Matador Resources Co - FORM 10-K

Matador Resources Co - FORM 10-K - April 2, 2012

Attached files

Attached files

file	filename
EX-99.1 - AUDIT REPORT OF NETHERLAND, SEWELL & ASSOCIATES, INC. - Matador Resources Co	d325766dex991.htm
EX-23.1 - CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC. - Matador Resources Co	d325766dex231.htm
EX-32.1 - CERTIFICATION OF PEO PURSUANT TO SECTION 906 - Matador Resources Co	d325766dex321.htm
EX-31.2 - CERTIFICATION OF PFO PURSUANT TO SECTION 302 - Matador Resources Co	d325766dex312.htm
EX-31.1 - CERTIFICATION OF PEO PURSUANT TO SECTION 302 - Matador Resources Co	d325766dex311.htm
EX-32.2 - CERTIFICATION OF PFO PURSUANT TO SECTION 906 - Matador Resources Co	d325766dex322.htm
EX-10.40 - FORM OF RESTRICTED STOCK AWARD AGREEMENT - Matador Resources Co	d325766dex1040.htm
EX-10.37 - FORM OF INCENTIVE STOCK OPTION AGREEMENT - Matador Resources Co	d325766dex1037.htm
EX-10.36 - FORM OF NON-QUALIFIED STOCK OPTION AGREEMENT - Matador Resources Co	d325766dex1036.htm
EX-10.38 - FORM OF NONQUALIFIED STOCK OPTION AGREEMENT - Matador Resources Co	d325766dex1038.htm
EX-10.39 - FORM OF RESTRICTED STOCK UNIT AWARD AGREEMENT - Matador Resources Co	d325766dex1039.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-34574

Matador Resources Company

(Exact name of registrant as specified in its charter)


Texas		27-4662601
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5400 LBJ Freeway, Suite 1500 Dallas, Texas 75240		75240
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (972) 371-5200

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered
Common Stock, par value $0.01 per share		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities

Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨ No x

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

As of June 30, 2011, the registrant was a privately held company and not publicly traded. Accordingly, the market value of its common stock held by non-affiliates on such date cannot be reasonably determined.

As of March 30, 2012, there were 55,272,860 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this annual report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2012 Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this annual report on Form 10-K relates.

MATADOR RESOURCES COMPANY

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2011

TABLE OF CONTENTS


		Page
PART I
ITEM 1.	BUSINESS.		3
ITEM 1A.	RISK FACTORS.		35
ITEM 1B.	UNRESOLVED STAFF COMMENTS.		57
ITEM 2.	PROPERTIES.		57
ITEM 3.	LEGAL PROCEEDINGS.		57
ITEM 4.	MINE SAFETY DISCLOSURES.		57

PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.		58
ITEM 6.	SELECTED FINANCIAL DATA.		60
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.		64
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK .		87
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.		90
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.		90
ITEM 9A.	CONTROLS AND PROCEDURES.		90
ITEM 9B.	OTHER INFORMATION.		90

PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.		91
ITEM 11.	EXECUTIVE COMPENSATION.		91
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.		91
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.		91
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES.		91

PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.		92

Cautionary Note Regarding Forward-Looking Statements

Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the meaning of applicable U.S. securities legislation. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “potential,” “predict,” “project,” “should” or other similar words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: changes in oil or 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, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this report and in other documents that we file with or furnish to the U.S. Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about:

•

our business strategy;

•

our reserves;

•

our technology;

•

our cash flows and liquidity;

•

our financial strategy, budget, projections and operating results;

•

our oil and natural gas realized prices;

•

the timing and amount of future production of oil and natural gas;

•

the availability of drilling and production equipment;

•

the availability of oil field labor;

•

the amount, nature and timing of capital expenditures, including future exploration and development costs;

•

the availability and terms of capital;

•

our drilling of wells;

•

government regulation and taxation of the oil and natural gas industry;

•

our marketing of oil and natural gas;

•

our exploitation projects or property acquisitions;

•

our costs of exploiting and developing our properties and conducting other operations;

•

general economic conditions;

•

competition in the oil and natural gas industry;

•

the effectiveness of our risk management and hedging activities;

•

environmental liabilities;

•

counterparty credit risk;

•

developments in oil-producing and natural gas-producing countries;

•

our future operating results;

•

estimated future reserves and the present value thereof; and

•

our plans, objectives, expectations and intentions contained in this report that are not historical.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.

You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements.

PART I

Item 1.

Business.

In this Annual Report on Form 10-K, references to “we,” “our,” or “the Company” refer to Matador Resources Company and its subsidiaries before the completion of our corporate reorganization on August 9, 2011 and Matador Holdco, Inc. and its subsidiaries after the completion of our corporate reorganization on August 9, 2011. Prior to August 9, 2011, Matador Holdco, Inc. was a wholly owned subsidiary of Matador Resources Company, now known as MRC Energy Company. Pursuant to the terms of our corporate reorganization, former Matador Resources Company became a wholly owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company.

Unless the context otherwise requires, the term “common stock” refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering on February 7, 2012, as the Class A common stock then became the only class of common stock authorized, and the term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering.

For certain oil and natural gas terms used in this report, please see the “Glossary of Oil and Natural Gas Terms” included in this report.

General

We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Our current operations are located primarily in the Eagle Ford shale play in south Texas and the Haynesville shale play in northwest Louisiana and east Texas. We expect the majority of our near-term capital expenditures will focus primarily on increasing our production and reserves from the Eagle Ford shale play. We believe our interests in the Eagle Ford shale play will enable us to create a more balanced commodity portfolio through the drilling of locations that are prospective for oil and liquids. In addition to these primary operating areas, we have acreage positions in southeast New Mexico and west Texas and in southwest Wyoming and adjacent areas in Utah and Idaho where we continue to identify new oil and natural gas prospects.

We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman, President and CEO, and Scott E. King, Co-Founder and Vice President, Geophysics and New Ventures. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million.

Since our first well in 2004, we have drilled or participated in drilling 236 wells through December 31, 2011, including 106 Haynesville and nine Eagle Ford wells. From December 31, 2008 through December 31, 2011, we grew our estimated proved reserves from 20.0 Bcfe to 193.2 Bcfe. At December 31, 2011, 34% of our estimated proved reserves were proved developed reserves, 12% of our estimated proved

reserves were oil and 88% of our estimated proved reserves were natural gas. Our average daily production for the year ended December 31, 2011 was 42.3 MMcfe per day, including 39.8 MMcf of natural gas per day and 422 Bbl of oil per day as compared to an average daily production of 23.6 MMcfe per day, including 23.0 MMcf of natural gas per day and 91 Bbl of oil per day for the year ended December 31, 2010. We have achieved this growth while lowering operating costs (consisting of lease operating expenses and production taxes and marketing expenses) from $1.16 per Mcfe for the year ended December 31, 2009, to $0.88 per Mcfe for the year ended December 31, 2011, or a decrease of approximately 24%.

The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2011:


			Producing Wells				Total Identified Drilling Locations⁽¹⁾				Estimated Net Proved Reserves				Avg. Daily Production (MMcfe)
	Net Acreage		Gross		Net		Gross		Net		Bcfe⁽²⁾		% Developed		Avg. Daily Production (MMcfe)
South Texas:
Eagle Ford		28,673		9.0		7.3		193.0		153.1		27.9		37.9		3.3
Austin Chalk		14,849		–		–		16.0		16.0		–		–		–

Area Total⁽³⁾		28,673		9.0		7.3		209.0		169.1		27.9		37.9		3.3
NW Louisiana/E Texas:
Haynesville		14,527		106.0		11.6		524.0		102.9		150.4		26.4		32.3
Cotton Valley⁽⁴⁾		23,054		108.0		71.7		60.0		36.0		14.2		100.0		6.5

Area Total⁽⁵⁾		25,339		214.0		83.3		584.0		138.9		164.6		32.7		38.8
SW Wyoming, NE Utah, SE Idaho		135,862		–		–		–		–		–		–		–
SE New Mexico, West Texas		6,658		13.0		5.7		–		–		0.7		100.0		0.2

Total		196,532		236.0		96.3		793.0		308.0		193.2		33.7		42.3

(1)

These locations have been identified for potential future drilling and are not currently producing. In addition, the total net identified drilling locations is calculated by multiplying the gross identified drilling locations in an operating area by our working interest participation in such locations. At December 31, 2011, these identified drilling locations included 8 gross and 8 net locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 102 gross and 17 net locations to which we have assigned proved undeveloped reserves in the Haynesville. We have no proved undeveloped reserves assigned to identified drilling locations in the Austin Chalk or Cotton Valley at December 31, 2011.

(2)	These estimates were prepared by our engineering staff and audited by independent reservoir engineers, Netherland, Sewell & Associates, Inc.

(3)

Some of the same leases cover the net acres shown for the Eagle Ford formation and the Austin Chalk formation, a shallower formation than the Eagle Ford formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for south Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.

(4)	Includes shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing from the San Miguel formation in Zavala County, Texas.

(5)

Some of the same leases cover the net acres shown for the Haynesville formation and the Cotton Valley formation, a shallower formation than the Haynesville formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for northwest Louisiana/east Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.

At December 31, 2011, our properties included approximately 51,000 gross acres and 29,000 net acres in the Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, LaSalle, Gonzales, Webb, Wilson and Zavala Counties in south Texas. We believe that approximately 85% of our Eagle Ford acreage is prospective predominantly for oil or liquids production. In addition, portions of the acreage are also prospective for other targets, such as the Austin Chalk, Olmos and Buda, from which we expect to produce predominantly oil and liquids. Approximately 80% of our Eagle Ford acreage is either held by production or not burdened by lease expirations before 2013. We have begun to explore and develop our Eagle Ford position and from November 2010 through December 2011, we completed our first seven operated wells in this area.

At December 31, 2011, we have identified 193 gross locations and 153 net locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated recoveries from nearby wells based on available public data, drilling densities observed from other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among others. At December 31, 2011, we have identified potential drilling locations on approximately 75% of our net Eagle Ford acreage. As we explore and develop our Eagle Ford acreage further, we believe it is possible that we may identify additional locations for drilling. At December 31, 2011, these identified potential future drilling locations in the Eagle Ford shale play included 8 gross and 8 net locations to which we have assigned proved undeveloped reserves.

In addition, at December 31, 2011, we had approximately 23,000 gross acres and 15,000 net acres in the Haynesville shale play in northwest Louisiana and east Texas. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data and information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, approximately 5,500 of our net acres are located in what we believe is the core area of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Over 90% of our Haynesville acreage is held by production from the Haynesville or other formations, and we believe much of it is also prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe approximately 1,700 of these net acres are prospective for the Middle Bossier shale play.

At December 31, 2011, we have identified 524 gross locations and 103 net locations for potential future drilling in our Haynesville acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated recoveries from our producing Haynesville wells and other nearby wells based on available public data, drilling densities observed from other operators including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among others. Of the 524 gross locations identified for future drilling, 449 of these locations (52 net locations) have been identified within the 5,500 net acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Haynesville acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2011, these identified potential future drilling locations included 102 gross and 17 net locations in the Haynesville shale play to which we have assigned proved undeveloped reserves.

We also have a large unevaluated acreage position in southwest Wyoming and adjacent areas in Utah and Idaho where we began drilling our initial well in February 2011 to test the Meade Peak natural gas shale. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September 2011 and completed drilling and coring operations on this well in November 2011. At December 31, 2011, this well had not been completed, as we were still evaluating the well logs and awaiting results from various core analysis tests. In addition, we have leasehold interests in the Delaware and Midland Basins in southeast New Mexico and west Texas where we are developing new oil and natural gas prospects.

We are active both as an operator and as a co-working interest owner with larger industry participants including affiliates of Chesapeake Energy Corporation, EOG Resources, Inc., Royal Dutch Shell plc and others. Of the 236 gross wells we have drilled or participated in drilling, we drilled approximately 40% of

these wells as the operator, although our working interest is small in many of the non-operated wells, particularly in the Haynesville shale. At December 31, 2011, we were the operator for approximately 85% of our Eagle Ford and 70% of our Haynesville acreage, including approximately 22% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in that core area is operated by a subsidiary of Chesapeake Energy Corporation. We also operate all of our acreage in southwest Wyoming and the adjacent areas of Utah and Idaho, as well as the vast majority of our acreage in southeast New Mexico and west Texas.

We are a non-operating working interest participant with affiliates of Chesapeake Energy Corporation, Royal Dutch Shell plc and several other companies in the Haynesville shale and with EOG Resources, Inc. in the Eagle Ford shale. We have entered into a joint operating agreement with an affiliate of Chesapeake Energy Corporation governing the Haynesville operations underlying our Elm Grove/Caspiana properties in southern Caddo Parish, Louisiana and a joint operating agreement with EOG Resources, Inc. governing all operations on our joint acreage in Atascosa County, Texas. We have not entered into a joint operating agreement with Royal Dutch Shell plc or certain other operators of wells in the Haynesville area in which we have a minority working interest. Particularly when our working interest is small, we do not always enter into formal operating agreements with the operators, and in such cases, we rely on applicable legal and statutory authority to govern our arrangement in accordance with industry standard practices.

Where we do have joint operating agreements with affiliates of Chesapeake Energy Corporation and EOG Resources, Inc., these agreements call for significant penalties should we elect not to participate in the drilling and completion of a well proposed by the operator, or a non-consent well. These non-consent penalties typically allow the operator to recover up to 400% of its costs to drill, complete and equip the non-consent well from the well’s future net revenue prior to us being allowed to participate in the non-consent well for our original working interest. Ultimately, the amount of these penalties may result in us having no participation at all in the non-consent well. We also have the right to propose wells under these joint operating agreements, and the same non-consent penalties apply to the operator should it elect not to consent to a well that we propose.

