a pro forma basis giving effect to the acquisition of the Samson Acquired Properties, our estimated proved undeveloped reserves at December 31, 2010 were 29.6 MMBoe. The net increase of 6.3 MMBoe in proved undeveloped reserves was due to several factors. Included in this change were upward adjustments of 7.7 MMBoe. Of this amount, 6.5 MMBoe was attributable to the identification of 82 additional vertical locations in our Wolfberry play that were classified as proved undeveloped reserves. These reserves were booked as 40 acre offset locations to producing vertical wells. Furthermore, additions of 2.0 MMBoe to proved undeveloped reserves were attributable to the reclassification of reserves previously categorized as probable and possible reserves. In aggregate revisions and reclassifications of our proved undeveloped reserves resulted in additions of 0.6 MMBoe to proved undeveloped reserves.

During the nine months ended September 30, 2011, we also reclassified a material portion of our proved undeveloped reserves into the proved developed producing category as the result of our drilling and completion program. We drilled or participated in 54 productive vertical wells during the nine months ended September 30, 2011 in our Permian acreage. Of the 54 wells drilled, 27 were proved undeveloped locations which resulted in reserves of 1.3 MMBoe being reclassified as proved developed producing reserves. The establishment of the 27 completed wells as generating proved undeveloped reserves also enabled us to recognize an additional 31 drilling locations as including proved undeveloped reserves. Our total proved undeveloped reserves were also impacted by a sale of non-operated assets, which resulted in 0.7 MMBoe of proved undeveloped reserves being removed from the September 30, 2011 reserve report. Finally, proved undeveloped locations, with reserves of 2.0 MMBoe, were removed from our estimated total proved undeveloped reserves because they became uneconomic due to lower gas prices. Our capital expenditures associated with the conversion of proved undeveloped reserves to proved developed reserves were approximately $20.0 million for the nine months ended September 31, 2011.

Our 2012 development plan includes approximately $90.6 million dedicated towards drilling proved undeveloped reserves. We have developed a capital expenditure program for the development of our proved undeveloped reserves for 2013, 2014, 2015 and 2016 of $88.8 million, $123.6 million, $121.6 million, and $71.4 million, respectively, which we believe should be sufficient to fully develop

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our proved undeveloped reserves. The remainder of our capital expenditure budget will be primarily focused on identified drilling locations targeting the Bone Spring formation in New Mexico. The majority of these locations are currently in a non-proved category.

We intend to convert our estimated proved undeveloped reserves at September 30, 2011 to proved developed reserves within five years of when they were initially disclosed as proved undeveloped reserves.

Independent petroleum engineers

Estimates of proved developed and proved undeveloped reserves as of December 31, 2010 and September 30, 2011 were prepared by our independent engineers Cawley, Gillespie & Associates, Inc., which has been a reputable engineering firm for over 40 years and provides services under the Texas Board of Professional Registered Engineers No. F-693. The technical person primarily responsible for preparing our estimates is Mr. Robert D. Ravnaas, who has been with Cawley, Gillespie & Associates, Inc. since 1983. He holds a Bachelor of Science in Chemical Engineering from the University of Colorado and a Master of Science in Petroleum Engineering from the University of Texas. He is also a licensed Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, the American Association of Petroleum Geologists and the Society of Professional Well Log Analysts.

Technology used to establish proved reserves

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to EUR with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field-tested and demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, Cawley, Gillespie & Associates, Inc. employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well-test data.

Internal controls over reserves estimation process

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. The preparation of our reserve estimates are completed in accordance with our prescribed internal control procedures,

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which include verification of input data into a reserve forecasting and economic evaluation software, as well as management review. We make representations to the independent engineers that we have provided all relevant operating data and documents, and in turn, we review the reserve reports provided by the independent engineers to ensure completeness and accuracy. James D. Keisling, our Vice President of Engineering, is the technical person primarily responsible for overseeing the preparation of our reserve estimates. Mr. Keisling has 41 years of experience in the petroleum industry. He holds a Bachelor of Science in Civil Engineering from New Mexico State University and is a licensed Professional Engineer in the State of Texas and a member of the Society of Petroleum Engineers. As the Vice President of Engineering, Mr. Keisling has oversight and compliance responsibility for the internal reserve estimate process and provides appropriate data to and oversees the independent third-party engineers.

Throughout the year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the reserve report is reviewed by our President with representatives of our independent reserve engineers and our internal technical staff. Following the consummation of this offering, we anticipate that our audit committee will conduct a similar review on an annual basis.

Production, Price and Cost History

Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand for oil and natural gas in the United States has increased during the last decade with periods of volatility. Demand is impacted by general economic conditions, weather and other seasonal conditions. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced, and our ability to access capital markets.

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The following table sets forth summary data with respect to our production results, average sales prices and production costs on a historical basis for the periods presented.

	Predecessor						Three Rivers (Successor)

							Period from March 8, 2010 (Inception) to December 31, 2010		Period from March 8, 2010 (Inception) to September 30, 2010
	Year Ended December 31,										Nine Months Ended September 30, 2011
	Year Ended December 31,				January 1 to April 9, 2010
	2008		2009		January 1 to April 9, 2010
Net production volumes:
Oil (Bbl)		359,370		330,734		78,029		224,758		143,249		825,885
Natural gas (Mcf)		5,439,334		4,225,255		1,073,621		2,662,231		1,834,972		5,281,878
Natural gas liquids (Bbl)		—		—		531		114,275		48,937		444,143

Total (Boe)		1,265,926		1,034,943		257,497		782,738		498,015		2,150,341
Average daily production volumes:
Oil (Bbl)		985		906		867		818		783		3,025
Natural gas (Mcf)		14,902		11,576		11,929		9,681		10,027		19,347
Natural gas liquids (Bbl)		—		—		6		416		267		1,627

Total (Boe)		3,468		2,835		2,861		2,847		2,721		7,877
Average prices:
Oil, without derivatives (Bbl)	$	96.89	$	56.12	$	73.38	$	75.67	$	74.40	$	91.13
Natural gas, without derivatives (Mcf)	$	7.36	$	3.48	$	5.27	$	3.55	$	3.78	$	3.54
Natural gas liquids (Bbl)	$	—	$	—	$	33.90	$	32.96	$	40.32	$	44.33
Total, without derivatives (Boe)	$	59.15	$	32.12	$	44.30	$	38.61	$	39.28	$	52.85
Operating costs and expenses (per Boe):
Lease operating expenses	$	17.44	$	17.66	$	12.24	$	15.33	$	15.80	$	10.24
Production and ad valorem taxes	$	4.88	$	3.02	$	2.85	$	3.64	$	3.73	$	4.11
Depreciation, depletion and amortization	$	14.13	$	9.08	$	8.77	$	10.31	$	10.40	$	10.56
General and administrative expenses	$	2.68	$	2.31	$	2.81	$	6.50	$	7.54	$	3.06

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The following table sets forth information regarding our average daily production from our core operating areas for the following periods:

	Average Daily Production

	Oil		Natural Gas		NGL		Total
	(Bbls)		(Mcf)		(Bbls)		(Boe)
Period from March 8, 2010 (Inception) to December 31, 2010:
Bone Spring		8		5		2		11
Wolfberry		26		123		21		67
Conventional Permian		784		9,553		393		2,769

Total		818		9,681		416		2,847

Nine Months ended September 30, 2011:
Bone Spring		137		704		64		319
Wolfberry		1,903		3,037		678		3,087
Conventional Permian		985		15,606		885		4,471

Total		3,025		19,347		1,627		7,877

Productive Wells

The following table presents our total gross and net productive wells by core operating area and by oil or natural gas completion as of September 30, 2011:

	Gross Productive Wells						Net Productive Wells

	Oil		Natural Gas		Total		Oil		Natural Gas		Total		% Operated
September 30, 2011
Bone Spring		30		5		35		12		2		14		23	%
Wolfberry		209		27		236		149		9		158		74	%
Conventional Permian		263		381		644		210		237		447		78	%

Total		502		413		915		371		248		619		75	%

"Gross wells" represents the number of wells in which a working interest is owned, and "net wells" represents the total of our fractional working interests owned in gross wells.

