As filed with the Securities and Exchange Commission on April 3, 2012

Registration No. 333-178990

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

Amendment No. 2
to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

Cinco Resources, Inc.
(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		1311 (Primary Standard Industrial Classification Code Number)		90-0522580 (I.R.S. Employer Identification No.)

2626 Howell Street, Suite 800
Dallas, Texas 75204
(214) 520-7727
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Jon L. Glass
President and Chief Executive Officer
Cinco Resources, Inc.
2626 Howell Street, Suite 800
Dallas, Texas 75204
(214) 520-7727
(Name, address, including zip code, and telephone number, including area code, of agent for service)


Copies to:
Joe Dannenmaier Jessica W. Hammons Thompson & Knight LLP 1722 Routh Street, Suite 1500 Dallas, Texas 75201 (214) 969-1700		Christine A. Hathaway Alan P. Baden Vinson & Elkins L.L.P. 2001 Ross Avenue, 37^th Floor Dallas, Texas 75201 (214) 220-7700

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

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

SUBJECT TO COMPLETION, DATED APRIL 3, 2012

PRELIMINARY PROSPECTUS

Shares

Cinco Resources, Inc.

Common Stock
$ per share

This is the initial public offering of our common stock. We are selling shares of our common stock. We currently expect the initial public offering price to be between $ and $ per share of common stock.

We have granted the underwriters an option to purchase up to additional shares of common stock to cover over-allotments.

We have applied to have the common stock listed on the NASDAQ National Market under the symbol "CINC."

Investing in our common stock involves risks. See "Risk Factors" beginning on page 15.

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.

	Per Share	Total

Public Offering Price	$	$
Underwriting Discount	$	$
Proceeds to Cinco Resources, Inc. (before expenses)	$	$

The underwriters expect to deliver the shares to purchasers on or about , 2012 through the book-entry facilities of The Depository Trust Company.


Citigroup		Wells Fargo Securities

, 2012

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We are responsible for the information contained in this prospectus and in any free-writing prospectus we prepare or authorize. We have not authorized anyone to provide you with different information, and we take no responsibility for any other information others may give you. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than its date.

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		Page

SUMMARY		1
RISK FACTORS		15
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		38
USE OF PROCEEDS		40
DIVIDEND POLICY		41
CAPITALIZATION		42
DILUTION		43
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA		44
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		46
BUSINESS		72
MANAGEMENT		106
EXECUTIVE COMPENSATION AND OTHER INFORMATION		112
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		133
PRINCIPAL STOCKHOLDERS		137
DESCRIPTION OF CAPITAL STOCK		140
SHARES ELIGIBLE FOR FUTURE SALE		144
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS TO NON-U.S. HOLDERS		146
CERTAIN ERISA CONSIDERATIONS		150
UNDERWRITING (Conflicts of Interest)		151
LEGAL MATTERS		157
EXPERTS		157
WHERE YOU CAN FIND MORE INFORMATION		157
INDEX TO FINANCIAL STATEMENTS		F-1
GLOSSARY OF INDUSTRY TERMS		A-1

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. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information. Some data is also based on our good faith estimates.

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SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all of the information that you should consider before investing in our common stock. You should read this 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 consolidated financial statements and related notes thereto included elsewhere in this prospectus. We have provided definitions for certain oil and natural gas terms used in this prospectus in the "Glossary of Industry Terms" beginning on page A-1 of this prospectus.

In this prospectus, unless the context otherwise requires, the terms "Cinco," "we," "us," "our" and the "company" refer to Cinco Resources, Inc. and its subsidiaries and the term "Yorktown" collectively refers to Yorktown Partners LLC and/or certain investment funds sponsored and managed by Yorktown Partners LLC. Additionally, unless specifically stated otherwise, the information in this prospectus is adjusted to reflect a four for one stock split of our shares of common stock to be effected prior to the closing of this offering.

Cinco Resources, Inc.

Overview

We are an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources. Our assets are located primarily in three core areas: the Eagle Ford Shale in South Texas, the Powder River Basin of Wyoming and the Woodford Shale in the Arkoma Basin of eastern Oklahoma. Our management and senior technical team have significant operational experience in these basins, as well as in the geological zones we target for development. We have accumulated a balanced portfolio of assets comprised of more mature, gas-prone Woodford Shale assets and less-developed, oil-prone properties in the Eagle Ford Shale and Powder River Basin. The majority of our Woodford Shale assets are held by production. We intend to focus most of our near-term activities on the development of our Eagle Ford Shale assets, as well as further evaluation of our Powder River Basin properties.

We have accumulated approximately 145,000 net acres across our operational footprint, approximately 74% of which are undeveloped. Our property base consists of 951 gross (379.6 net) identified drilling locations. Given the early stage in our evaluation of the play, so far, we have identified 24 gross (23.9 net) drilling locations on our Powder River Basin acreage. Netherland, Sewell & Associates, Inc., our independent reserve engineers, estimated our proved reserves as of December 31, 2011 to be 286.1 Bcfe, of which approximately 85% were natural gas and 26% were classified as proved developed reserves. For December 2011, our average net daily production was 30.0 MMcfed, approximately 66% of which was natural gas. We exercise a high degree of operational control over our assets. We operated approximately 95% of our estimated proved reserves on a volume basis as of December 31, 2011 and approximately 90% of our average daily net production for December 2011.

The majority of our Eagle Ford Shale acreage was acquired from March 2007 to June 2010 and is located in southeastern Atascosa, Karnes, Live Oak and Zavala counties in South Texas. We have over 13,000 net acres in what we believe to be a largely oil-prone portion of the play. The Eagle Ford Shale is one of the most active resource plays in the United States, with a rig count of approximately 240 as of March 31, 2012. We drilled and completed 14 gross (12.8 net) wells on our Eagle Ford Shale acreage through March 31, 2012, and we plan to devote a significant portion of our drilling capital to this play in the near term. For the month of December 2011, net production from our Eagle Ford Shale wells averaged 10.5 MMcfed, consisting of 81% oil, 8% natural gas liquids and 11% natural gas.

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Since acquiring our first acreage in the Powder River Basin in April 2011, we have established a position of over 72,000 net acres primarily in Niobrara and Weston counties in Wyoming. The Powder River Basin is one of the key oil and natural gas-producing basins located in the Rocky Mountain states of Wyoming and Montana. We believe our acreage offers multiple stacked horizons prospective for oil that include the Niobrara Shale, the Turner Sandstone, Mowry Shale and Muddy Sandstone. We believe the basin's geological characteristics and historical vertical well data support the development of our acreage as an economic oil resource play. Throughout the Powder River Basin, and specifically to the north and west of our acreage, significant drilling activity is currently being conducted by industry participants like Chesapeake Energy, EOG Resources and El Paso Corp. We are currently evaluating our Powder River Basin acreage position and developing a drilling plan.

We acquired our initial Woodford Shale assets in March 2009 and have over 29,200 net acres in Atoka, Pittsburg and Haskell counties in Oklahoma. The Woodford Shale is one of the more mature and prolific shale gas plays in the United States, with over 1,000 horizontal wells drilled in the Arkoma Basin Woodford Shale since the first horizontal well was drilled in this play in 2005. A substantial portion of our acreage is positioned within one of the more actively drilled parts of the play, allowing us to utilize significant data from nearby analogous wells as well as our own development expertise to better determine well potential. We believe our acreage represents a high-quality natural gas component for our portfolio due to its low-risk development profile, scale and largely held-by-production status.

The following table provides our summary operating data:

			Identified Drilling Locations(1)(3)						Producing Wells(2)				Estimated Proved Reserves as of December 31, 2011								December 2011 Average Daily Net Production

	Net Acreage(1)		Identified Drilling Locations(1)(3)						Producing Wells(2)				Estimated Proved Reserves as of December 31, 2011								December 2011 Average Daily Net Production
	Net Acreage(1)		Gross		Net		PUDs(4)		Gross		Net		Bcfe		%Gas			%Developed			(MMcfed)		%Gas
South Texas:
Eagle Ford Shale		15,045		110		94.4		20		12		10.8		43.0		18	%		25	%		10.5		11	%
Other		3,739		37		21.8		17		42		16.5		40.4		81			36			3.2		81

Area		18,784		147		116.2		37		54		27.3		83.4		48			30			13.7		27
Rocky Mountains:
Powder River Basin(5)		72,894		24		23.9		—		6		5.9		1.1		30			100			0.2		54
DJ Basin		21,201		—		—		—		78		70.3		2.2		100			100			0.9		100

Area		94,095		24		23.9		—		84		76.2		3.3		76			100			1.1		89
Arkoma Basin:
Woodford Shale(6)(7)		29,292		780		239.5		64		131		39.0		199.4		100			23			15.2		100
Other		3,614		—		—		—		1		0.0		—		—			—			—		—

Area		32,906		780		239.5		64		132		39.0		199.4		100			23			15.2		100

Total		145,785		951		379.6		101		270		142.5		286.1		85	%		26	%		30.0		66	%

(1): As of March 31, 2012.
(2): As of December 31, 2011.
(3): See "Business—Overview" for more information regarding the processes and criteria through which these drilling locations were identified.
(4): Represents the number of gross identified potential drilling locations to which proved undeveloped reserves were attributable, based on our December 31, 2011 reserve report.
(5): Given the early stage in our evaluation of the play, so far, we have identified 24 gross (23.9 net) drilling locations on our Powder River Basin acreage.

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(6): Gross and net identified drilling locations in the Woodford Shale are primarily based on 80-acre spacing.
(7): Includes Woodford Shale wells, all up-hole zones in Woodford Shale wells and Hunton wells with Woodford Shale offset locations.

Our capital expenditure budget is primarily focused on developing our Eagle Ford Shale acreage through the use of horizontal drilling and multi-stage fracture stimulation techniques, as well as further evaluating our Powder River Basin acreage. We will also continue to seek acreage in our three core areas. The following table details our anticipated capital expenditure budget by region for the year ending December 31, 2012:

	Number of Wells

	Number of Wells				Capital Expenditures
	Gross		Net		Capital Expenditures
					($ in millions)
Drilling
Eagle Ford Shale		11		11.0	$	107.6
Powder River Basin		2		2.0		22.2
Woodford Shale		2		0.9		6.6
Other Areas(1)		—		—		2.1

Sub-total		15		13.9		138.5
Leasehold, Seismic and Other(2)		—		—		23.2

Total		15		13.9	$	161.7

(1): Includes workovers on South Texas non-Eagle Ford Shale properties.
(2): Includes $16.3 million in payments due in 2012 with respect to our acquisitions of Powder River Basin acreage in 2011. The majority of the remaining amount is intended for leasehold acquisitions.

The actual amount of capital we spend in 2012 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."

Our History

We were founded in 2002 by Jon L. Glass, our President and Chief Executive Officer, and Yorktown, a New York-based private investment firm founded in 1991 and focused on making investments in energy and energy-related companies. Originally, our strategy was to grow through acreage acquisitions, with a geographical focus in South Texas, initially developing our drilling prospects and then selling an operated interest to industry participants to fund further expansion. Over time, our strategy evolved to focus primarily on having operational control of our key assets, with our core focus areas expanding to other basins and geological zones where we have particular expertise. We have grown through both leasing efforts and acquisitions. The following are some of the key acquisitions that we have completed to assemble our current asset base:

•: In November 2011, we acquired approximately 20,000 net acres in the Powder River Basin from a private oil company. This acreage is located in close proximity to our existing Powder River Basin acreage, giving us a total of approximately 72,000 net acres.
•: In November 2011, we acquired Cima Resources, Inc. ("Cima"), an Eagle Ford Shale-focused company that was managed by our executive officers and primarily owned and controlled by Yorktown. This acquisition provided the majority of our current Eagle Ford Shale asset base and a majority of our Powder River Basin properties. Most of Cima's acreage was acquired through

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the leasing or purchase of undeveloped acreage with the strategy to grow production and reserves organically.

•: In 2009, we acquired a private Arkoma Basin company that was primarily owned and controlled by Yorktown, providing the majority of our current Arkoma Basin asset base.
•: In 2007, we acquired a South Texas producer primarily owned and controlled by Yorktown and whose primary asset was the Hostetter Field in southeastern McMullen County, Texas.

Our Strategies

Our primary objective is to increase stockholder value by growing estimated proved reserves, production and cash flow at attractive rates of return on invested capital. We intend to achieve this objective by pursuing the following strategies:

Continue Development of Our Eagle Ford Shale Assets; Accelerate Evaluation of Powder River Basin Properties

We intend to allocate over 93% of our 2012 drilling capital expenditure budget to drilling on our Eagle Ford Shale and Powder River Basin assets. We are actively developing our Eagle Ford Shale acreage and plan to drill 11 gross (11.0 net) wells in 2012. We intend to accelerate the evaluation of our Powder River Basin properties in 2012. This evaluation includes completing vertical wellbores, drilling and completing horizontal wells, analysis of core data, existing 3-D seismic data, production data and well data and continued review of industry activity in the area.

Balance Commodity Mix Through Growth in Oil Production

We believe our development efforts in the Eagle Ford Shale and Powder River Basin will better balance our commodity mix. While our current estimated proved reserves and production are predominantly natural gas from the Woodford Shale, the majority of our project inventory that we plan to develop through 2012 is oil-prone. As we develop this portion of our asset base, we believe our production profile will reflect a more oil-oriented commodity mix that capitalizes on the current commodity price environment. With over 58% of our Woodford Shale acreage held by production, we have the option to expand our natural gas development efforts as the commodity price environment supports such activity.

Enhance Returns Through Operational Efficiencies

Our management team is focused on continually improving efficiencies in developing and operating our asset base. We seek to manage drilling and completion costs to decrease the amount of initial capital invested in our wells, and we are building centralized infrastructure that can be repeatedly used for future development. Specifically, we have invested time and capital in planning and installing production infrastructure, such as central gas treating, oil and water storage and gas compression facilities that can service our future development needs with minimal additional capital investment. We also believe the concentration of our acreage position, the significant percentage of acreage that is already held by production and our high degree of operational control will allow us to realize cost efficiencies with future development.

Pursue Strategic Acquisitions within Our Core Areas

In the near term, we intend to continue to identify, evaluate and acquire additional acreage in our core areas. We intend to focus on acquiring undeveloped acreage with minimal existing production or producing acreage with significant undeveloped potential. While we do not currently have any plans to expand beyond our core areas, we may evaluate other basins that we believe have the potential for attractive returns.

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Maintain Financial Discipline and Actively Manage Commodity Price Risk

We seek a capital structure with sufficient liquidity to execute our growth plans while maintaining conservative leverage, providing financial and operational flexibility. We manage commodity price risk through the use of derivatives that we continually evaluate. We intend to use a portion of the net proceeds from this offering to repay all of our outstanding indebtedness under our credit facilities.

Our Strengths

The following are our key competitive strengths that we believe will allow us to effectively execute our business strategies.

Substantial Acreage Positions in Key Unconventional Plays

We currently have a total of approximately 145,000 net acres in our three core operating areas. The majority of this acreage is in or near areas of considerable activity by both major and independent operators. We believe that a substantial portion of our acreage in the Eagle Ford Shale and Powder River Basin is oil-prone. We believe our Woodford Shale acreage represents a highly predictable and well-defined asset with significant value which we have continued to enhance through cost reduction and reserve and production enhancement initiatives. We hold the majority of our Woodford Shale acreage by production. We believe our lease terms in our other core areas will allow us to hold our other acreage within term based on our current drilling plans.

Powder River Basin Resource Potential

We currently have approximately 72,000 net acres in the Powder River Basin. We believe this acreage offers significant oil resource potential in a series of stacked horizons including the Niobrara Shale, Turner Sandstone, Mowry Shale and Muddy Sandstone. We believe the basin's geological characteristics and historic vertical well production data may support development as an economic oil resource play. We are continuing our geological analysis. Our operational program for 2012 contemplates fracture stimulating two existing vertical wells, re-entering and re-completing two existing short, horizontal wells and drilling three new additional horizontal wells.

Substantial Drilling Inventory

We have an inventory of 951 gross (379.6 net) identified drilling locations. In 2012 we plan to drill 15 gross (13.9 net) wells, leaving us a substantial drilling inventory for future years. Of our oil-prone assets, we have approximately 110 gross (94.4 net) identified drilling locations in the Eagle Ford Shale and 24 gross (23.9 net) locations currently identified in our Powder River Basin acreage. We expect to identify additional Powder River Basin drilling locations as we further evaluate this acreage. We also have a substantial natural gas drilling location inventory with approximately 780 gross (239.5 net) identified drilling locations in the Woodford Shale, as well as approximately 37 gross (21.8 net) identified locations on our other properties in South Texas.

High Degree of Operational Control

We operate over 92% of our net acreage and 86% of our identified drilling locations. Additionally, we operated approximately 95% of our estimated proved reserves on a volume basis as of December 31, 2011 and approximately 90% of our average daily net production for December 2011. We believe that our high level of operational control will enable us to develop our resource base in an efficient and cost-effective manner. Additionally, our operated positions enable us to better manage the pace of development and align our capital spending with our capital resources.

Proximity to Significant Industry Infrastructure and Access to Multiple Product Markets

Our core areas have substantial existing hydrocarbon transportation, processing and refining capacity, as well as access to multiple product sales points. We believe that our access to this

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infrastructure will allow us to get production on line more rapidly and achieve competitive product pricing when compared to other more remote producing basins.

Experienced, Incentivized Management and Employee Base

Our senior management team has significant experience in the oil and gas industry and has spent a substantial amount of their careers focused on our core areas. Our senior technical team is comprised of geoscience, engineering and operational professionals who average over 28 years of industry experience and have worked extensively in multiple North American resource plays. Additionally, our management and employees will have a significant common stock ownership interest following the completion of this offering, which we believe will better align the interest of management, employees and stockholders.

Recent Developments

Eagle Ford Shale Drilling Activity. As of March 31, 2012, we had drilled, completed and placed on production 14 gross (12.8 net) Eagle Ford Shale wells. Our 13^th and 14^th wells in the Eagle Ford Shale, the Atascosa 601 A #1H and the Atascosa 601 B #1H, were placed on production February 28, 2012. For their first full 30 days of production, the Atascosa 601 A #1H averaged 616 Boed, consisting of approximately 85% oil, and the Atascosa 601 B #1H averaged 548 Boed, consisting of approximately 87% oil. Both of these wells flared their gas production during this period, and contributions of natural gas liquids and natural gas were calculated based on gas volumes produced, measured Btu content and estimated gas processing economics. We expect to have both of these wells connected to a gas sales line by the end of April 2012.

For the month of March 2012, net production from all of our Eagle Ford Shale wells averaged MMcfed, consisting of approximately % oil, % natural gas liquids and % natural gas. As of March 31, 2012, we also had completed drilling our 15^th and 16^th wells in the Eagle Ford Shale. These wells are located on our Simmons project area in south central Atascosa County, Texas and we expect to complete them in April 2012. We have a 100% working interest in these wells.

Eagle Ford Shale Leasing Activity. In March 2012, based on an existing letter of intent, we closed an acreage swap adding approximately 2,500 net Eagle Ford Shale acres to our Simmons project area. An additional 640 net acres are subject to this letter of intent. Pending conclusion of satisfactory diligence and documentation, we anticipate closing an acreage swap on these additional acres by the end of April 2012. We have not paid any cash consideration for this acreage as we traded rights below the Eagle Ford Shale for rights for and above the Eagle Ford Shale. The addition of this acreage increased our net Simmons acreage position by approximately 37% to 9,226 net acres. The acquisition of the additional 640 net acres would increase our net acreage in the Simmons project area to approximately 9,866 net acres.

Powder River Basin Acreage Farm-in. In March 2012, we completed a farm-in involving acreage in the Powder River Basin in close proximity to our existing Powder River Basin acreage. For an initial payment of $50,000, we have the rights to drill to earn an additional 6,960 net acres below the top of the Mowry formation, for all of which we would be the operator. Additionally, we have the right to acquire approximately 23 square miles of 3-D seismic for cash consideration of approximately $342,000. The addition of this acreage brings our total Powder River Basin position to approximately 72,900 net acres.

Risk Factors

Investing in our common stock involves a high degree of risk. You should consider and read carefully all of the risks and uncertainties described in "Risk Factors" beginning on page 15, together with all of the other information contained in this prospectus, including our consolidated financial statements and related notes thereto included elsewhere in this prospectus before deciding to invest in our common stock.