While we do not have direct access to our operating partners’ drilling plans with respect to future well locations, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations. We review these locations with Netherland, Sewell & Associates, Inc., our independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves.

The following table presents our 2012 anticipated capital expenditure budget of approximately $313.0 million segregated by target formation and by whether the wells are expected to be exploration or development wells.


	2012 Anticipated Drilling												2012 Anticipated Capital Expenditure Budget
	Gross Wells⁽¹⁾						Net Wells⁽¹⁾						(in millions)⁽²⁾
	Exploration		Development		Total		Exploration		Development		Total		Exploration		Development		Total
South Texas
Eagle Ford		13.0		15.0		28.0		11.8		13.8		25.6	$	122.3	$	134.9	$	257.2
Austin Chalk		2.0		–		2.0		2.0		–		2.0		11.3		–		11.3

Area Total		15.0		15.0		30.0		13.8		13.8		27.6		133.6		134.9		268.5
NW Louisiana / E Texas
Haynesville		6.0		19.0		25.0		0.2		1.3		1.5		1.9		11.6		13.5
Cotton Valley		–		–		–		–		–		–		–		–		–

Area Total		6.0		19.0		25.0		0.2		1.3		1.5		1.9		11.6		13.5
SW Wyoming, NE Utah, SE Idaho		1.0		–		1.0		0.4		–		0.4		2.5		–		2.5	⁽³⁾
SE New Mexico, West Texas		–		–		–		–		–		–		–		–		–
Other		N/A		N/A		N/A		N/A		N/A		N/A		25.0		3.5		28.5	⁽⁴⁾

Total		22.0		34.0		56.0		14.4		15.1		29.5	$	163.0	$	150.0	$	313.0

(1)	Includes wells we currently expect to drill and complete as operator, plus those wells in which we currently plan to participate as a non-operator in 2012.

(2)	Our capital expenditure budget is based on our net working interests in the properties.

(3)	We have a carried interest for $5.0 million of the cost of this well presuming the election of our joint venture partner to participate in the drilling of this well.

(4)	Includes $20.0 million to acquire additional leasehold interests primarily prospective for oil and liquids production in southeast New Mexico and west Texas.

Although we intend to allocate a portion of our 2012 capital expenditure budget to financing exploration, development and acquisition of additional interests in the Haynesville shale play, we currently intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration, development and acquisition of additional interests in the Eagle Ford shale play. Including these anticipated capital expenditures in the Eagle Ford shale play, we plan to dedicate about 94% of our 2012 anticipated capital expenditure budget to opportunities prospective for oil and liquids production. While we have budgeted $313.0 million for 2012, the aggregate amount of capital we will expend may fluctuate materially based on market conditions and our drilling results. Since at December 31, 2011, over 90% of our Haynesville acreage was held by production and approximately 80% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2013, we possess the financial flexibility to allocate our capital when we believe it is economical and justified.

Recent Developments

On February 7, 2012, we completed our initial public offering of 14,883,334 shares of common stock at $12.00 per share. We sold 12,209,167 shares of common stock in this offering and certain selling shareholders sold 2,674,167 shares of common stock, including shares sold by us and the selling shareholders pursuant to the partial exercise of the underwriters’ over-allotment option on March 7, 2012.

Between November 2011 and February 2012, we entered into various costless collars to mitigate our exposure to oil price volatility and enhance predictability of our cash flows. As of March 30, 2012, we had hedged a total of 1,180,000 Bbls of oil for 2012, 1,260,000 Bbls of oil for 2013 and 120,000 Bbls of oil for 2014. For 2012, these collars have a weighted average price floor of $90.51 per Bbl and a weighted average price ceiling of $109.84 per Bbl. For 2013, these collars have a weighted average price floor of $87.14 per Bbl and a weighted average price ceiling of $110.26 per Bbl. For 2014, these collars have a weighted average price floor of $90.00 per Bbl and a weighted average price ceiling of $114.90 per Bbl.

In December 2011, we amended and restated our senior secured revolving credit agreement. This amendment increased the maximum facility amount from $150.0 million to $400.0 million. Borrowings are limited to the lesser of $400.0 million or the borrowing base, which was $125.0 million as of March 30, 2012.

In November and December 2011, we completed three operated Eagle Ford horizontal wells, the Martin Ranch #2H, #3H and #5H in northeastern LaSalle County, Texas. During initial flow tests on these wells, the Martin Ranch #2H tested at approximately 1,310 Bbls of oil and 1.8 MMcf of natural gas per day, the Martin Ranch #3H tested at approximately 620 Bbls of oil and 0.5 MMcf of natural gas per day, and the Martin Ranch #5H tested at approximately 810 Bbls of oil and 0.6 MMcf of natural gas per day. All three wells were turned to sales in late December 2011. We are the operator and have a 100% working interest in these three wells.

Between March and July 2011, we acquired leasehold interests in approximately 6,300 gross and 4,800 net acres in DeWitt, Karnes, Wilson and Gonzales Counties, Texas in the Eagle Ford shale play from Orca ICI Development, JV. We believe that all of this acreage is in an oil and liquids prone area of the Eagle Ford play. We believe that the acreage in Wilson and Gonzales Counties and a portion of DeWitt County will be prospective for oil and liquids from the Austin Chalk formation in addition to the Eagle Ford. We paid approximately $31.5 million to acquire this acreage. We currently own a 50% working interest in the acreage (approximately 2,800 gross and 1,400 net acres) in DeWitt County and are the operator. We currently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net acres) in Karnes, Wilson and Gonzales Counties and are the operator.

Principal Areas of Interest

Our focus since inception has been the exploration for oil and natural gas in unconventional resource plays with a particular focus over the last few years in the Haynesville shale play and more recently in the Eagle Ford shale play. Our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our prospects, as well as to explore for more conventional targets in addition to the unconventional resource plays.

At December 2011, our principal areas of interest consisted of (1) the Eagle Ford shale play in south Texas, (2) the Haynesville shale play, including the Middle Bossier shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations in northwest Louisiana and east Texas, (3) the Meade Peak shale play in southwest Wyoming and the adjacent areas of Utah and Idaho and (4) southeast New Mexico and west Texas, including the Delaware and Midland Basins.

South Texas

Eagle Ford Shale and Other Formations

About 8% of our daily production, or 3.3 MMcfe per day, including 331 Bbls of oil per day and 1.3 MMcf of natural gas per day, was produced from the Eagle Ford shale in south Texas for the year ended December 31, 2011. The Eagle Ford contributed approximately 78% of our daily oil production and about 3% of our daily natural gas production for 2011. For the month of December 2011, about 13% of our daily production, or 5.6 MMcfe per day, including 706 Bbls of oil per day and 1.3 MMcf per day, was produced from the Eagle Ford. During December 2011, the Eagle Ford contributed 91% of our daily oil production and about 4% of our daily natural gas production. At December 31, 2011, approximately 14% of our proved reserves, or 27.9 Bcfe, was attributable to the Eagle Ford, including approximately 3.6 million Bbls of oil and 6.1 Bcf of natural gas. Our Eagle Ford proved reserves at December 31, 2011 comprised approximately 96% of our proved oil reserves and approximately 4% of our proved natural gas reserves. The present value discounted at 10% for our proved reserves in the Eagle Ford at December 31, 2011 was $130.2 million, or about 52% of the PV-10 for our total proved reserves of $248.7 million. We anticipate that the percentage of our daily production and reserves attributable to the Eagle Ford shale will grow in 2012 as we intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration, development and acquisition of additional interests in the Eagle Ford play in an effort to grow the oil and liquids component of our production and reserves.

The Eagle Ford shale extends across portions of south Texas from the Mexican border into east Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale, in places transitioning to an organic, argillaceous lime-mudstone. It lies between the deeper Buda limestone and the shallower Austin Chalk formation. Most, if not all, of the oil found in the Austin Chalk and Buda formations is generally believed to be sourced from the Eagle Ford shale. In the prospective areas for the Eagle Ford shale, the interval averages 200 feet thick, is found at depths ranging from as shallow as 4,000 feet to as deep as 13,000 feet, and in much of the deeper portions of the play is overpressured. The Eagle Ford shale has a total organic carbon content of 1% to 7% that is comparable to the Haynesville shale, and is generally porous, with core-measured porosities ranging between 4% and 14%.

Along the entire length of the Eagle Ford trend the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the formation is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford shale is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces wet gas with condensate. We believe that approximately 85% of our Eagle Ford acreage lies within those portions of the Eagle Ford shale that are prone to produce oil or wet gas with condensate.

Most of the current Eagle Ford shale activity is concentrated in Atascosa, Bee, DeWitt, Dimmit, Frio, Gonzales, Karnes, LaSalle, Lavaca, Live Oak, Maverick, McMullen, Webb, Wilson and Zavala Counties in south Texas. The first horizontal wells drilled specifically for the Eagle Ford shale were drilled in 2008, leading to a discovery in LaSalle County. Since then, the play has expanded significantly across a large portion of south Texas.

Publicly available information indicates that operators are typically drilling 3,500 to 7,000 feet horizontal laterals and applying hydraulic fracture stimulation in multiple stages along the full length of the horizontal laterals to complete the wells and establish production. Although production rates vary across the

different areas of the play, initial production rates in the oil areas have been reported as high as 1,000 to 1,500 Bbls of oil per day with varying amounts of associated natural gas. In the natural gas areas of the Eagle Ford play, initial production rates as high as 5.0 to 15.0 MMcfe per day have been reported with varying amounts of associated oil and liquids.

At December 31, 2011, our aggregate leasehold interests consisted of approximately 51,000 gross acres and 29,000 net acres in the Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, LaSalle, Gonzales, Webb, Wilson and Zavala Counties in south Texas. We believe portions of this acreage are also prospective for the Austin Chalk, Buda, Olmos and other formations, from which we expect to produce predominantly oil and liquids. In particular, the Austin Chalk formation, which is a naturally fractured carbonate ranging in thickness from 200 to 400 feet, has produced from several fields on or nearby portions of our acreage. Our Zavala County acreage, for example, is located within the historic Pearsall (Austin Chalk) field.

We believe that approximately 85% of our Eagle Ford acreage is prospective predominantly for oil and liquids. At December 31, 2011, we owned a 100% working interest in approximately 26,000 gross acres and 23,000 net acres in Dimmit, Gonzales, Karnes, LaSalle, Webb, Wilson and Zavala Counties and a 50% working interest in approximately 2,800 gross and 1,400 net acres in DeWitt County and are the operator of this acreage. We also owned an approximate 21% working interest in approximately 22,000 gross acres in Atascosa County operated by EOG Resources, Inc. At December 31, 2011, approximately 80% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2013.

At December 31, 2011, we had drilled and completed seven Eagle Ford wells on our operated properties. All of these wells were producing to sales, although four of these wells were initially placed on production in late December. At December 31, 2011, we had also participated in two Eagle Ford wells with EOG Resources, Inc. as operator, on the Atascosa County acreage. Our first operated Eagle Ford horizontal well, the JCM Jr. Minerals #1H in southern LaSalle County along the Edwards Reef, was completed in November 2010. First sales of oil and natural gas began from this well in late January 2011, and during December 2011, the well produced at an average daily rate of approximately 0.5 MMcf of natural gas and 9 Bbls of condensate per day, and through December 31, 2011, had produced a total of approximately 430 MMcf of natural gas and 11,200 Bbls of condensate. Our second operated Eagle Ford horizontal well, the Martin Ranch #1H in northeastern LaSalle County, was completed in January 2011 and tested approximately 1,200 Bbls of oil per day during an initial flow test. First sales of oil and natural gas from this well began in late March at approximately 700 Bbls of oil and 350 Mcf of natural gas per day. During December 2011, the well produced at an average daily rate of approximately 330 Bbls of oil and 0.6 MMcf of natural gas per day, and through December 31, 2011, had produced a total of 117,000 Bbls of oil and 144 MMcf of natural gas.

Our third operated Eagle Ford horizontal well, the Affleck #1H, was completed in February 2011 in eastern Dimmit County, Texas, and tested at approximately 415 Bbls of oil and 5.4 MMcf of natural gas per day during an initial flow test. During December 2011, the well produced at an average daily rate of 0.8 MMcf of natural gas and 38 Bbls of oil per day. In August 2011, we completed our fourth operated Eagle Ford horizontal well, the Lewton #1H in DeWitt County, Texas. This well tested at approximately 2.7 MMcf of natural gas and 1,040 Bbls of condensate per day during an initial flow test. The Lewton well began producing to sales in late December 2011.

In November and December 2011, we completed three additional operated Eagle Ford horizontal wells, the Martin Ranch #2H, #3H and #5H, in northeastern LaSalle County, Texas. During initial flow tests on these wells, the Martin Ranch #2H tested at approximately 1,310 Bbls of oil and 1.8 MMcf of

natural gas per day, the Martin Ranch #3H tested at approximately 620 Bbls of oil and 0.5 MMcf of natural gas per day, and the Martin Ranch #5H tested at approximately 810 Bbls of oil and 0.6 MMcf of natural gas per day. All three wells were turned to sales in late December 2011.

Between March and July 2011, we acquired leasehold interests in approximately 6,300 gross and 4,800 net acres in DeWitt, Karnes, Wilson and Gonzales Counties, Texas in the Eagle Ford shale play from Orca ICI Development, JV. We paid approximately $31.5 million to acquire this acreage. We currently own a 50% working interest in the acreage (approximately 2,800 gross and 1,400 net acres) in DeWitt County and are the operator. We currently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net acres) in Karnes, Wilson and Gonzales Counties and are the operator. At December 31, 2011, we had drilled and completed only one well on this acreage, the Lewton #1H in DeWitt County.