Acreage

The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2011 for each of our core operating areas. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

	Undeveloped Acres				Developed Acres				Total				% of Acreage Held-by- Production

	Gross		Net		Gross		Net		Gross		Net		% of Acreage Held-by- Production
As of December 31, 2011
Bone Spring		22,171		19,049		38,816		20,683		60,987		39,732		52.1	%
Wolfberry		22,015		18,079		49,487		27,148		71,502		45,227		60.0	%
Conventional Permian		33,640		32,245		144,228		83,394		177,868		115,639		72.1	%

Total		77,826		69,373		232,531		131,225		310,357		200,598		65.4	%

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Undeveloped Acreage Expirations

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2011 that will expire over the next three years unless production is established within the spacing units covering the acreage prior to the expiration dates:

As of December 31, 2011

2012				2013				2014				Thereafter
Gross		Net		Gross		Net		Gross		Net		Gross		Net
	15,968		12,985		21,856		19,041		12,024		11,913		27,977		25,435

Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities. While we may attempt to secure a new lease upon the expiration of certain of our acreage, there are some third-party leases that may become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date. We have options to extend some of our leases through payment of additional lease bonus payments prior the expiration of the primary term of the leases. Our leases are mainly fee leases with three to five years of primary term. We believe that our leases are similar to our competitors fee lease terms as they relate to primary term and reserved royalty interests.

Drilling Activity

The following table summarizes our operated and non-operated drilling activity for the period from March 8, 2010 (Inception) through December 31, 2010 and the nine months ended September 30, 2011. We drilled no gross or net exploratory wells during the periods covered. "Gross wells" represents the number of wells in which a working interest is owned and "net wells" represents the total of our fractional working interests owned in gross wells.

	Period from March 8, 2010 (Inception) Through December 31, 2010				Nine Months Ended September 30, 2011

	Gross		Net		Gross		Net
Development Wells
Productive		15		9		54		34
Dry		—		—		—		—
Total Wells
Productive		15		9		54		34
Dry		—		—		—		—

Total		15		9		54		34

As of September 30, 2011, we had one gross (one net) operated well awaiting completion.

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Capital Expenditures

The following table provides information regarding our estimated 2011 capital expenditures and our 2012 capital expenditure budget for drilling, completion and recompletion activities:

	Year Ended December 31, 2011		Year Ending December 31, 2012

	(in thousands)
Bone Spring	$	5,305	$	99,978
Wolfberry		75,306		130,526
Conventional Permian		15,418		23,732
Acquisition of leasehold acreage and other property interests		12,282		10,000
Capitalized G&A		1,762		1,856

Total	$	110,073	$	266,092

The ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

Marketing and Transportation

General. We market our oil and natural gas in accordance with standard industry practices utilizing employees and external consultants. The marketing effort is coordinated with our operations group as it relates to the planning and preparation of future drilling programs so that available markets can be assessed and secured. This planning also involves the coordination of procuring the physical facilities necessary to connect new producing wells as efficiently as possible upon their completion.

Oil. We do not transport, refine or process the oil we produce. The majority of our oil is trucked to unloading stations and transported by third parties by pipeline to Cushing, Oklahoma. A small portion of our oil is trucked by third parties to a refinery complex in Southeast New Mexico. We sell the oil we produce under contracts using market-based pricing. This price is then adjusted for differentials based upon delivery location and oil quality.

Natural Gas. During the initial development of our fields we consider all natural gas gathering and delivery infrastructure in the areas of our production and evaluate market options to obtain the best price reasonably available under the circumstances.

The majority of the natural gas we sell is casinghead gas sold at the lease under a percentage of proceeds processing contract. The purchaser gathers our casinghead natural gas in the field where it is produced and transports it via pipeline to a natural gas processing plant where the natural gas liquid products are extracted and sold by the processor. The remaining natural gas product is residue gas, or dry gas, which is placed in residue pipeline systems available in the area. Under our percentage of proceeds contracts, we receive a percentage of the value for the extracted liquids and the residue gas. Each of the liquid products has its own individual market and is therefore priced separately.

A limited portion of our natural gas (typically dry gas production) is gathered and transported by a third party gathering company which transports the production from the production location to the purchaser's mainline. The majority of our dry gas and residue gas is subject to term agreements that are less than three years.

Although we are not currently experiencing any significant involuntary curtailment of our oil or natural gas production, market, economic, transportation and regulatory factors may in the future

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materially affect our ability to market our oil or natural gas production. See "Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production."

Our Principal Customers

We sell our oil and natural gas production principally to marketers and other purchasers that have access to pipeline facilities. In areas where there is no practical access to pipelines, oil is transported to storage facilities by trucks owned or otherwise arranged by the marketers or purchasers. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.

For the nine months ended September 30, 2011, purchases by Sunoco Inc., DCP Midstream LP and Plains Marketing LP accounted for approximately 27%, 12% and 11% of oil and gas sales, respectively. For the period from March 8, 2010 (Inception) through December 31, 2010, purchases by Chesapeake Operating Inc. and Plains Marketing, LP accounted for approximately 31% and 16% of our oil and gas sales, respectively. Purchases by Chesapeake Operating, Inc. were made primarily during the months of April, May and June of 2010, as it was the primary purchaser for production from the assets we purchased in April 2010. Chesapeake Operating, Inc. is no longer the purchaser for any substantial amount of our oil or gas production.

Title to Properties

As is customary in the oil and gas industry, we initially conduct a preliminary 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. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases, and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our revolving credit facility, liens for current taxes, and other burdens which we believe do not materially interfere with the use or affect our carrying value of the properties. See "Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—We may incur losses as a result of title defects in the properties in which we invest."

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 12.5% to 25%, resulting in a net revenue interest to us generally ranging from 75% to 87.5%. 65.4% of our leasehold acreage is held-by-production.

Competition

The oil and natural gas industry is highly competitive in all phases. We encounter competition from other oil and natural gas companies in all areas of operation, from the acquisition of leasing options on oil and natural gas properties to the exploration and development of those properties. Our

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competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do. Such companies may be able to pay more for lease options on oil and natural gas properties and exploratory locations and to define, evaluate, bid for and purchase a greater number of properties and locations than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See "Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel."

Hydraulic Fracturing

We use hydraulic fracturing as a means to maximize the productivity of almost every well that we drill and complete. Hydraulic fracturing is a necessary part of the completion process for our producing properties in Texas and New Mexico because our properties are dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. We are currently conducting hydraulic fracturing activity in the completion of both our vertical and horizontal wells in the Permian Basin. While hydraulic fracturing is not required to maintain 65.4% of our leasehold acreage that is currently held-by-production from existing wells, it will be required in the future to develop the proved non-producing and proved undeveloped reserves associated with this acreage. Nearly all of our proved non-producing and proved undeveloped reserves associated with future drilling, recompletion, and refracture stimulation projects, or nearly all of our total estimated proved reserves as of September 30, 2011, require hydraulic fracturing.

We have and continue to follow applicable industry standard practices and legal requirements for groundwater protection in our operations which are subject to supervision by state and federal regulators (including the Bureau of Land Management on federal acreage). These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by regulatory agencies, and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design essentially eliminates a pathway for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval.

Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Hydraulic fracturing operations would be shut down immediately if an abrupt change occurred to the injection pressure or annular pressure.

Certain state regulations require disclosure of the components in the solutions used in hydraulic fracturing operations. Approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand. The remainder of the constituents in the fracturing fluid are managed and used in accordance with applicable requirements.

Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we dispose of it in a way that minimizes the impact to nearby surface water by disposing into approved disposal or injection wells. We currently do not discharge water to the surface.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read "—Regulation of the Oil and Natural Gas Industry—Environmental, Health and Safety Regulation." For related risks to our stockholders, please read "Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—Federal

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and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays."

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations could result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in material compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations could be, and are frequently are, amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance or non-compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission, or FERC, and the courts. We cannot predict when or whether any such proposals may become effective.

Regulation of transportation of oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls or impose other regulatory requirements in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil (including NGLs) pipeline transportation service and rates under the Interstate Commerce Act. Historically, interstate oil pipeline rates were required to be cost-based. Currently, rates are generally set by reference to an index, although rates may be cost-based, and settlement rates agreed to by all shippers are permitted. In addition, market based rates are permitted in circumstances where a pipeline demonstrates a lack of market power in a given geographical area before FERC. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on the Producer Price Index (PPI), plus or minus a value set by FERC) for transportation rates for oil that allows for an annual increase or decrease in such index-based transportation rates. FERC re-evaluates the currently applicable index for setting such index-based rates every five years. The most recent review resulted in an increase of the index, and thus allows pipelines to increase rates annually by PPI + 3.65%, a larger percentage in addition to PPI for the five year period ending in July 2016 than had previously been in effect (which was PPI + 1%). This most recent index adjustment is currently being challenged by oil pipeline shippers in Federal court, and if successful this challenge could result

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in a decrease in the currently applicable index for annual adjustment of oil pipeline rates, although this is by no means certain or likely.

Intrastate oil pipeline transportation rates typically are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this common carrier standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines' published tariffs. Often the priority of a given shipper in the event of prorationing is dependent upon its history of shipping on a particular pipeline, with higher priority, and thus more capacity, allocated to relatively long standing shippers over new shippers. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors on a given pipeline.

Regulation of transportation and sales of natural gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by FERC under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or NGPA, and regulations issued under those Acts. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at unregulated market prices, it is conceivable that Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open access and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines' historical role as wholesalers of natural gas was eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC does not directly regulate natural gas producers (except with respect to a producer's role as a marketer of natural gas, where FERC does exercise certain limited jurisdiction as discussed below), the current FERC regulatory structure is intended to foster increased competition within all phases of the natural gas industry.

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In 2000, FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised FERC's pricing policy by waiving price ceilings for short-term released capacity, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. FERC-regulated interstate pipelines' tariffs now reflect the policies set forth in Order No. 637 and subsequent orders, and most major aspects of these policies that have been subject to court challenges have been upheld on judicial review. In 2008, FERC issued Order No. 712, which further modified applicable rules related to the release by shippers of interstate pipeline capacity, including through revisions intended to facilitate the use of interstate pipeline capacity by shippers. We cannot predict what action FERC will take on these matters in the future, or whether any such FERC's actions will survive further judicial review. In recent years, FERC has made use of its anti-manipulation authority (discussed below) to extend its jurisdiction to entities such as producers whose role in the interstate natural gas market is typically limited to selling gas or transporting gas on interstate pipelines, including to develop and enforce its policies with respect to capacity release, open season bidding on new pipeline capacity, and related areas of FERC's jurisdiction over interstate pipeline transportation. There are regulatory risks stemming from FERC's aggressive enforcement of its regulations and policies related to pipeline capacity release, and the use of interstate pipeline capacity generally, by shippers like us.

The natural gas industry historically has been very heavily regulated. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission, or the CFTC. See below the discussion of "Other federal laws and regulations affecting our industry—Energy Policy Act of 2005." Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to FERC requirements regarding reporting by anyone who buys or sells more than a de minimis amount of natural gas in the interstate market introduced in Order No. 704, some of our operations may be required to annually report to FERC. Under these FERC reporting requirements, certain natural gas market participants must report information regarding their reporting of transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. However, we do not report our gas sales transactions to price index publishers and therefore we do not have any regulatory requirements associated with reporting to price index publishers. If in the future we decided to report to price index publishers, there would be regulatory requirements to which we would be subject. See below the discussion of "Other federal laws and regulations affecting our industry—FERC Market Transparency Rules."

Gathering services, which occur upstream of jurisdictional transmission services, are not regulated by FERC under the NGA and may be regulated by the states onshore and in state waters. FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase our costs of getting gas to point of sale locations, since the rates charged for such gathering services are not subject to FERC regulation. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

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Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

The failure to comply with these rules and regulations could result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Other federal laws and regulations affecting our industry

Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005, or the EPAct 2005. EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC's civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise

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non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of FERC's NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines.

FERC Market Transparency Rules. On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC's policy statement on price reporting. In October 2011, the U.S. Court of Appeals for the 5th Circuit struck down other FERC regulations designed to promote market transparency that extended new reporting requirements to other entities (in this case certain non-interstate pipelines) historically outside of FERC's jurisdiction. These rules, originally set forth in Order No. 720, were vacated by the court because they were found to exceed the scope of FERC's authority under the NGA.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

Environmental, Health and Safety Regulation

Our exploration, development and production operations are subject to various federal, state and local laws and regulations governing health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and gas drilling and production; restrict the way we handle or dispose of our wastes; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly waste handling, disposal, cleanup and remediation requirements for the oil and gas industry could have a significant impact on our operating costs.

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The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on our financial condition or results of operations, there is no assurance that this trend will continue in the future.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous substances and waste

The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these "responsible persons" may be subject to joint and several, strict 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. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes.

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial operations to prevent future contamination.

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Air emissions

Climate change

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA have allowed the agency to proceed with the adoption and implementation of regulations restricting emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Among other things, EPA regulations now require specified large greenhouse gas emitters in the United States including companies in the energy industry to annually report those emissions. Additionally, starting in 2011, new sources or modifications of existing sources of significant quantities of greenhouse gas emissions are required to obtain permits—and to use best available control technology to control those emissions—pursuant to the Clean Air Act as a prerequisite to the development of that emissions source. While these regulations have not to date materially affected the company, such regulations may over time require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce.

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able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

Water discharges

The Federal Water Pollution Control Act, as amended, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the U.S. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

The Oil Pollution Act of 1990, OPA, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A "responsible party" under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the U.S.

Endangered Species Act

The federal Endangered Species Act, or ESA, restricts activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

As a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the ESA. The law prohibits the harming of endangered or threatened species, provides for habitat protection, and imposes stringent penalties for noncompliance. One of the species being considered for listing pursuant to the settlement is the Dunes Sagebrush Lizard. Some of our operations are located in or near areas that may potentially be designated as Dunes Sagebrush Lizard habitat. If the lizard is classified as an endangered species, our operations in any area that is designated as the lizard's habitat may be limited, delayed or, in some circumstances, prohibited, and we may be required to comply with expensive mitigation measures intended to protect the lizard and its habitat. Under the September 9, 2011 settlement, the U.S. Fish and Wildlife Service is required to begin issuing decisions with respect to the 250 candidate species by the end of 2011. In December 2011, the U.S. Fish and Wildlife Service announced that it would delay its decision on whether to list the Dunes Sagebrush Lizard as an endangered species for six months to provide for additional time to study the issue. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

Employee health and safety

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whose purpose is to

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protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Other laws

The federal Energy Policy Act of 2005 amended the Underground Injection Control, or UIC, provisions of the federal Safe Drinking Water Act, or the SDWA, to exclude hydraulic fracturing from the definition of "underground injection." However, the U.S. Senate and House of Representatives are currently considering bills entitled, the Fracturing Responsibility and Awareness of Chemicals Act, or the FRAC Act, to amend the SDWA to repeal this exemption. If enacted, the FRAC Act would amend the definition of "underground injection" in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceeding. In addition, we are not aware of any material legal or governmental proceedings contemplated to be brought against us.