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Ownership Structure

The following diagram depicts our ownership structure after giving effect to this offering. For more information on the ownership of our common stock by our principal stockholders, see "Principal Stockholders."

(1): Assumes an initial offering price of $ per share, which is the mid-point of the range set forth on the cover page of this prospectus.
(2): All subsidiaries are wholly-owned.

Corporate Information

Our principal executive offices are located at 2626 Howell Street, Suite 800, Dallas, Texas 75204, and our telephone number at that address is (214) 520-7727.

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The Offering


Common stock offered by Cinco Resources, Inc.		shares
Common stock to be outstanding after this offering		shares
Over-allotment option		We have granted the underwriters an option, exercisable upon notice to us, to purchase up to additional shares of common stock at the offering price to cover over-allotments, if any, for a period of 30 days from the date of this prospectus.
Use of proceeds		We will receive approximately $ million of net proceeds from the sale of the common stock by us in this offering, based upon the assumed initial public offering price of $ per share and after deducting underwriting discounts and estimated offering expenses. We intend to use a portion of the net proceeds from this offering to repay all outstanding indebtedness under our senior secured revolving credit facility, approximately $80.0 million of which was outstanding on March 31, 2012, and to repay all $30.0 million of outstanding indebtedness under and retire our second lien term loan facility. All of this indebtedness may be pre-paid without penalty. We intend to use the remaining net proceeds to fund a portion of our 2012 capital expenditure budget.
Dividend policy		We do not anticipate declaring or paying any cash dividends on our common stock. In addition, our senior secured revolving credit facility prohibits us from paying cash dividends on our common stock. See "Dividend Policy."
Risk factors		You should carefully read and consider the information beginning on page 15 of this prospectus set forth under the heading "Risk Factors" and all other information set forth in this prospectus before deciding to invest in our common stock.
Conflicts of Interest		Affiliates of each of Citigroup Global Markets Inc. and Wells Fargo Securities, LLC, two of the underwriters in this offering, will receive in excess of 5% of the net proceeds of this offering in connection with our repayment of amounts outstanding under our senior secured revolving credit facility and second lien term loan facility. See "Use of Proceeds." Accordingly, this offering is being made in compliance with Financial Industry Regulatory Authority ("FINRA") Rule 5121. FINRA Rule 5121 requires that a "qualified independent underwriter" participate in the preparation of this prospectus and the registration statement of which this prospectus is a part and exercise the usual standards of due diligence with respect thereto. Simmons & Company International has assumed the responsibilities of acting as the qualified independent underwriter in this offering. For more information, see "Underwriting—Conflicts of Interest."

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Proposed NASDAQ National Market Symbol		CINC
Other information about this prospectus		Unless specifically stated otherwise, the information in this prospectus:


		•		is adjusted to reflect a four for one stock split of our shares of common stock to be effected prior to the closing of this offering;
		•		assumes the underwriters' over-allotment option is not exercised; and
		•		assumes an initial public offering price of $ per share, which is the mid-point of the range set forth on the cover page of this prospectus.

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Summary Historical Consolidated Financial Data

You should read the following summary financial data in conjunction with "Selected Historical Consolidated Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Business" and our historical consolidated financial statements and related notes thereto included elsewhere in this prospectus. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

Set forth below is our summary historical consolidated financial data for the periods indicated. The historical consolidated financial data for the periods ended December 31, 2009, 2010 and 2011 and the balance sheet data as of December 31, 2010 and 2011 have been derived from our audited consolidated financial statements included elsewhere in this prospectus. The historical consolidated balance sheet data as of December 31, 2009 has been derived from our audited financial statements not included in this prospectus. The historical consolidated financial data presented below includes the results of Cima from the date of its formation on March 31, 2010, as it and Cinco are entities under common control, and the results of Dernick Resources, Inc. ("DRI") since the date of its acquisition on March 9, 2009.

	Year Ended December 31,

	2009			2010			2011
	(in thousands)
Statement of Operations Data:
Revenues:
Natural gas sales	$	12,079		$	23,453		$	27,352
Oil sales		2,539			3,723			23,641
Natural gas liquids sales		834			964			893

Total revenues		15,452			28,140			51,886
Operating expenses:
Lease operating		4,947			6,687			9,415
Workovers		764			1,993			1,320
Severance and ad valorem taxes		1,265			1,803			2,906
Exploration		1,547			3,579			4,934
Depletion, depreciation and amortization		13,208			17,288			33,992
Impairment of natural gas and oil properties		7,963			20,788			25,525
General and administrative		25,700			16,711			24,786

Total operating expenses		55,394			68,849			102,878

Operating loss		(39,942	)		(40,709	)		(50,992	)
Other income (expense):
Gain on property sales		46			802			281
Gain on derivative instruments		63			7,865			7,381
Interest expense		(4,582	)		(6,787	)		(6,947	)
Other income (expense)		160			(566	)		(42	)

Total other income (expense)		(4,313	)		1,314			673

Loss from continuing operations before taxes		(44,255	)		(39,395	)		(50,319	)
Income tax expense		(33	)		(13	)		(51	)

Loss from continuing operations		(44,288	)		(39,408	)		(50,370	)
Income from discontinued operations		2,150			5,912			9,946

Net loss		(42,138	)		(33,496	)		(40,424	)
Net loss attributable to non-controlling interests		1,365			—			—

Net loss attributable to Cinco Resources, Inc. stockholders		(40,773	)		(33,496	)		(40,424	)
Less: net effect of induced conversion of preferred stock to common stock(1)		—			—			(42,000	)

Net loss attributable to common shares	$	(40,773	)	$	(33,496	)	$	(82,424	)

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	As of December 31,		As of December 31, 2011

	As of December 31,					As Adjusted(2)
	2010		Actual			As Adjusted(2)
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	37,982	$	8,766		$
Net property and equipment		227,452		322,472
Total assets		308,116		355,524
Long-term debt, including current maturities		86,000		109,871	(3)
Total stockholders' equity		161,187		204,741

	Year Ended December 31,

	2009			2010			2011
	(in thousands)
Other Financial Data:
Net cash provided by (used in) operating activities	$	(40,027	)	$	14,734		$	16,867
Net cash used in investing activities		(25,153	)		(84,619	)		(121,772	)
Net cash provided by financing activities		55,986			98,220			75,689
Adjusted EBITDAX(4)		(11,970	)		14,215			31,307

(1): Represents the value of common stock issued to holders of our preferred stock in excess of original conversion value as an inducement to convert all shares of preferred stock into common stock prior to completion of this offering.
(2): Gives effect to (i) a four for one stock split of our common stock to be effected prior to the closing of this offering, (ii) the issuance of 213,676 restricted shares of common stock that will occur concurrently with the closing of this offering and (iii) this offering and the application of the net proceeds as described in "Use of Proceeds."
(3): As of December 31, 2011, all amounts outstanding under our senior secured revolving credit facility and our second lien term loan facility are shown as current maturities due to our non-compliance with the applicable current ratio covenants. We have been granted a limited waiver related to this non-compliance for the quarters ended December 31, 2011 and March 31, 2012. As adjusted for this offering, we expect to be in compliance with our current ratio covenants through 2012.
(4): Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to our loss from continuing operations, see "—Non-GAAP Financial Measure" below.

Non-GAAP Financial Measure

Adjusted 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 Adjusted EBITDAX as income or loss from continuing operations before interest expense, income tax expenses or benefits, realized gains or losses on interest rate derivatives, depletion, depreciation and amortization, property impairments, exploration expenses, unrealized derivative gains or losses, interest and other income or expense, gains or losses on property sales and share-based compensation expense. Adjusted EBITDAX is not a measure of net income or loss as determined by U.S. generally accepted accounting principles, or GAAP. Our management believes Adjusted EBITDAX is useful because it allows us 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 income or loss from continuing operations in arriving at Adjusted 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

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method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, income or loss from continuing operations as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted 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 Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that Adjusted 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 of Adjusted EBITDAX to the GAAP financial measure of loss from continuing operations.

	Year Ended December 31,

	2009			2010			2011
	(in thousands)
Adjusted EBITDAX reconciliation to loss from continuing operations:
Loss from continuing operations	$	(44,288	)	$	(39,408	)	$	(50,370	)
Exploration		1,547			3,579			4,934
Depletion, depreciation and amortization		13,208			17,288			33,992
Impairment of natural gas and oil properties		7,963			20,788			25,525
Share-based compensation expense		5,287			8,723			10,976
Gains on property sales		(46	)		(802	)		(281	)
Realized loss on interest rate derivatives		340			978			1,002
Unrealized derivative gains		(436	)		(4,297	)		(1,511	)
Interest expense		4,582			6,787			6,947
Other (income) expense		(160	)		566			42
Income tax expense		33			13			51

Adjusted EBITDAX	$	(11,970	)	$	14,215		$	31,307

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Summary Historical Operating and Reserve Data

The following table presents summary data with respect to our estimated proved oil and natural gas reserves as of the dates indicated. The reserve estimates at December 31, 2009, 2010 and 2011 presented in the table below are based on reports prepared by Netherland, Sewell & Associates, Inc., our independent reserve engineers, and were prepared consistent with the rules promulgated by the Securities and Exchange Commission, or the SEC, regarding oil and natural gas reserves. For additional information regarding our reserves, see "Business—Estimated Proved Reserves."

	At December 31,

	2009			2010			2011
Estimated Proved Reserves(1):
Natural gas (Bcf)		138.5			229.5			242.3
Oil (MMBbls)		1.5			2.2			6.1
Natural gas liquids (MMBbls)		0.8			0.8			1.2
Total (Bcfe)		151.9			247.5			286.1
Estimated proved developed (Bcfe)		64.0			84.7			75.2
Percent developed		42.1	%		34.2	%		26.3	%
Estimated proved undeveloped (Bcfe)		87.9			162.8			210.9
PV-10 (in millions)(2)	$	62.1		$	130.7		$	211.2
Standardized Measure (in millions)(3)	$	61.6		$	129.8		$	205.6

(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. Our estimated proved reserves were determined using the unweighted averages of the historical first-day-of-the-month prices for the prior 12 months of $57.65 per Bbl for oil and $3.87 per MMBtu for natural gas at December 31, 2009; $75.96 per Bbl for oil and $4.38 per MMBtu for natural gas at December 31, 2010; and $92.71 per Bbl for oil and $4.12 per MMBtu for natural gas at December 31, 2011. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
(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. PV-10 is not 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 estimated proved reserves held by companies without regard to the specific tax characteristics of such entities. The following table provides a reconciliation of our Standardized Measure to PV-10 for the periods presented:

	At December 31,

	2009		2010		2011
	(in millions)
Standardized Measure of discounted net cash flows	$	61.6	$	129.8	$	205.6
Present value of future income tax discounted at 10%(4)		0.5		0.9		5.6

PV-10	$	62.1	$	130.7	$	211.2

(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 the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our oil and natural gas properties.
(4): Based on our net operating losses, we do not anticipate paying any future federal income taxes for the periods indicated. Taxes shown are state taxes.

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The following table sets forth summary data with respect to our revenues, realized commodity derivative activities, production results, average sales prices and production costs on a historical basis for the periods presented. We determine natural gas equivalents by using the ratio of six Mcf of natural gas to one barrel of oil or one barrel of natural gas liquids.

	Year Ended December 31,

	2009			2010		2011
Revenues (in thousands):
Natural gas sales	$	12,079		$	23,453	$	27,352
Oil sales		2,539			3,723		23,641
Natural gas liquids sales		834			964		893

Total revenues		15,452			28,140		51,886
Realized gain (loss) on commodity derivatives		(33	)		4,546		6,872

Revenues including derivative impact	$	15,419		$	32,686	$	58,758

Production data:
Natural gas (MMcf)		3,601.3			6,627.0		8,038.7
Oil (MBbls)		43.5			48.2		250.7
Natural gas liquids (MBbls)		25.9			24.1		18.5
Equivalents (MMcfe)		4,017.7			7,060.8		9,653.9
Average daily equivalent production (MMcfed)		11.0			19.3		26.4
Average sales prices:
Natural gas ($ per Mcf)	$	3.35		$	3.54	$	3.40
Oil ($ per Bbl)		58.37			77.24		94.30
Natural gas liquids ($ per Bbl)		32.20			40.00		48.27
Equivalents ($ per Mcfe)		3.85			3.99		5.37
Realized gain (loss) on commodity derivatives ($ per Mcfe)		(0.01	)		0.64		0.72

Natural gas equivalents including realized gain (loss) on commodity derivatives ($ per Mcfe)(1)	$	3.84		$	4.63	$	6.09

Costs and expenses (per Mcfe of production):
Lease operating	$	1.23		$	0.95	$	0.98
Workovers		0.19			0.28		0.14
Severance and ad valorem taxes		0.31			0.26		0.30
Depletion, depreciation and amortization		3.29			2.45		3.52
General and administrative		6.40			2.37		2.57

(1): These prices include realized gains or losses on cash settlements for our commodity derivatives. None of our commodity derivatives are designated as cash flow or fair value hedges.

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RISK FACTORS

You should carefully consider the risks described below 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 natural gas, oil and natural gas liquids 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 natural gas, oil and natural gas liquids heavily influences our revenues, profitability, access to capital and future rate of growth. Natural gas, oil and natural gas liquids 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 natural gas, oil and natural gas liquids 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:

•: domestic and worldwide economic conditions impacting the supply and demand for natural gas, oil and natural gas liquids;
•: the actions of the Organization of Petroleum Exporting Countries, or OPEC;
•: the price and quantity of imports of foreign oil and natural gas;
•: political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
•: the level of global oil and natural gas exploration and production;
•: the level of global oil and natural gas inventories;
•: 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.

Substantially all of our production that is not subject to derivative contracts is sold to purchasers under short-term (less than 12-month) contracts at market-based prices. Lower natural gas, oil or natural gas liquids prices will reduce our cash flows, 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 needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves." Lower natural gas, oil and natural gas liquids prices may also reduce the amount of natural gas, oil and natural gas liquids that we can produce economically and may cause negative revisions to our estimated proved reserves by shortening the economic lives of producing properties, rendering proved undeveloped reserves uneconomic or lowering proved undeveloped reserves' estimated rates of return below our commerciality criteria. See also "—The present value of future net revenues from our estimated proved

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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 exploitation, exploration, development 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. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

•: shortages of or delays in obtaining equipment and qualified personnel;
•: facility or equipment malfunctions;
•: unexpected operational events;
•: pressure or irregularities in geological formations;
•: adverse weather conditions, such as ice storms, hurricanes and flooding;
•: declines in oil and natural gas prices;
•: delays imposed by or resulting from compliance with regulatory requirements;
•: proximity to and capacity of transportation and processing facilities;
•: title problems; and
•: limitations in the market for natural gas, oil and natural gas liquids.

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—Estimated Proved Reserves" for information about our estimated natural gas, oil and natural gas liquids reserves and the PV-10 and Standardized Measure of discounted future net revenues as of December 31, 2010 and December 31, 2011. In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise. Actual future production, oil and

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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 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 in the Eagle Ford Shale, the estimates of future production associated with these properties may be subject to greater variance from actual production than would be the case with properties having a longer production history.

The present value of future net revenues from our estimated 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 estimated proved reserves is the current market value of our estimated natural gas, oil and natural gas liquids reserves. We have based the estimated discounted future net revenues from our estimated proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the month price for the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our natural gas, oil and natural gas liquids properties will be affected by factors such as:

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

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from estimated proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates included in this prospectus. If oil and natural gas liquids prices decline by $1.00 per Bbl, then our PV-10 as of December 31, 2011 would decrease approximately $3.3 million. If natural gas prices decline by $0.10 per Mcf, then our PV-10 as of December 31, 2011 would decrease approximately $8.4 million.

Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks, and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

Operations in the Woodford Shale, the Eagle Ford Shale and the Mowry Shale/Muddy Sandstone formations involve utilizing the latest drilling and completion techniques that we and our service providers have developed in order to attempt to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, failures of any of the following: landing our well bore in the desired part of the geologic formation; staying in the desired part of the geologic formation while drilling horizontally through the formation; running our casing the entire length of the well bore; and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, failures of any of the following: being able to fracture stimulate the planned number of stages; being able to run tools the entire length of the well bore during completion operations; and successfully cleaning out the well bore after completion of the final fracture stimulation stage.

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Our experience with horizontal drilling utilizing the latest drilling and completion techniques specifically in the Woodford Shale formation, and particularly in the Eagle Ford Shale formation, is limited. We have not drilled any horizontal wells in the Powder River Basin. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, limited takeaway capacity, limited processing capacity or otherwise, and/or natural gas, oil and natural gas liquids prices decline, the return on our investment in these areas may not be as attractive as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Additionally, hydraulic fracturing operations can result in surface spillage, mishandling of fluids, including chemical additives that may be toxic, or, in rare cases, the underground migration of fracturing fluids. Any such spillage, mishandling or migration could result in litigation, government fines and penalties or remediation or restoration obligations.

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed 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, development and exploitation 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 natural gas, oil and natural gas liquids reserves. Our cash flows used in investing activities related to capital for exploration and development expenditures were $145.9 million for the year ended December 31, 2011. To date, our capital expenditures have been financed with capital contributions from Yorktown and other private investors, borrowings under our credit facilities and net cash provided by operating activities. As of December 31, 2011, we had a working capital deficit of approximately $111.7 million and have suffered recurring net losses resulting in our accumulated deficit of approximately $231.2 million. Further, as of December 31, 2011, we were not in compliance with the minimum current ratio requirements specified in our senior secured revolving credit facility and our second lien term loan facility. As a result of this offering, we expect to be in compliance with these requirements for the quarter ended June 30, 2012 and the remainder of 2012. We project that we will incur capital costs in excess of $136.8 million through 2014 to develop the proved undeveloped reserves covered by the December 31, 2011 reserve report prepared by Netherland, Sewell & Associates, Inc., our independent reserve engineers. Because these costs cover less than six percent of our total potential drilling locations, we will be required to generate or raise additional capital to develop all of our potential drilling locations should we elect to do so. 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. We intend to finance our future capital expenditures primarily through cash flows provided by operating activities, borrowings under our senior secured revolving credit facility and the 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 and equity linked 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 and equity-linked securities could have a dilutive effect on the value of your common stock. In addition, upon the issuance of certain debt securities (other than on a borrowing base redetermination date), our borrowing base under our senior secured revolving credit facility will be reduced by an amount that is not determinable at this time. Our next scheduled

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borrowing base redetermination is June 1, 2012. Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:

•: our estimated proved reserves;
•: the level of natural gas, oil and natural gas liquids we are able to produce from existing wells;
•: the prices at which our production is sold;
•: the costs of developing our properties and producing from them over time;
•: our ability to acquire, locate and develop new reserves;
•: the ability and willingness of our banks to lend us additional funds;
•: the overall conditions of capital markets; and
•: our ability to access the equity and debt capital markets.

If the borrowing base under our senior secured revolving credit facility or our revenues decreases as a result of lower natural gas, oil and natural gas liquids 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 senior secured 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 possible expiration of certain of our leases and a decline in our natural gas, oil and natural gas liquids reserves, and could adversely affect our business, financial condition and results of operations.

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, which may result in a decrease in the amount available under our senior secured 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 senior secured revolving credit facility and our results of operations for the periods in which such charges are taken.

We have limited control over the timing of exploration or development efforts, associated costs or the rate of production on properties we do not operate.

We operate more than 92% of our net acreage. For the balance of our net acreage, our business activities are conducted through joint operating agreements under which we own partial interests in oil and natural gas properties. Additionally, as we carry out our drilling programs, 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 others. 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 others 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;

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•: approval of other participants in drilling wells;
•: 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.

Substantially all of our producing properties and operations are located in our core areas of the Arkoma Basin and South Texas, making us vulnerable to risks associated with operational concentrations in two geographic areas.

As of December 31, 2011, substantially all of our estimated proved reserves were located in our core areas of the Arkoma Basin and South Texas. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation or processing capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of natural gas, oil and natural gas liquids produced from the wells in these areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

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 natural gas, oil and natural gas liquids transportation and processing arrangements may hinder our access to product markets or delay our production. The availability of a ready market for our production depends on a number of factors, including the demand for and supply of natural gas, oil and natural gas liquids and the proximity of reserves to pipelines, processing facilities and terminal facilities. Our ability to market our production depends, in substantial part, on the availability, proximity and capacity of gathering systems, pipeline systems and treating and processing facilities owned and operated by third-parties. The 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 can be interrupted by those having firm arrangements. If our production becomes shut-in for any of these or other reasons, we would be unable to realize revenues from those wells until other arrangements were made to deliver the products to market.