We will pay 100% of the costs to drill and complete the first six wells drilled on the acreage in DeWitt County. We will have an 85% working interest in these six wells until we have recovered all of our acquisition, drilling and completion costs from each well, at which time Orca’s working interest will increase to 50%. When the cumulative production from each of the first six wells reaches 500,000 BOE, on a well-by-well basis, then Orca’s working interest in that well increases to 55%. If the cumulative production from each of the first six wells reaches 750,000 BOE, on a well-by-well basis, then Orca’s working interest in that well will increase to 70%. Both we and Orca will own a 50% working interest in all subsequent wells drilled after the first six wells on the acreage in DeWitt County.

We will have a 100% working interest in the first five wells drilled on the acreage in Karnes, Wilson and Gonzales Counties. When we have recovered all of our acquisition, drilling and completion costs from each of these five wells, Orca may elect, on a well-by-well basis, to back-in for a 25% working interest in these wells. In addition, Orca retains a one-time election for a short period of time after we complete these first five wells to participate for a 25% working interest in all subsequent wells drilled on this acreage by paying a purchase price equal to 25% of our costs to acquire the acreage in Karnes, Wilson and Gonzales Counties.

At March 30, 2012, we had drilled an aggregate of 15 Eagle Ford horizontal wells in south Texas as operator, including 10 wells in LaSalle County, one well in Dimmit County, three wells in Karnes County and one well in DeWitt County. Thirteen of these wells have been completed and are producing and two of these wells are awaiting completion. At March 30, 2012 we had two contracted drilling rigs operating in the Eagle Ford play in south Texas: one in LaSalle County and one in Karnes County. We are not currently experiencing difficulties in securing completion, and particularly hydraulic fracturing services, for our newly drilled wells, although we experienced these problems at various times during 2011 in south Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling and completion services and reducing drilling and completion costs will be essential to the successful development and profitability of the Eagle Ford shale play. See “Risk Factors – The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.”

We experienced temporary pipeline interruptions from time to time during 2011 associated with natural gas production from our Eagle Ford wells and have been required to either shut in wells for brief periods or to flare some of the natural gas we produce. At March 30, 2012, we were experiencing pipeline capacity limitations at our Martin Ranch lease in LaSalle County and are currently flaring a portion of the natural gas we are producing there as a result. We believe that these pipeline interruptions and capacity

constraints are temporary and that additional oil and natural gas pipeline infrastructure currently being built throughout south Texas will help to alleviate these problems within 60 to 90 days. If we were required to shut in our production for long periods of time due to these pipeline interruptions, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Risk Factors – The Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Transportation Agreements Would Have a Material Adverse Effect on Our Revenue.”

In addition to the Eagle Ford potential on our acreage, we believe that approximately 24,000 gross acres and 15,000 net acres in south Texas are prospective primarily for the Austin Chalk formation, which has historically been targeted by operators in south Texas. We have not yet drilled an Austin Chalk well, and although we believe that other prospective well locations exist on this acreage, we have only included 16 gross and net well locations in our total identified drilling locations at December 31, 2011.

Northwest Louisiana and East Texas

At December 31, 2011, most of our production and proved reserves was attributable to our acreage in northwest Louisiana and east Texas. For the year ended December 31, 2011, about 76% of our daily production, or 32.3 MMcfe per day, was produced from the Haynesville shale, with another 15%, or 6.5 MMcfe per day, produced from the Cotton Valley and other shallower formations in this area. At December 31, 2011, approximately 78% of our proved reserves, or 150.4 Bcfe, were attributable to the Haynesville shale underlying this acreage with another 7% of our proved reserves, or 14.2 Bcfe, associated with the Cotton Valley and shallower formations. In addition, we are evaluating the Bossier shale play which is generally encountered above the Haynesville shale and below the Cotton Valley formation.

We operate all of our Cotton Valley and shallower production under this acreage, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville play. Of the approximately 5,500 net acres that we consider to be in the core area of the Haynesville play, we operate about 22% of that acreage.

In recent months, natural gas prices have declined to their lowest levels in many years, and at March 30, 2012, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at $2.13 per MMBtu. We would not expect to drill any operated natural gas wells in either our Haynesville or Cotton Valley properties until natural gas prices improved substantially from these levels or unless the costs to drill and complete these wells were also to decline substantially from their recent levels. See “Risk Factors – Our Identified Drilling Locations Are Scheduled Out Over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.”

Haynesville and Middle Bossier Shales

The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout northwest Louisiana and east Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale has a typical thickness ranging from 100 to 300 feet. Total organic carbon ranges from 0.5% to 5.0%, with core-measured porosities from 3% to 15%. The Haynesville shale produces primarily dry natural gas with almost no associated liquids.

The oil and natural gas industry has focused significant attention on the Haynesville shale play over the last several years. Operators are typically drilling 4,500 to 5,000 feet horizontal laterals and applying hydraulic fracture stimulation in multiple stages along the entire length of the horizontal laterals to complete the wells and establish production. Although initial production rates vary widely across the play, initial production rates as high as 20.0 to 25.0 MMcf per day of natural gas have been reported by operators from horizontal wells drilled and completed in the Haynesville shale.

The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics to the deeper Haynesville shale. Typically, the Middle Bossier shale is found at depths ranging from 500 to 800 feet shallower than the Haynesville shale, has a typical thickness ranging from 150 to 300 feet, has core-measured porosities ranging between 5% and 14%, and total organic carbon values between 0.5% and 4%. Although there is some overlap between the Bossier and Haynesville shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation.

At December 31, 2011, we had leasehold and mineral interests in approximately 23,000 gross and 15,000 net acres prospective for the Haynesville shale. Portions of our acreage are located in Caddo, DeSoto, Bossier and Red River Parishes, Louisiana and in Harrison County, Texas. This acreage includes approximately 5,500 net acres in what we believe is the core area of the play. Over 90% of our Haynesville acreage is held by production and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,700 net acres are prospective for the Middle Bossier play as well. We have not yet drilled a Middle Bossier shale well, and, although we believe that prospective well locations exist on this acreage, we have not yet included any Middle Bossier locations in our identified drilling locations at December 31, 2011.

Within the 5,500 net acres that we believe to be in the core area of the Haynesville shale play, we are the operator in two sections where we have working interests of 95% and 100% in all wells to be drilled. In October 2010, as operator, we drilled and completed our L.A. Wildlife H #1 horizontal Haynesville well in the section in which we have a 95% working interest and on December 31, 2010 first sales of natural gas began from this well. During December 2011, the well produced at an average daily rate of approximately 8.7 MMcf of natural gas per day, and through December 31, 2011, had produced a total of approximately 3.4 Bcf of natural gas. In March 2011, we completed our operated Williams 17 H #1 horizontal Haynesville well on the second section where we have a 100% working interest. During December 2011, this well produced at an average daily rate of 3.9 MMcf of natural gas per day and, through December 31, 2011, had produced approximately 1.8 Bcf of natural gas. We began producing both of these wells at a constrained rate of about 10.0 MMcf of natural gas per day. We have identified 12 gross and approximately 12 net potential additional Haynesville locations that we may drill and operate in the future in these two sections.

The remainder of our acreage in the core area of the Haynesville shale play, about 4,300 net acres, is operated by other companies. Just over half of our non-operated Haynesville acreage in this area of the play results from a transaction with a subsidiary of Chesapeake in July 2008. The remainder of our non-operated Haynesville acreage is attributable to leasehold interests that we hold in approximately 87 sections in Caddo, DeSoto, Bossier and Red River Parishes. Our working interests in the Haynesville wells in these sections range from less than 1% to more than 30%. At December 31, 2011, our production from these non-operated Haynesville wells averaged approximately 22 MMcfe per day.

We do not plan to drill any operated Haynesville wells in 2012, but we have budgeted capital expenditures of approximately $13 million for our anticipated participation in approximately 25 gross (1.5 net) non-operated wells that may be drilled in order to hold expiring acreage or that may be proposed in multi-well development programs to evaluate optimal well spacing.

Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations

Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in northwest Louisiana and east Texas were attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in northwest Louisiana and east Texas.

All of the shallow rights underlying our acreage in our Elm Grove/Caspiana properties in northwest Louisiana, approximately 10,000 gross and net acres at December 31, 2011, is held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to discovery of the Haynesville shale. The Cotton Valley formation is a low permeability gas sand that ranges in thickness from 200 to 300 feet and has porosities ranging from 6% to 10%.

In January 2011, we completed our first horizontal Cotton Valley well, the Tigner Walker H #1-Alt. in our Elm Grove/Caspiana properties, in DeSoto Parish and commenced sales of natural gas from this well. Prior to this time, we had only drilled and completed vertical Cotton Valley and Hosston wells on these properties. During December 2011, this well produced at an average daily rate of approximately 1.6 MMcf of natural gas per day and through December 31, 2011, had produced a total of approximately 950 MMcf of natural gas. We are the operator and have a 100% working interest in this well. We have identified 60 gross and 36 net additional drilling locations for future Cotton Valley horizontal wells in our Elm Grove/Caspiana properties. We do not plan to drill any of these locations in 2012. As all of this acreage is held by existing production, we expect to allocate the majority of our near-term capital expenditures primarily to exploration and development of our Eagle Ford shale acreage in south Texas.

We also continue to hold the shallow rights by existing production or by leases that are still in their primary terms in our central and southwest Pine Island, Longwood, Woodlawn and other prospect areas in northwest Louisiana and east Texas. At December 31, 2011, we held an estimated 11,500 net leasehold and mineral acres by existing production in these areas.

Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale

The Meade Peak shale is an organic-rich source rock that has sourced much of the oil and natural gas in conventional reservoirs in the western Wyoming and eastern Utah area. The Meade Peak shale has an observed shale thickness of 70 to 350 feet, total organic carbon of 3% to 7% and vitrinite reflectance values ranging from 1.8% to 2.7%. The Meade Peak shale is encountered at drill depths of 3,000 to 14,000 feet, with the majority of our acreage in the depth range of 3,000 to 10,000 feet. The shale has been penetrated by over 100 wells in the area, most of which have natural gas shows. Seismic and subsurface data show distinct, stacked thrust plates with areas of sediment prospective for natural gas.

At December 31, 2011, we had assembled approximately 144,000 gross, or approximately 136,000 net, acres in southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploratory prospect targeting the Meade Peak shale. The majority of this acreage, with lease terms of five to ten years, has been acquired by us within the past four to five years, and we are the operator of this prospect.

We believe there have been no previous attempts to drill horizontally or to hydraulically fracture the Meade Peak shale in this area. Our focus to date has been to confirm the structure of the Meade Peak shale, understand its characteristics and evaluate its potential. We have gathered well log data in the area and studied the petrophysical characteristics. In addition, we have purchased 2-D seismic data and have worked with a structural geologist that has experience in the immediate area to better understand the area’s tectonic history.

We have entered into a participation and joint operating agreement with other parties covering the initial exploration efforts and, if successful, the future development of this acreage. We began drilling the initial test well on this prospect, the Crawford Federal #1 well in Lincoln County, Wyoming, in February 2011. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September 2011 and completed drilling and coring operations on this well in November 2011. At December 31, 2011, this well had not been completed, as we were still evaluating the well logs and awaiting results from various core analysis tests.

Approximately 102,000 gross, or approximately 93,000 net, acres in this prospect are scheduled to expire at various times during 2012. Although we plan to seek extensions on some of this acreage, certain leases, particularly those taken on state lands, do not offer the opportunity for automatic extension, and we will be required to obtain new leases on these lands should we desire and be able to do so. We expect that a significant portion of the 93,000 net acres will be allowed to expire during 2012, while we and our partners continue to evaluate the results from our initial test well and plan for its completion and further testing. We have no production and no proved reserves attributable to this acreage at December 31, 2011.

Southeast New Mexico and West Texas — Delaware and Midland Basins

The Delaware and Midland Basins are mature exploration and production provinces with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in these basins has focused on relatively conventional reservoir targets, but we believe the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of these basins.

One example of such an opportunity appears to be the so-called “Wolf-Bone” play of the Delaware Basin. Together, the Lower Permian age Bone Spring (also called Leonardian) and Wolfcamp formations span several thousand feet of stacked shales, sandstones, limestones and dolomites representing complex and dynamic submarine depositional systems that include several organic rich source rocks. Throughout these intervals, oil and natural gas have been produced primarily from conventional sandstone and carbonate reservoirs even though hydrocarbons are trapped in the tight sands, limestones and dolomites interbedded within organic rich shale. Recently, these hydrocarbon-bearing zones have been recognized by a number of operators as targets for horizontal drilling and multi-stage hydraulic fracturing techniques. As a result, several large industry players are expanding positions and conducting drilling programs throughout Lea and Eddy Counties in southeast New Mexico and Loving, Reeves and Ward Counties in west Texas.

Although the Delaware and Midland Basins have not been a primary focus of our recent operations or exploration efforts, we were developing new oil and natural gas prospects in these basins at December 31, 2011. Most notably, we have identified potential drilling opportunities on our acreage, particularly in southeast New Mexico, near old vertical wells, some of which have produced up to 1,000,000 BOE from the Wolfcamp formation and up to 500,000 BOE from the Bone Spring formation. These wells suggest a hydrocarbon-rich environment in the area of our acreage, and after completing our internal geologic studies, we may determine to drill a Wolfcamp or Bone Spring vertical well or to drill a horizontal well to test these formations on our acreage.

At December 31, 2011, we had not included any potential drilling locations on our acreage in our total identified drilling locations, and we had not budgeted any capital expenditures to drill wells in southeast New Mexico or west Texas during 2012. We have budgeted $20.0 million of our anticipated 2012 capital expenditures to acquire additional leasehold interests primarily prospective for oil and liquids production in areas of southeast New Mexico and west Texas where we are developing new prospects. Although we do have existing leasehold interests in this area of approximately 11,000 gross and approximately 7,000 net acres at December 31, 2011, we believe approximately 8,000 gross and 4,000 net acres are no longer prospective, and we plan to let them expire without drilling.