Employees

As of December 31, 2011, we employed 62 people, including 6 employees in geology, 10 employees in operations and engineering, 14 employees in accounting and finance, 7 employees in land, 23 employees in the field and 2 employees in administration. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. From time to time we utilize the services of independent contractors to perform various field and other services.

Offices

We currently lease approximately 11,814 square feet of office space in Austin, Texas at 1122 South Capital of Texas Highway, Suite 325, where our principal offices are located. The lease for our Austin office expires in November 2013. We also have a lease for a field office in Midland, Texas.

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MANAGEMENT

Directors and Executive Officers

The following table sets forth information regarding our directors and executive officers as of January 20, 2012. There are no family relationships among any of our directors or executive officers.

Name		Position

Michael A. Wichterich	44	President and Director
James D. Keisling	64	Vice President Engineering
Gabriel L. Ellisor	38	Chief Financial Officer
Barry S. Smith	59	Vice President Exploration
Robert M. Tichio	34	Director

The following table sets forth information regarding other key employees as of January 20, 2012.

Name		Position

Bryant Williams	35	Manager of Business Development
Tim L. Kane	51	Land Manager
Thomas J. Stratton	60	Acting Operations Manager
Michael W. Daniel	64	Operations Engineer
Kirk Orgeldinger	35	Controller

Set forth below is the description of the backgrounds of our directors, executive officers and other key employees.

Michael A. Wichterich has served as our President and one of our directors since our inception in March 2010 and has 20 years of experience in the oil and gas industry. From 2004 to 2008, he served as Chief Financial Officer of Texas American Resources, which operated wells throughout Texas, Colorado and Wyoming. Prior to working for Texas American Resources, he was at Mariner Energy Inc. gaining experience at both offshore Gulf of Mexico and West Texas projects. During his time at Mariner from 1998 to 2001, he served as Controller and later as Chief Financial Officer. Before joining Mariner, Mr. Wichterich worked for nine years in the energy auditing practices of PricewaterhouseCoopers LLP. Mr. Wichterich is a Certified Public Accountant in the State of Texas and is a graduate of the University of Texas.

James D. Keisling has served as our Vice President of Engineering since our inception in March 2010 and has 41 years of experience in the oil and gas industry. Previously, Mr. Keisling served as Senior Reservoir Engineer with W.D. Von Gonten & Associates from February 2009 through March 2010. Prior to joining W.D. Von Gonten, Mr. Keisling was Senior Vice President of Operations for Texas American Resources from 2006 to 2008. As Senior Vice President of Operations, he was responsible for drilling and production operations in Texas, Colorado and Wyoming. Mr. Keisling served as Vice-President of Production for Edge Petroleum Corp. from 2000 to 2006, where he was responsible for drilling, production and reservoir engineering and operations in New Mexico, Texas, Michigan, Louisiana and Mississippi. Prior to joining Edge Petroleum, Mr. Keisling was Production Operations Manager with Ocean Energy following its merger with Seagull Energy in 1999. He joined Seagull Energy as Production Manager in 1991 as a result of a property acquisition from Mesa Limited Partnership. Prior to joining Mesa Limited Partnership in 1989, his energy experience includes positions in management and engineering with PanCanadian Petroleum, Edwin L. Cox and Mitchell Energy, all located in Denver. Mr. Keisling began his career with Texaco in Midland, Texas in 1970. Mr. Keisling received a B.S. in Civil Engineering from New Mexico State University in 1970. He is a Registered Professional Engineer in the state of Texas and an active member of SPE.

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Gabriel L. Ellisor has served as our Chief Financial Officer since May 2010. Prior to joining Three Rivers, Mr. Ellisor was a principal at Rivington Capital Advisors, a boutique investment banking firm that specializes in raising private capital and providing merger and acquisition advisory services for the energy and production sector. He originally joined Rivington in 2008 to assist in the establishment of Rivington's Houston office. Mr. Ellisor has approximately 16 years of experience in the finance sector of the oil and gas industry, including holding various positions at First Interstate Bank, Wells Fargo, and BNP Paribas. During his tenure at BNP Paribas from June 1997 to May 2008, Mr. Ellisor was responsible for arranging, structuring and underwriting various financings, including revolving bank facilities, institutional term loans and high yield offerings. Mr. Ellisor earned a B.B.A., with a major in Finance, from Texas Christian University.

Barry S. Smith has served as our Vice President of Geoscience and Land since our inception in March 2010. Previously, Mr. Smith served with Texas American Resources Company from June 2007 to March 2009 as Chief Geoscientist involved with the application of technological solutions to risk management on both domestic and international projects. He worked with the amplitude analysis group at Weinman Geoscience from 2000 to 2007 where he was involved with AVO, inversion and neural network technologies. Prior to joining Weinman Geoscience, he was at Mobil Oil Corporation for 20 years where he held a variety of positions in the New Business Development Group. Mr. Smith has applied his project and process management and geological expertise to numerous basins of the Asia/Pacific region, West Africa, and Brazil as well as the GOM shelf, South and East Texas as well as the Texas Panhandle and Permian Basin. Mr. Smith earned a B.S. in Geology from Indiana University. He is a registered professional geophysicist in the State of Texas and member of SEG, AAPG.

Robert M. Tichio has served as one of our directors since our inception in March 2010. Mr. Tichio currently serves as a Managing Director of Riverstone, our sponsor, where he has been since 2006. He is also currently on the boards of directors or equivalent of; CanEra Resources Inc., a Calgary, Canada-based oil and gas, acquisition and development company; Titan Operating LLC, an oil and gas company focused on acquisitions and development in the Barnett Shale play in the Fort Worth Basin; Eagle Energy of Oklahoma, a Tulsa-based oil gas company active in the Mid-Continent; Gibson Energy Inc., a Calgary based provider of midstream services to the oil and gas industry; Northern Blizzard Resources Inc., a Calgary based oil and gas, acquisition and development company; Barra Energia do Brasil Petróleo e Gás Ltda., a Rio de Janeiro, Brazil-based oil and gas, acquisition and development company; and Riverstone Vantage Pipeline US LP and Riverstone Vantage Pipeline Canada LP, a Calgary based natural gas and liquids midstream energy company. Prior to joining Riverstone, Mr. Tichio was an Associate in the Principal Investment Area of Goldman, Sachs & Co. He began his career at JPMorgan Chase Bank, N.A. in the Mergers and Acquisitions group. Mr. Tichio received his A.B. from Dartmouth College and his M.B.A. from Harvard Business School.

Bryant Williams joined us in December 2010 as Manager of Business Development. Mr. Williams has been in the oil and gas business for 14 years and has held various engineering and management positions with Mobil Oil, ExxonMobil, XTO Energy, and Texas American Resources. Prior to joining Three Rivers, he served as the Vice President of Engineering for Texas American Resources from May 2006 to September 2010 where he oversaw all aspects of reservoir engineering. From September 2001 to May 2006, he served as a reservoir engineer at XTO Energy, working properties in Arkansas, Oklahoma, and Kansas. He also assisted in the evaluation of multiple acquisitions opportunities in Texas, Oklahoma, Kansas, Arkansas, and New Mexico. Beginning in May 1998, Mr. Williams worked for Mobil Oil as an operations engineer in West Texas, and following the merger with Exxon, he served until September 2001 as a senior reservoir engineer in South Texas . Mr. Williams earned a B.S. in Petroleum Engineering from Texas Tech University in 1998 and a M.B.A. from Texas Christian University in 2005.