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 or what prices will be charged. A total shut-in of production 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.

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 also adversely affect our ability to produce, gather and transport our oil and natural gas.

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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.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing estimated proved reserves, our estimated proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future natural gas, oil and natural gas liquids 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, completion equipment, other 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, completion and other 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.

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 and shoreline contamination;
•: abnormally pressured formations;
•: mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
•: 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 and equipment;
•: pollution and other environmental damage;

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•: regulatory investigations and penalties;
•: suspension of our operations; and
•: repair and 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.

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

Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield natural gas, oil or natural gas liquids 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 natural gas, oil or natural gas liquids will be present or, if present, whether they will be present in sufficient quantities to be economically viable. Even if sufficient amounts of natural gas, oil or natural gas liquids 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 our core areas may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

We have incurred losses from operations during certain periods since our inception and may continue to do so in the future.

We incurred net losses of $40.8 million, $33.5 million and $82.4 million for the years ended December 31, 2009, 2010 and 2011, respectively. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this prospectus may impede our ability to economically find, develop, exploit and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by operating activities in the future.

Our ability to use our net operating loss carry forwards and other tax attributes may be limited by Section 382 of the Internal Revenue Code.

At December 31, 2011, we had net operating loss carry forwards for federal income tax purposes of approximately $313.6 million available to offset future taxable income. Section 382 of the Internal Revenue Code of 1986, as amended, generally limits the ability of a corporation that undergoes an "ownership change" to utilize its net operating loss carry forwards ("NOLs") and certain other tax attributes against taxable income in taxable periods after the ownership change. The amount of taxable income in each taxable year after the ownership change that may be offset by pre-change NOLs and certain other pre-change tax attributes is generally equal to the product of (a) the fair market value of the corporation's outstanding stock immediately prior to the ownership change and (b) the "long-term tax exempt rate," increased by certain recognized built-in gains with respect to our assets in existence at

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the time of the ownership change. In general, an "ownership change" occurs whenever the percentage of the stock of a corporation owned, directly or indirectly, by "5-percent shareholders" (within the meaning of Section 382 of the Internal Revenue Code) increases by more than 50 percentage points over the lowest percentage of the stock of such corporation owned, directly or indirectly, by such 5-percent shareholders at any time over the preceding three years. Based on our preliminary analysis, we do not expect to experience an ownership change as a result of this equity offering (when considered with prior issuances and transfers of our stock). The shift in ownership with respect to our stock in connection with this offering may, however, increase the likelihood that we could experience an ownership change in the future. Based on the expected value of our shares immediately before this offering and projections regarding future income and loss, if an ownership change were to occur as a result of this offering, the Section 382 limitation resulting from any such ownership change should not significantly limit our ability to utilize our existing NOLs. However, these conclusions are based on a variety of assumptions, including the Company's estimates regarding the amount and timing of certain deductions and future earnings, any of which could be incorrect. Accordingly, there can be no assurance that these limitations would not have an adverse effect on the Company's ability to utilize its NOL carry forwards.

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

Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2011, only 101 of our 951 specifically identified potential future gross drilling locations were attributed to proved undeveloped reserves included in our December 31, 2011 reserve report. These potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, regulatory approvals, the prices of natural gas, oil and natural gas liquids, costs and drilling results. Because of these uncertainties, 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 natural gas, oil or natural gas liquids from these or any other potential drilling locations. Pursuant to the current 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. These rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Our actual drilling activities may be materially different from our current expectations based on potential drilling locations, which could adversely affect our financial condition, results of operations and cash flows.

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.

Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. As of March 31, 2012, we had leases representing 9,288 net acres expiring in 2012; 13,865 net acres expiring in 2013; and 9,676 net acres expiring in 2014. 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.

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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 other aspects of our business relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of a permit 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, generation of waste and 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 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.

The potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells.

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 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 in, but not passed by, Congress that would provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the

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hydraulic-fracturing process. If similar legislation were enacted in the future, it could 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. Future Congressional legislation also could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Certain states in which we operate, including Texas and Wyoming, 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, the Railroad Commission of Texas, or the RCT, has adopted regulations requiring the public disclosure 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 the Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC 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. These on-going or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanism.

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 Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs. The EPA proposed rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion, or REC, techniques developed in the 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

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NESHAPS include maximum achievable control technology, or 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 April 3, 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 and increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.

Climate change legislation or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other "greenhouse gases," or GHGs, present an endangerment to public 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. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating GHG emissions under the Clean Air Act, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

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Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These proposed changes would include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of these or any other similar changes in U.S. federal income tax laws 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 could negatively impact the value of an investment in our common stock.

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, 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 unsuccessful drilling attempts, sustained periods of volatility in financial 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 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. The loss of the services of our senior management or technical personnel, including Jon L. Glass, our Chairman, President and Chief Executive Officer; Edward P. Travis, our Senior Vice President and Chief Operating Officer; or Wayne B. Stoltenberg, our Senior Vice President and Chief Financial Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

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

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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 counterparty 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.

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

The adoption of financial reform legislation by the United States Congress in 2010 could have an adverse effect on our ability to hedge risks associated with our business.

We enter into derivatives contracts in order to hedge a portion of our natural gas and oil production. The United States Congress adopted comprehensive financial reform legislation in 2010 that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as ours, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was signed into law by the President on July 21, 2010, and its provisions generally are effective 360 days from the date of enactment, on July 16, 2011. Provisions that require rulemaking by the Commodity Futures Trading Commission, or the CFTC, and/or the SEC will not take effect until at least 60 days after publication of the related final rule. The CFTC and the SEC have not completed all of the rulemaking the Dodd-Frank Act directs them to carry out. The regulators have granted temporary relief from the general effective date for various requirements of the Dodd-Frank Act, and also have indicated they may phase in implementation of various requirements of the new rules. In its rulemaking under the Dodd-Frank Act, the CFTC proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. The CFTC adopted these proposed regulations with modifications on October 18, 2011, but it is not possible at this time to predict when these regulations will take effect. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivatives activities, although the application of those provisions to us is uncertain at this time. The Dodd-Frank Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivatives contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our business, financial condition or results of operations.

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

Our senior secured revolving credit facility includes certain 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 our senior secured 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 crude 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 senior secured revolving credit facility requires us to maintain certain financial ratios, such as leverage ratios. 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 senior secured 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 senior secured 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 senior secured revolving credit facility, together with accrued interest, to be due and payable. For example, as of December 31, 2011, we were not in compliance with the applicable current ratio covenants under our senior secured revolving credit facility and our second lien term loan facility and were granted limited waivers related to this non-compliance for the quarters ended December 31, 2011 and March 31, 2012. If we were unable to repay such borrowings or interest, our lenders could proceed against their collateral. If the indebtedness under our senior secured revolving credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.

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

Upon the completion of this offering, we expect to have no indebtedness outstanding and will have a borrowing capacity of approximately $85.0 million under our senior secured revolving credit facility.

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Our next scheduled borrowing base redetermination is June 1, 2012. In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

Our 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 who, therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
•: our debt covenants may 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 or other purposes.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends 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 borrowing base under our senior secured revolving credit facility 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 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, financial condition and results of operations.

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

Our principal exposures to credit risk are through receivables resulting from the sale of our natural gas, oil and natural gas liquids production to energy marketing companies, pipelines and other midstream companies and affiliates ($7.3 million in natural gas and oil receivable at December 31, 2011) and joint interest owners receivable ($2.9 million at December 31, 2011).

We are subject to credit risk due to the concentration of our natural gas, oil and natural gas liquids receivables with several significant customers. This concentration of customers may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. For the year ended December 31, 2011, sales to two customers accounted for approximately 59% of our total natural gas and oil sales. For the year ended December 31, 2010, sales to four customers accounted for approximately 60% of our total natural gas and oil sales. 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.

Joint interest owner receivables arise from billing entities who own a partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells.

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

We periodically 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.

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:

•: existing or potential problems or liabilities;
•: 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

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•: 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, financial condition and results of operations may be adversely affected.

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 with those of ours. 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 to 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 are, and from time to time may be, subject to legal proceedings and claims that could adversely affect our business, financial condition and results of operations.

We are, and from time to time in the future may be, subject to legal proceedings and claims brought by business partners, third party contractors, working interest owners, vendors and others relating to matters incidental to our business. As with all legal proceedings, no assurance can be provided as to the outcome of these matters. In general, legal proceedings could result in substantial costs and a diversion of our management's attention and resources. We may not be successful in the defense of these legal proceedings, which could result in settlements or damages that could adversely affect our business, financial condition and results of operations. See "Business—Legal Proceedings."

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

In many instances, we acquire oil and gas leases or interests without incurring 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 entails expense. Our failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. There is no assurance that we will not suffer a monetary loss from title defects or title failure. 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.

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Risks Relating to this 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 drop 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 was determined by negotiations between us and the 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 you paid in this offering.

The following factors could affect the market price of our common stock:

•: our operating and financial performance, our number of drilling locations and our reserve estimates;
•: quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;
•: changes in revenues or earnings estimates or publication of reports by equity research analysts;
•: speculation in the press or investment community;
•: sales of our common stock by us or our stockholders, or the perception that such sales may occur;
•: 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 market price of our common stock.

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

Purchasers of our common stock in this offering will experience an immediate and substantial dilution of $ per share in the pro forma as adjusted net tangible book value per share of common stock from the assumed initial public offering price of $ per share. Our pro forma as adjusted net tangible book value as of December 31, 2011 after giving effect to this offering would be $ per share. See "Dilution" for a complete description of the calculation of the net tangible book value of our common stock.

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 of 2002 and the Dodd-Frank 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 laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, or the

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Sarbanes-Oxley Act, related regulations of the SEC, the Dodd-Frank Act and the requirements of the NASDAQ National Market, or NASDAQ, 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 controls 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 NASDAQ;
•: 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.

In addition, we also expect that being a public company subject to these rules and regulations will require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.

If we fail to maintain effective internal control over financial reporting, our ability to accurately report our financial results and become compliant with the Sarbanes-Oxley Act could be adversely affected.

We are not currently required to comply with the SEC's rules implementing 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, to the extent not alleviated by the Jumpstart Our Business Startups Act, or the JOBS Act, 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 any earlier than 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 may need to upgrade our systems, including information technology, implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Our efforts to further 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, NASDAQ or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.

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We do not intend to declare, and we are currently prohibited from paying, 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 intend to declare dividends on shares of our common stock in the foreseeable future. Additionally, we are currently prohibited from paying any cash dividends on our common stock pursuant to the terms of our senior secured revolving credit facility. 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 subsequent issuances of our common stock or convertible securities may dilute your ownership in us.

After the completion of this offering, we will have outstanding shares of common stock (assuming the underwriters exercise their over-allotment option in full). We may issue additional shares of common stock or securities convertible into common stock. Following the completion of this offering, Yorktown will own shares, or approximately % of our outstanding shares, and certain of our other affiliates will own shares, or approximately % of our outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between such parties and the underwriters described in "Underwriting," but may be sold into the market in the future. The holders of the remaining shares, or approximately % of our outstanding shares, are not subject to lock-up agreements and, subject to compliance with Rule 144 under the Securities Act, such holders may sell their shares into the public market.

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 2011 Long Term Incentive Plan and our 2012 Long Term Incentive Plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under this 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. Future issuances or sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such issuances or sales could occur, may adversely affect prevailing market prices of our common stock and may dilute your percentage ownership in us.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, 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

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for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

•: once Yorktown no longer beneficially owns more than 50% of our issued and outstanding common stock, a classified board of directors, so that only approximately one-third of our directors will be 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.

Delaware law prohibits us from engaging in any business combination with any "interested stockholder," meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors. See "Description of Capital Stock—Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law."

The concentration of our capital stock ownership among our largest stockholders and their affiliates will significantly limit your ability to influence corporate matters.

Upon completion of this offering, Yorktown will own approximately % of our outstanding common stock (based on an assumed initial public offering price of $ per share). Consequently, Yorktown will continue to have the ability to control decisions 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 Yorktown or any other of its portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Yorktown is a New York-based private investment firm focused on making investments in energy and energy-related companies. As a result, Yorktown's existing and future portfolio companies which it controls may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.

We have indemnified Yorktown against losses it may incur by virtue of the fact it is our stockholder or former stockholder.

We have agreed to indemnify and hold harmless Yorktown from and against any and all losses, claims, damages, settlements and other amounts arising from claims, demands, actions or proceedings in which Yorktown may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as our stockholder or former stockholder or by virtue of the fact it is our stockholder or former stockholder. See "Certain Relationships and Related Party Transactions—Indemnification of Directors, Officers and Certain Affiliated Stockholders." We could be required to pay substantial amounts pursuant to this indemnity.

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 any business opportunity that involves any aspect of the energy business or industry and that may be from time to time presented to (i) any of our

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non-employee directors or any of their affiliates or (ii) Yorktown or any other investment fund sponsored or managed by Yorktown, including any fund still to be formed, or any affiliate or subsidiary of Yorktown, or any other investment fund sponsored or managed by Yorktown, including any fund still to be formed, and in which such parties participate or desire to participate, 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. Our amended and restated certificate of incorporation further provides that no such person or party shall be liable to us by reason of the fact that such person pursues any such business opportunity, or fails to offer any such business opportunity to us, unless, in the case of any such person who is our director, officer or employee, any such business opportunity is expressly offered in writing to such director, officer or employee solely in his or her capacity as our director, officer or employee.

As a result, our non-employee directors, Yorktown, other investment funds sponsored or managed by Yorktown, including any fund or funds still to be formed, or their respective affiliates 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 they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, by renouncing our interest and expectancy in any business opportunity that may be from time to time presented to our non-employee directors, Yorktown, other investment funds sponsored or managed by Yorktown, including any fund or funds still to be formed, or their respective affiliates, our business or prospects could be adversely affected if attractive business opportunities are procured by such parties for their own benefit rather than for ours. See "Certain Relationships and Related Party Transactions—Corporate Opportunities Renunciation."

We expect to be a "controlled company" within the meaning of NASDAQ rules and, if applicable, would qualify for and will rely on exemptions from certain corporate governance requirements.

Because Yorktown will own a majority of our outstanding common stock following the completion of this offering, we expect to be a "controlled company" as that term is set forth in NASDAQ Rule 5616(c)(2). Under the NASDAQ 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 NASDAQ corporate governance requirements, including:

•: the requirement that a majority of our board of directors consist of independent directors;
•: the requirement that our nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities; and
•: the requirement that our compensation committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities.

These requirements will not apply to us as long as we remain a "controlled company." Following this offering, we may 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 NASDAQ. Yorktown's 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:

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

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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, intentions and expectations reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, intentions or expectations 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 Financial Condition and Results of Operations" and elsewhere in this prospectus. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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USE OF PROCEEDS

We will receive net proceeds of approximately $ million from the sale of the common stock by us in this offering, assuming an initial public offering price of $ per share and after deducting estimated expenses and underwriting discounts and commissions of approximately $ million. If the underwriters' over-allotment is exercised in full, we estimate that our net proceeds will be approximately $ million.

We intend to use the net proceeds from this offering to (i) repay all outstanding indebtedness under our senior secured revolving credit facility, approximately $80.0 million of which was outstanding on March 31, 2012 and (ii) repay the $30.0 million of outstanding debt under and retire our second lien term loan facility. We intend to use the remaining net proceeds from this offering, our cash flows from operations and available borrowings under our senior secured revolving credit facility to fund our 2012 capital expenditure budget. We have the ability to re-borrow amounts repaid under our senior secured revolving credit facility for working capital or other purposes. We intend to use the following amounts for the above uses:

Use of Proceeds		Amount

		(in millions)
Repayment of senior secured revolving credit facility		$
Repayment of second lien term loan facility
Payment of a portion of 2012 capital expenditure budget

Total		$

Our senior secured revolving credit facility matures in January 2016, and our borrowings bear interest at a variable rate, which was approximately 3.24% per annum as of March 31, 2012. Our outstanding borrowings under our senior secured revolving credit facility were incurred to fund exploration, development and other capital expenditures. Affiliates of certain of the underwriters are lenders under our senior secured revolving credit facility and second lien term loan facility and, accordingly, will receive a portion of the proceeds from this offering. See "Underwriting." We will pay all expenses related to this offering.

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 and underwriting discounts and commissions, to increase or decrease, as applicable, by approximately $ million.

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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 senior secured revolving credit facility prohibits us from paying cash dividends on our common stock, and we may enter into debt agreements in the future that also prohibit our ability to declare or pay cash dividends on our common stock.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and our capitalization as of December 31, 2011:

•: on an actual basis;
•: on an as adjusted basis to give effect to (i) our four for one common stock split to be effected prior to the closing of this offering, (ii) the issuance of 213,676 restricted shares of common stock that will occur concurrently with the closing of this offering and (iii) this offering and the application of the net proceeds as described in "Use of Proceeds."

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

	As of December 31, 2011

	Actual			As Adjusted
	($ in thousands, except per-share amounts)
Cash and cash equivalents	$	8,766		$

Long-term debt, including current maturities:
Senior secured revolving credit facility	$	60,000		$
Second lien term loan facility		30,000
Acquisition notes payable, net of discount of $305		19,871

Total long-term debt, including current maturities		109,871
Stockholders' Equity:
Preferred Stock—$0.001 par value per share (actual), $0.001 par value per share (as adjusted), 880,000 shares authorized (actual), 50,000,000 shares authorized (as adjusted); no shares issued and outstanding (actual), no shares issued and outstanding (as adjusted)		—
Common stock—$0.001 par value per share (actual), $0.001 par value per share (as adjusted), 20,000,000 shares authorized (actual), 150,000,000 shares authorized (as adjusted); 17,950,036 shares issued and outstanding (actual), and shares issued and outstanding (as adjusted)		18
Additional paid-in capital		463,562
Notes receivable from stockholders		(27,634	)
Accumulated deficit		(231,205	)

Total stockholders' equity		204,741

Total capitalization	$	314,612		$

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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 December 31, 2011 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 (i) our four for one common stock split to be effected prior to the closing of this offering, (ii) the issuance of 213,676 restricted shares of common stock that will occur concurrently with the closing of this offering and (iii) the sale of the shares of common stock in this offering and further 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 December 31, 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. All per share amounts in this section have been adjusted for our four for one common stock split to be effected in the form of a stock dividend concurrently with the closing of this offering. 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 December 31, 2011	$
Increase per share attributable to new investors in this offering

As adjusted pro forma net tangible book value per share after giving effect to 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 December 31, 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, calculated before deduction of estimated underwriting discounts and commissions:

	Shares Acquired		Total Consideration

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

Total			$		$

(1): The number of shares of common stock presented above for the existing stockholders includes 213,676 restricted shares of common stock to be issued concurrently with the closing of this offering. See "Executive Compensation and Other Information—Compensation Discussion and Analysis—Elements of Compensation—Equity-Based Incentive Awards."

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

Set forth below is our selected historical consolidated financial data for the periods indicated. The historical consolidated financial data for the periods ended December 31, 2009, 2010 and 2011 and the balance sheet data as of December 31, 2010 and 2011 have been derived from our audited consolidated financial statements included elsewhere in this prospectus. The historical consolidated balance sheet data as of December 31, 2008 and 2009 and the historical consolidated financial data for the period ended December 31, 2009 have been derived from our audited financial statements not included in this prospectus. The historical consolidated financial data as of and for the period ended December 31, 2007 and 2008 has been derived from our accounting records.