Operating Summary

The following table sets forth certain unaudited production data for the years ended December 31, 2011, 2010 and 2009:


	Year Ended December 31,
	2011		2010		2009
Unaudited Production Data
Net Production Volumes:
Oil (MBbls)		154		33		30
Natural gas (Bcf)		14.5		8.4		4.8
Total natural gas equivalents (Bcfe)⁽¹⁾		15.4		8.6		5.0
Average daily production (MMcfe/d)⁽¹⁾		42.3		23.6		13.7

Average Sales Prices:
Oil (per Bbl)	$	93.80	$	76.39	$	57.72
Natural gas, with realized derivatives (per Mcf)	$	4.11	$	4.38	$	5.17
Natural gas, without realized derivatives (per Mcf)	$	3.62	$	3.75	$	3.59

Operating Expenses (per Mcfe):
Production taxes and marketing	$	0.41	$	0.23	$	0.22
Lease operating	$	0.47	$	0.61	$	0.94
Depletion, depreciation and amortization	$	2.06	$	1.81	$	2.15
General and administrative	$	0.87	$	1.13	$	1.42

(1)	Estimated using a conversion ratio of one Bbl per six Mcf.

The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2010 from our primary operating areas:


	Average Net Daily Production						Total Net Production (MMcfe)		Percentage of Total Net Production
	Gas (Mcf/d)		Oil (Bbls/d)		Gas Equivalent (Mcfe/d)		Total Net Production (MMcfe)		Percentage of Total Net Production
South Texas:
Eagle Ford		4		19		119		43		0.5	%
Austin Chalk⁽¹⁾		–		–		–		–		–

Area Total		4		19		119		43		0.5

NW Louisiana/E Texas:
Haynesville		17,127		1		17,132		6,253		72.7
Cotton Valley⁽²⁾		5,840		40		6,074		2,218		25.8

Area Total		22,967		41		23,206		8,471		98.5

SW Wyoming, NE Utah, SE Idaho⁽¹⁾		–		–		–		–		–
SE New Mexico, West Texas		43		31		228		83		1.0

Total		23,014		91		23,553		8,597		100.0	%

(1)	We currently have no production from our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificant production from the Austin Chalk formation in south Texas.

(2)	Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing from the San Miguel formation in Zavala County, Texas.

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


	Average Net Daily Production						Total Net Production (MMcfe)		Percentage of Total Net Production
	Gas (Mcf/d)		Oil (Bbls/d)		Gas Equivalent (Mcfe/d)		Total Net Production (MMcfe)		Percentage of Total Net Production
South Texas:
Eagle Ford		1,298		331		3,286		1,200		7.8	%
Austin Chalk⁽¹⁾		–		–		–		–		–

Area Total		1,298		331		3,286		1,200		7.8

NW Louisiana/E Texas:
Haynesville		32,319		–		32,319		11,797		76.4
Cotton Valley⁽²⁾		6,084		64		6,465		2,360		15.3

Area Total		38,403		64		38,784		14,157		91.7

SW Wyoming, NE Utah, SE Idaho⁽¹⁾		–		–		–		–		–
SE New Mexico, West Texas		59		27		221		81		0.5

Total		39,760		422		42,291		15,438		100.0	%

(1)	We currently have no production from our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificant production from the Austin Chalk formation in south Texas.

(2)	Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing from the San Miguel formation in Zavala County, Texas.

Our total production of 15.4 Bcfe for the year ended December 31, 2011 was an increase of 79% over our total production of 8.6 Bcfe for the year ended December 31, 2010. This increased production was primarily due to drilling operations in the Haynesville shale, but a portion of the increase also reflects production due to our initial drilling operations in the Eagle Ford shale. Our total production of 8.6 Bcfe for the year ended December 31, 2010 was an increase of 72% over our total production of 5.0 Bcfe for the year ended December 31, 2009. Most of this increase was attributable to our drilling operations in the Haynesville shale play. In addition, as a result of production from new wells that were completed in 2011, our daily production for the year ended December 31, 2011 averaged approximately 42.3 MMcfe per day, as compared to 23.6 MMcfe per day for the year ended December 31, 2010. Our daily oil production for the year ended December 31, 2011 averaged 422 Bbls per day, an approximate five-fold increase from 91 Bbls per day for the year ended December 31, 2010.

Producing Wells

The following table sets forth information relating to producing wells at December 31, 2011. Wells are classified as oil or natural gas according to their predominant production stream. We do not have any currently active dual completions. We have an approximate average working interest of 92% in all wells that we operate. For wells where we are not the operator, our working interests range from less than 1% to as much as 44%, and average approximately 9%. In the table below, gross wells are the total number of producing wells in which we own a working interest, and net wells represent the total of our fractional working interests owned in the gross wells.


	Natural Gas Wells				Oil Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
South Texas:
Eagle Ford		2.0		2.0		7.0		5.3		9.0		7.3
Austin Chalk⁽¹⁾		–		–		–		–		–		–

Area Total		2.0		2.0		7.0		5.3		9.0		7.3
NW Louisiana/E Texas:
Haynesville		106.0		11.6		–		–		106.0		11.6
Cotton Valley⁽²⁾		106.0		69.7		2.0		2.0		108.0		71.7

Area Total		212.0		81.3		2.0		2.0		214.0		83.3
SW Wyoming, NE Utah, SE Idaho⁽¹⁾		–		–		–		–		–		–
SE New Mexico, West Texas		1.0		0.6		12.0		5.1		13.0		5.7

Total		215.0		83.9		21.0		12.4		236.0		96.3

(1)	We currently have no producing wells on our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificant production from the Austin Chalk formation in south Texas.

(2)	Includes shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing from the San Miguel formation in Zavala County, Texas.

Estimated Proved Reserves

The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2011, 2010 and 2009. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. 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 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,⁽¹⁾
	2011			2010			2009
Estimated Proved Reserves Data:⁽²⁾
Estimated proved reserves:
Oil (MBbls)		3,794			152			103
Natural Gas (Bcf)		170.4			127.4			63.9

Total (Bcfe)		193.2			128.3			64.5

Estimated proved developed reserves:
Oil (MBbls)		1,419			152			103
Natural Gas (Bcf)		56.5			43.1			25.4

Total (Bcfe)		65.1			44.1			26.0

Percent developed		33.7	%		34.3	%		40.3	%
Estimated proved undeveloped reserves:
Oil (MBbls)		2,375			–			–
Natural Gas (Bcf)		113.9			84.3			38.6

Total (Bcfe)		128.1			84.3			38.6

PV-10⁽³⁾ (in millions)	$	248.7		$	119.9		$	70.4
Standardized Measure⁽⁴⁾(in millions)	$	215.5		$	111.1		$	65.1

(1)	Numbers in table may not total due to rounding.

(2)

Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2009 were $57.65 per Bbl for oil and $3.866 per MMBtu for natural gas, for the 12 months ended December 31, 2010 were $75.96 per Bbl for oil and $4.376 per MMBtu for natural gas, and for the 12 months ended December 31, 2011 were $92.71 per Bbl for oil and $4.118 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing 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 properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2009, 2010 and 2011 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2009, 2010 and 2011 were, in millions, $5.3, $8.8 and $33.2, respectively.

(4)

Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, 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 properties.

Our total proved oil and natural gas reserves increased from 128.3 Bcfe at December 31, 2010 to 193.2 Bcfe at December 31, 2011. Most of this increase is attributable to proved reserves added due to our drilling operations in both the Eagle Ford and Haynesville shale plays. The increase in proved oil reserves specifically from 152 MBbls at December 31, 2010 to 3,794 MBbls at December 31, 2011 is attributable to proved oil reserves added due to our drilling operations in the Eagle Ford shale play. Our proved reserves at December 31, 2011 were made up of approximately 88% natural gas and 12% oil. Our proved developed reserves increased from 44.1 Bcfe at December 31, 2010 to 65.1 Bcfe at December 31, 2011 due primarily to proved developed reserves added as a result of drilling operations in both the Eagle Ford and Haynesville shale plays. The increase in proved developed oil reserves specifically from 152 MBbls at December 31, 2010 to 1,419 MBbls at December 31, 2011 is attributable to proved developed oil reserves added due to our drilling operations in the Eagle Ford shale play. Our proved undeveloped reserves increased from 84.3 Bcfe at December 31, 2010 to 128.1 Bcfe at December 31, 2011 due primarily to our drilling operations in the Eagle Ford and Haynesville shale plays. The increase in our proved undeveloped oil reserves specifically from zero to 2,375 MBbls at December 31, 2011 is attributable to our drilling operations in the Eagle Ford shale play. The net increase of 43.8 Bcfe in our proved undeveloped reserves from December 31, 2010 to December 31, 2011 is composed of (1) additions of 49.0 Bcfe to proved undeveloped reserves identified through drilling operations, less (2) the conversion of 3.4 Bcfe of proved undeveloped reserves to proved developed reserves, less (3) the downward revisions of proved undeveloped reserves by 1.8 Bcfe in the period. During this period, we recorded no changes to proved undeveloped reserves as a result of the acquisition or divestment of reserves. At December 31, 2011, we had no proved reserves in our estimates that remained undeveloped for five years or more following their initial booking.

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


	Net Proved Reserves⁽¹⁾						PV-10⁽²⁾		Standardized Measure⁽³⁾
	Oil		Gas		Gas Equivalent		PV-10⁽²⁾		Standardized Measure⁽³⁾
	(MBbls)		(Bcf)		(Bcfe)		(in millions)		(in millions)
South Texas:
Eagle Ford		3,636		6.1		27.9	$	130.2	$	112.8
Austin Chalk⁽⁴⁾		–		–		–		–		–

Area Total		3,636		6.1		27.9		130.2		112.8
NW Louisiana/E Texas:
Haynesville		–		150.4		150.4		96.6		83.7
Cotton Valley⁽⁵⁾		61		13.8		14.2		19.5		16.9

Area Total		61		164.2		164.6		116.1		100.6
SW Wyoming, NE Utah, SE Idaho⁽⁴⁾		–		–		–		–		–
SE New Mexico, West Texas		97		0.1		0.7		2.4		2.1

Total		3,794		170.4		193.2	$	248.7	$	215.5

(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 properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties 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 income taxes associated with such reserves. The discounted future income taxes at December 31, 2011 were approximately $33.2 million.

(3)

(4)	At December 31, 2011, we had no proved reserves attributable to the Austin Chalk formation in south Texas or to our acreage in southwest Wyoming and adjacent areas of Utah and Idaho.

(5)	Includes Cotton Valley and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing from the San Miguel formation in Zavala County, Texas.

Technology Used to Establish Reserves

Under current 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 reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods.

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 Reserves Manager is primarily responsible for overseeing the preparation of our reserves estimates and has over 15 years of industry experience. Our Reserves Manager received his Ph.D. degree in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and received a certificate of completion in a prescribed course of study in Reserves and Evaluation from Texas A&M University in May 2009. Our Vice President – Reservoir Engineering is responsible for reviewing and approving our reserves estimates and has over 30 years of industry experience. Following the preparation of our reserves estimates, we had our reserves estimates audited for their reasonableness by Netherland, Sewell & Associates, Inc., our independent petroleum engineers. The Engineering Committee of our board of directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by members of our board of directors, including members of our Audit Committee.

Acreage Summary

The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2011. At that date, only about 12% of our total acreage had been developed, although these percentages are much higher in northwest Louisiana and east Texas.


	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
South Texas:
Eagle Ford		2,514		2,130		48,225		26,543		50,739		28,673
Austin Chalk		–		–		24,473		14,849		24,473		14,849

Area Total⁽¹⁾		2,514		2,130		48,225		26,543		50,739		28,673
NW Louisiana/E Texas:
Haynesville		18,713		10,599		4,158		3,928		22,871		14,527
Cotton Valley⁽²⁾		20,942		17,846		5,327		5,208		26,269		23,054

Area Total⁽³⁾		23,033		19,691		5,866		5,648		28,899		25,339
SW Wyoming, NE Utah, SE Idaho		–		–		144,368		135,862		144,368		135,862
SE New Mexico, West Texas		1,160		1,038		9,554		5,620		10,714		6,658

Total		26,707		22,859		208,013		173,673		234,720		196,532

(1)	Some of the same leases cover the net acres shown for the Eagle Ford shale and the Austin Chalk formation, a shallower formation than the Eagle Ford shale. Consequently, the total acreage will not equal the sum of the acreage by operating area.

(2)	Includes shallower zones and also includes acreage surrounding one well producing from the Frio formation in Orange County, Texas.

(3)	Some of the same leases cover the net acres shown for the Haynesville formation and the Cotton Valley formation, a shallower formation than the Haynesville shale. Consequently, the total acreage will not equal the sum of the acreage by operating area.

Undeveloped Acreage Expiration

The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2011 that will expire prior to December 31, 2013 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
	Gross		Net		Gross		Net
South Texas:
Eagle Ford		15,044		4,349		12,165		7,149
Austin Chalk		5,731		1,133		3,851		2,646

Area Total⁽¹⁾		15,044		4,349		12,165		7,149
NW Louisiana/E Texas
Haynesville		644		395		40		5
Cotton Valley		750		401		40		5

Area Total⁽²⁾		750		401		40		5
SW Wyoming, NE Utah, SE Idaho		101,905		93,356		8,461		8,301
SE New Mexico, West Texas		1,712		79		8,454		2,715

Total		119,411		98,185		29,120		18,170

(1)	Some of the same leases cover the net acres shown for the Eagle Ford shale and the Austin Chalk formation, a shallower formation than the Eagle Ford shale. Consequently, the total acreage will not equal the sum of the acreage by operating area.

(2)	Some of the same leases cover the net acres shown for the Haynesville shale and the Cotton Valley formation, a shallower formation than the Haynesville shale. Consequently, the total acreage will not equal the sum of the acreage by operating area.