Tim L. Kane joined us in April 2010 as Land Manager. From 2002 to 2009, he was a Partner in Legend Petroleum, generating prospects in South Louisiana and South Texas. From 1992 to 2002 he

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was a Landman with Torch Energy Advisors focusing on Acquisitions and Divestitures throughout the lower 48 producing basins. Prior to his work at Torch Mr. Kane held positions at Swift Energy from 1990 to 1992 and Susman Godfrey from 1986 to 1990, and he was an independent landman in East Texas for several clients. He attended the University of Houston where he obtained a B.S. in Petroleum Land Management in 1984.

Thomas J. Stratton joined us in December 2010 as acting Operations Manager and has 37 years of experience in the oil and gas industry. Since 1992, Mr. Stratton has been an independent operator/producer in Texas, New Mexico and Louisiana. His primary focus in the last five years has been the Permian Basin, concentrating on re-completing and producing deeper gas wells. Previously, he worked for several independent companies in North Texas, including Bettis Boyle & Stovall from 1977 to 1980 and Littlepage Oil Properties from 1987 to 1992, participating in numerous drilling, completion and production operations in the Permian, Eastern Shelf and Fort Worth Basins. Mr. Stratton began his career in the oil and gas industry in 1974 with Texaco Inc. in Midland, Texas, where he worked until 1977. He designed and supervised installation of several waterflood facilities in the Permian Basin, and worked in several of their production field offices, as well as the district office. Mr. Stratton received a B.S. in Civil Engineering from Texas A&M University in 1974. He has been involved in several oil and gas organizations, including TIPRO, West Central Texas O&G, North Texas O&G, and SPE.

Michael W. Daniel joined us in June 2011 as Operations Engineer and currently manages drilling operations. From 2001 to 2011, he worked as an independent engineering consultant supervising drilling, completion and workover activities. In addition, he has over 30 years of experience with various major and independent operators, including Coastal Oil & Gas, Natomas, N.A., and Cities Service. Mr. Daniel has managed operations throughout North America, the Gulf of Mexico and internationally. He graduated from Texas A&M University with a B.S. in Mechanical Engineering and is a Registered Professional Engineer in Texas.

Kirk Orgeldinger joined us in March 2011 as Controller. Prior to joining us, he spent 13 years in the aerospace and defense industry, most recently as a finance director for BAE Systems where he worked from 1998 to 2011. Mr. Orgeldinger has significant training and experience in accounting and business systems, in financial management, and in leading finance organizations. He is a graduate of Saint Anselm College in Manchester, New Hampshire, where he earned his B.S. in Business Administration in 1998, and of Boston College in Chestnut Hill, Massachusetts, where he earned his M.B.A. in 2002.

Board of Directors

Our board of directors currently consists of two members, Michael A. Wichterich, our President, and Robert M. Tichio, a designee of Riverstone, which we expect will control a majority of the voting power of our outstanding common stock through Three Rivers Holdings following this offering. We expect to increase the number of members on our board of directors in connection with the completion of this offering.

We intend to appoint independent directors to our board of directors contemporaneously with and following the completion of this offering. We also expect that our board will review the independence of our current directors using the independence standards of the NYSE.

In evaluating director candidates, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board's ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

Following the completion of this offering, our directors will be divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2013, 2014 and 2015, respectively. At each annual meeting of stockholders held after

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the initial classification, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.

Status as a "Controlled Company"

Upon completion of this offering, we expect to be a "controlled company" under NYSE corporate governance standards. A controlled company need not comply with NYSE corporate governance rules that require a listed company's board of directors to have a majority of independent directors and independent compensation and nominating and governance committees. We intend to avail ourselves of the controlled company exception under the NYSE corporate governance standards. Notwithstanding our status as a controlled company, we will remain subject to the NYSE corporate governance standard that requires us to have an audit committee composed entirely of independent directors. As a result, we must have at least one independent director on our audit committee by the date our common stock is listed on the NYSE, at least two independent directors within 90 days of the listing date and at least three independent directors within one year of the listing date.

If and when we cease to be a controlled company, our board of directors will be required to have a compensation committee and a nominating and governance committee, each with at least one independent director. Within 90 days of ceasing to be a controlled company, we will be required to have a majority of independent directors on each of a compensation committee and a nominating and governance committee, and within one year of ceasing to be a controlled company, a majority of our board of directors and each member of our compensation committee and nominating and governance committee must be independent directors.

Committees of the Board of Directors

Upon the conclusion of this offering, we intend to have an audit committee, and in the event we are no longer a controlled company, a compensation committee and a nominating and governance committee, of our board of directors, and may have such other committees as the board of directors shall determine from time to time. We anticipate that each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

We will establish an audit committee prior to the completion of this offering. We will rely on the phase-in rules of the SEC and NYSE with respect to the independence of our audit committee. These rules permit us to have an audit committee that has one member that is independent upon the effectiveness of the registration statement of which this prospectus forms a part and the listing of our common stock on the NYSE, a majority of members that are independent within 90 days thereafter and all members that are independent within one year thereafter.

Our audit committee will oversee, review, act on and report to our board of directors on various auditing and accounting matters, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to our independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee will oversee our compliance programs related 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 NYSE standards.

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Compensation Committee

Because we will be a "controlled company" within the meaning of the NYSE corporate governance standards, we will not be required to, and will not, have a compensation committee.

If and when we are no longer a controlled company, we will be required to establish a compensation committee. We anticipate that, subject to the transition rules described under "—Status as a 'Controlled Company"' above, the compensation committee will consist of three 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 NYSE standards.

Nominating and Governance Committee

Because we will be a "controlled company" within the meaning of the NYSE corporate governance standards, we will not be required to, and will not, have a nominating and governance committee. While we are a controlled company, our board of directors will identify and evaluate potential candidates for nomination as a director.

If and when we are no longer a controlled company, we will be required to establish a nominating and governance committee. We anticipate that, subject to the transition rules described under "—Status as a 'Controlled Company"' above, the nominating and governance committee will consist of three 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 governance committee, we expect to adopt a nominating and governance committee charter defining the committee's primary duties in a manner consistent with the rules of the SEC and NYSE standards.

Compensation Committee Interlocks and Insider Participation

Because we will be a "controlled company" within the meaning of the NYSE corporate governance standards, we will not be required to, and will not, have a compensation committee. None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board. No member of our board is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Code of Business Conduct and Ethics

Our board of directors will adopt a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Our code of business conduct and ethics will be available on our corporate website at www.3rnr.com on or prior to the completion of this offering.

Corporate Governance Guidelines

Our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of the NYSE. Our code of corporate governance guidelines will be available on our corporate website at www.3rnr.com on or prior to the completion of this offering.

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EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

This compensation discussion and analysis, or CD&A, provides information about our compensation objectives and policies for our executive officers, and is intended to place in perspective the information contained in the executive compensation tables that follow this discussion. This CD&A provides a general description of our compensation program and specific information about its various components.

Although this CD&A focuses on the information in the tables below and related footnotes, as well as the supplemental narratives relating to the last completed fiscal year, we also describe compensation actions taken after the end of the last completed fiscal year to the extent such discussion enhances the understanding of our executive compensation disclosure. Contemporaneously with this offering, we anticipate making adjustments to our compensatory practices to be utilized in 2012 and later years that we believe will be more appropriate for a company with public stockholders. This CD&A discusses the compensatory practices in place during 2011 and highlights changes we expect to implement upon the consummation of this offering.