You should read the following selected historical consolidated financial data in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our historical consolidated financial statements and related notes thereto included elsewhere in this prospectus. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

	Year Ended December 31,

	2007			2008			2009			2010			2011
	(in thousands)
Statement of Operations Data:
Revenues:
Natural gas sales	$	16,663		$	13,978		$	12,079		$	23,453		$	27,352
Oil sales		6,108			5,477			2,539			3,723			23,641
Natural gas liquids sales		926			1,290			834			964			893

Total revenues		23,697			20,745			15,452			28,140			51,886
Operating expenses:
Lease operating		4,752			4,326			4,947			6,687			9,415
Workovers		1,330			3,434			764			1,993			1,320
Severance and ad valorem taxes		1,313			1,287			1,265			1,803			2,906
Exploration		24,967			6,839			1,547			3,579			4,934
Depletion, depreciation and amortization		11,805			7,130			13,208			17,288			33,992
Impairment of natural gas and oil properties		7,335			4,536			7,963			20,788			25,525
General and administrative		9,303			9,083			25,700			16,711			24,786

Total operating expenses		60,805			36,635			55,394			68,849			102,878

Operating loss		(37,108	)		(15,890	)		(39,942	)		(40,709	)		(50,992	)
Other income (expense):
Gain on property sales		2,375			168			46			802			281
Gain on derivative instruments		—			—			63			7,865			7,381
Interest expense		(681	)		(425	)		(4,582	)		(6,787	)		(6,947	)
Other income (expense)		711			746			160			(566	)		(42	)

Total other income (expense)		2,405			489			(4,313	)		1,314			673

Loss from continuing operations before taxes		(34,703	)		(15,401	)		(44,255	)		(39,395	)		(50,319	)
Income tax (expense) benefit		3,639			(16	)		(33	)		(13	)		(51	)

Loss from continuing operations		(31,064	)		(15,417	)		(44,288	)		(39,408	)		(50,370	)
Income from discontinued operations		—			—			2,150			5,912			9,946

Net loss		(31,064	)		(15,417	)		(42,138	)		(33,496	)		(40,424	)
Net loss attributable to non-controlling interests		—			—			1,365			—			—

Net loss attributable to Cinco Resources, Inc. stockholders		(31,064	)		(15,417	)		(40,773	)		(33,496	)		(40,424	)
Less: net effect of induced conversion of preferred stock to common stock(1)		—			—			—			—			(42,000	)

Net loss attributable to common shares	$	(31,064	)	$	(15,417	)	$	(40,773	)	$	(33,496	)	$	(82,424	)

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	As of December 31,								As of December 31, 2011

	2007		2008		2009		2010		Actual			As Adjusted(2)
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	7,608	$	18,841	$	9,647	$	37,982	$	8,766		$
Net property and equipment		76,652		93,157		156,361		227,452		322,472
Total assets		93,693		119,966		204,761		308,116		355,524
Long-term debt, including current maturities		5,863		12,000		70,700		86,000		109,871	(3)
Total stockholders' equity		69,262		85,698		102,524		161,187		204,471

	Year Ended December 31,

	2007			2008			2009			2010			2011
	(in thousands)
Other Financial Data:
Net cash provided by (used in) operating activities	$	699		$	7,312		$	(40,027	)	$	14,734		$	16,867
Net cash used in investing activities		(21,397	)		(32,244	)		(25,153	)		(84,619	)		(121,772	)
Net cash provided by financing activities		7,533			36,165			55,986			98,220			75,689
Adjusted EBITDAX(4)		8,030			4,440			(11,970	)		14,215			31,307

(1): Represents the value of common stock issued to holders of our preferred stock in excess of original conversion value as an inducement to convert all shares of preferred stock into common stock prior to completion of this offering.
(2): Gives effect to (i) a four for one stock split of our common stock to be effected prior to the closing of this offering, (ii) the issuance of 213,676 restricted shares of common stock that will occur concurrently with the closing of this offering and (iii) this offering and the application of the net proceeds as described in "Use of Proceeds."
(3): As of December 31, 2011, all amounts outstanding under our senior secured revolving credit facility and our second lien term loan facility are shown as current maturities due to our non-compliance with the applicable current ratio covenants. We have been granted a limited waiver related to this non-compliance for the quarters ended December 31, 2011 and March 31, 2012. As adjusted for this offering, we expect to be in compliance with our current ratio covenants through 2012.
(4): Adjusted 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 Adjusted EBITDAX as income or loss from continuing operations before interest expense, income tax expenses or benefits, realized gains or losses on interest rate derivatives, depletion, depreciation, and amortization, property impairments, exploration expenses, unrealized derivative gains or losses, interest and other income or expense, gains or losses on property sales and share-based compensation expense. Adjusted EBITDAX is not a measure of net income or loss as determined by GAAP. Our management believes Adjusted EBITDAX is useful because it allows us 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 income or loss from continuing operations in arriving at Adjusted 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. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, income or loss from continuing operations as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted 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 Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that Adjusted 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 of Adjusted EBITDAX to the GAAP financial measure of loss from continuing operations.

	Year Ended December 31,

	2007			2008			2009			2010			2011
	(in thousands)
Adjusted EBITDAX reconciliation to loss from continuing operations:
Loss from continuing operations	$	(31,064	)	$	(15,417	)	$	(44,288	)	$	(39,408	)	$	(50,370	)
Exploration		24,967			6,839			1,547			3,579			4,934
Depletion, depreciation and amortization		11,805			7,130			13,208			17,288			33,992
Impairment of natural gas and oil properties		7,335			4,536			7,963			20,788			25,525
Share-based compensation expense		1,031			1,825			5,287			8,723			10,976
Gains on property sales		(2,375	)		(168	)		(46	)		(802	)		(281	)
Realized loss on interest rate derivatives		—			—			340			978			1,002
Unrealized derivative gains		—			—			(436	)		(4,297	)		(1,511	)
Interest expense		681			425			4,582			6,787			6,947
Other (income) expense		(711	)		(746	)		(160	)		566			42
Income tax expense (benefit)		(3,639	)		16			33			13			51

Adjusted EBITDAX	$	8,030		$	4,440		$	(11,970	)	$	14,215		$	31,307

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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 related notes included 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. Some of the key factors which could cause actual results to vary from our expectations include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this prospectus, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See "Cautionary Note Regarding Forward-Looking Statements."

Overview

We are an independent exploration and production company focused on the acquisition, development and production of unconventional oil and natural gas resources. Our assets are located primarily in three core areas: the Eagle Ford Shale in South Texas, the Powder River Basin of Wyoming and the Woodford Shale in the Arkoma Basin of eastern Oklahoma. Our management and senior technical team has significant operational experience in these basins as well as in the geological zones we target for development. We have accumulated a balanced portfolio of properties between our more mature, gas-prone Woodford Shale properties and our oil-prone, less-developed properties in the Eagle Ford Shale and Powder River Basin. The majority of our Woodford Shale properties are held by production. We intend to focus our near-term activities on the development of our Eagle Ford Shale assets as well as further evaluation of our Powder River Basin properties.

From our inception in 2002 through 2008, we focused on the acquisition and development of conventional reserves in our historical core area of South Texas. In 2009, we acquired a private Arkoma Basin company that was primarily owned and controlled by Yorktown. This acquisition provided the majority of our current Arkoma Basin property base and included a significant acreage position in the Woodford Shale, which is an unconventional resource play. Unconventional resource plays typically involve a geologic formation that is productive over a larger area than a conventional reservoir but require more advanced techniques such as horizontal drilling and hydraulic fracturing to produce hydrocarbons in economic quantities. Subsequent to our entry into the Woodford Shale, we began to evaluate other unconventional opportunities that were potentially oil-prone, unlike the Woodford Shale, which is gas prone in our area. Based on these efforts, we have established positions in the Eagle Ford Shale of South Texas and the Powder River Basin of Wyoming, both active areas for the development of unconventional oil resources.

Since 2009, we have drilled and completed 35 gross Woodford Shale wells and 14 gross Eagle Ford Shale wells. Netherland, Sewell & Associates, Inc., our independent reserve engineers, estimated our proved reserves as of December 31, 2011 to be 286.1 Bcfe, of which 85% were natural gas and 26% were classified as proved developed reserves. For December 2011, our average net daily production was 30.0 MMcfed, of which 66% was natural gas. We exercise a high degree of operational control over our assets. We operated approximately 95% of our estimated proved reserves on a volume basis as of December 31, 2011 and approximately 90% of our average daily net production for December 2011.

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Known Trends and Uncertainties

The performance of our business is dependent on many factors that are difficult to predict and beyond our control including economic, political and regulatory developments.

Commodity prices. Natural gas and oil prices have historically been volatile. Since 2009 through March 2012, natural gas and oil prices, as quoted on the NYMEX, have ranged from a high of $6.072 per MMBtu of natural gas and $113.93 per Bbl of oil to a low of $2.23 per MMBtu of natural gas and $33.98 per Bbl of oil. While we utilize derivative instruments tied to natural gas and oil prices in an effort to mitigate some of this volatility, changes in natural gas and oil prices will continue to impact our revenues.

Availability of third party services. Like many other industry participants, we contract with third party service providers to drill and complete our wells. Some of the biggest challenges that we face are equipment shortages, increasing costs and lack of qualified personnel to operate drilling and completion equipment. Due to increasing levels of industry activity in the Eagle Ford Shale, drilling rigs, fracture stimulation services and associated materials have become harder to obtain and more expensive. Moreover, we have seen overall service costs increase in the Arkoma Basin despite the fact that industry activity has generally decreased over the last twelve months as a result of the lower natural gas price environment.

Regulatory environment. Exploration and production is a highly regulated business at the federal, state and local levels. The amount of regulatory scrutiny, as evidenced in the time and expense required to obtain required permitting, has generally been increasing. In the Powder River Basin, we operate largely on public lands managed by the Federal Bureau of Land Management. The amount of lead time and regulatory process required to permit wells and other surface facilities on public lands is typically longer and more complicated than it is on private lands. The majority of our properties in Oklahoma and Texas are on private land. Moreover, 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 current regulatory environment, and changes to it, could impact our ability to execute our development plans within budget and on the schedule we have forecast, materially impacting our financial condition, results of operations and cash flow.

Financial reporting and compliance. We believe that our general and administrative expenses will increase in connection with the completion of this offering as a result of our becoming a public company. This increase will consist primarily of legal and accounting fees and additional expenses associated with compliance with the Sarbanes-Oxley Act and other regulations. Increases in our staff compensation and other ongoing general and administrative expenses will be necessary to maintain and grow a publicly traded exploration and production company. A large part of these increases will be due to the cost of accounting support services, filing annual, quarterly and periodic reports with the SEC, investor relations activities, directors' fees, incremental directors' and officers' liability insurance costs and transfer agent fees.

Liquidity and Capital Resources

Our primary sources of liquidity have been capital contributions from Yorktown, cash flows from operations, borrowings under our credit facilities and asset sales. Our primary use of capital has been for the acquisition, exploration, development and production of oil and gas properties. As we pursue reserve and production growth, we continually monitor which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure

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activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us.

At March 31, 2012, we had a combined total of $130.2 million of debt outstanding, consisting of $80.0 million drawn on our senior secured revolving credit facility, $30.0 million drawn on our second lien term loan facility and $20.2 million in notes payable related to property acquisitions. At March 31, 2012, the borrowing base of our senior secured revolving credit facility was $85.0 million, resulting in $5.0 million of undrawn capacity.

After giving effect to this offering, assuming an initial public offering price of $ and the application of a portion of the net proceeds to pay down all amounts outstanding under our senior secured revolving credit facility and all amounts outstanding under our second lien term loan facility, we expect to have approximately $85.0 million available for borrowings under our senior secured revolving credit facility. We believe this liquidity, as well as cash flows from operations and the remaining net proceeds from this offering, will be sufficient to fund our 2012 capital expenditure budget.

Credit Facilities

We have a senior secured revolving credit facility and a second lien term loan facility. In December 2011, we amended each of our credit facilities. We intend to use a portion of the net proceeds from this offering to repay all amounts outstanding under our senior secured revolving credit facility and to repay all amounts outstanding under and retire our second lien term loan facility. There are no pre-payment penalties under either facility.

Senior secured revolving credit facility. We have a senior secured revolving credit facility with a four-year term that matures in January 2016. The amount of borrowings under our senior secured credit facility is limited to the lesser of $300.0 million or the amount of the borrowing base which is determined semi-annually on June 1 and December 1 by the lenders primarily based on estimates of the value of our proved reserves. As of December 31, 2011, our borrowing base was $85.0 million. Borrowings under our credit facilities are secured by mortgages on substantially all of our producing oil and gas properties and by equity interests in all of our subsidiaries.

Borrowings under our senior secured revolving credit facility bear interest at our election at either (i) a London Inter Bank Offer Rate, or LIBOR, based rate or (ii) the issuing bank's base rate plus an applicable margin tied to the amount drawn on the credit facility. Historically, we have elected LIBOR-based pricing where our applicable margin ranges from 2.00% to 3.00%. Upon the completion of this offering, our applicable margin range will decrease to 1.75% to 2.75%. Should we elect base rate pricing, our applicable margin would be 1.00% to 2.00%. Upon the completion of this offering, our applicable margin range should we elect base rate pricing will decrease to 0.75% to 1.75%.We can elect to have LIBOR-based borrowings based on one, two, three or six month LIBOR rates and have historically selected one or three-month based pricing. As of March 31, 2012, the interest rate payable on borrowings under our senior secured revolving credit facility was approximately 3.24%, which does not include the impact of our interest rate derivative transactions. There is also an annual commitment fee, payable quarterly, ranging between 0.375% and 0.500% on the undrawn portion of our borrowing base.

Key financial covenants under our senior secured revolving credit facility require us:

•: to maintain a minimum current ratio, which is defined as consolidated total current assets plus the unused availability under the credit agreement less current derivative assets divided by consolidated total current liabilities less current derivative liabilities, of not less than 1.00 to 1.00;

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•: to maintain a total debt to consolidated EBITDAX (as defined in our senior secured revolving credit facility) ratio, which is defined as total debt outstanding divided by an annualized or rolling four quarter EBITDAX calculation, of not more than 4.00 to 1.00; and
•: to maintain a consolidated EBITDAX to consolidated interest expense ratio, with both EBITDAX and consolidated interest expense calculated on an annualized or rolling quarter basis, of not less than 2.75 to 1.00.

The calculation of EBITDAX for purposes of our senior secured revolving credit facility differs from the calculation of Adjusted EBITDAX as presented in this prospectus and further described under "Summary—Summary Historical Consolidated Financial Data—Non-GAAP Financial Measure." In general, the EBITDAX calculation under our senior secured revolving credit facility permits us to also add back to earnings expensed workover costs and other one-time litigation settlement expenses.

As of December 31, 2011, the most recent date on which we were required to measure compliance, we were in compliance with each of these EBITDAX-based financial covenants; however, our ratio of current assets to current liabilities was 0.96 to 1.00. On February 28, 2012, our bank group granted a limited waiver of our non-compliance with our minimum current ratio requirements for the quarter ended December 31, 2011 and for our potential failure to comply with such covenant for the quarter ended March 31, 2012. As a result of this offering, we expect to be in compliance with our current ratio covenant for the quarter ending June 30, 2012 and for the remainder of 2012.

Our bank group has not completed its review of the title information that we have delivered to it. Consequently, the group waived until May 1, 2012 any default resulting from our failure to deliver title information in form and substance reasonably satisfactory to its agent. We believe that the title information that we have delivered should be reasonably satisfactory to the agent, and the agent is now in the process of reviewing the information. We do not believe that additional waivers will be required for title information.

Our senior secured revolving credit facility contains various covenants that limit our ability to take certain actions including, but not limited to, the following:

•: incur liens,
•: sell assets,
•: merge or consolidate,
•: make loans and investments,
•: incur debt,
•: engage in transactions with affiliates, and
•: make restricted payments such as dividends or distributions of property.

If an event of default exists under our senior secured revolving credit facility, the lenders will be able to accelerate the maturity of our senior secured revolving credit facility and exercise other rights and remedies. Events of default include, but are not limited to, the following events:

•: failure to pay any principal, interest, letters of credit or other fees when due,
•: material breach of representations or warranties,
•: failure to perform or observe any term, covenant, obligation or agreement in our senior secured revolving credit facility,
•: a bankruptcy or insolvency event involving us or our subsidiaries, and
•: a change of control as defined in our senior secured revolving credit facility.

As of March 31, 2012, we had outstanding borrowings of $80.0 million under our senior secured revolving credit facility and a borrowing base of $85.0 million, resulting in $5.0 million available for

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additional borrowings. We had outstanding borrowings under our senior secured revolving credit facility of $60.0 million at December 31, 2011 and of $56.0 million at December 31, 2010. At March 31, 2012, the interest rate on our senior secured revolving credit facility was approximately 3.24%.

Second lien term loan facility. We have a second lien term loan facility that matures in July 2016. As of December 31, 2011, we had outstanding borrowings of $30.0 million under our second lien term loan facility. We intend to use a portion of the net proceeds from this offering to repay all amounts outstanding under our second lien term loan facility and retire this facility.

Our second lien term loan facility requires us to comply with key financial covenants that are substantially similar to those financial covenants found in our senior secured revolving credit facility, except that:

•: we are required to maintain a total debt to consolidated EBITDAX ratio of not more than 4.50 to 1.00; and
•: we are required to maintain a consolidated EBITDAX to consolidated interest expense ratio of not less than 2.50 to 1.00.

As of December 31, 2011, the most recent date on which we were required to measure compliance, as with our senior secured revolving credit facility, we were in compliance with each of these EBITDAX-based financial covenants; however, our ratio of current assets to current liabilities was 0.96 to 1.00. On February 28, 2012, our bank group granted a limited waiver of our non-compliance with our minimum current ratio requirements for the quarter ended December 31, 2011 and for our potential failure to comply with such covenant for the quarter ended March 31, 2012.

Our bank group has not completed its review of the title information that we have delivered to it. Consequently, as with our senior secured revolving credit facility, the group waived until May 1, 2012 any default resulting from our failure to deliver title information in form and substance reasonably satisfactory to its agent. We believe that the title information that we have delivered should be reasonably satisfactory to the agent, and the agent is now in the process of reviewing the information. We do not believe that additional waivers will be required for title information.

Capital Expenditures Budget

Expenditures for acquisitions, exploration and development of oil and gas properties are the primary uses of our capital resources. We anticipate having capital expenditures of $161.7 million in 2012. The table below details our anticipated capital expenditures by region for the year ending December 31, 2012.

	Number of Wells

	Number of Wells				Capital Expenditures
	Gross		Net		Capital Expenditures
					($ in millions)
Drilling
Eagle Ford Shale		11		11.0	$	107.6
Powder River Basin		2		2.0		22.2
Woodford Shale		2		0.9		6.6
Other Areas(1)		—		—		2.1

Sub-total		15		13.9		138.5
Leasehold, Seismic and Other(2)		—		—		23.2

Total		15		13.9	$	161.7

(1): Includes workovers on South Texas non-Eagle Ford Shale properties.
(2): Includes $16.3 million in payments due in 2012 with respect to our acquisitions of Powder River Basin acreage in 2011. The majority of the remaining amount is intended for leasehold acquisitions.

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The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil and natural gas prices decline below what we consider acceptable levels, or costs increase to levels we consider unacceptable, we may choose to defer a portion of our budgeted capital expenditures until later periods in order to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Cash Flows

The following table summarizes our cash flows for the periods indicated.

	Year Ended December 31,

	2009			2010			2011
	(in thousands)
Net cash provided by (used in) operating activities	$	(40,027	)	$	14,734		$	16,867
Net cash used in investing activities		(25,153	)		(84,619	)		(121,772	)
Net cash provided by financing activities		55,986			98,220			75,689

Net increase (decrease) in cash	$	(9,194	)	$	28,335		$	(29,216	)

Cash flows provided by (used in) operating activities. Net cash provided by operating activities was approximately $16.9 million for the year ended December 31, 2011 and $14.7 million for the year ended December 31, 2010. The increase of $2.2 million was primarily due to an increase in revenues from our Eagle Ford Shale drilling program in 2011 that was partially offset by the increase in accrued liabilities related to the deferred payment on the November 2011 acquisition of Powder River Basin properties.

Net cash provided by (used in) operating activities was approximately $14.7 million for the year ended December 31, 2010 and approximately $(40.0) million for the year ended December 31, 2009. The increase of $54.8 million was primarily due to an increase in revenues from our successful Woodford Shale drilling program in 2010, as well as a substantial use of $34.8 million of cash in 2009 mostly related to bringing current overdue trade payables related to the acquisition of a private Arkoma Basin company.

Cash flows used in investing activities. The following table summarizes our cash flows used in investing activities for the periods indicated.

	Year Ended December 31,

	2009			2010			2011
	(in thousands)
Exploration and development of natural gas and oil properties	$	(25,032	)	$	(92,640	)	$	(120,397	)
Proceeds from property sales		3,455			8,409			24,277
Acquisition of natural gas and oil properties		(3,384	)		(299	)		(25,499	)
Cash acquired upon acquisition of private Arkoma Basin company		67			—			—
Other property and equipment additions		(259	)		(89	)		(153	)

Net cash used in investing activities	$	(25,153	)	$	(84,619	)	$	(121,772	)

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The increase in the cash we used in investing activities of $37.2 million during 2011 as compared to 2010 was primarily related to increased spending on our Eagle Ford Shale drilling activities and on our acreage purchased in the Powder River Basin of Wyoming, which was partially offset by the sale of non-strategic Arkoma Basin oil and gas properties.