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

Drilling Results

The following table summarizes our drilling activity for the three years ended December 31, 2011, 2010 and 2009:


	Year Ended December 31,
	2011				2010				2009
	Gross		Net		Gross		Net		Gross		Net
Development Wells
Productive		30		0.6		5		1.7		3		1.3
Dry		–		–		–		–		–		–
Exploration Wells
Productive		30		10.2		36		3.4		15		6.0
Dry		–		–		–		–		2		2.0
Total Wells
Productive		60		10.8		41		5.1		18		7.3
Dry		–		–		–		–		2		2.0

Marketing

Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. Transportation costs related to moving crude oil are also deducted from the price received for crude oil.

Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated mid-stream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees. When there is an opportunity to do so, the mid-stream companies may, at our request, process our natural gas at a processing facility and extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on a negotiated percentage of the proceeds that are generated from the mid-stream companies’ sale of the liquids, or based on other negotiated pricing arrangements.

The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include the level of demand for oil and natural gas, weather conditions, hurricanes in the Gulf Coast region, natural gas storage levels, domestic and foreign governmental regulations, the actions of OPEC, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall

economic conditions. Decreases in these commodity prices do adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production do occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations do curtail our production capabilities and ability to maintain a steady source of revenue for our company. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.”

For the year ended December 31, 2009, we had three significant purchasers that each accounted for more than 10% of our total oil and natural gas revenues: Chesapeake Operating Inc. (32%), Regency Gas Services LP (25%), and J-W Operating Company (17%). For the year ended December 31, 2010, we had three significant purchasers that each accounted for more than 10% of our total oil and natural gas revenues: Chesapeake Operating Inc. (42%), Regency Gas Services LP (17%) and Petrohawk Energy Corporation (11%). For the year ended December 31, 2011, we had three significant purchasers that each accounted for more than 10% of our total oil and natural gas revenues: Sequent Energy Management (24%), Chesapeake Operating Inc. (21%) and Eastex Crude Company (15%). Due to the nature of the markets for oil and natural gas, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time.

While we do not have any commitments to sell a fixed and determinable quantity of oil or natural gas to a particular buyer, we were party to two natural gas transportation agreements at December 31, 2011 that require us to deliver a specified volume of natural gas through pipelines for a fixed period of time. If we fail to meet the volume requirements, we are required to pay an amount to the owners of the pipelines to offset a portion of the expenses they incurred in building the pipelines to our well locations. Neither of these contracts constitutes a material commitment.

Title to Properties

We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by making lease rental payments or by producing wells in paying quantities prior to expiration of various time periods to avoid lease termination. Certain of the leases that we have obtained to date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.”

Competition

The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill,

operate and develop our properties. Most of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs.

Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while our competitors have a longer history of operations, and most of them have also demonstrated the ability to operate through industry cycles.

The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors – Competition in the Oil and Natural Gas Industry Is Intense Making It More Difficult for Us to Acquire Properties, Market Natural Gas and Secure Trained Personnel.”

Regulation

Oil and Natural Gas Regulation

Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are frequently amended or reinterpreted and new rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations.

Texas, New Mexico, Louisiana, Wyoming, Idaho and Utah and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases.

Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue.

In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the NGA, the NGPA, or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third party damage claims.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated.

The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations.

In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future regulations or their impact.

U.S. Federal and State Taxation

presidential administrations concerning a variety of energy tax proposals. President Obama has recently proposed sweeping changes in federal laws on the income taxation of small oil and natural gas exploration and production companies such as us. President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Many states have raised state taxes on energy sources, and additional increases may occur. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.”

Hydraulic Fracturing Policies and Procedures

We use hydraulic fracturing as a means to maximize the productivity of our oil and natural gas wells in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately 50% of the drilling and completion costs for our horizontal wells are associated with hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditures budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.”

The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM with respect to federal acreage). Our policy and practice is to follow all applicable guidelines and regulations in the areas where we conduct hydraulic fracturing. A surface casing string is typically set deeper than the deepest usable quality fresh water zones and cemented back to the surface in accordance with the appropriate regulations, lease requirements and legal requirements. This surface string of casing is then pressure tested to ensure mechanical integrity of the casing string prior to continuing drilling operations. We follow strict quality control procedures for conducting hydraulic fracturing operations that include a multi-point safety checklist, managing inventories of all materials and chemicals on the well site and ensuring that Material Safety Data Sheets are on location for every well that is hydraulically fractured. We contract with third parties to conduct hydraulic fracturing operations, and we send at least one of our own engineers or an experienced consultant to the well site to personally supervise each hydraulic fracture treatment. On a real-time basis, we closely monitor pump rates and pressures on existing casing strings to ensure that wellbore integrity is maintained during hydraulic fracturing operations. Our policy regarding monitoring well pressures would require stopping the hydraulic fracturing operations upon any indication that wellbore integrity may have been compromised.

We follow additional regulatory requirements and recommended practices to ensure wellbore integrity and full isolation of any underground aquifers and protection of surface waters. These include the following:

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Prior to perforating the production casing and hydraulic fracturing operations, a cement bond log is run to verify cement integrity between the formation to be fractured and shallow formations. Then, the casing is pressure tested to ensure no leaks exist within the casing;

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Before the fracturing operation commences, all surface equipment is pressure tested, which includes the wellhead and all high pressure lines and connections leading from the pumping equipment to the wellhead. During the pumping phases of the hydraulic fracturing treatment, the service companies we engage must provide specialized equipment to monitor and record surface pressures, pumping rates, volumes and chemical concentrations to ensure the treatment is proceeding as designed and the wellbore integrity is sound. Our engineers at the job site have laptop computers with special software to monitor and collect, for permanent archiving, information from the hydraulic fracturing operations. As part of this process, when fracturing operations are being performed down casing, we also monitor the casing annular pressure to ensure that there is no communication of hydraulic pressure and fracture fluids outside the casing that could communicate with shallow formations. Should any problem be detected at any time during the hydraulic fracturing treatment, the operation would be shut down until the problem is evaluated, reported and remediated; and

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As a means to further protect against the negative impacts of any potential surface release of fluids associated with the hydraulic fracturing operation, special precautions are taken both during and after the operation. During the fracturing operation, all chemicals are mixed into the fracturing fluid as it is being pumped into the well as opposed to being pre-mixed in the “frac pits” or work tanks. While chemical additives are stored on location in independent containment vessels, only fresh water is stored in the frac pits or work tanks. All pumping equipment used during the operation is pressure tested and monitored. When the well is flowed back, after the fracturing operation, all fluids are produced into closed-top storage tanks. All flowback equipment and piping are pressure tested to ensure no leaks are present and the fluids are properly contained.

Once the final string of casing is set in place, cement is pumped into the casing/wellbore annulus where it hardens and creates a permanent, isolating barrier between the steel casing pipe and surrounding geological formations. This aspect of the well design establishes a pressure seal essentially eliminating any pathway for the fracturing fluid to contact fresh water aquifers during the hydraulic fracturing operation. Furthermore, in the areas in which we conduct hydraulic fracturing, the hydrocarbon bearing formations are separated from any usable quality underground fresh water aquifers by thousands of feet of impermeable rock layers. This natural geological separation serves as a protective barrier, preventing migration of fracturing fluids or hydrocarbons upwards into any fresh water zones.

Although rare, if and when the cement and steel casing used in well construction need to be remediated, we deal with these problems by evaluating the issue, running diagnostic tools including cement bond logs, temperature logs and pressure testing, followed by pumping remedial cement jobs. We repair wellhead leaks by replacing wellhead components, re-installing components to proper specifications and re-testing. In wellbores that utilize downhole packers, pressure integrity issues are rectified by repairing or replacing packers. Casing integrity lost due to corrosion on a producing well is remedied by identifying the specific location of the leak by cased hole logging tools, mechanical isolation and pressure testing or other diagnostic methods, followed by high pressure squeeze cementing and subsequent pressure testing to ensure the leak has been repaired. Throughout the process we believe we abide by applicable regulations.

The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in the fracturing operation as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to

develop more environmentally friendly fracturing fluids. As previously mentioned, we also follow strict safety procedures and monitor all aspects of the fracturing operation to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures.

While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in a way that does not impact surface waters. All produced water is disposed of in permitted and regulated disposal facilities.

Environmental Regulation

The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and expect that these laws and regulations will not have a material adverse impact on us.

The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable requirements under the OPA 90 will not have a material and adverse effect on us.

The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. Certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water,

produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the U.S. Environmental Protection Agency, or the EPA, has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require certain oil-storing facilities to prepare plans and meet construction and operating standards.

CERCLA, also known as the “Superfund” law, and comparable state statutes impose liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that may be classified as hazardous substances under CERCLA. Certain state statutes may not contain a similar exemption for petroleum. Furthermore, we may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed to, prior releases of hazardous wastes.

RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes.

The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On July 28, 2011, the EPA proposed new regulations targeting air emissions from the oil and natural gas industry. The proposed rules, if adopted, would impose new requirements on production and processing and transmission and storage facilities and on hydraulic fracturing activities. While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air emission-related issues, we do not believe that such requirements will affect our operations in any way that is materially different from our competitors.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce depressing the prices we receive for oil and natural gas.

The EPA has published its findings that emissions of greenhouse gases presented an endangerment to human health and the environment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. Subsequently, the EPA proposed and adopted two sets of regulations, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulated emissions of greenhouse gases from certain large stationary sources. In addition, on October 30, 2009, the EPA published a rule requiring the reporting of greenhouse gas emissions from specified sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a rule that expands its final rule on greenhouse gas emissions reporting to include owners and operators of onshore and offshore oil and natural gas production, onshore natural gas processing, natural gas storage, natural gas transmission and natural gas distribution facilities. Reporting of greenhouse gas emissions from such onshore production will be required on an annual basis beginning in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our profits or could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas.

Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or state or regional greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less significant sources of emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. We currently own and operate five underground injection wells and expect to own other similar wells. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties.

Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “Business — Regulation — Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection on the federal level pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of chemicals used in the fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition, results of operations and cash flows.

In addition, at the federal level and in some states, there has been a push to place additional regulatory burdens upon hydraulic fracturing activities and in some areas to severely restrict or prohibit those activities. Certain bills have been introduced in the Senate and the House of Representatives that, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could, and in all likelihood would, result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations and increasing our costs of compliance. At the state level, Wyoming and Texas, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. On June 17, 2011, Texas signed into law a mandate for public disclosure of the chemicals that operators use during hydraulic fracturing in Texas. The law went into effect in 2011 and implementing regulations have been adopted. In addition, at least a few local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. Additional burdens upon hydraulic fracturing, such as reporting requirements or permitting requirements for the hydraulic fracturing activity, will result in additional expense and delay in our operations.

The EPA has recently been taking action to assert federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. The EPA is currently conducting a study on the effects of hydraulic fracturing on drinking water resources. Interim results of the study are expected in 2012, with final results expected in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming. This study remains subject to review and public comment but such studies could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire reserves against some of the liability for environmental claims associated with these properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability.

Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us.

We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards.

We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We cannot assure you that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, including Complex Environmental Laws, Which Could Require Significant Expenditures.”

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons.

We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows.

Office Lease

Our corporate headquarters are located in 28,743 square feet of office space in One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas. In April 2011, we entered into a third amended and restated office lease agreement pursuant to which our office space was increased from 20,849 to 28,743 square feet and the term of our lease was extended from July 1, 2011 to June 30, 2022. Beginning July 1, 2011, through

June 30, 2012, we are not required to pay a monthly base rent. From July 1, 2012 through June 30, 2015, our monthly base rent is $47,905. From July 1, 2015 through June 30, 2017, our monthly base rent is $50,300. From July 1, 2017 through June 30, 2019, our monthly base rent is $52,696. From July 1, 2019 through June 30, 2020, our monthly base rent is $55,091. From July 1, 2020 through the expiration date of the lease, our monthly base rent is $57,726. In addition, the lease contains a renewal option in our favor for an additional 60-month period at the then existing market rate as determined in accordance with the lease.

Employees

At December 31, 2011, we had 41 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities.

Available Information

Our Internet website address is www.matadorresources.com. We expect to make available, free of charge, through our website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee and Nominating, Compensation and Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only.

Item 1A.

Risk Factors.

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

Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.

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

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the domestic and foreign supply of oil and natural gas;

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the domestic and foreign demand for oil and natural gas;

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the prices and availability of competitors’ supplies of oil and natural gas;

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the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls;

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the price and quantity of foreign imports;

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the impact of U.S. dollar exchange rates on oil and natural gas prices;

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domestic and foreign governmental regulations and taxes;

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speculative trading of oil and natural gas futures contracts;

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the availability, proximity and capacity of gathering and transportation systems for natural gas;

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the availability of refining capacity;

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the prices and availability of alternative fuel sources;

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weather conditions and natural disasters;

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political conditions in or affecting oil and natural gas producing regions, including the Middle East and South America;

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the continued threat of terrorism and the impact of military action and civil unrest;

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public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;

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the level of global oil and natural gas inventories and exploration and production activity;

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the impact of energy conservation efforts;

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technological advances affecting energy consumption; and

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overall worldwide economic conditions.

Approximately 98% of our production during the year ended December 31, 2010, 94% of our production during the year ended December 31, 2011 and 88% of our proved reserves at December 31,

2011 are attributable to natural gas. In addition, three of our largest prospects, our Haynesville shale, Cotton Valley properties and our Meade Peak shale prospect, currently produce or are expected to produce predominantly natural gas. As a result, they are sensitive to fluctuations in natural gas prices.