Compensation Program Philosophy and Objectives

As a private company, historically our compensation arrangements with our executive officers have been determined on an individual basis, based on negotiations between the individual and our President, in consultation with Riverstone. Our President negotiated his own compensation directly with Riverstone. All of our executive officers have entered into employment agreements, which we expect will be replaced by new agreements in connection with the closing of this offering. Although we have not historically had a formal compensation committee, our President and Riverstone's representatives on the board of Three Rivers Holdings currently operate as an informal compensation committee.

Following the completion of this offering, we expect to be a "controlled company" within the meaning of the NYSE corporate governance standards. As long as we are a controlled company, we will not be required to have a compensation committee composed entirely of independent directors, and we intend to continue to rely on our informal compensation committee process. Future independent directors that we add to our board may be included in this process.

Our board of directors will be required to have a compensation committee with at least one independent director upon ceasing to be a controlled company. Within 90 days of ceasing to be a controlled company, we will be required to have a compensation committee with a majority of independent directors, and within one year of ceasing to be a controlled company, our compensation committee would have to be composed entirely of independent directors.

Our company has not engaged a compensation consultant in the past. In anticipation of implementing a compensation structure after becoming a public company that includes certain performance metrics and targets commonly used by public companies in our industry to set compensation for executive officers, we plan to retain a compensation consultant to assist with future development of our compensation strategy, to annually review the competitiveness of our executive compensation programs and to provide recommendations for changes or adjustments to these programs. It is anticipated that the compensation consultant will begin its engagement during the first quarter of 2012. As of this time, however, we have not determined the specific nature and scope of the compensation consultant's role in determining or recommending the amount or form of compensation for our named executive officers.

In connection with becoming a public company, we intend to perform at least annually a strategic review of our named executive officers' overall compensation package to determine whether it provides

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adequate incentives and motivation and whether it adequately compensates our named executive officers relative to comparable officers in other companies with which we compete for executives.

Elements of our Compensation and Why We Pay Each Element

Compensation of our executive officers has historically included the following key components:

•: Base salaries,
•: Annual discretionary cash bonus awards, and
•: Long term incentives in the form of Series B Units in Three Rivers Holdings.

Base Salary. Base salary is the fixed annual compensation we pay to each Named Executive Officer for performing specific job responsibilities. It represents the minimum income a Named Executive Officer may receive in any year. Contemporaneously with the consummation of this offering, we expect to implement salary increases for our Named Executive Officers in order to bring their base salaries in line with similarly titled executives at other companies within our peer group. We believe that paying base salaries close to the market median is necessary to achieve our compensation objectives of attracting and retaining executives with the appropriate abilities and experience required to lead us.

Cash Bonuses. We utilize discretionary cash bonuses to reward our Named Executive Officers on a yearly basis. Historically, cash bonuses have been determined based on both the overall success of the Company as well as each Named Executive Officers' individual contribution and performance. While we intend to institute performance targets in the future that are tied to the level of cash bonuses awarded each year, historically our cash bonuses have been determined on a subjective basis. In the future, we believe that the payment of cash bonuses upon the achievement of performance targets will be necessary to achieve our compensation objectives of motivating and rewarding our named executive officers, as well as aligning the interests of our named executive officers and stockholders with the performance of our company on a short-term basis.

Series B Units. As a private company, we historically have offered long-term incentives to our executive officers through grants of Series B Units in Three Rivers Holdings. The Series B Units are intended to create incentives for the management team to reach a return hurdle, defined as the amount of aggregate capital contributions plus a preferred rate of return on the capital contributions to be paid to holders of Series A Units. These Series B Units represent an interest in the future profits of Three Rivers Holdings and are intended to be treated as "profits interests" for federal income tax purposes. They are subject to both time-vesting requirements and to meeting the return hurdle. The Series B Units participate in a percentage of the total distributions to all equity holders after the return hurdle has been reached.

The Series B Units vest in 20% increments on each of the first, second and third anniversaries of the date they were granted. Unvested Series B Units vest fully upon the occurrence of a change of control of Three Rivers Holdings, an approved sale of Three Rivers Holdings, certain liquidation events with respect to Three Rivers Holdings or an initial public offering that results in the achievement of the return hurdle described above for the holders of the Series A Units.

To create incentives for our executive officers to continue to grow our company, we are in the process of evaluating a formal long-term incentive plan. We intend to adopt the formal plan in connection with the completion of this offering. We believe that having an equity component to our compensation program is vital to align our executive officers' interests with our stockholders' long-term interests through shared ownership. We expect that our independent compensation consultant will help us design the long-term incentive plan by providing a survey of the main components of long-term incentive plans for similarly-situated public companies.

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Other Benefits. Our named executive officers are eligible to participate in all of our employee benefit plans, such as medical, dental, group life, disability, and accidental death and dismemberment insurance and our Simple IRA plan, in each case on the same basis as other employees, subject to applicable law. We also provide vacation and other paid holidays to all employees, including our named executive officers, which are comparable to those provided at peer companies.

Stock Ownership Guidelines

Stock ownership guidelines have not been implemented for our Named Executive Officers or directors. We will continue to periodically review best practices and reevaluate our position with respect to stock ownership guidelines.

Securities Trading Policy

We plan to implement a securities trading policy that will provide that executive officers, including the Named Executive Officers, and our directors, may not, among other things, purchase or sell puts or calls to sell or buy our stock, engage in short sales with respect to our stock, buy our securities on margin, or otherwise hedge their ownership of our stock. Our policy is expected to provide that the purchase or sale of stock by our executive officers and directors may only be made during certain windows of time and under the other conditions contained in our policy.

Employment Agreements

Each of our Named Executive Officers entered into an employment contract in conjunction with his initial employment with Three Rivers Operating Company LLC. Each employment contract has an initial two-year term and automatically renews and extends for a period of 12 months, unless written notice of non-renewal is delivered from either party to the other not less than sixty days prior to the expiration of the then-existing term. Mr. Ellisor's agreement was effective on March 10, 2010 and the agreements of Messrs. Wichterich, Keisling and Smith were effective on March 11, 2010. Each employment contract was executed with substantially similar terms and conditions, with the exceptions of each Named Executive Officer's title and job description and individual salary, as well as signing bonuses paid to Messrs. Ellisor and Smith ($25,000 and $15,000, respectively) and an allowance of up to $20,000 for reimbursement of Mr. Ellisor's moving expenses. Each contract provides for an annual cash bonus payment of up to 100% of each individual's salary and 20 days of paid vacation. The amounts paid to each Named Executive Officer in 2011 are set forth on the Summary Compensation Table below. The contracts contain general employment provisions, including, but not limited to, provisions for termination, either by cause of for convenience, an employee's right to termination for Good Reason or for convenience, conflicts of interest, confidentiality, and non-competition. If any of our Named Executive Officers is terminated by us for convenience or leaves for Good Reason (after providing us with notice and an opportunity to cure the condition giving rise to Good Reason), he is eligible for 18 months of severance pay upon signing a form releasing us from liability and to the extent that the executive abides by confidentiality, non-competition and protection of intellectual property provisions of the employment agreement. Good Reason is defined as a material breach of the agreement by us or relocation of the executive's principal place of employment by more than 100 miles from the principal place of employment on the effective date of the employment agreement. In conjunction with the proposed offering, we anticipate that all employment contracts will be cancelled and it is anticipated that each Named Executive Officer will enter into a new employment contract on terms similar to other comparably sized companies in our industry.

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Executive Compensation

Summary Compensation Table

The following table shows information concerning the annual compensation for services provided to us by our Named Executive Officers during the fiscal year ended December 31, 2011.