The increase in the cash we used in investing activities during 2010 versus 2009 amounted to approximately $59.5 million and was primarily related to acreage acquisition and drilling costs on our Eagle Ford Shale properties and drilling costs on our Woodford Shale properties.

Cash flows provided by financing activities. Cash flows provided by financing activities were $75.7 million and $98.2 million for 2011 and 2010, respectively. During 2011, we received additional capital contributions, primarily from Yorktown, of $82.5 million, and we had $4.0 million in borrowings under our senior secured revolving credit facility. During 2010, we received $84.0 million in capital contributions from Yorktown and had net borrowings of $15.3 million under our senior secured revolving credit facility.

During the two years ended December 31, 2009 and 2008, cash flows provided by financing activities were $56.0 million and $36.2 million, respectively. Net cash provided by financing activities in 2009 resulted primarily from $105.0 million in preferred equity capital from Yorktown and repayments of $46.0 million on our senior secured revolving credit facility.

Contractual Obligations

We had the following material commitments and contractual obligations at December 31, 2011, unless otherwise stated.

	Payments due by period

	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years
	(in thousands)
Senior secured revolving credit facility(1)	$	60,000	$	—	$	—	$	60,000	$	—
Second lien term loan facility(1)		30,000		—		—		30,000		—
Office lease and equipment		4,922		1,820		3,102		—		—
Drilling rig commitments(2)		10,766		10,766		—		—		—
Executive employment obligations(3)		46,306		46,306		—		—		—
Asset retirement obligations(4)		7,148		—		—		—		7,148
Product transportation obligations(5)		7,213		2,617		4,596		—		—
Deferred payments for acreage acquisition(6)		20,176		15,724		4,452		—		—

Total	$	186,531	$	77,233	$	12,150	$	90,000	$	7,148

(1): At March 31, 2012, we had $80.0 million in borrowings outstanding under our senior secured revolving credit facility and $30.0 million outstanding under our second lien term loan facility. Our senior secured revolving credit facility matures on January 4, 2016, and our second lien term loan facility matures on July 4, 2016. These amounts do not include estimated interest on these borrowings, because our revolving borrowings have short-term interest periods, and we are unable to determine what our borrowing costs may be in future periods. Additionally, these amounts do not include commitment fees and other expenses as they depend on factors that change, such as the amounts borrowed, and are therefore not determinable. As of December 31, 2011, amounts outstanding under these facilities were included in current liabilities on our consolidated balance sheet due to our non-compliance with one of the financial covenants as described under "—Liquidity and Capital Resources—Credit Facilities." Such amounts are included in payments due between three and five years above based on their contractual maturities.

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(2): At March 31, 2012, we had three drilling rig contracts. Two were for periods of six months and one was for a period of three months.
(3): Immediately prior to this offering, we expect to enter into employment arrangements with certain members of our executive management team. Our maximum commitment under these employment arrangements, which would apply if the employees covered by these arrangements were all terminated without cause, was approximately $46.3 million. See "Executive Compensation and Other Information—Potential Payments Upon Termination or Change of Control" and "Executive Compensation and Other Information—Employment Agreements."
(4): Amounts represent our estimate of future asset retirement obligations. 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, including the rate of inflation, changing technology and the political and regulatory environment.
(5): In June 2007, we entered into a combination gathering and transportation service agreement. The contract term is for ten years and commits us to a 34,657,232 MMBtu minimum volume over an initial seven-year period. The contract is cancelable at any time; however, if terminated, a termination fee of the remaining minimum volume times $0.41 per MMBtu would be due. At December 31, 2011, the remaining volume was approximately 17,092,436 MMBtu and the termination fee would be approximately $7.0 million.
(6): In April 2011, we purchased acreage in the Powder River Basin of Wyoming for $18.7 million. We made a $12.0 million payment at closing and will pay the remaining $6.7 million in three equal installments in April 2012, 2013 and 2014. Additionally, in November 2011, we purchased approximately 20,000 additional net acres in the Powder River Basin for a purchase price of approximately $27.0 million. We paid $13.5 million of this amount at closing and will pay the additional $13.5 million in November 2012. This additional $13.5 million is included in amounts due within one year.

Sources of Our Revenues

We derive our revenues from the sale of natural gas, oil and natural gas liquids in the continental United States. Our revenues do not include the effects of commodity derivatives. For the year ended December 31, 2011, natural gas sales amounted to 53% and oil and natural gas liquids sales amounted to 45% and 2% of our revenues, respectively. In 2011, the percentage of our revenues that was derived from oil sales increased to 45%, from 13% in 2010, primarily as a result of our drilling program in the Eagle Ford Shale. Our revenues can vary significantly from period to period based on the level of our production and commodity pricing, which pricing historically has been volatile.

Derivative Instruments

Commodity Derivatives

We periodically enter into derivative financial instruments to mitigate the risk of volatility in commodity prices with respect to a portion of our gas and oil production. These instruments are used to manage the inherent uncertainty of future revenues due to gas and oil price volatility and to mitigate some of the potential negative impact on our cash flow. Our derivative financial instruments include fixed-price swaps, closed out swaps, basis swaps, costless price collars, call options and put spreads. We have not designated these derivatives as either cash-flow or fair value hedges, and, therefore, the unrealized gains and losses on open positions are reflected in gain (loss) on derivative instruments. At each period end, we recognize cash settled derivatives as a realized gain or loss, and we estimate the fair value of our commodity derivatives that will cash settle in future periods and recognize an unrealized gain or loss.

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Interest Rate Swaps

We periodically enter into interest rate swaps to manage our exposure to interest rate volatility. Our interest rate swaps include contracts in which we pay a fixed rate and receive a variable rate on a total notional principal amount.

Principal Components of Our Cost Structure

We use the successful efforts method of accounting for our oil and natural gas producing activities. See "—Critical Accounting Policies and Estimates—Method of accounting for oil and natural gas properties."

Lease operating. These are daily costs incurred to bring oil and gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance and repairs related to our oil and gas properties.

Workovers. These are costs incurred in remedial operations to maintain optimal production rates or to restore production from a previously producing zone. Costs related to attempting to secure production from a zone that has not previously produced are capitalized.

Severance and ad valorem taxes. Severance taxes are paid on produced natural gas, oil and natural gas liquids 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 severance taxes we pay correlate to the changes in oil and gas revenues. Ad valorem taxes are property taxes.

Exploration. These are costs incurred in identifying areas that may warrant examination, and in further examining specific areas, for oil and gas reserves that are not capitalized as part of a specific property. They would include such costs as geological and geophysical evaluation costs, seismic acquisition costs, accretion of asset retirement obligations, maintenance of land and title records, delay rentals and exploratory dry hole costs resulting from the unsuccessful drilling of an exploratory well to find and produce oil and gas in an unproved area.

Depletion, depreciation and amortization. Capitalized amounts attributed to estimated proved natural gas and oil properties are depleted by the unit-of-production method. Depletion, depreciation and amortization are computed based on quantities produced in relation to estimated proved reserves. Depreciation of other property and equipment is based on the estimated useful life of the asset which ranges from five to seven years. Depletion, depreciation and amortization also includes the accretion of the estimated discounted amount of our asset retirement obligations for our oil and gas properties.

Impairment of natural gas and oil properties. Unproved properties are periodically assessed for impairment of value, and a loss is recognized at the time of the impairment by providing an impairment allowance. Capitalized costs of proved properties are evaluated for impairment based on an analysis of undiscounted future cash flows. If the future undiscounted cash flows are insufficient to recover the net capitalized cost related to proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized cost related to proved properties and their estimated fair values.

In determining impairments, we assess undiscounted future net cash flows for a field relative to its carrying value. If a field's undiscounted future net cash flows are less than its carrying value, the field will most likely be impaired. Following determination of impairments for 2011, all of our material fields had undiscounted future net cash flows substantially in excess of carrying values. Our Red Fish Bay field, which is a conventional field in South Texas, has a carrying value in excess of our estimate of fair market value, although its undiscounted future net cash flows are greater than its carrying value. We estimate the fair market value for the field to be approximately $40 million, compared to a carrying

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value of $57.8 million. Our Red Fish Bay field could be impaired if oil and natural gas prices trend lower. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Method of accounting for oil and natural gas properties" for a discussion of factors considered in determining impairments.

General and administrative expense. These expenses consist primarily of personnel, legal, consulting, office rent and non-cash stock compensation expense. These expenses are reduced by overhead reimbursements received from other working interest owners where we are the operator of the property.

Gain (loss) on property sales. This represents the gain or loss recognized on oil and gas properties or other equipment sold. Sales proceeds in excess of cost basis result in a gain while sales proceeds less than cost basis result in a loss.

Gain (loss) on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of crude oil and natural gas. Additionally, we utilize interest rate derivatives, such as swaps and caps, to reduce our exposure to fluctuations in interest rates on our outstanding debt. These amounts represent (i) the recognition of unrealized gains and losses associated with our open derivative contracts as commodity prices or interest rates change and commodity derivative and interest rate contracts expire or new ones are entered into, and (ii) our realized gains and losses on the settlement of these commodity or interest rate derivative instruments. We classify these gains and losses as operating activities in our consolidated statements of cash flows.

Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our senior secured revolving credit facility and our second lien term loan facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We have entered into various interest rate derivative contracts to mitigate the effects of interest rate changes. We do not designate these derivative contracts as hedges and, therefore, hedge accounting treatment is not applicable. Realized and unrealized gains or losses on these interest rate contracts are included in non-operating income (expense) as discussed above. We reflect interest paid to the lenders as interest expense. In addition, we include the amortization of deferred financing costs (including origination and amendment fees) and commitment fees in interest expense.

Income (loss) from discontinued operations. During the years ended December 31, 2011 and 2010, we sold portions of our Arkoma Basin properties that were either located in non-core areas of our operations in the Arkoma Basin or represented small, non-operated interests in such properties. We include all of the historic operating results of the properties sold, along with the related gains on sale, in discontinued operations on our statement of operations.

Results of Operations

The following is a discussion of our consolidated results of operations. You should read this discussion in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this prospectus. Comparative results of operations for the periods indicated are discussed below.

Revenues

Year ended December 31, 2011 as compared to year ended December 31, 2010

The following table sets forth summary information regarding natural gas, oil and natural gas liquids revenues, production volumes, average product prices and realized gains or losses on commodity

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derivatives for the periods indicated. We determine natural gas equivalents by using the ratio of six Mcf of natural gas to one barrel of oil or one barrel of natural gas liquids.

	Year Ended December 31,

	Year Ended December 31,				Total Unit Change			Total % Change
	2010		2011		Total Unit Change			Total % Change
	(in thousands, except as otherwise noted)
Revenues:
Natural gas sales	$	23,453	$	27,352	$	3,899			17	%
Oil sales		3,723		23,641		19,918			535
Natural gas liquids sales		964		893		(71	)		(7	)

Total revenues		28,140		51,886		23,746			84
Realized gain on commodity derivatives		4,546		6,872		2,326			51

Total revenues including derivative impact	$	32,686	$	58,758	$	26,072			80

Production:
Natural gas (MMcf)		6,627.0		8,038.7		1,411.7			21
Oil (MBbls)		48.2		250.7		202.5			420
Natural gas liquids (MBbls)		24.1		18.5		(5.6	)		(23	)
Equivalents (MMcfe)		7,060.8		9,653.9		2,593.1			37
Average daily equivalent production (MMcfed)		19.3		26.4		7.1			37
Average prices:
Natural gas ($ per Mcf)	$	3.54	$	3.40	$	(0.14	)		(4	)
Oil ($ per Bbl)		77.24		94.30		17.06			22
Natural gas liquids ($ per Bbl)		40.00		48.27		8.27			21
Equivalents ($ per Mcfe)		3.99		5.37		1.38			35
Realized gain (loss) on commodity derivatives ($ per Mcfe)		0.64		0.72		0.08			11

Natural gas equivalents including realized derivative impact ($ per Mcfe)	$	4.63	$	6.09	$	1.46			32

Natural gas, oil and natural gas liquids revenues. The total increase in revenues for the year ended December 31, 2011 as compared to the year ended December 31, 2010 was largely attributable to higher oil and gas production volumes as well as an increase in realized oil prices, and the increasing percentage of oil and natural gas liquids as an overall percentage of our equivalent production. The increase in our production volumes for the year ended December 31, 2011, as compared to the year ended December 31, 2010, was primarily related to our drilling operations in the Eagle Ford Shale. We expect continued growth in oil and natural gas liquids production volumes while the drilling we plan to do specifically for natural gas will generally mitigate natural declines.

Without taking into consideration the impact of realized gains or losses on commodity derivatives, the net dollar effect of changes in prices (calculated as the change in period-to-period average prices multiplied by current period production volumes for natural gas, oil and natural gas liquids) and the net dollar effect of the change in production (calculated as the changes in period-to-period volumes for oil and gas multiplied by the prior period average prices) are shown below.

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Effects of Changes in Prices and Volumes:

	Change in prices(1)			Production volumes for the year ended December 31, 2011(2)		Total net dollar effect of change

				(in thousands)		(in thousands)
Effect of change in prices:
Natural gas	$	(0.14	)		8,038.7	$	(1,098	)
Oil		17.06			250.7		4,277
Natural gas liquids		8.27			18.5		153

Total due to prices							3,332

	Change in production volumes(2)			Average prices for the year ended December 31, 2010(1)

	(in thousands)
Effect of change in volumes:
Natural gas		1,411.7		$	3.54		4,997
Oil		202.5			77.24		15,641
Natural gas liquids		(5.6	)		40.00		(224	)

Total due to volumes							20,414

Total change in revenues						$	23,746

(1): Prices shown are realized, exclude realized gains (losses) on commodity derivatives and are based on $ per Mcf for natural gas and $ per Bbl for oil and natural gas liquids.
(2): Production volumes are presented in MMcf for natural gas and MBbls for oil and natural gas liquids.

Realized gain on commodity derivatives. Our realized gain on commodity derivatives increased by approximately $2.3 million to $6.8 million for the year ended December 31, 2011 from $4.5 million for the year ended 2010. The realized gain from our open natural gas positions increased primarily as a result of the decline in natural gas prices during the comparable periods. The realized gain from our open oil positions increased because of the decline in oil prices and our decision to monetize our oil positions in August of 2011. Due to realized gains on commodity derivatives, for the year ended December 31, 2011, we realized an additional $0.80 per Mcf on our natural gas volumes and an additional $1.85 per Bbl on our oil volumes. On a natural gas equivalent basis, the gain was $0.72 per Mcfe. For the year ended December 31, 2010, realized gains on commodity derivatives increased prices on our natural gas by $0.69 per Mcf. On a natural gas equivalent basis, the gain was $0.64 per Mcfe.

Year ended December 31, 2010 as compared to year ended December 31, 2009

The following table sets forth summary information regarding natural gas, oil and natural gas liquids revenues, production volumes, average product prices and realized gains or losses on commodity

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derivatives for the periods indicated. We determine natural gas equivalents by using the ratio of six Mcf of natural gas to one barrel of oil or one barrel of natural gas liquids.

	Year Ended December 31,

	Year Ended December 31,					Total Unit Change			Total % Change
	2009			2010		Total Unit Change			Total % Change
	(in thousands, except as otherwise noted)
Revenues:
Natural gas sales	$	12,079		$	23,453	$	11,374			94	%
Oil sales		2,539			3,723		1,184			47
Natural gas liquids sales		834			964		130			16

Total revenues		15,452			28,140		12,688			82
Realized gain (loss) on commodity derivatives		(33	)		4,546		4,579			—

Total revenues including derivative impact	$	15,419		$	32,686	$	17,267			112

Production:
Natural gas (MMcf)		3,601.3			6,627.0		3,025.7			84
Oil (MBbls)		43.5			48.2		4.7			11
Natural gas liquids (MBbls)		25.9			24.1		(1.8	)		(7	)
Equivalents (MMcfe)		4,017.7			7,060.8		3,043.1			76
Average daily equivalent production (MMcfed)		11.0			19.3		8.3			76
Average Prices:
Natural gas ($ per Mcf)	$	3.35		$	3.54	$	0.19			6
Oil ($ per Bbl)		58.37			77.24		18.87			32
Natural gas liquids ($ per Bbl)		32.20			40.00		7.80			24
Equivalents ($ per Mcfe)		3.85			3.99		0.14			4
Realized gain (loss) on commodity derivatives ($ per Mcfe)		(0.01	)		0.64		0.65			—

Natural gas equivalents including derivative impact ($ per Mcfe)	$	3.84		$	4.63	$	0.79			21

Natural gas, oil and natural gas liquids revenues. Our increase in total revenues was attributable to higher oil and gas production volumes as well as an increase in realized oil, gas and natural gas liquids prices for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase in production was primarily related to our Arkoma Basin Woodford Shale drilling program.

Without taking into consideration the impact of realized gains or losses on commodity derivatives, the net dollar effect of increases in prices (calculated as the change in period-to-period average prices multiplied by current period production volumes for natural gas, oil and natural gas liquids) and the net dollar effect of the change in production (calculated as the change in period-to-period volumes for oil, gas and natural gas liquids multiplied by the prior period average prices) are shown below.

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Effects of Changes in Prices and Volumes:

	Change in prices(1)		Production volumes for the year ended December 31, 2010(2)		Total net dollar effect of change

			(in thousands)		(in thousands)
Effect of change in prices:
Natural gas	$	0.19		6,627.0	$	1,238
Oil		18.87		48.2		910
Natural gas liquids		7.80		24.1		188

Total due to prices						2,336

	Change in production volumes(2)			Average prices for the year ended December 31, 2009(1)

	(in thousands)
Effect of change in volumes:
Natural gas		3,025.7		$	3.35		10,136
Oil		4.7			58.37		274
Natural gas liquids		(1.8	)		32.20		(58	)

Total due to volumes							10,352

Total change in revenues						$	12,688

(1): Prices shown are realized, exclude realized gains (losses) on commodity derivatives and are based on $ per Mcf for natural gas and $ per Bbl for oil and natural gas liquids.
(2): Production volumes are presented in MMcf for natural gas and MBbls for oil and natural gas liquids.

Realized gain (loss) on commodity derivatives. Our realized gain on commodity derivatives increased by approximately $4.6 million to $4.5 million for the year ended December 31, 2010 from a realized loss of $33,000 for the year ended December 31, 2009. The realized gain from our open natural gas positions increased primarily as a result of the decline in natural gas prices during the comparable periods. Due to realized gains on commodity derivatives, for the year ended December 31, 2010, we realized an additional $0.69 per Mcf on our natural gas volumes. On a natural gas equivalent basis, the gain was $0.64 per Mcfe. For the year ended December 31, 2009, realized losses on commodity derivatives decreased prices on our natural gas by $0.01 per Mcf. On a natural gas equivalent basis, the loss was $0.01 per Mcfe.

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Expenses

Year ended December 31, 2011 as compared to year ended December 31, 2010

The following table summarizes our operating expenses and other income (expense) for the periods indicated.