One of our current business strategies is to focus on increasing our oil and liquids production. Specifically, our near-term drilling opportunities in the Eagle Ford shale play focus on oil and liquids. We currently intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration of the Eagle Ford shale. We believe that approximately 85% of our Eagle Ford acreage is prospective predominantly for oil and liquids production, and we have identified 193 gross locations for potential future drilling in our Eagle Ford acreage. Therefore, our Eagle Ford shale play is highly susceptible to changes in oil prices.

Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically. Should natural gas or oil prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect in the future to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, each of which would have a material adverse effect on our business, financial condition, results of operations and reserves.

In recent months, natural gas prices have declined to their lowest levels in many years, and at March 30, 2012, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at $2.13 per MMBtu. We would not expect to drill any operated natural gas wells, except for natural gas wells in specific exploration prospects like the Meade Peak shale, until natural gas prices improved substantially from these levels or unless the costs to drill and complete these wells were also to decline substantially from their recent levels.

Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business.

Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from a location that is ready to drill to a location that will require substantial additional interpretation before it can be drilled. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling and operating processes. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly.

If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may

damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from the well or abandonment of the well. Whether a well is ultimately productive and profitable depends on a number of additional factors, including the following:

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general economic and industry conditions, including the prices received for oil and natural gas;

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shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel;

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potential drainage by operators on adjacent properties;

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loss of or damage to oilfield development and service tools;

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problems with title to the underlying properties;

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increases in severance taxes;

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adverse weather conditions that delay drilling activities or cause producing wells to be shut down;

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domestic and foreign governmental regulations; and

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proximity to and capacity of transportation facilities.

If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected.

We May Have Accidents, Equipment Failures or Mechanical Problems While Drilling or Completing Wells or in Production Activities, Which Could Adversely Affect Our Business.

While we are drilling and completing wells or involved in production activities, we may have accidents or experience equipment failures or mechanical problems in a well that cause us to be unable to drill and complete the well or to continue to produce the well according to our plans. We may also damage a potentially hydrocarbon-bearing formation during drilling and completion operations. Such incidents may result in a reduction of our production and reserves from the well or in abandonment of the well.

Because Our Reserves and Production Are Concentrated in a Small Number of Properties, Problems in Production and Markets Relating to Any Property Could Have a Material Impact on Our Business.

Almost all of our current oil and natural gas production and our proved reserves are attributable to properties in northwest Louisiana and east Texas, and we expect that most of our operations in the near future will be primarily in 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 capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance. In particular, our operations in south Texas may be adversely impacted by a lack of pipeline infrastructure and natural gas processing facilities in light of the oil and natural gas industry’s increased focus on the exploration and development of the Eagle Ford shale. Our operations in south Texas may also be adversely affected by hurricanes and tropical storms resulting in delays in exploration and drilling, damage to facilities and equipment and the inability to receive equipment or to access personnel and products at affected job sites in a timely manner. 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, results of operations and cash flows.

Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in: (i) efficiently developing and exploiting our current reserves on properties owned by us or by other persons or entities and (ii) economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing primarily on increasing our production and reserves from the Eagle Ford shale play, an area in which industry activity has increased rapidly. As a result of this increased activity, we may have difficulty expanding our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected.

Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Receive, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.

The process of estimating accumulations of oil and natural gas is complex and is not exact, due to numerous inherent uncertainties. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of:

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the quality and quantity of available data;

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the interpretation of that data;

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the judgment of the persons preparing the estimate; and

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the accuracy of the assumptions.

The accuracy of any estimates of proved reserves generally increases with the length of the production history. Due to the limited production history of many of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data is available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance to our estimates could materially affect the quantities and present value of our reserves.

The Calculated Present Value of Future Net Revenues from Our Proven Reserves Will Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves.

It should not be assumed that the present value of future net cash flows included in this report is the current market value of our estimated proved oil and natural gas reserves. We generally base the estimated discounted future net cash flows from proved reserves on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index

prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as:

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actual prices we receive for oil and natural gas;

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actual cost and timing of development and production expenditures;

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the amount and timing of actual production; and

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changes in governmental regulations or taxation.

In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under Generally Accepted Accounting Principles, or GAAP, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general.

Approximately 67% of Our Total Proved Reserves at December 31, 2011 Consisted of Undeveloped and Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced.

At December 31, 2011, approximately 66% of our total proved reserves were undeveloped and approximately 1% were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced or such reserves may not be developed or produced within the time periods we have projected or at the costs we have budgeted. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify our proved reserves as unproved reserves, which would materially affect our business, financial condition, results of operations and ability to raise capital.

Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.

Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash and cash equivalents, operating cash flows and future potential borrowings under our credit agreement or otherwise may not be adequate to fund our future acquisitions or future capital expenditure requirements. The rate of our future growth may be dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable.

We may sell additional securities to raise capital. If we succeed in selling additional securities to raise funds, at such time the ownership of our existing shareholders would likely be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities.

Our cash flows from operations and access to capital are subject to a number of variables, including:

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our estimated proved oil and natural gas reserves;

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the amount of oil and natural gas we produce from existing wells;

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the prices at which we sell our production;

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the costs of developing and producing our oil and natural gas reserves;

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our ability to acquire, locate and produce new reserves;

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the ability and willingness of banks to lend to us; and

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our ability to access the equity and debt capital markets.

In addition, future events, such as terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets have caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future.

If our revenues decrease as a result of lower oil and gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in additional exploration opportunities. Alternatively, a significant improvement in oil and gas prices could result in an increase in our capital expenditures and we may be required to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise to meet any increase in capital needs. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and future results of operations could be adversely affected.

Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May Not Be Adequately Insured.

There are numerous operational hazards inherent in oil and natural gas exploration, development, production and gathering, including:

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unusual or unexpected geologic formations;

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natural disasters;

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adverse weather conditions;

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unanticipated pressures;

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loss of drilling fluid circulation;

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blowouts where oil or natural gas flows uncontrolled at a wellhead;

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cratering or collapse of the formation;

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pipe or cement leaks, failures or casing collapses;

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fires or explosions;

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releases of hazardous substances or other waste materials that cause environmental damage;

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pressures or irregularities in formations; and

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equipment failures or accidents.

In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum

hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.

Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate Exploration Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect Our Future Cash Flows and Results of Operations.

We intend to employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Poor results from our exploration activities could limit our ability to replace and grow reserves and materially and adversely affect our future cash flows and results of operations.

We Currently Own Only a Limited Amount of Seismic and Other Geological Data and May Have Difficulty Obtaining Additional Data at a Reasonable Cost, Which Could Adversely Affect Our Future Cash Flows and Results of Operations.

We currently own only a limited amount of seismic and other geological data to assist us in exploration and development activities. We intend to obtain access to additional data in our areas of interest through licensing arrangements with companies that own or have access to that data or by paying to obtain that data directly. Seismic and geological data can be expensive to license or obtain. We may not be able to license or obtain such data at an acceptable cost.

The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.

Shortages or the high cost of drilling rigs, completion equipment and services, supplies or personnel could delay or adversely affect our operations. When drilling activity in the United States increases,

associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. These costs may increase, and necessary equipment and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our financial condition, results of operations and cash flows.

In addition, the demand for hydraulic fracturing services currently exceeds the availability of fracturing equipment and crews across the industry and in our operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages has further amplified this equipment and crew shortage. If demand for fracturing services continues to increase or the supply of fracturing equipment and crews decreases, then higher costs could result and could adversely affect our business and results of operations.

Our Identified Drilling Locations Are Scheduled Out Over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.

Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including the availability of equipment and capital, approval by regulators, seasonal conditions, oil and natural gas prices, assessment of risks, costs and drilling results. The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our financial condition, results of operations and cash flows.

We Have Limited Control Over Activities on Properties We Do Not Operate.

We are not the operator on some of our properties, particularly in the Haynesville shale. As a result of our sale of certain assets to a subsidiary of Chesapeake Energy Corporation in 2008, we do not operate one of our most significant natural gas assets in the Haynesville shale. We have also acquired other non-operated acreage positions in northwest Louisiana. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs or control the risks could materially and adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including:

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timing and amount of capital expenditures;

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the operator’s expertise and financial resources;

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the rate of production of reserves, if any;

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approval of other participants in drilling wells; and

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selection of technology.

In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production.

A Component of Our Growth May Come Through Acquisitions, and Our Failure to Identify or Complete Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth.

We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Our financial position, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. If we are not successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted.

We may engage in bidding and negotiating to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise. Our credit agreement includes covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas.

We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know About or That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could Adversely Affect Our Results of Operations.

Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities.

Strategic Relationships Upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations.

Our ability to explore, develop and produce oil and natural gas resources successfully and acquire oil and natural gas interests and acreage depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These realities are subject to change and may impair our ability to grow.

To develop our business, we will endeavor to use the business relationships of our management, board and special board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies, including those that supply equipment and other resources that we expect to use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

The Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.

The unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay production from our wells. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for, and supply of, oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases.

The disruption of third party facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. The third parties control when or if such facilities are restored and what prices will be charged. We generally do not purchase firm transportation on third party facilities, and, therefore, our production transportation can be interrupted by those having firm arrangements. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses.

To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars,” with respect to a portion of our future production. A costless collar provides us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, this arrangement is

initially “costless” to us. The goal of these and other hedges is to lock in a range of prices so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil or natural gas prices rise above the maximum price established by the call option and may offer protection if prices fall below the minimum price established by the put option only to the extent of the volumes then hedged.

In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option contracts fail to perform under the contracts.

Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions.

Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil and gas prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful.

An Increase in the Differential Between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the prices we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. We do not have, and may not have in the future, any derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials.

We Are Subject to Government Regulation and Liability, including Complex Environmental Laws, Which Could Require Significant Expenditures.

The exploration, development, production and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation or environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. These expenditures could include payments for:

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personal injuries;

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property damage;

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containment and clean up of oil and other spills;

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the management and disposal of hazardous materials;

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remediation and clean-up costs; and

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other environmental damages.

We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations.

We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. In the past, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. Many states have raised state taxes on energy sources, and additional increases may occur. Changes to tax laws that are applicable to us could adversely affect our business and our financial results.

Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain United States production activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. These changes were included in the White House budget proposals, released on February 26, 2009, February 1, 2010, February 14, 2011 and February 13, 2012, and may be raised again in the future. The passage of any legislation as a result of the budget proposals or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows.

We May Be Required to Write Down the Carrying Value of Our Proved Properties Under Accounting Rules and these Write-Downs Could Adversely Affect Our Financial Condition.

There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low. In addition, non-cash write-downs may occur if we have:

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downward adjustments to our estimated proved reserves;

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increases in our estimates of development costs; or

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deterioration in our exploration results.

We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is based on the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity and could lower the value of our common stock.

We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.

If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such oil and natural gas lease as well as any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost.

It is our practice, in acquiring oil and natural gas leases, or undivided interests in oil and natural gas leases, not to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, we will rely upon the judgment of oil and natural gas lease brokers and/or landmen who perform the field work in examining records in the appropriate governmental office before attempting to acquire a lease on a specific mineral interest.

Prior to the drilling of an oil and natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil and natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies 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. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated 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 which could adversely affect our financial condition, results of operations and cash flows.

The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business.

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, sets forth the new framework for regulating certain derivative products including the commodity hedges of the type used by us, but many aspects of this law are subject to further rulemaking and will take effect over several years. As a result, it is difficult to

anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to continue entering into and maintaining such commodity hedges and the terms thereof. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future.

If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our future ability to conduct acquisitions.

Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.

In past sessions, Congress has considered, but did not pass, legislation to amend the SDWA to remove the exemption from restrictions on underground injection of fluids near drinking water sources granted to most hydraulic fracturing operations and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to produce commercial quantities of oil, liquids and natural gas from shale formations such as the Eagle Ford and the Haynesville shales, where we focus our operations. Sponsors of bills before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Such legislation, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could, and in all likelihood would, result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations and increasing our costs of compliance. Moreover, the EPA is conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water and groundwater. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution of a natural gas field in Wyoming, although this study remains subject to review and public comments. Consequently, even if federal legislation is not adopted soon or at all, the performance of the hydraulic fracturing study by the EPA could spur further action at a later date towards federal legislation and regulation of hydraulic fracturing or similar production operations.

In addition, a number of states are considering or have implemented more stringent regulatory requirements applicable to fracturing, which could include a moratorium on drilling and effectively prohibit further production of natural gas through the use of hydraulic fracturing or similar operations. For example, Texas has adopted legislation that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and the public. This legislation and any implementing regulation could increase our costs of compliance and doing business.

The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal

legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.

Legislation or Regulations Restricting Emissions of “Greenhouse Gases” Could Result in Increased Operating Costs and Reduced Demand for the Natural Gas, Natural Gas Liquids and Oil We Produce While the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to those Effects.

The EPA has published its final findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. Accordingly, the EPA has adopted regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and permitting and presumably requiring a reduction in greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a final rule that expands its rule on reporting of greenhouse gas emissions to include owners and operators of petroleum and natural gas systems. Monitoring of those newly covered emissions commenced on January 1, 2011, with the first annual reports due to the EPA in 2012. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Any such legislation could adversely affect demand for the natural gas, oil and liquids that we produce.

A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy by It May Result in Increased Regulation of Our Assets, Which May Cause Our Revenues to Decline and Operating Expenses to Increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. A change in the jurisdictional characterization by FERC or Congress or a change in policy by either of them may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and Orders, We Could Be Subject to Substantial Penalties and Fines.

Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. Our systems have not yet been regulated by FERC, as a natural gas company subject to the provisions of the NGA. FERC has adopted regulations that may subject certain of our otherwise

non-FERC/NGA jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability.

Competition in the Oil and Natural Gas Industry Is Intense Making It More Difficult for Us to Acquire Properties, Market Natural Gas and Secure Trained Personnel.

Our ability to acquire additional prospects 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 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 prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other 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 in recent 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.