Name and Principal Position	Salary	Bonus	All Other Compensation	Total

Michael A. Wichterich	$	$	$	$
President
James D. Keisling
Vice President Engineering
Gabriel L. Ellisor
Chief Financial Officer
Barry S. Smith
Vice President Exploration

Other than our Simple IRA Plan, we do not have any plan that provides for payments or other benefits at, following, or in connection with, retirement.

Grants of Plan-Based Awards

The following table provides information concerning each award of Series B Units of Three Rivers Holdings granted to our named executive officers during the fiscal year ended December 31, 2011.

Name		Grant Date			Unit Awards			Grant Date Fair Value of Unit Awards

Michael A. Wichterich								$
James D. Keisling
Gabriel L. Ellisor
Barry S. Smith

Outstanding Equity Awards at Fiscal Year-End

The following table provides information concerning unvested Series B Units of Three Rivers Holdings held by our named executive officers as of December 31, 2011.

Name		Number of Units That Have Not Vested			Market Value of Units That Have Not Vested

Michael A. Wichterich					$
James D. Keisling
Gabriel L. Ellisor
Barry S. Smith

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Units Vested in Fiscal Year

The following table provides information concerning Series B Units of Three Rivers Holdings that vested during the fiscal year ended December 31, 2011 for our named executive officers.

Name		Number of Units Acquired on Vesting			Value Realized on Vesting

Michael A. Wichterich					$
James D. Keisling
Gabriel L. Ellisor
Barry S. Smith

Non-Qualified Deferred Contribution and Other Non-Qualified Compensation Plans

We do not have any plan that provides for the deferral of compensation on a basis that is not tax qualified.

Director Compensation

Our board of directors believes that attracting and retaining qualified non-employee directors will be critical to the future value growth and governance. Our board of directors also believes that the compensation package for our non-employee directors should require a significant portion of the total compensation package to be equity-based to align the interests of these directors with our stockholders.

We intend to conduct a review of our planned director compensation with our compensation consultant prior to the proposed offering, but believe that the key components of our director compensation will be as follows:

•: an annual cash retainer fee and cash payments for each board and committee meeting attended;
•: an initial equity award of restricted stock; and
•: an annual equity award of restricted stock.

Directors who are also our employees will not receive any additional compensation for their service on the board of directors.

We expect that each director will be reimbursed for (i) travel and miscellaneous expenses to attend meetings and activities of our board of directors or its committees; (ii) travel and miscellaneous expenses related to such director's participation in our general education and orientation program for directors; and (iii) travel and miscellaneous expenses for each director's spouse who accompanies a director to attend meetings and activities of our board of directors or any of our committees.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Since March 8, 2010, the date of our inception, there has not been, nor is there currently proposed, any transaction or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our voting securities, or any member of the immediate family of any of the foregoing persons, had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in "Executive Compensation," and the transactions described or referred to below.

Corporate Reorganization

In connection with our corporate reorganization, we will engage in certain transactions with Three Rivers Holdings. Please see "Corporate Reorganization" for a description of these transactions.

Historical Transactions with Three Rivers Holdings and Riverstone

Since our inception, we have from time to time issued membership interests to our parent company, Three Rivers Holdings, in exchange for capital contributions from our parent. Capital contributions for the period from inception to December 31, 2010 were $270.7 million. Our parent made no capital contributions to us in the nine months ended September 30, 2011. We did not make any distributions to our parent company in the period from inception to December 31, 2010 and made distributions to our parent in the aggregate amount of $60.1 million in the nine months ended September 30, 2011. Three Rivers Holdings is owned by Riverstone and members of our management. See "Principal and Selling Stockholders."

In connection with each of its capital contributions to Three Rivers Holdings, Riverstone receives a placement fee in an amount equal to 2% of its capital contributions. Such placement fees are remitted by us to Riverstone or its designee. Placement fees for the year ended December 31, 2010 were $5.5 million. At the end of each fiscal year, we also pay to Riverstone an annual management fee equal to the greater of $500,000 or 1% of EBITDA. The management fee paid for the period from inception to December 31, 2010 was $405,479. Following the completion of this offering, we will not pay Riverstone any management fees.

Registration Rights Agreement

In connection with the closing of our corporate reorganization and this offering, we expect to enter into a registration rights agreement with Three Rivers Holdings pursuant to which we will agree to register the resale of shares of our common stock held by Three Rivers Holdings or its permitted transferees under certain circumstances.

Procedures for Approval of Related Person Transactions

A "related party transaction" is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeded or exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A "related person" means:

•: any person who is, or at any time during the applicable period was, one of our executive officers or directors;
•: any person who is known by us to be the beneficial owner of more than 5.0% of our outstanding common stock;

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•: any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law, or any person (other than a tenant or employee) sharing the household; and
•: any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10.0% or greater beneficial ownership interest.

We expect that our board of directors will adopt a written related party transactions policy prior to the completion of this offering. Pursuant to this policy, we expect that the audit committee will review all material facts of all related party transactions and either approve or disapprove entry into the related party transaction, subject to certain limited exceptions. We anticipate that the policy will provide that, in determining whether to approve or disapprove entry into a related party transaction, the audit committee shall take into account, among other factors, the following: (1) whether the related party transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (2) the extent of the related person's interest in the transaction. Further, we expect the policy to require that all related party transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations.

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CORPORATE REORGANIZATION

Three Rivers Operating Company Inc. is a Delaware corporation that was formed for the purpose of making this offering. Pursuant to the terms of our corporate reorganization that will be completed concurrently with the closing of this offering, Three Rivers Operating Company Inc. will become a holding company for Three Rivers Operating Company LLC. Therefore, investors in this offering will only receive, and this prospectus only describes the offering of, shares of common stock of Three Rivers Operating Company Inc. Our business will continue to be conducted through Three Rivers Operating Company LLC, as a wholly owned subsidiary of Three Rivers Operating Company Inc. See "Description of Capital Stock" for additional information regarding the terms of our amended and restated certificate of incorporation and amended and restated bylaws as will be in effect upon the closing of this offering.

Our reorganization will consist of a contribution by Three Rivers Holdings of all of the outstanding membership interests in Three Rivers Operating Company LLC to its wholly owned subsidiary, Three Rivers Operating Company Inc., in exchange for additional shares of common stock of Three Rivers Operating Company Inc. As a result of this contribution, Three Rivers Operating Company LLC will become a wholly owned subsidiary of Three Rivers Operating Company Inc. In this prospectus we refer to this transaction as our "reorganization" or "corporate reorganization." Following the offering, the stockholders of Three Rivers Operating Company Inc. will consist of purchasers in this offering ( %) and Three Rivers Holdings ( %), assuming no exercise of the underwriters' option to purchase additional shares.

In connection with our reorganization, an estimated net deferred tax liability of approximately $ will be established for differences between the book and tax basis of our assets and liabilities, and a corresponding expense will be recorded to net income from continuing operations.

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PRINCIPAL AND SELLING STOCKHOLDERS

As a result of the corporate reorganization that will be completed simultaneously with the closing of this offering, Three Rivers Operating Company LLC will become a wholly owned subsidiary of Three Rivers Operating Company Inc.

The table below sets forth information regarding the beneficial ownership of the common stock of Three Rivers Operating Company Inc. as of , 2012, on a pro forma basis giving effect to the reorganization, by (1) each beneficial owner of more than 5% of our outstanding common stock, (2) each director of Three Rivers Operating Company Inc., (3) each of our Named Executive Officers, and (4) all executive officers and directors as a group. As of , 2012, on the basis stated above, there were shares of our common stock outstanding. The table also sets forth information regarding the shares of our common stock that will be offered and sold by the selling stockholder in this offering. The ownership percentages after the offering are based on the issuance and sale by us of shares of common stock in the offering, and the sale by the selling stockholder of outstanding shares of common stock in the offering, assuming no exercise of the underwriters' option to purchase additional shares. After the offering, there will be shares of our common stock outstanding.

Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Except as indicated by footnote, to our knowledge the persons named in the table below have sole voting and investment power with respect to all common stock shown as beneficially owned by them, subject to community property laws where applicable. Unless otherwise indicated, the address for each director and executive officer listed is: c/o 1122 South Capital of Texas Highway, Suite 325, Austin, Texas 78746.

								Shares of Common Stock Offered Pursuant to Option to Purchase Additional Shares

	Shares of Common Stock Beneficially Owned Prior to the Offering			Shares of Common Stock		Shares of Common Stock Beneficially Owned After The Offering
				Being Offered
Name of Beneficial Owner	Number	Percentage		Being Offered		Number	Percentage	Number
*Selling Stockholder and 5% Holder*
Three Rivers Natural Resource Holdings LLC			%
*Directors and Executive Officers*
Michael A. Wichterich			%		—
James D. Keisling			%		—
Gabriel L. Ellisor			%		—
Barry S. Smith			%		—
Robert M. Tichio			%		—
*All directors and executive officers as a group* (five persons)			%

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The following table sets forth the beneficial ownership of Three Rivers Holdings as of , 2012:

	Number of Series A Units Beneficially Owned					Number of Series B Units Beneficially Owned

Name of Beneficial Owner	Number		Percentage			Number		Percentage
R/C IV TR Holdings, L.P.(1)		276,653,941		99.85	%		—		—
Michael A. Wichterich		200,000		0.07	%		250,000		30.30	%
James D. Keisling		100,000		0.03	%		125,000		15.15	%
Gabriel L. Ellisor		50,000		0.02	%		125,000		15.15	%
Barry S. Smith		75,000		0.03	%		125,000		15.15	%
Robert M. Tichio		—		—			—		—

(1)

R/C IV TR Holdings, L.P. is the record holder of 276,653,941 Series A Units of Three Rivers Holdings. Riverstone/Carlyle Energy Partners IV, L.P. is the general partner of R/C IV TR Holdings, L.P.; however, its general partner, R/C Energy GP IV, LLC, exercises investment discretion and control over the shares held by R/C IV TR Holdings, L.P. Accordingly, R/C Energy GP IV, LLC and Riverstone/Carlyle Energy Partners IV, L.P. may each be deemed to share beneficial ownership of the Series A Units of Three Rivers Holdings owned of record by R/C IV TR Holdings, L.P.

For a description of our relationships with the Riverstone, please read "Certain Relationships and Related Party Transactions."

R/C Energy GP IV, LLC is managed by an eight person managing board. Pierre F. Lapeyre, Jr., David M. Leuschen, Andrew W. Ward, Michael B. Hoffman, Lord John Browne, N. John Lancaster, Daniel A. D'Aniello and Edward J. Mathias, as the members of the managing board of R/C Energy GP IV, LLC, may be deemed to share beneficial ownership of the shares beneficially owned by R/C IV TR Holdings, L.P. Such individuals expressly disclaim any such beneficial ownership. The business address of R/C IV TR Holdings, L.P. is c/o Riverstone Holdings LLC, 712 Fifth Avenue, 51st Floor, New York, NY 10019.

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DESCRIPTION OF CAPITAL STOCK

Upon completion of this offering, the authorized capital stock of Three Rivers Operating Company Inc. will consist of shares of common stock, $0.01 par value per share, of which shares will be issued and outstanding, and shares of preferred stock, $0.01 par value per share, of which no shares will be issued and outstanding.

The following summary of the anticipated capital stock and amended and restated certificate of incorporation and amended and restated bylaws of Three Rivers Operating Company Inc. does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our amended and restated certificate of incorporation and amended and restated bylaws, which will be filed as exhibits to the registration statement of which this prospectus is a part.

Common Stock

Except as provided by law or in a preferred stock designation, holders of common stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders, will have the exclusive right to vote for the election of directors and do not have cumulative voting rights. Except as otherwise required by law, holders of common stock, as such, are not entitled to vote on any amendment to the certificate of incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to the amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the General Corporation Law of the State of Delaware. Subject to preferences that may be applicable to any outstanding shares or series of preferred stock, holders of common stock are entitled to receive ratably such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. All outstanding shares of common stock are fully paid and non-assessable, and the shares of common stock to be issued upon completion of this offering will be fully paid and non-assessable. The holders of common stock have no preferences or rights of conversion, exchange, pre-emption or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock. In the event of any liquidation, dissolution or winding-up of our affairs, holders of common stock will be entitled to share ratably in our assets that are remaining after payment or provision for payment of all of our debts and obligations and after liquidation payments to holders of outstanding shares of preferred stock, if any.

Preferred Stock

Our amended and restated certificate of incorporation will authorize our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

Anti-Takeover Effects of Provisions of Our Certificate of Incorporation, Our Bylaws and Delaware Law

Some provisions of Delaware law and our amended and restated certificate of incorporation and our amended and restated bylaws, will contain provisions that could make the following transactions

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more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise; or removal of our incumbent directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

Opt Out of Section 203 of the Delaware General Corporation Law

In our amended and restated certificate of incorporation, we will elect not to be subject to the provisions of Section 203 of the Delaware General Corporation Law ("DGCL") regulating corporate takeovers. In general, those provisions prohibit a Delaware corporation, including those whose securities are listed for trading on the NYSE, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

•: the transaction is approved by the board of directors before the date the interested stockholder attained that status;
•: upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or
•: on or after such time the business combination is approved by the board of directors and authorized at a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws

Among other things, upon the completion of this offering, our amended and restated certificate of incorporation and amended and restated bylaws will:

•: establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary date of the annual meeting for the preceding year. Our amended and restated bylaws specify the requirements as to form and content of all stockholders' notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting;
•: provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

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•

provide that the authorized number of directors may be changed only by resolution of the board of directors;

•

provide that all vacancies, including newly created directorships, may, except as otherwise required by law, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;

•

at any time after Riverstone and our management no longer collectively own more than 50% of the outstanding shares of our common stock,

•: provide that any action required or permitted to be taken by the stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of preferred stock (prior to such time, provide that such actions may be taken without a meeting by written consent of holders of common stock having not less than the minimum number of votes that would be necessary to authorize such action at a meeting);
•: provide that our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of at least two-thirds of our then outstanding common stock (prior to such time, provide that our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of a majority of our then outstanding common stock); and
•: provide that special meetings of our stockholders may only be called by the board of directors, the chief executive officer or the chairman of the board (prior to such time, provide that a special meeting may also be called by stockholders holding a majority of the outstanding shares entitled to vote);

•

provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms, other than directors which may be elected by holders of preferred stock, if any. For more information on the classified board of directors, please see "Management." This system of electing and removing directors may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it generally makes it more difficult for stockholders to replace a majority of the directors;

•

provide that we renounce any interest in the business opportunities of Riverstone or any of its officers, directors, agents, stockholders, members and partners (other than our directors that are presented business opportunities in their capacity as our directors) and that they have no obligation to offer us those opportunities; and

•

provide that our bylaws can be amended or repealed at any regular or special meeting of stockholders or by the board of directors.

Limitation of Liability and Indemnification Matters

Our amended and restated certificate of incorporation will limit the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

•: for any breach of their duty of loyalty to us or our stockholders;
•: for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

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•: for unlawful payment of a dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or
•: for any transaction from which the director derived an improper personal benefit.

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our amended and restated certificate of incorporation and amended and restated bylaws will also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our amended and restated bylaws will also permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that p

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