	Year Ended December 31,

	Year Ended December 31,						Total Unit Change			Total % Change
	2010			2011			Total Unit Change			Total % Change
	(in thousands, except as otherwise noted)
Operating expenses:
Lease operating	$	6,687		$	9,415		$	2,728			41	%
Workovers		1,993			1,320			(673	)		(34	)
Severance and ad valorem taxes		1,803			2,906			1,103			61
Exploration		3,579			4,934			1,355			38
Depletion, depreciation and amortization		17,288			33,992			16,704			97
Impairment of natural gas and oil properties		20,788			25,525			4,737			23
General and administrative		16,711			24,786			8,075			48

Total operating expenses		68,849			102,878			34,029			49

Operating loss		(40,709	)		(50,992	)		(10,283	)		25
Other income (expense):
Gain on property sales		802			281			(521	)		(65	)
Gain on derivative instruments		7,865			7,381			(484	)		(6	)
Interest expense		(6,787	)		(6,947	)		(160	)		2
Other income (expense)		(566	)		(42	)		524			(93	)

Total other income (expense)		1,314			673			(641	)		(49	)

Loss from continuing operations before taxes		(39,395	)		(50,319	)		(10,924	)		28
Income tax expense		(13	)		(51	)		(38	)		292

Loss from continuing operations		(39,408	)		(50,370	)		(10,962	)		28
Income from discontinued operations		5,912			9,946			4,034			68

Net loss	$	(33,496	)	$	(40,424	)	$	(6,928	)		21

Expenses per Mcfe:
Lease operating	$	0.95		$	0.98		$	0.03			3
Workovers		0.28			0.14			(0.14	)		(50	)
Severance and ad valorem taxes		0.26			0.30			0.04			15
Depletion, depreciation and amortization		2.45			3.52			1.07			44
General and administrative		2.37			2.57			0.20			8

Lease operating and workovers. Our lease operating expense increased by $2.7 million, an increase of 41% for the year ended December 31, 2011 as compared to the year ended December 31, 2010. Over this period, our production increased 37% from 7.1 Bcfe to 9.7 Bcfe. As a result, our lease operating expense per unit increased $0.03 per Mcfe, or 3% for 2011 as compared to 2010. This increase was related to the increasing percentage of oil of our overall production mix, which has higher per unit operating costs. Our workovers decreased substantially for 2011 as compared to 2010. This

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decrease was a result of workover activities on some of our conventional South Texas properties that took place during 2010 that did not occur during the comparable period in 2011.

Severance and ad valorem taxes. Our severance and ad valorem taxes increased 61%, for 2011 as compared to 2010. The increase in our severance and ad valorem taxes was primarily due to the increases in our production and revenues by 37% and 84%, respectively, for 2011 as compared to 2010.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization increased 97%, for 2011 as compared to 2010. This increase is a result of additional drilling and completion costs associated with our Eagle Ford Shale development activities. As we receive additional well results and new proved reserve estimates, we will reassess our unit-of-production depletion calculation. A portion of this increase was also due to the increases in our production by 37% for 2011 as compared to 2010.

Impairment of natural gas and oil properties. Impairment charges on our oil and gas properties consisted of the following during the years ended December 31:

	2010		2011

Proved Properties:
Eagle Ford Shale	$	—	$	18,265
Other South Texas Properties		16,541		2,515
Woodford Shale		58		177
Other Areas		291		10
Unproved Properties
Eagle Ford Shale		—		1,438
Other South Texas Properties		2,122		7
Woodford Shale		1,592		3,113
Other Areas		184		—

Total Impairment	$	20,788	$	25,525

Impairment charges on our Eagle Ford Shale proved properties resulted from downward reserve revisions based on the results of our drilling performance. Additionally, we concluded during the year ended December 31, 2011 that, given the current low natural gas price environment, we would no longer pursue drilling activities on an Eagle Ford Shale prospect area located in the dry gas window in the near term, which resulted in the unproved property impairment. Impairment charges on our other South Texas Properties resulted from declines in natural gas prices that reduced our estimated future net cash flow related to these properties during both the year ended December 31, 2010 and 2011. For our other Arkoma Basin unproved properties, we drilled a dry hole on our Oklahoma Wildlife Prospect that led to our decision to forego developing the remainder of that prospect, resulting in the unproved property impairment. Unproved property impairments recorded during 2010 and 2011 on our other South Texas Properties resulted from our decision to not pursue development on certain leaseholds in that area. Remaining impairment charges were relatively comparable between periods.

General and administrative expense. The increase in general and administrative expense resulted from compensation expense increasing by $4.5 million in 2011 from 2010's total, as well as increases in other categories described below. This increase in compensation expense was related to $2.3 million of additional stock compensation expense resulting from the accelerated vesting of stock related to the closing of the Fort Smith office and the acquisition of Cima, an additional $2.0 million of cash bonus compensation related to the sale of non-strategic Arkoma Basin properties for both executives and former Fort Smith offices employees and an increase of approximately $0.9 million of severance expense related to the closure of our Fort Smith office. Additionally, consultant compensation increased by $1.1 million mainly due to the cost of the fairness opinion related to the acquisition of

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Cima, and legal expenses increased by $1.2 million related to continuing litigation and Cima acquisition related work. We also incurred board of director fees of $0.5 million that we did not have prior to adding independent board members in 2011. Lastly, our well operating overhead income, that reduces general and administrative expense, decreased by $0.7 million due to the sale of our non-strategic Arkoma Basin properties.

Gain on derivative instruments. The following table summarizes our gain on derivative instruments for the periods indicated.

	Year Ended December 31,

	2010			2011
	(in thousands)
Gain on derivative instruments:
Realized commodity derivative gain	$	4,546		$	6,872
Unrealized commodity derivative gain		5,156			565

Total commodity derivative gain		9,702			7,437
Realized interest rate derivative loss		(978	)		(1,002	)
Unrealized interest rate derivative gain (loss)		(859	)		946

Total interest rate derivative loss		(1,837	)		(56	)

Total gain on derivative instruments	$	7,865		$	7,381

Our unrealized gain on commodity derivatives was $0.6 million for 2011, compared to a gain of $5.2 million for 2010.

During the period from January 1, 2011 through December 31, 2011, the net fair value of our commodity derivatives increased by $0.6 million. This increase in the net fair value of our commodity derivatives was primarily due to a decrease in natural gas prices in 2011, and the addition of natural gas derivative contracts.

Our realized losses from interest rate derivatives remained fairly constant at $1.0 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010. We recorded an unrealized gain of $0.9 million for 2011 as compared to an unrealized loss of $0.9 million for 2010. The gain we recorded in 2011 related to an increase in the one month LIBOR rates during the period, while the loss we recorded in 2010 related to a decrease in one month LIBOR rates during the period. The impacts of our commodity derivatives are described in our discussion of revenues.

Income (loss) from discontinued operations. During both 2010 and 2011, we sold portions of our Arkoma Basin properties that were either located in non-core areas of our operations in the Arkoma Basin or represented small, non-operated interests in such properties. The increase in income from discontinued operations resulted primarily from increased gains on sale. Properties sold during 2010 resulted in a gain of $2.1 million versus $8.2 million for properties sold during 2011. The net results of operations on sold properties decreased by $2.0 million from 2010 to 2011, due to the absence of the result of operations of the properties sold during 2010.

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Year ended December 31, 2010 as compared to year ended December 31, 2009

The following table summarizes our operating expenses and other income (expense) for the periods indicated.

	Year Ended December 31,

	Year Ended December 31,						Total Unit Change			Total % Change
	2009			2010			Total Unit Change			Total % Change
	(in thousands, except as otherwise noted)
Operating expenses:
Lease operating	$	4,947		$	6,687		$	1,740			35	%
Workovers		764			1,993			1,229			161
Severance and ad valorem taxes		1,265			1,803			538			43
Exploration		1,547			3,579			2,032			131
Depletion, depreciation and amortization		13,208			17,288			4,080			31
Impairment of natural gas and oil properties		7,963			20,788			12,825			161
General and administrative		25,700			16,711			(8,989	)		(35	)

Total operating expenses		55,394			68,849			13,455			24

Operating loss		(39,942	)		(40,709	)		(767	)		2
Other income (expense):
Gain on property sales		46			802			756			—
Gain on derivative instruments		63			7,865			7,802			—
Interest expense		(4,582	)		(6,787	)		(2,205	)		48
Other income (expense)		160			(566	)		(726	)		(454	)

Total other income (expense)		(4,313	)		1,314			5,627			(131	)

Loss from continuing operations before taxes		(44,255	)		(39,395	)		4,860			(11	)
Income tax expense		(33	)		(13	)		20			(61	)

Loss from continuing operations		(44,288	)		(39,408	)		4,880			(11	)
Income from discontinued operations		2,150			5,912			3,762			175

Net loss		(42,138	)		(33,496	)		8,642			(21	)
Net loss attributable to non-controlling interests		1,365			—			(1,365	)		—

Net loss attributable to Cinco Resources, Inc. stockholders	$	(40,773	)	$	(33,496	)	$	7,277			(18	)

Expenses per Mcfe:
Lease operating	$	1.23		$	0.95		$	(0.28	)		(23	)
Workovers		0.19			0.28			0.09			47
Severance and ad valorem taxes		0.31			0.26			(0.05	)		(16	)
Depletion, depreciation and amortization		3.29			2.45			(0.84	)		(26	)
General and administrative		6.40			2.37			(4.03	)		(63	)

Lease operating and workovers. The increase in our lease operating expense of 35% in 2010, as compared to 2009, resulted from the combination of a 76% increase in production from 4.0 Bcfe in 2009 to 7.1 Bcfe in 2010 and a 23% decrease in our expense per unit. The decrease in our expense per unit was attributable to our ability to spread our fixed well operating costs over a larger production volume. The increase in workover expense resulted from greater workover activity on some of our

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conventional South Texas properties during the year ended December 31, 2010 as compared to the year ended December 31, 2009.

Severance and ad valorem taxes. The increase in our severance and ad valorem taxes was primarily due to the increases in our production and revenues by 76% and 82%, respectively, for the year ended December 31, 2010 as compared to the year ended December 31, 2009.

Exploration. The increase in exploration costs was primarily attributable to an increase in seismic purchases and other geological and geophysical expenses incurred in 2010 relative to 2009.

Depletion, depreciation and amortization. The increase in our depletion, depreciation and amortization expense resulted from the combination of an 76% increase in production in 2010 relative to 2009 and a 26% decrease in our depletion expense per unit-of-production for 2010 relative to 2009. The decrease in our depletion expense per unit of production resulted primarily from our addition in 2010 of estimated proved reserves associated with our Woodford Shale properties.

Impairment of natural gas and oil properties. Impairment charges on our oil and gas properties consisted of the following during the years ended December 31:

	2009		2010

Proved Properties:
Other South Texas Properties	$	4,742	$	16,541
Woodford Shale		2,207		58
Other Areas		211		291
Unproved Properties
Other South Texas Properties		—		2,122
Woodford Shale		—		1,592
Other Areas		803		184

Total Impairment	$	7,963	$	20,788

Impairment charges on our proved properties resulted from declines in natural gas prices that reduced our estimated future net cash flow related to these properties during both the years ended December 31, 2009 and 2010. Unproved property impairments recorded during both periods resulted primarily from our decision to not pursue development on certain leaseholds in the respective areas.

General and administrative expense. Our general and administrative expense decreased by approximately 35% for the year ended December 31, 2010 as compared to the year ended December 31, 2009. This decrease was primarily the result of a $1.5 million decrease in personnel expense related synergies realized with our acquisition of a private Arkoma Basin company. In addition to these personnel synergies, consulting expense decreased by approximately $3.5 million as a result of lower legal, tax and accounting fees, and miscellaneous expenses decreased by $2.6 million primarily due to decreased legal settlement expenses.

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Gain (loss) on derivative instruments. The following table summarizes our gain (loss) on derivative instruments for the periods indicated.

	Year Ended December 31,

	2009			2010
	(in thousands)
Gain (loss) on derivative instruments:
Realized commodity derivative gain (loss)	$	(33	)	$	4,546
Unrealized commodity derivative gain		1,124			5,156

Total commodity derivative gain		1,091			9,702
Realized interest rate derivative loss		(340	)		(978	)
Unrealized interest rate derivative loss		(688	)		(859	)

Total interest rate derivative loss		(1,028	)		(1,837	)

Total gain on derivative instruments	$	63		$	7,865

Our unrealized gain on commodity derivatives was $5.2 million for 2010, compared to a gain of $1.1 million during 2009.

During the period from January 1, 2010 through December 31, 2010, the net fair value of our commodity derivatives increased from $1.1 million to $6.3 million, resulting in a net unrealized gain of $5.2 million for the year ended December 31, 2010. This increase in the net fair value of our commodity derivatives was primarily due to a decrease in natural gas prices during 2010. During the period from January 1, 2009 through December 31, 2009, the net fair value of our commodity derivatives increased from $0.0 million to $1.1 million, resulting in a net unrealized gain of $1.1 million for the year ended December 31, 2009. This increase in the net fair value of our commodity derivatives was primarily due to a decrease in natural gas prices in 2009 and the initiation of a commodity risk management strategy using derivatives.

Our realized losses from interest rate derivatives increased to $1.0 million for the year ended December 31, 2010 as compared to a loss of $0.3 million for the year ended December 31, 2009. We recorded an unrealized loss of $0.9 million for the year ended December 31, 2010 as compared to an unrealized loss of $0.7 million for the year ended December 31, 2009. The losses we recorded in the years ended December 31, 2010 and 2009 related to a decrease in the one month LIBOR rates during the applicable periods. The impacts of our commodity derivatives are described in our discussion of revenues.

Interest expense. During the year ended December 31, 2010, the amount drawn on our senior secured revolving credit facility was higher than in 2009, and we ended the year with a balance of $56.0 million, as compared to the year-end balance of $40.7 million in 2009. This increase in borrowings was the primary reason for higher interest expense in 2010 as compared to 2009.

Income (loss) from discontinued operations. During the years ended December 31, 2010 and 2011, we sold portions of our Arkoma Basin properties that were either located in non-core areas of our operations in the Arkoma Basin or represented small, non-operated interests in such properties. The increase in income from discontinued operations resulted from increased gains on sale and higher revenues due primarily to increased commodity prices. Properties sold during the year ended December 31, 2010 resulted in a gain of $2.1 million while there were no properties sold during the year ended December 31, 2009. The net results of operations on sold properties increased by $1.7 million from 2009 to 2010, due primarily to increased commodity prices realized during 2010 as compared to 2009.

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Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based on our consolidated financial statements and have been prepared in accordance with GAAP and include the accounts of Cinco Resources, Inc. and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. We have outlined below certain accounting policies that are of particular importance to the presentation of our financial condition and results of operations and require the application of significant judgment or estimates by our management. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, share-based compensation, asset retirement obligations, and deferred income tax assets and liabilities. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material.

Revenues and accounts receivable

We recognize revenues for our production when the quantities are delivered to, or collected by, the respective purchaser using the sales method. Delivery or collection by a customer occurs at the custody transfer point, which is typically when the natural gas enters a third party's pipeline or oil exits the lease by truck. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. All transportation costs are included in lease operating expense.

Method of accounting for oil and natural gas properties

We use the successful efforts method of accounting for our oil and natural gas producing activities. Costs to acquire mineral interests in natural gas and oil properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have found proved reserves. If we determine that the wells did not find proved reserves, the costs are charged to expense. There were no exploratory wells capitalized, pending determination of whether the wells found proved reserves at December 31, 2011, 2010 or 2009.

Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties are charged to expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than one year while activities are in progress to bring the assets to their intended use. Through December 31, 2011, 2010 and 2009, we have not capitalized any interest costs because our exploration and development projects generally last less than one year. Costs incurred to maintain wells and related equipment are charged to expense as incurred. On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depletion, depreciation and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depletion and amortization with a resulting gain or loss recognized in income.

Capitalized amounts attributable to proved natural gas and oil properties are depleted by the unit-of-production method over proved reserves. Unproved natural gas and oil properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance.

Capitalized costs related to proved natural gas and oil properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income from operations equal to the

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difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

In determining impairments, we assess undiscounted cash flow for a field relative to its carrying value. If a field's undiscounted cash flow is less than its carrying value, the field will be impaired. If a field's undiscounted cash flow is less than its fair market value but exceeds its carrying value, the field may be impaired as a result of lower commodity prices. Fair market value is generally considered to be the price that a willing buyer would pay and a willing seller would accept for a property that has been exposed to the market for a reasonable period, with neither party being under compulsion to buy or sell, and both having a reasonable knowledge of the relevant facts. Estimates of fair market value are based on our knowledge of current trading values of petroleum properties correlated with projected producing rates and the quality of reserves. Our calculation of the fair market value for each field area used our internal interpretation of proved, probable and possible reserves and consider various price and cost scenarios to recovery these reserves. The key assumptions we used in our evaluation were the NYMEX futures price strip as of the valuation date and the current cost to produce the properties. The net present value for each reserve category was then risked. This total risked net present value calculation was compared to generally known trading values on a reserve and production basis. In addition, we considered most recent cash flow multiples and future project cash flows to estimate a reasonable fair market value for each property.

As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment. Our estimation of fair market value has been influenced by our understanding of the technological, economic, political, and other factors that may affect the value of the properties.

Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to certain economic assumptions, our estimates are based on other assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions used in our evaluation.

Share-based compensation

We measure and record compensation expense for all share-based payment awards to employees and directors based on estimated grant-date fair values. Compensation costs for share-based awards are recognized over the requisite service period based on the grant-date fair value. Restricted stock compensation cost is based on the award's estimated grant-date fair value. Since we are not publicly traded we do not have a listed price with which to calculate fair value. We have historically and consistently calculated fair value using combined valuation models including an income approach, utilizing future discounted and undiscounted cash flows, a market approach, taking into consideration peer group analysis of publicly traded companies, and when available, actual cash transactions in our common stock.

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Derivative instruments

We are exposed to certain risks relating to our ongoing business operations. Our largest areas of risk exposure relate to commodity prices and interest rates. We use derivative instruments primarily to manage commodity price risk and interest rate risk.

All derivative financial instruments are recognized at fair value as either assets or liabilities on our consolidated balance sheet. Changes in the fair value of these derivative financial instruments are recorded in the consolidated statement of operations. Cash settlements with counterparties to our derivative financial instruments are also recorded in the consolidated statement of operations. By using derivative financial instruments to hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the derivative instruments are placed with a number of counterparties whom we believe to be creditworthy. It is our policy to enter into derivative contracts only with counterparties deemed by management to be competent and competitive market makers.

Market risk is the change in the value of a derivative financial instrument that results from a change in commodity prices, interest rates or other relevant factors affecting the value of the derivative. The market risks associated with commodity price and interest rate contracts are managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. We do not hold or issue derivative financial instruments for speculative trading purposes.

Fair value measures

Certain of our assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the "exit price."

Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 measurements are based on inputs other than quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active. Level 3 measurements have the lowest priority and are based upon inputs that are not observable from objective sources. The most common Level 3 fair value measurement is an internally developed cash flow model. We use valuation techniques based on the available inputs to measure the fair values of our assets and liabilities.

Oil and natural gas reserve quantities and future net revenues

Netherland, Sewell & Associates, Inc., our independent reserve engineers, has prepared 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 estimated proved reserves in this prospectus. The SEC's revised rules define proved reserves as the 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 project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Our independent reserve engineers must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated at least annually and consider recent production levels and other technical information about each well.

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Estimating oil and natural gas reserves is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, revenues, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial position, results of operations and cash flows. We cannot predict the amounts or timing of future reserves 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.

Recent Accounting Pronouncements

Fair value

In May 2011, the FASB issued Accounting Standards Update, or ASU, 2011-04 Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and International Financial Reporting Standards. This new guidance changes some fair value measurement principles and disclosure requirements, but does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. The update is effective for annual periods beginning after December 15, 2011 and we are in the process of evaluating the impact, if any, the adoption of this update will have on our financial statements.

Internal Controls and Procedures

We have begun the process of evaluating our internal control over financial reporting. We are in the early phases of our review and will not complete our review until well after this offering is completed. We cannot predict the outcome of our review at this time. During the course of the review, we may identify control deficiencies, which could give rise to significant deficiencies and other material weaknesses. Management has taken steps to improve our internal control over financial reporting, including the implementation of new accounting processes and control procedures and the identification of gaps in our skills base and expertise of the staff required to meet the financial reporting requirements of a public company.

We are not currently required to comply with the SEC's rules implementing 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, to the extent not alleviated by the JOBS Act, 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 any earlier than 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, including information technology, implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting until such time as we become an "accelerated filer" as defined in Rule 12b-2 of the Exchange Act. 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, operated or monitored.

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Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into to manage commodity price or interest rate risk, rather than for speculative trading.

Commodity price exposure

For a discussion of how we use financial commodity put, collar, swap and basis swap contracts to mitigate some of the potential negative impact on our cash flow caused by changes in oil and gas prices, see "—Derivative Instruments."