Our Competitors May Use Superior Technology and Data Resources that We May Be Unable to Afford or that Would Require a Costly Investment by Us in Order to Compete with Them More Effectively.

Our industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, many of our competitors will have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may become obsolete, and we may be adversely affected.

Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases that Will Expire Over the Next Several Years Unless Production Is Established on Units Containing the Acreage.

At December 31, 2011, we had leasehold interests in approximately 116,000 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to December 31, 2013. Unless we establish production in paying quantities on units containing these leases during their terms or we renew such leases, these leases will expire. If our leases expire, we will lose our right to develop the related properties. 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 may have been taken and could 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, financial condition, results of operations and cash flows.

We May Have Difficulty Managing Growth in Our Business, Which Could Have a Material Adverse Effect on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our Business Plan in a Timely Fashion.

Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our activities, including our planned increase in oil exploration, development and production, and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers and landmen could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion.

Financial Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third Party Operators or Other Third Parties Could Decrease Our Cash Flow from Operations and Adversely Affect the Exploration and Development of Our Prospects and Assets.

We derive essentially all of our revenues from the sale of our oil and natural gas to unaffiliated third party purchasers, independent marketing companies and mid-stream companies. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations and cash flows.

Liquidity and cash flow problems encountered by our working interest co-owners or the third party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary to fund either of these contingencies or that we would be able to find a new farmout party.

We May Incur Indebtedness Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations and Our Unit Costs.

At March 30, 2012, we had available borrowings of approximately $108.7 million under our credit agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future acquired oil and gas reserves. Our credit agreement is secured by substantially all of our interests in our oil and gas properties and other assets and contains covenants restricting our ability to incur additional indebtedness, which may limit our ability to obtain additional financing. In addition, the borrowing base under our credit agreement is subject to periodic redeterminations, and we could be forced to repay a portion of our borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments.

Borrowings under our credit agreement at March 30, 2012 bear interest at a variable rate of 1.75% plus a Eurodollar-based rate per annum, which equated to approximately 2.0% per annum. In the future, we may incur significant amounts of additional indebtedness, including under our credit agreement, in order to make acquisitions or to develop our properties. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly.

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;

•

any covenants contained in the agreements governing our outstanding indebtedness could limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

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a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness may prevent us from pursuing;

•

our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; and

•

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and 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. We may not be able to generate sufficient cash flows to pay the principal or 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. 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 or have a portion of our assets foreclosed upon which could have a material adverse effect on our business and financial results.

Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our Chairman of the Board, Chief Executive Officer and President, the Members of Our Board of Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board Advisor Could Disrupt Our Business Operations.

Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman, President and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or any of these other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

We have an active board of directors that meets several times throughout the year and is intimately involved in our business and the determination of our operational strategies. Members of our board of directors work closely with management to identify potential prospects, acquisitions and areas for further development. Many of our directors have been involved with us since our inception and have a deep

understanding of our operations and culture. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and as a result, our operations may be adversely affected.

In addition, our board consults regularly with our special advisors regarding our business and the evaluation, exploration, engineering and development of our prospects. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected.

Our Management Team Owns Approximately 13% of Our Common Stock Which Could Give Them Influence in Corporate Transactions and Other Matters, and the Interests of Our Management Could Differ from Other Shareholders.

Our directors and officers beneficially own approximately 13% of our outstanding shares of common stock. These shareholders are positioned to influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the company may have the effect of delaying or preventing a change of control of the company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, they may be able to remain entrenched in their positions.

Risks Relating to Our Common Stock

Our Common Stock Has Only Been Publicly Traded Since February 2, 2012, and the Price of our Common Stock Has Fluctuated Substantially Since Then and May Fluctuate Substantially in the Future.

Our common stock has been publicly traded only since February 2, 2012. The market price of our common stock could vary significantly as a result of a number of factors. In addition, the trading volume of our common stock may fluctuate and cause significant price variations to occur. 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. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.

Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include:

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our actual or anticipated operating and financial performance and drilling locations, including reserves estimates;

•

quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us;

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changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts;

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speculation in the press or investment community;

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public reaction to our press releases, announcements and filings with the Securities and Exchange Commission, or SEC;

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sales of our common stock by us or shareholders, or the perception that such sales may occur;

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general financial market conditions and oil and gas industry market conditions, including fluctuations in commodity prices;

•

the realization of any of the risk factors presented in this report;

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the recruitment or departure of key personnel;

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commencement of or involvement in litigation;

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the prices of oil and natural gas;

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the success of our exploration and development operations, and the marketing of any oil and natural gas we produce;

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changes in market valuations of companies similar to ours; and

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

The Requirements of Being a Public Company, Including Compliance with the Reporting Requirements of the Securities Exchange Act of 1934, as Amended, and the Requirements of the Sarbanes-Oxley Act of 2002, May Strain Our Resources, Increase Our Costs and Distract Management; and It May Be Difficult to Comply with These Requirements in a Timely or Cost-Effective Manner.

As a new public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the New York Stock Exchange, or the NYSE, with which we were 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:

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institute a more comprehensive compliance function;

•

establish 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;

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comply with rules promulgated by the NYSE;

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prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

•

establish new internal policies, such as those relating to disclosure controls and procedures and insider trading; and

•

involve and retain to a greater degree outside counsel and accountants in the above activities.

In addition, as a result of being subject to these rules and regulations, we may have to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain acceptable 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 Any of the Material Weaknesses Previously Identified by Our Independent Registered Public Accountants Persist or if We Fail to Establish and Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected.

Until February 1, 2012, we were a private company and maintained internal controls and procedures in accordance with being a private company. We have maintained limited accounting personnel to perform our

accounting processes and limited supervisory resources with which to address our internal control over financial reporting. In connection with our audits for the years ended December 31, 2011 and 2010, our independent registered public accountants identified and communicated material weaknesses. In 2010, the material weaknesses related to controls over accounting and reporting for deferred income taxes, impairment of oil and natural gas properties, assessment of unproved and unevaluated properties and the administration of our stock and incentive plan. In 2011, the material weakness related only to accounting and reporting for stock compensation expense.

A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual and interim financial statements will not be prevented or detected and corrected on a timely basis. We have begun the process of evaluating our internal control over financial reporting and expect to put into place new accounting processes and control procedures to address the weaknesses described above, including the hiring of outside consultants to review significant or complex accounting issues and calculations, the implementation of a more formalized closing process, the formation of a disclosure committee and the hiring of additional personnel.

As a public company, we are required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act, which require our management to certify financial and other information in our quarterly and annual reports and to provide an annual management report on the effectiveness of our internal control over financial reporting. We will be required to make our first assessment of our internal control over financial reporting for the year ended December 31, 2012. To comply with the requirements of being a public company, we are upgrading our systems, including information technology, implementing additional financial and management controls, reporting systems and procedures and have hired additional accounting and financial reporting staff.

Further, our independent registered public accountants are not yet required to formally attest to the effectiveness of our internal control over financial reporting. Once they are required to do so, our independent registered public accountants may issue a report that is adverse in the event they are not satisfied with the level at which our controls are documented, designed, operated or reviewed. Our remediation efforts may not enable us to remedy or avoid material weaknesses in the future.

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

We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock.

We do not presently intend to pay any cash dividends on our common stock. Any payment of future dividends will be at the discretion of the board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems

relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. In addition, certain covenants in our credit agreement may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment and there is no guarantee that the price of our common stock that will prevail in the market will exceed the price paid by you.

The Trading Volume in Our Common Stock Has Been Low, and the Sale of a Substantial Number of Shares in the Public Market Could Depress the Price of Our Common Stock.

Our common stock is listed on the NYSE, but since the completion of our initial public offering, it has had a relatively low average daily trading volume relative to many other stocks. Thinly traded stock can be more volatile than stock trading in an active public market, which can lead to significant price swings even when a relatively small number of shares are being traded and can limit an investor’s ability to quickly sell blocks of stock. Shareholders holding more than 75% of our outstanding shares of common stock are subject to lockup agreements that prohibit the disposition of those shares until at least July 30, 2012, subject to certain exceptions. We cannot predict what effect, if any, the expiration of these lockups will have on future sales of our common stock in the market, including the availability of our common stock for sale in the market and the market price of our common stock.

Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our Common Stock by Us Could Depress the Price of Our Common Stock.

The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders sell, or indicate an intent to sell, substantial amounts of our common stock in the public market after any contractual lockup and other legal restrictions on resale lapse, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales also could cause our stock price to fall and make it more difficult for you to sell shares of our common stock.

We may also sell additional shares of common stock or securities convertible into common stock in subsequent offerings. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities will have on the market price of our common stock.

Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects that Could Prevent a Change in Control Even if It Might Be Beneficial to Our Shareholders.

Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include:

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authorization for our board of directors to issue preferred stock without shareholder approval;

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a classified board of directors so that not all members of our board of directors are elected at one time;

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the prohibition of cumulative voting in the election of directors; and

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a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock.

Provisions of Texas law also may discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or any “affiliated shareholder,” cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our board of directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder.

Our Board of Directors Can Authorize the Issuance of Preferred Stock, which Could Diminish the Rights of Holders of Our Common Stock, and Make a Change of Control of the Company More Difficult Even if It Might Benefit Our Shareholders.

Our board of directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the company, even if that change of control might benefit our shareholders.

Item 1B.

Unresolved Staff Comments.

Not applicable.

Item 2.

Properties.

See “Business” for descriptions of our properties. We also have various operating leases for rental of office space, office and field equipment, and vehicles. See Note 12, Commitments and Contingencies, to the consolidated financial statements for the future minimum rental payments. Such information is incorporated herein by reference.

Item 3.

Legal Proceedings.

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

Item 4.

Mine Safety Disclosures

Not applicable.

PART II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

General Market Information

On February 2, 2012, our common stock began trading on the NYSE under the symbol “MTDR.” On February 7, 2012, we completed our initial public offering of 14,883,334 shares of common stock at $12.00 per share. We sold 12,209,167 shares of common stock in this offering, and certain selling shareholders sold 2,674,167 shares of common stock, including shares sold by us and the selling shareholders pursuant to the partial exercise of the underwriters’ over-allotment on March 7, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock.

On March 30, 2012, we had 55,272,860 shares of common stock outstanding held by approximately 516 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name.

The following table sets forth the high and low sales prices of our common stock as reported by the NYSE for the period indicated:


	High		Low
Period from February 2, 2012 to March 30, 2012	$	12.33	$	10.85

On March 30, 2012, the last reported sales price of our common stock on the NYSE was $10.95 per share.

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 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, certain covenants in our credit agreement may limit our ability to pay dividends on our common stock.

Prior to consummation of our initial public offering, the holders of our Class B common stock were entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These dividends accrued and were payable quarterly at the rate of $0.06-2/3 per share of Class B common stock outstanding. For the years ended December 31, 2011, 2010 and 2009, we declared dividends on our outstanding shares of Class B common stock totaling $274,853 in each year. Upon the automatic conversion of the outstanding shares of Class B common stock at the closing of our initial public offering, the right of the holders of Class B common stock to dividends was terminated and such holders were paid approximately $28,000 during the first quarter of 2012 for all accrued but unpaid dividends existing at the time of such conversion.

Equity Compensation Plan Information

The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2011.


Equity Compensation Plan Information
Plan Category	Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted- Average Exercise Price of Outstanding Options, Warrants and Rights ($)		Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans
Equity compensation plans approved by security holders⁽¹⁾		1,024,500	$	9.75		–
Equity compensation plans not approved by security holders⁽²⁾		–		–		4,000,000

Total		1,024,500	$	9.75		4,000,000

(1)	Our board of directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and Incentive Plan.

(2)	Our 2012 Long-Term Incentive Plan was approved by our board of directors in December 2011 and took effect on January 1, 2012. For a description of our 2012 Long-Term Incentive Plan, see Note 17 to our consolidated financial statements included elsewhere in this Form 10-K.

Recent Sales of Unregistered Securities

From October 2010 through January 2011, we sold 1,922,199 shares of our common stock to accredited investors for the aggregate consideration of $21,144,189. These shares were issued in a transaction exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act and Rule 506.

During 2011, we issued an aggregate of 93,001 shares of common stock pursuant to the exercise of stock options held by certain directors and employees and received an aggregate of $837,009 for such exercises. The issuance of these shares was exempt from the registration requirements of the Securities Act pursuant to Rule 701.

During 2011, we issued an aggregate of 17,500 shares of our common stock to our outside directors and advisors in connection with their service to the board. These shares were issued in transactions exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.

In October 2011, we issued an aggregate of 2,575 shares of our common stock to General Mills, Inc. Benefits Finance Committee on behalf of General Mills Group Trust and Voluntary Employees Beneficiary Assoc. Trust General Mills & Bakery, Confectionary, Tobacco & Grain Millers in connection with prior service on the board by officers of General Mills, Inc. Benefits Finance Committee. These shares were issued in transactions exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.

Use of Proceeds

Our initial public offering of common stock was effected through a Registration Statement on Form S-1 (File No. 333-176263), which was declared effective by the SEC on February 1, 2012. RBC Capital Markets, LLC; Citigroup Global Markets Inc.; Jefferies & Company, Inc.; Howard Weil Incorporated; Stifel, Nicolaus & Company, Incorporated; Stephens Inc.; and Comerica Securities, Inc. acted as underwriters for the offering. RBC Capital Markets, LLC and Citigroup Global Markets Inc. acted as the co-managers for the offering. Under the Form S-1, we registered the offer and sale of an aggregate of 15,333,334 shares of our common stock, 12,209,167 shares of which were issued and sold by us and 2,674,167 shares of which were sold by the selling shareholders named in the Form S-1, including shares sold by us and certain of the selling shareholders pursuant to the partial exercise of the underwriters’ option to purchase additional shares. The initial public offering closed on February 7, 2012 and the over-allotment option closed on March 7, 2012. We issued and sold all but 450,000 of the shares that were registered.