A summary of our commodity derivative positions as of December 31, 2011 through the periods presented below is as follows:

	Contract Period

Position Descriptions	2012(1)			2013
NATURAL GAS POSITIONS
Swaps (MMBtu)		1,370,000			912,500
Average Price per MMBtu	$	5.17		$	5.22
Two-way collars (MMBtu):		127,500			—
Average Price per MMBtu
Floor purchase price (put)	$	7.00			—
Ceiling sold price (call)		7.50			—
Three-way collars (MMBtu):		127,500
Average Price per MMBtu					—
Floor sold price (put)	$	5.00			—
Floor purchase price (put)		7.00			—
Ceiling sold price (call)		8.55			—
Put spreads (MMBtu):		1,846,000
Average Price per MMBtu					—
Floor sold price (put)	$	4.93			—
Floor purchase price (put)		6.62			—
Short calls (MMBtu):		1,846,000
Average Price per MMBtu					—
Ceiling sold price (call)	$	6.40			—
Basis Swaps (MMBtu) (NYMEX—CPE)		1,448,077
Average Price per MMBtu	$	(0.49	)		—
OIL POSITIONS
Swaps (Bbl)		183,000
Average Price per Bbl	$	97.90			—
Two-way collars (Bbl):					109,500
Average Price per Bbl		—
Floor purchase price (put)		—		$	90.00
Ceiling sold price (call)		—			96.82

(1): From January 1, 2012 to June 30, 2012, the following derivative positions will expire: natural gas swaps for 910,000 MMBtu, natural gas two-way collars for 127,500 MMBtu, natural gas three-way

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collars for 127,500 MMBtu, natural gas put spreads for 1,046,000 MMBtu, natural gas short calls for 1,046,000 MMBtu, natural gas basis swaps for 968,077 MMBtu and oil swaps for 91,000 Bbls.

Interest rate risk

As part of our senior secured revolving credit facility and our second lien term loan facility, we have debt which bears interest at floating rates. At March 31, 2012, the indebtedness outstanding on our senior secured revolving credit facility was $80.0 million and bore an interest rate of approximately 3.24%, while the $30.0 million outstanding as of that date on our second lien term loan facility bore an interest rate of 9.5%. Based on the total outstanding borrowing under our senior secured revolving credit facility at March 31, 2012, a 1.0% increase in LIBOR or base rate levels would result in an estimated $0.8 million increase in interest expense for the year ended December 31, 2012 before giving effect to interest rate derivatives. While our second lien term loan facility is a floating rate facility, the levels of the interest rate floors of 1.50% for LIBOR borrowings and 3.00% for base rate borrowings are well above the 1-month LIBOR level of 0.24% or LIBOR-base rate level of 1.24% at March 31, 2012. Therefore, a 1.0% change in LIBOR or LIBOR-base rate levels would not impact the 9.50% interest rate paid on our second lien term loan.

Through interest rate derivative contracts, we have attempted to mitigate our exposure to changes in interest rates. We have entered into fixed interest rate swap agreements which hedge our exposure to interest rate variations on our senior secured revolving credit facility. As shown in the following table, at December 31, 2011, we had interest rate swaps outstanding for a notional amount of $50.0 million with fixed pay rates averaging 2.21% that expire in September 2012.

	2012

Notional principal amount (in thousands)	$	50,000
Weighted average interest rates		2.21	%

Counterparty risk and customer concentration

Our principal exposures to credit risk are through receivables resulting from commodity derivatives contracts (approximately $6.4 million at January 31, 2012), joint interest owner receivables and the receivables from the sale of our oil and natural gas production to energy marketing companies and pipeline companies. We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not generally require our customers to post collateral, and the inability of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial results.

For the year ended December 31, 2011, we had two significant customers that each accounted for more than 10% of our oil and gas revenues. These customers accounted for approximately 59% of our total natural gas and oil sales. We also had one customer that accounted for approximately 58% of our natural gas and oil accounts receivable.

For the year ended December 31, 2010, natural gas and oil sales to four customers amounted to approximately 60% of our total natural gas and oil sales. For the year ended December 31, 2009, natural gas and oil sales to two purchasers amounted to approximately 40% of our total natural gas and oil sales. Management believes that there are potential alternative purchasers. However, there can be no assurance that we can establish such relationships or that those relationships will result in increased purchases.

Off-Balance Sheet Arrangements

As of December 31, 2011, we did not have any off-balance sheet arrangements.

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BUSINESS

Overview

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component for our portfolio due to its low-risk development profile, scale and largely held-by-production status.

The following table provides our summary operating data:

			Identified Drilling Locations(1)						Producing Wells(2)				Estimated Proved Reserves as of December 31, 2011								December 2011 Average Daily Net Production

	Net Acreage(1)		Identified Drilling Locations(1)						Producing Wells(2)				Estimated Proved Reserves as of December 31, 2011								December 2011 Average Daily Net Production
	Net Acreage(1)		Gross		Net		PUDs(3)		Gross		Net		Bcfe		%Gas			%Developed			(MMcfed)		%Gas
South Texas:
Eagle Ford Shale		15,045		110		94.4		20		12		10.8		43.0		18	%		25	%		10.5		11	%
Other		3,739		37		21.8		17		42		16.5		40.4		81			36			3.2		81

Area		18,784		147		116.2		37		54		27.3		83.4		48			30			13.7		27
Rocky Mountains:
Powder River Basin(4)		72,894		24		23.9		—		6		5.9		1.1		30			100			0.2		54
DJ Basin		21,201		—		—		—		78		70.3		2.2		100			100			0.9		100

Area		94,095		24		23.9		—		84		76.2		3.3		76			100			1.1		89
Arkoma Basin:
Woodford Shale(5)(6)		29,292		780		239.5		64		131		39.0		199.4		100			23			15.2		100
Other		3,614		—		—		—		1		0.0		—		—			—			—		—

Area		32,906		780		239.5		64		132		39.0		199.4		100			23			15.2		100

Total		145,785		951		379.6		101		270		142.5		286.1		85	%		26	%		30.0		66	%

(1): As of March 31, 2012.
(2): As of December 31, 2011.
(3): Represents the number of gross identified potential drilling locations to which proved undeveloped reserves were attributable, based on our December 31, 2011 reserve report.
(4): Given the early stage in our evaluation of the play, so far, we have identified 24 gross (23.9 net) drilling locations on our Powder River Basin acreage.
(5): Gross and net identified drilling locations in the Woodford Shale are primarily based on 80-acre spacing.
(6): Includes Woodford Shale wells, all up-hole zones in Woodford Shale wells and Hunton wells with Woodford Shale offset locations.

In drilling our identified locations to establish commercial quantities of oil, natural gas liquids and natural gas production, we consider numerous factors that include but are not limited to the following:

(i): the presence of a prospective reservoir interval under our acreage,
(ii): the presence of hydrocarbons in the reservoir interval,
(iii): the ability to utilize existing and well proven methods to drill and complete wells in the reservoir that will produce hydrocarbons and
(iv): the potential to produce hydrocarbons that will provide an acceptable rate of return based on drilling costs, amount and type of hydrocarbons recovered, commodity prices and operating costs.

We evaluated all of these factors in assessing our existing acreage and formulating our development plans in each of our core areas. We expect to develop the majority of our identified

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drilling locations utilizing horizontal drilling and hydraulic fracture stimulation, but have developed specific drilling and completion procedures and techniques in each of our core areas based on the reservoir conditions and other relevant factors.

As of March 31, 2012, we have identified a total of 951 gross potential drilling locations, 110 of which underlie our Eagle Ford Shale acreage, 24 of which underlie our Powder River Basin acreage, 780 of which underlie our Woodford Shale acreage and 37 of which underlie our non-Eagle Ford Shale South Texas acreage. We expect to drill our Eagle Ford Shale and Woodford Shale acreage horizontally. We will evaluate the merits of both horizontal drilling and vertical drilling on our Powder River Basin acreage. We expect to develop our non-Eagle Ford Shale South Texas acreage with vertical wells. We consider our Eagle Ford Shale, Powder River Basin and Woodford Shale as resource plays, with similar technical attributes used in identifying potential drilling locations. We consider our non-Eagle Ford Shale South Texas properties as a conventional play, with some, but not all, of the technical attributes used in identifying potential drilling locations in a resource play.

In the Woodford Shale and Eagle Ford Shale, we have identified potential locations through a combination of geological and engineering analysis. Both the Arkoma Basin of eastern Oklahoma and the Eagle Ford Shale of South Texas are historically productive basins where there is extensive geological and engineering information available. Specifically, this technical information includes open-hole log data, production statistics from operated and non-operated wells, petro-physical data describing the reservoir rock attributes and 2-D and 3-D seismic data. We have obtained this information from public sources and our own proprietary databases developed from our prior operational experience in these basins. Based on this data and our evaluation and analysis of it, we have developed detailed maps on which we have identified potential drilling locations. We plan an active drilling program in both of these areas subject to acceptable commodity prices, availability of drilling and completion equipment and qualified personnel and sufficient capital resources.

In the Powder River Basin, several intervals of interest have been developed historically using vertical wells on, and in close proximity to, our acreage. As of December 31, 2011, we had not drilled any wells on our Powder River Basin acreage and are basing our technical analysis on open-hole log data, production statistics from non-operated wells, petro-physical data describing the reservoir rock attributes and 2-D and 3-D seismic data. We believe several of the intervals, including the Niobrara Shale, the Turner Sandstone, the Mowry Shale and the Muddy Sandstone being developed on and around our acreage are potential oil resource plays. As such, we have used this technical data, particularly log and historical production data, in mapping the gross interval for these horizons that underlie a majority of our entire acreage position in the Powder River Basin. This is the main factor we considered in identifying our potential locations on this acreage. As of March 31, 2012, we had identified 24 drilling locations and expect to identify more potential drilling locations through the information we intend to gather from our drilling and re-completion activity and geological analysis planned for 2012. See "Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—Drilling locations that we decide to drill may not yield natural gas, oil or natural gas liquids in commercially viable quantities" and "Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—Our identified potential drilling location inventories are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. 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 potential drilling locations."

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areas. The following table details our anticipated capital expenditure budget by region for the year ending December 31, 2012:

	Number of Wells

	Number of Wells				Capital Expenditures
	Gross		Net		Capital Expenditures
					($ in millions)
Drilling
Eagle Ford Shale		11		11.0	$	107.6
Powder River Basin		2		2.0		22.2
Woodford Shale		2		0.9		6.6
Other Areas(1)		—		—		2.1

Sub-total		15		13.9		138.5
Leasehold, Seismic and Other(2)		—		—		23.2

Total		15		13.9	$	161.7

(1): Includes workovers on South Texas non-Eagle Ford Shale properties.
(2): Includes $16.3 million in payments due in 2012 with respect to our acquisitions of Powder River Basin acreage in 2011. The majority of the remaining amount is intended for leasehold acquisitions.

Our Strategies

Continue Development of Our Eagle Ford Shale Assets; Accelerate Evaluation of Powder River Basin Properties

Balance Commodity Mix Through Growth in Oil Production

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Enhance Returns Through Operational Efficiencies

Pursue Strategic Acquisitions within Our Core Areas

Maintain Financial Discipline and Actively Manage Commodity Price Risk

Our Strengths

The following are our key competitive strengths that we believe will allow us to effectively execute our business strategies.

Substantial Acreage Positions in Key Unconventional Plays

Powder River Basin Resource Potential

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Substantial Drilling Inventory

High Degree of Operational Control

We operate over 92% of our net acreage and 86% of our identified drilling locations. Additionally, we operated approximately 95% of our estimated proved reserves on a volume basis as of December 31, 2011 and approximately 90% of our average daily net production for December 2011. We believe that this high level of operational control will enable us to develop our resource base in an efficient and cost-effective manner. Additionally, our operated positions enable us to better manage the pace of development and align our capital spending with our capital resources.

Proximity to Significant Industry Infrastructure and Access to Multiple Product Markets

Our core areas have substantial existing hydrocarbon transportation, processing and refining capacity, as well as access to multiple product sales points. We believe that our access to this infrastructure will allow us to get production on line more rapidly and achieve competitive product pricing when compared to other more remote producing basins.

Experienced, Incentivized Management and Employee Base

Focus Areas

We have focused our efforts on developing a multi-year drilling inventory of onshore unconventional resource plays in geographic areas and geologic settings where our management and senior technical staff have significant experience. We have sought to develop this drilling inventory so that it consists of both natural gas and oil-prone projects, allowing us to enhance returns by allocating capital based on prevailing commodity price conditions. We have also sought to balance our portfolio between well established unconventional plays which have significant drilling and production history with earlier stage opportunities that have less horizontal drilling and modern fracture stimulation history available but provide a lower cost of entry. Based on these criteria, our focus is on three specific core areas consisting of the Eagle Ford Shale of South Texas, the Powder River Basin of Wyoming and the Woodford Shale in the Arkoma Basin of eastern Oklahoma.

South Texas—Eagle Ford Shale

The Eagle Ford Shale of South Texas extends from the Mexican border to the northeast into East Texas. It is an organically rich, Cretaceous age shale that is prospective in areas with depths ranging

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from 4,000 to 14,000 feet and formation thicknesses of 75 to 300 feet. Depending on several factors, but primarily on depth, the Eagle Ford Shale has three distinctive phase windows—a dry gas window, a wet gas window and an oil window. The dry gas window produces natural gas with little associated oil or natural gas liquids, the wet gas window produces natural gas with significant amounts of associated oil and natural gas liquids and the oil window produces oil with some associated natural gas that contains significant amounts of natural gas liquids. The dry gas window runs along the southern portion of the play and transitions into the wet gas window moving north before transitioning into the oil window in the northern part of the play. The first horizontal Eagle Ford Shale well was drilled in 2008 in LaSalle County. Since then, drilling activity has expanded across South Texas to the counties of Atascosa, Bee, Dewitt, Dimmit, Frio, Gonzales, Karnes, Lavaca, Live Oak, Maverick, McMullen, Webb, Wilson and Zavala.

The Eagle Ford Shale is one of the most active domestic onshore unconventional plays with a reported 200 rigs running as of November 2011. The Eagle Ford Shale is being developed using horizontal drilling and hydraulic fracture stimulation. Public information indicates that operators are typically drilling wells with laterals from 3,500 to 8,000 feet. Wells are typically being completed with 15 to 25 fracture stimulation stages. Like most unconventional plays, production rates in the Eagle Ford Shale typically decline rapidly from their initially reported rates over the first several years of production. In addition to the Eagle Ford Shale, development of other historically productive formations like the Austin Chalk, Buda Limestone and the Pearsall Shale are occurring in proximity to our Eagle Ford Shale acreage. We intend to monitor this development and evaluate any potential implications for our acreage.

At March 31, 2012, we had a total 15,045 net acres across the Eagle Ford Shale play, 13,330 net acres of which were located in our four primary acreage blocks. We have an average working interest of 88% and are the operator in all these acreage blocks. These acreage blocks consist of contiguous tracks of at least 1,100 net acres in size and are located within a 20 mile radius of each other. We specifically targeted contiguous acreage blocks in excess of 1,000 acres where we could drill multiple wells from the same pad and build central production facilities to service our wells. We believe this type of concentrated operational footprint will lead to greater operational efficiencies. We have drilled and completed 14 gross wells on our Eagle Ford Shale acreage and have identified 110 gross (94.4 net) drilling locations. For December 2011, our net production from our Eagle Ford Shale wells averaged 10.5 MMcfed, consisting of 81% oil, 8% natural gas liquids and 11% natural gas. We intend to concentrate our drilling efforts primarily in acreage blocks that are in the oil window of the Eagle Ford Shale play. A further description of our primary acreage blocks follows:

Axle Tree Ranch

Our Axle Tree Ranch properties consist of 1,139 gross (1,139 net) acres located in northern Live Oak and southern Karnes Counties in South Texas. The average depth of the Eagle Ford Shale on our Axle Tree Ranch acreage is 11,500 feet, and results to date indicate that this acreage is within the oil window. We own a 100% working interest in this acreage and are the operator. We have drilled and completed three gross (three net) wells on this acreage, and we have identified eight additional drilling locations. We expect the lateral lengths of our remaining locations to average approximately 4,500 feet. We have installed central gas treating facilities that will remove impurities such as carbon dioxide and hydrogen sulfide, allowing us to process our gas and improve our per unit economics through sales of the resulting natural gas liquids. With the three completed wells, approximately 80% of this acreage is held by production, and we will be required to drill and complete one additional well by February 2013 to hold the remaining acreage by production. We have the option to extend for an additional two years any acreage that is not held by production by February 2013.

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Heard Ranch

Our Heard Ranch properties consist of 1,583 gross (1,583 net) acres located in southeastern Atascosa County in South Texas. The average depth of the Eagle Ford Shale on our Heard Ranch acreage is 10,800 feet, and results to date indicate that this acreage is within the oil window. We own a 100% working interest in this acreage and are the operator. We have drilled five gross (five net) wells on this acreage, and we have identified 14 additional drilling locations. We expect the lateral lengths of our remaining locations to average approximately 4,400 feet. Our gas production on this acreage has a relatively high liquids content and low levels of impurities, allowing it to be processed without additional treating. We improve our per unit economics through sales of the resulting natural gas liquids. All of this acreage is held by production.

Simmons Area

Our Simmons properties consist of 10,031 gross (9,226 net) acres located in southeastern Atascosa County in South Texas. The average depth of the Eagle Ford Shale on our Simmons acreage is 8,500 feet, and results to date indicate that this acreage is within the oil window. We own a 92% working interest in this acreage and are the operator. We have drilled and completed three gross (three net) wells on this acreage. We have identified 62 additional drilling locations on this acreage, two of which we have drilled and expect to complete in April 2012. The average size and configuration of our Simmons project will allow us to drill our longest laterals, averaging over 7,000 feet, with some locations being longer than 8,000 feet. Our gas production has a high level of impurities, including carbon dioxide and hydrogen sulfide, and a high liquids content. We connected to a sour gas line to the west of this acreage, allowing our gas production to be treated and processed to separate the higher value natural gas liquids to improve our per unit economics. We plan to concentrate our 2012 drilling in this area as we will be required to drill and complete approximately 25 additional wells by June 2013 to hold this acreage by production. We have the option to extend a majority of this acreage for an additional two years if it is not held by production by June 2013 by making extension payments.

Southwest Pawnee

Our Southwest Pawnee properties consist of 2,345 gross (1,382 net) acres located in central Live Oak County in South Texas. The average depth of the Eagle Ford Shale on our Southwest Pawnee acreage is 14,000 feet, and our wells on this acreage are some of the deepest Eagle Ford Shale wells drilled to date by any operator. Results to date indicate that this acreage is within the dry gas window of the play. We own a 59% working interest in this acreage and are the operator. We have drilled three gross (1.8 net) wells on this acreage and we have identified 26 additional drilling locations. As of December 31, 2011, the Dena Forehand #2H well was not fully completed as we finished only four of the expected 12 fracture stimulation stages. We expect to complete the remaining stages at a later date and do not believe production rates from this well are comparable to the fully completed wells in the area. Our gas production contains levels of carbon dioxide in excess of pipeline quality specifications, and we have installed central treating facilities to process produced gas to pipeline specifications. With the three drilled and completed wells, approximately 64% of this acreage is held by production, and we will be required to drill and complete two additional wells by April 2013 and May 2014, respectively, to hold the remaining acreage by production. Given that this acreage is in the dry gas window, we do not anticipate significant activity in this area in the near term.

Other Eagle Ford Shale Acreage

We own approximately 3,823 gross (1,715 net) acres in southwestern Zavala County in South Texas. The average depth of the Eagle Ford Shale on this acreage is 5,000 feet. We own an approximate 45% working interest in this acreage and are not the operator. We do not believe that well results in the surrounding area justify additional development at this time. Our leases in this area will begin to expire in April 2012 and will have fully expired by August 2012.

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Rocky Mountains—Powder River Basin

The Powder River Basin is one of the key oil and gas basins located in the Rocky Mountain States of Wyoming and Montana. Specifically, the Powder River Basin is located in southwestern Montana and northeastern Wyoming. Most of the oil development in the Powder River Basin has been through drilling conventional vertical wells, but over the last decade operators have successfully tested multiple zones through horizontal drilling and multistage fracture stimulation. Throughout the Power River Basin, and specifically to the north and west of our acreage, large domestic operators such as Chesapeake Energy, EOG Resources and El Paso Corp. have leased large acreage positions and are conducting significant amounts of horizontal drilling activity. In addition, we have observed an increase in transaction activity and broad interest in the basin by new entrants such as large international operators and private equity sponsors. Given the significant amount of historic production and the high levels of current activity in the basin, there is substantial infrastructure including pipelines, refineries and oilfield service equipment.

The basin has a history of substantial oil and gas production from multiple pay zones. Based on our geologic evaluation, we believe the organically rich, Cretaceous age Mowry Shale could be the source rock for production from several oil-prone formations including the Turner Sandstone and the Muddy Sandstone. The Mowry Shale dips gently from east to west and pinches out on the eastern part of the basin. In our area of the basin, the Mowry Shale is found at an average depth of 7,500 to 8,000 feet, and ranges in thickness from 150 to 200 feet. We believe that the Muddy Sandstone, which sits directly below the Mowry Shale, could act as a conduit for oil sourced from the Mowry Shale.

Largely through the acquisition of acreage from two private companies, we have assembled a position of approximately 72,000 net acres in the southeastern portion of the Powder River Basin, specifically northwestern Niobrara County and Weston County. Given our high level of working interest in many of the sections we own, we expect to be the operator on the majority of this acreage. The Muddy Sandstone has been drilled vertically on our acreage and has been an oil producing zone on our acreage and throughout the basin. Based on data from offsetting wells located on or near our acreage, the Muddy Sandstone's thickness in our area is typically 10 feet to 30 feet. We believe the Mowry Shale and Muddy Sandstone sequence is a prospective oil resource play on our acreage as it has been shown to be productive in offsetting vertical wells, is present in acceptable thickness based on nearby well control, appears to have natural fracturing and is a good candidate for horizontal drilling and hydraulic fracture stimulation. We will attempt to drill horizontally in the Muddy Sandstone and fracture stimulate both zones. Our operational program for 2012 contemplates fracture stimulating two existing vertical wells and drilling two new additional horizontal wells. Due to the early stage of evaluation of our acreage so far, we have identified 24 gross (23.9 net) drilling locations but will continue to evaluate and expect to identify additional drilling locations.

In addition to the Mowry / Muddy sequence, other area operators, including Chesapeake Energy, EOG Resources and El Paso Corp. are actively drilling the Niobrara Shale, the Turner Sandstone and other prospective formations in close proximity to our acreage. We plan to monitor this activity as data from offsetting wells indicate both formations are present on our acreage.

The lease terms we have in the Powder River Basin are typically longer than we have in either South Texas or the Arkoma Basin. Our acreage leased from private individuals in the Powder River Basin averages approximately four years of primary term with the option to extend for an additional four years, while our federal acreage typically carries a term of eight years.

Other Rocky Mountain Acreage

In addition to our Powder River Basin acreage, we also have 21,201 net acres in the McCourt Field in Cheyenne County, Nebraska. This field is located in the northeastern portion of the DJ Basin and produces dry gas from the Niobrara Shale formation at average depths of 3,600 feet. We are the

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operator of this field, own an average working interest of 87% and hold all of our acreage by production. Our net production from this field averaged approximately 900 Mcf per day in December 2011. Due to the current gas price environment and relatively low reserves per well, we do not anticipate drilling any new gas wells in the near term.

Arkoma Basin—Woodford Shale

The Arkoma Basin is a historically prolific, largely gas-prone basin in eastern Oklahoma and western Arkansas. The basin produces largely natural gas from multiple horizons ranging in depth from 3,000 to 14,000 feet. Given the basin's long productive history, there is significant pipeline, processing and service company infrastructure available to operators. While operators have historically developed the basin using vertical wells, in 2005 operators began drilling horizontal wells in the Woodford Shale. Since then, developing the Woodford Shale using horizontal drilling and hydraulic fracture stimulation has become common practice and the Woodford Shale is regarded as one of the more mature onshore, gas shale plays in the United States. Industry sources indicate that as of December 31, 2011, over 700 horizontal wells have been drilled in the Woodford Shale, and companies such as BP, ExxonMobil, Newfield Exploration and Petroquest are all active in the play. The productive fairway for the Arkoma Basin Woodford Shale consists of Atoka, Coal, Haskell, Hughes and Pittsburg Counties, Oklahoma. In this productive fairway, the Woodford Shale ranges in depth from 5,000 to 13,000 feet and has thicknesses ranging from 30 to 250 feet.

Our Woodford Shale properties consist of approximately 29,300 net acres primarily in Atoka, Haskell and Pittsburg Counties in Oklahoma. The depth of the Woodford Shale on our acreage ranges from approximately 6,000 to 13,000 feet, while thicknesses range from approximately 50 to 250 feet. We drilled our first horizontal well in 2009 and since then have drilled 35 gross (11.9 net) horizontal wells and have completed all of them as producers. Our Woodford Shale properties represent a substantial undeveloped resource base, and we have identified 780 gross (239.5 net) drilling locations on our acreage. Based on our high ownership interest in many of our sections, we expect to operate 403 gross (201.8 net) wells as development occurs. Given the basin's multiple producing horizons above the Woodford Shale, we do encounter other productive zones while drilling our Woodford Shale horizontal wells. We are evaluating completions on several Atoka zones in existing wellbores and believe industry participants are evaluating the potential of horizontal drilling in other horizons that have produced in vertical wellbores across the basin. Many of these zones of interest are shallower than the Woodford Shale, and hence would be held by production through establishing production from the Woodford Shale. Considering the current low natural gas price environment and the fact that approximately 58% of our Woodford Shale acreage is held by production, we expect to drill 2 gross (0.9 net) Woodford Shale wells in 2012.

Operating Summary

The following table sets forth information regarding our unaudited oil and natural gas production, revenues and realized prices and production costs for the years ended December 31, 2009, 2010 and 2011. For additional information on price calculations, see information set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operations." We determine natural gas

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equivalents by using the ratio of six Mcf of natural gas to one barrel of oil or one barrel of natural gas liquids.

	Years Ended December 31

	2009			2010		2011
Production data:
Natural gas (MMcf)		3,601.3			6,627.0		8,038.7
Oil (MBbls)		43.5			48.2		250.7
Natural gas liquids (MBbls)		25.9			24.1		18.5
Equivalents (MMcfe)		4,017.7			7,060.8		9,653.9
Average daily equivalent production (MMcfed)		11.0			19.3		26.4
Average sales prices:
Natural gas ($ per Mcf)	$	3.35		$	3.54	$	3.40
Oil ($ per Bbl)		58.37			77.24		94.30
Natural gas liquids ($ per Bbl)		32.20			40.00		48.27
Equivalents ($ per Mcfe)		3.85			3.99		5.37
Realized gain (loss) on commodity derivatives ($ per Mcfe)		(0.01	)		0.64		0.72

Natural gas equivalents including realized gain (loss) on commodity derivatives ($ per Mcfe)(1)	$	3.84		$	4.63	$	6.09

Costs and expenses (per Mcfe of production):
Lease operating	$	1.23		$	0.95	$	0.98
Workovers		0.19			0.28		0.14
Severance and ad valorem taxes		0.31			0.26		0.30

(1): These prices include realized gains or losses on cash settlements for our commodity derivatives. None of our commodity derivatives are designated as cash flow or fair value hedges.

The following table sets forth information regarding our average daily net production and total production for the year ended December 31, 2011 from our primary operating areas:



South Texas:
Eagle Ford Shale	2,018	593	11	5,642	65	%
Other	2,209	91	39	2,989	35

Area Total	4,227	684	50	8,631
Rocky Mountains:
Powder River Basin	13	2	—	25	3
DJ Basin	961	0.0	0.0	962	97

Area Total	974	2	—	987
Arkoma Basin:
Woodford Shale	15,290	1	—	15,296	91
Other	1,534	—	—	1,534	9

Area Total	16,824	1	—	16,830

Total	22,025	687	50	26,448

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Producing Wells

The following table sets forth the number of oil and natural gas wells in which we owned a working interest at December 31, 2011. Producing wells consist of producing wells and wells capable of producing, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have working interests, and net wells are the sum of our fractional working interests owned in gross wells.

	Oil				Natural Gas				Total

	Gross		Net		Gross		Net		Gross		Net
South Texas:
Eagle Ford Shale		9		9.0		3		1.8		12		10.8
Other		2		1.5		40		15.0		42		16.5

Area Total		11		10.5		43		16.8		54		27.3
Rocky Mountains:
Powder River Basin		6		5.9		—		—		6		5.9
DJ Basin		—		—		78		70.3		78		70.3

Area Total		6		5.9		78		70.3		84		76.2
Arkoma Basin:
Woodford Shale		—		—		131		39.0		131		39.0
Other		—		—		1		0.0		1		0.0

Area Total		—		—		132		39.0		132		39.0

Total		17		16.4		253		126.1		270		142.5

Estimated Proved Reserves

The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2009, 2010 and 2011. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from

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known reservoirs under existing economic and operating conditions. Our total estimated proved reserves are estimated using a conversion ratio of one Bbl per six Mcf.

	At December 31,

	2009		2010		2011
Estimated Proved Reserves(1)(2)
Natural gas (MMcf)		138,525		229,497		242,283
Oil (MBbls)		1,463		2,183		6,066
Natural gas liquids (MBbls)		770		812		1,244

Total natural gas equivalent (MMcfe)		151,923		247,467		286,143

Estimated Proved Developed Reserves
Natural gas (MMcf)		58,808		78,210		64,695
Oil (MBbls)		466		693		1,514
Natural gas liquids (MBbls)		394		387		245

Total natural gas equivalent (MMcfe)		63,968		84,690		75,249

Estimated Proved Undeveloped Reserves
Natural gas (MMcf)		79,717		151,287		177,588
Oil (MBbls)		997		1,490		4,552
Natural gas liquids (MBbls)		376		425		999

Total natural gas equivalent (MMcfe)		87,955		162,777		210,894

PV-10(3) (in thousands)	$	62,138	$	130,675	$	211,230
Standardized Measure(4) (in thousands)	$	61,573	$	129,810	$	205,591

(1): Numbers in table may not total due to rounding.
(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. Our estimated proved reserves were determined using the unweighted averages of the historical first-day-of-the-month prices for the prior 12 months of $57.65 per Bbl for oil and $3.87 per MMBtu for natural gas at December 31, 2009; $75.96 per Bbl for oil and $4.38 per MMBtu for natural gas at December 31, 2010; and $92.71 per Bbl for oil and $4.12 per MMBtu for natural gas at December 31, 2011. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
(3): 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. PV-10 is not 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 estimated proved reserves held by companies without regard to the specific tax characteristics of such entities. The following table provides a reconciliation of our Standardized Measure to PV-10 for the periods presented:

	At December 31,

	2009		2010		2011
	(in millions)
Standardized Measure of discounted net cash flows	$	61.6	$	129.8	$	205.6
Present value of future income tax discounted at 10%(5)		0.5		0.9		5.6

PV-10	$	62.1	$	130.7	$	211.2

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(4): 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 the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our oil and natural gas properties.
(5): Based on our net operating losses, we do not anticipate paying any future federal income taxes for the periods indicated. Taxes shown are state taxes.

Our total estimated proved oil and natural gas reserves increased from 247.5 Bcfe at December 31, 2010 to 286.1 Bcfe at December 31, 2011. The increase of our estimated proved reserves resulted primarily from additions related to extensions of 91.8 Bcfe, the majority of which were related to drilling on our Eagle Ford Shale properties. Offsetting these additions from extensions were the sale of approximately 24.5 Bcfe of estimated proved reserves in the Arkoma Basin and negative revisions of 19.2 Bcfe, largely related to negative reserve revision at our Southwest Pawnee field in the Eagle Ford Shale of South Texas. Our estimated proved reserves comprised of oil and natural gas liquids increased 4,315 MBbls, or 144%, to 7,310 MBbls at December 31, 2011, from the prior estimated total of 2,995 MBbls at December 31, 2010. This increase in estimated oil and natural gas liquids proved reserves is a result of our drilling program in the oil and natural gas liquids windows of the Eagle Ford Shale of South Texas. At December 31, 2011, the percentage of our estimated proved reserves that consisted of oil and natural gas liquids was 15.3%, representing an increase over the total at December 31, 2010 of 7.3%. This increase in the percentage of our estimated proved reserves that were comprised of oil and natural gas liquids resulted from our drilling program in the oil and natural gas liquids windows of the Eagle Ford Shale of South Texas.

Our total estimated proved oil and natural gas reserves of 247.5 Bcfe for the year ended December 31, 2010, increased by 62.9% from the comparable period in 2009 when estimated proved reserves were 151.9 Bcfe. This increase is primarily attributable to our active drilling program in the gas-prone Woodford Shale and our initial drilling program in the Eagle Ford Shale that primarily targeted acreage in the gas window of the Eagle Ford Shale trend. Our estimated proved reserves comprised of oil and natural gas liquids increased by 761 MBbls to 2,995 MBbls at December 31, 2010 from 2,234 MBbls at December 31, 2009. However, our estimated proved reserves comprised of oil and natural gas liquids decreased on a percentage basis to 7.3% for the year ended December 31, 2010 from 8.8% for the year ended December 31, 2009. The reason for this increase on an absolute volume basis and decrease on a percentage basis is that while we added oil and natural gas liquids volumes from some of our Eagle Ford Shale drilling, we added proportionally more gas volumes from both our Woodford Shale and Eagle Ford Shale drilling.

Our proved undeveloped reserves increased from 162.8 Bcfe at December 31, 2010 to 210.9 Bcfe at December 31, 2011, due primarily to our drilling operations in the Eagle Ford Shale and Woodford Shale. The increase in our proved undeveloped oil reserves specifically attributable to our drilling operations in the oil window of the Eagle Ford Shale was 27.8 Bcfe. The net increase of 48.1 Bcfe in our proved undeveloped reserves from December 31, 2010 to December 31, 2011 is composed of (i) additions of 67.4 Bcfe to proved undeveloped reserves identified through drilling operations, (ii) less, the conversion of 2.2 Bcfe of proved undeveloped reserves to proved developed reserves, (iii) less, the downward revisions of proved undeveloped reserves of 3.9 Bcfe primarily attributable to performance of wells in the gas window of the Eagle Ford Shale, (iv) less, the downward adjustment of 12.8 Bcfe for divestment of reserves in the Arkoma Basin and (v) less, the 2011 calendar year production attributable to wells drilled in 2011 of 0.4 Bcfe. During this period, we recorded no changes to proved undeveloped reserves as a result of acquisitions. In addition, at December 31, 2011, we had no proved reserves in our estimates that remained undeveloped for five years or more following their initial booking.

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During the calendar year 2011, we drilled four wells that were carried as proved undeveloped reserves as of December 31, 2010. The net cost to drill these four wells was $21.7 million, and the production attributable to these wells in 2011 was 0.4 Bcfe. Our pre-drill proved undeveloped reserve estimates were 5.3 Bcfe while our current reserves as of December 31, 2011 were 2.2 Bcfe after considering production in 2011. The primary performance revision to reserves was attributable to one well drilled in the gas window of the Eagle Ford Shale play where we had a downward revision of 2.2 Bcfe.

The following table sets forth additional summary information by operating area with respect to our estimated proved reserves at December 31, 2011:

	Estimated Proved Reserves(1)

	Gas MMcf		Oil (MBbls)		Natural gas liquids (MBbls)		Equivalent (MMcfe)		PV-10(2)
									(in millions)
South Texas:
Eagle Ford Shale		7,727.7		4,633.0		1,243.3		42,985.5	$	127.0
Other		32,610.4		1,304.2		0.5		40,438.6		32.4

Area Total		40,338.1		5,937.2		1,243.8		83,424.1		159.3
Rocky Mountains:
Powder River Basin		336.6		129.1		—		1,111.2		3.7
DJ Basin		2,158.8		—		—		2,158.8		(0.3	)

Area Total		2,495.4		129.1		—		3,270.0		3.4
Arkoma Basin:
Woodford Shale		199,449.4		—		—		199,449.4		48.5
Other		—		—		—		—		0.0

Area Total		199,449.4		—		—		199,499.4		48.5

Total		242,282.9		6,066.3		1,243.8		286,143.5	$	211.2

(1): Numbers in table may not total due to rounding.
(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. PV-10 is not 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 estimated proved reserves held by companies without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2011 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future federal and state income taxes associated with such reserves. For a reconciliation of PV-10 to Standardized Measure, see "Summary—Summary Historical Operating and Reserve Data."

Internal Control Over Reserves Estimation Process

We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our policies regarding internal controls over the recording of reserves estimates require reserve estimates to be in compliance with the SEC rules, regulations, definitions and guidance and prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our proved reserves are estimated at the property level and

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compiled by our engineering staff. Our engineering staff interacts with our internal staff of operations engineers and geoscience professionals and with accounting employees to obtain the necessary data for the reserves estimation process. Our internal professional staff works closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their independent reserve estimation process. All of our reserve information is provided to our independent reserve engineers. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to our independent reserve engineers as part of their evaluation of our reserves.

Our Senior Vice President and Chief Operating Officer is primarily responsible for overseeing the preparation of our reserves estimates and has over 26 years of industry experience. Our Senior Vice President and Chief Operating Officer received his B.S. degree in Petroleum Engineering from Marietta College and is a Licensed Professional Engineer in the State of Texas. Our Senior Vice President and Chief Operating Officer reports directly to our Chief Executive Officer. Following the preparation of our reserves estimates, for the years ended December 31, 2009, 2010 and 2011, we engaged Netherland, Sewell & Associates, Inc., our independent reserve engineers, to prepare independent estimates of the extent and value of the proved reserves associated with our oil and gas properties. See "—Independent Reserve Engineers" below for further information regarding Netherland, Sewell & Associates, Inc.'s reports.

Technology Used to Establish Reserves

Under the 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. 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. Reasonable certainty can be established using techniques that have been proven 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 have been 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, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods.

Independent Reserve Engineers

Our estimates of reserves and related future net revenues at December 31, 2009, 2010 and 2011 were based on reports prepared by Netherland, Sewell & Associates, Inc., our independent reserve engineers ("NSAI"), in compliance with the SEC rules, regulations, definitions and guidance and in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves

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Information promulgated by the Society of Petroleum Engineers. Copies of these reports have been filed as exhibits to the registration statement of which this prospectus forms a part.

NSAI was established in 1961 and performs consulting petroleum engineering services, including the issuance of reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. The NSAI technical person primarily responsible for preparing the estimates set forth in the NSAI reserves reports included as exhibits to the registration statement of which this prospectus forms a part is Mr. Mike Begland. Mr. Begland has been practicing consulting petroleum engineering at NSAI since 1993. Mr. Begland is a Licensed Professional Engineer in the State of Texas (No. 104898) and has over 26 years of experience in the estimation and evaluation of reserves. He graduated from The Ohio State University in 1983 with a Bachelor of Science Degree in Chemical Engineering. Mr. Begland meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; and he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Acreage

We hold leasehold, mineral or other interests in developed and undeveloped oil and natural gas acreage in the locations set forth in the table below. The following table presents a summary of our acreage interests as of March 31, 2012:

	Developed Acreage				Undeveloped Acreage				Total Acreage

	Gross		Net		Gross		Net		Gross		Net
South Texas:
Eagle Ford Shale		4,961		4,346		13,959		10,699		18,921		15,045
Other		6,504		2,942		1,978		797		8,482		3,739

Area Total		11,465		7,288		15,937		11,496		27,403		18,784
Rocky Mountains:
Powder River Basin		280		280		83,117		72,614		83,397		72,894
DJ Basin		13,440		11,740		10,832		9,462		24,272		21,201

Area Total		13,720		12,020		93,949		82,076		107,669		94,095
Arkoma Basin:
Woodford Shale		40,827		18,673		23,612		10,618		64,439		29,292
Other		—		—		8,657		3,615		8,657		3,614

Area Total		40,827		18,673		32,269		14,233		73,096		32,906

Total		66,012		37,981		142,155		107,805		208,168		145,785

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Undeveloped Acreage Expiration

The following table sets forth the number of gross and net undeveloped acres at March 31, 2012 that will expire over the next three years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates or unless the existing leases are renewed prior to expiration:

	Acres Expiring 2012				Acres Expiring 2013				Acres Expiring 2014				Acres Expiring 2015

	Gross		Net		Gross		Net		Gross		Net		Gross		Net
South Texas:
Eagle Ford Shale(1)(2)		5,063		2,827		7,054		6,413		1,457		1,143		103		100
Other		—		—		320		227		—		—		—		—

Area Total		5,063		2,827		7,374		6,640		1,457		1,143		103		100
Rocky Mountains:
Powder River Basin(3)		—		—		—		—		7,312		4,724		13,881		10,183
DJ Basin		—		—		—		—		—		—		—		—

Area Total		—		—		—		—		7,312		4,724

RBC Capital Markets

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International

Tudor, Pickering, Holt & Co.

Dahlman Rose & Company

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