The shares were sold at a price to the public of $12.00 per share and we received cash proceeds of approximately $133.6 million from this transaction, net of underwriting discounts and commissions. We did not receive any proceeds from the sale of shares by the selling shareholders. The underwriters received underwriting discounts and commissions totaling approximately $9.9 million, and we incurred additional costs of approximately $3.0 million in connection with the offering, which amounted to total fees and costs of approximately $12.9 million. No offering costs were paid directly or indirectly to any of our directors or officers (or their associates) or persons owning 10% or more of any class of our equity securities or to any other affiliates, other than advancement of legal fees for one counsel to represent the selling shareholders.

We used $123.0 million to repay the then outstanding borrowings under our credit agreement. We used the remaining proceeds to fund a portion of our 2012 capital expenditure requirements.

Item 6.

Selected Financial Data.

You should read the following selected 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 report. The financial information included in this report may not be indicative of our future results of operations, financial position or cash flows.

The following selected financial information is summarized from our results of operations for the five-year period ended December 31, 2011 and selected consolidated balance sheet data at December 31, 2011, 2010, 2009, 2008 and 2007 and should be read in conjunction with the consolidated financial statements at the years ended December 31, 2011, 2010 and 2009 included herewith.


	Year Ended December 31,
	2011			2010			2009			2008			2007
(In thousands)
Statement of operations data:
Revenues:
Oil and natural gas revenues	$	67,000		$	34,042		$	19,039		$	30,645		$	13,988
Realized gain (loss) on derivatives		7,106			5,299			7,625			(1,326	)		213
Unrealized gain (loss) on derivatives		5,138			3,139			(2,375	)		3,592			(211	)

Total revenues		79,244			42,480			24,289			32,911			13,990
Expenses:
Production taxes and marketing		6,278			1,982			1,077			1,639			779
Lease operating		7,244			5,284			4,725			4,667			3,099
Depletion, depreciation and amortization		31,754			15,596			10,743			12,127			7,889
Accretion of asset retirement obligations		209			155			137			92			70
Full-cost ceiling impairment		35,673			–			25,244			22,195			–
General and administrative		13,394			9,702			7,115			8,252			5,189

Total expenses		94,552			32,719			49,041			48,972			17,026

Operating (loss) income		(15,308	)		9,761			(24,752	)		(16,061	)		(3,036	)

Other (expense) income:
Net (loss) gain on asset sales and inventory impairment		(154	)		(224	)		(379	)		136,977			–
Interest expense		(683	)		(3	)		–			–			–
Interest and other income		315			364			781			2,984			2,736

Total other (expense) income		(522	)		137			402			139,962			2,736
Net (loss) income	$	(10,309	)	$	6,377		$	(14,425	)	$	103,878		$	(300	)

Earnings (loss) per common share
Basic
Class A	$	(0.25	)	$	0.15		$	(0.37	)	$	2.50		$	(0.05	)

Class B	$	0.02		$	0.42		$	(0.10	)	$	2.77		$	0.22

Diluted
Class A	$	(0.25	)	$	0.15		$	(0.37	)	$	2.46		$	(0.05	)

Class B	$	0.02		$	0.42		$	(0.10	)	$	2.73		$	0.22


Class B dividend declared, per share	$	0.27		$	0.27		$	0.27		$	0.27		$	0.27


	At December 31,
	2011			2010			2009			2008			2007
(In thousands)
Balance sheet data:
Cash and cash equivalents	$	10,284		$	21,060		$	104,230		$	150,768		$	9,017
Certificates of deposit		1,335			2,349			15,675			20,782			–
Short-term investments		–			–			–			–			57,925
Net property and equipment		399,865			303,880			142,078			125,261			105,814
Total assets		439,469			346,382			277,400			314,539			179,152
Current liabilities		74,576			30,097			8,868			35,475			5,541
Long term liabilities		93,377			34,408			4,210			2,059			1,568
Total shareholders’ equity	$	271,515		$	281,877		$	264,321		$	277,005		$	172,043

	Year Ended December 31,
	2011			2010			2009			2008			2007
Other financial data:
Net cash provided by operating activities	$	61,868		$	27,273		$	1,791		$	25,851		$	7,881
Net cash (used in) provided by investing activities		(160,088	)		(147,334	)		(49,415	)		115,481			(108,296	)
Oil and natural gas properties capital expenditures		(156,431	)		(159,050	)		(54,244	)		(104,119	)		(50,310	)
Expenditures for other property and equipment		(4,671	)		(1,610	)		(307	)		(3,012	)		(1,300	)
Net cash provided by financing activities		87,444			36,891			1,086			419			66,250
Adjusted EBITDA⁽¹⁾	$	49,911		$	23,635		$	15,184		$	18,411		$	8,090

(1)	Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.

Non-GAAP Financial Measures

We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, non-recurring income and expenses and non-cash stock-based compensation expense, including stock option and grant expense and restricted stock grants. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. Adjusted EBITDA 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.

Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA 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 certain assets were acquired.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively.


	Year Ended December 31,
	2011			2010			2009			2008			2007
(In thousands)
Unaudited Adjusted EBITDA reconciliation to Net Income (Loss):
Net (loss) income	$	(10,309	)	$	6,377		$	(14,425	)	$	103,878		$	(300	)
Interest expense		683			3			–			–			–
Total income tax (benefit) provision		(5,521	)		3,521			(9,925	)		20,023			–
Depletion, depreciation and amortization		31,754			15,596			10,743			12,127			7,889
Accretion of asset retirement obligations		209			155			137			92			70
Full-cost ceiling impairment		35,673			–			25,244			22,195			–
Unrealized (gain) loss on derivatives		(5,138	)		(3,139	)		2,375			(3,592	)		211
Stock option and grant expense		2,362			824			622			605			205
Restricted stock grants		44			74			34			60			15
Net loss (gain) on asset sales and inventory impairment		154			224			379			(136,977	)		–

Adjusted EBITDA	$	49,911		$	23,635		$	15,184		$	18,411		$	8,090


	Year Ended December 31,
	2011			2010			2009			2008			2007
(In thousands)
Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities:
Net cash provided by operating activities	$	61,868		$	27,273		$	1,791		$	25,851		$	7,881
Net change in operating assets and liabilities		(12,594	)		(2,230	)		15,717			(17,888	)		209
Interest expense		683			3			–			–			–
Current income tax (benefit) provision		(46	)		(1,411	)		(2,324	)		10,448			–

Adjusted EBITDA	$	49,911		$	23,635		$	15,184		$	18,411		$	8,090

Item 7.

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 appearing elsewhere in this report. 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 or 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, 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 report, 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 were founded in July 2003 by Mr. Joseph Wm. Foran and Mr. Scott E. King, and we drilled our first well in 2004. Since that time, we have drilled or participated in drilling 236 wells through December 31, 2011, including 106 Haynesville and nine Eagle Ford wells. At December 31, 2011, based on the reserves audit by our independent reservoir engineers, we had 193.2 Bcfe of estimated proved reserves with a PV-10 of $248.7 million and a Standardized Measure of $215.5 million. At December 31, 2011, 34% of our estimated proved reserves were proved developed reserves, 12% of our estimated proved reserves were oil and 88% of our estimated proved reserves were natural gas. Our average daily production for the year ended December 31, 2011 was 42.3 MMcfe per day, including 39.8 MMcf of natural gas per day and 422 Bbl of oil per day, as compared to an average daily production of 23.6 MMcfe per day, including 23.0 MMcf of natural gas per day and 91 Bbl of oil per day for the year ended December 31, 2010. We have achieved this growth while lowering operating costs (consisting of lease operating expenses and production taxes and marketing expenses) from $1.16 per Mcfe for the year ended December 31, 2009 to $0.88 per Mcfe for the year ended December 31, 2011, or a decrease of approximately 24%.

Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk factor for us. Commodity prices are affected by changes in market supply and demand, which is impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, natural gas price differentials and other factors. Prices for oil

and natural gas will affect the cash flows available to us for capital expenditures and our ability to borrow and raise additional capital. Declines in oil or natural gas prices would not only reduce our revenues, but could also reduce the amount of oil and/or natural gas that we can produce economically, and as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves.

In response to the recent commodity price environment, and in particular, the general decline in natural gas prices since July 2008 in contrast with the rebound in oil prices since February 2009, we have sought to balance our exploration and development plans by targeting more oil prone reservoirs, such as the Eagle Ford shale. While most of our historical and current production is natural gas, we believe that our future production profile will reflect a more balanced oil and natural gas commodity mix as a result of our strategic shift to target more oil development than we have historically.

In recent months, natural gas prices have declined to their lowest levels in many years, and at March 30, 2012, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at $2.13 per MMBtu. We would not expect to drill any operated natural gas wells, except for natural gas wells in specific exploratory prospects like the Meade Peak shale, until natural gas prices improved substantially from these levels or unless the costs to drill and complete these wells were also to decline substantially from their recent levels. See “Risk Factors – Our Identified Drilling Locations Are Scheduled Out Over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.”

During 2012, we intend to allocate 84% of our 2012 capital expenditure budget of $313.0 million to the exploration, development and acquisition of additional interests in the Eagle Ford shale play. Including these anticipated capital expenditures in the Eagle Ford shale, we plan to dedicate about 94% of our 2012 anticipated capital expenditure budget to opportunities prospective for oil and liquids production. While we have budgeted $313.0 million for 2012, the aggregate amount of capital we will expend may fluctuate materially based on market conditions and our drilling results.

As we transition our operations from the Haynesville shale and Cotton Valley in northwest Louisiana to the Eagle Ford shale in south Texas, we may face challenges associated with establishing operations and securing the necessary services to drill and complete wells and with securing the necessary pipeline and natural gas processing capabilities to transport, process and market the oil and natural gas that we produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure and facilities on our leases throughout the area. We believe we have successfully secured the necessary drilling and completion services for our current Eagle Ford operations, and at March 30, 2012, we had two contracted drilling rigs operating in south Texas: one in LaSalle County and one in Karnes County. We are not currently experiencing difficulties in securing completion, and particularly hydraulic fracturing services, for our newly drilled wells, although we experienced these problems at various times during 2011 in south Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling and completion services and reducing drilling and completion costs will be essential to the successful development and profitability of the Eagle Ford shale play. See “Risk Factors – The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.”

capacity limitations at our Martin Ranch lease in LaSalle County and are currently flaring a portion of the natural gas we are producing there as a result. We believe that these pipeline interruptions and capacity constraints are temporary and that additional oil and natural gas pipeline infrastructure currently being built throughout south Texas will help to alleviate these problems within 60 to 90 days. If we were required to shut in our production for long periods of time due to these pipeline interruptions, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Risk Factors – The Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Transportation Agreements Would Have a Material Adverse Effect on Our Revenue.”

On February 2, 2012, our common stock began trading on the NYSE under the symbol “MTDR.” We believe that our general and administrative expenses will increase as a result of us operating as 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 and increases in our staff compensation and other ongoing general and administrative expenses necessary to maintain and grow a publicly traded exploration and production company. A large part of this increase will be due to the cost of accounting and legal support services, filing annual and quarterly reports with the SEC, investor relations activities, directors’ fees, incremental directors’ and officers’ liability insurance costs and transfer and registrar agent fees. As a result, we believe that our general and administrative expenses for future periods will increase significantly. Our consolidated financial statements for future periods will reflect the impact of these increased expenses and affect the comparability of our financial statements with periods before the completion of this offering.

Revenues

Our revenues are derived primarily from the sale of oil and natural gas production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in oil or natural gas prices.

Realized gain (loss) on derivatives. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil and natural gas prices. This revenue item includes the net realized cash gains and losses associated with the settlement of these derivative financial instruments for a given reporting period.

Unrealized gain (loss) on derivatives. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil and natural gas prices. This revenue item recognizes the non-cash change in the fair value of our open derivative contracts between reporting periods.

The following table summarizes our revenues and production data for the periods indicated:


	Year Ended December 31,
	2011		2010		2009
Operating Results:
Revenues (in thousands):
Oil	$	14,457	$	2,507	$	1,719
Natural gas		52,543		31,535		17,320

Total oil and natural gas revenues		67,000		34,042		19,039
Realized gain (loss) on derivatives		7,106		5,299		7,625
Unrealized gain (loss) on derivatives		5,138		3,139		(2,375	)

Total revenues	$	79,244	$	42,480	$	24,289
Net Production Volumes:
Oil (MBbls)		154		33		30
Natural gas (Bcf)		14.5		8.4		4.8
Total natural gas equivalents (Bcfe) ⁽¹⁾		15.4		8.6		5.0
Average net daily production (MMcfe/d) ⁽¹⁾		42.3		23.6		13.7
Average Sales Prices:
Oil (per Bbl)	$	93.80	$	76.39	$	57.72
Natural gas, with realized derivatives (per Mcf)	$	4.11	$	4.38	$	5.17
Natural gas, without realized derivatives (per Mcf)	$	3.62	$	3.75	$	3.59

(1)	Estimated using a conversion ratio of one Bbl per six Mcf.

Year Ended December 31, 2011 as Compared to Year Ended December 31, 2010

Oil and natural gas revenues. Our oil and natural gas revenues increased by $33.0 million to $67.0 million, or an increase of about 97%, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. This increase in oil and natural gas revenues corresponds with an increase of about 79% in our oil and natural gas production to 15.4 Bcfe for the year ended December 31, 2011 from 8.6 Bcfe for the year ended December 31, 2010. This increased production was almost entirely due to drilling operations in the Eagle Ford and Haynesville shales. A portion of the increase in oil and natural gas revenues reflects the approximate five-fold increase in our oil production for the year ended December 31, 2011 as compared to the year ended December 31, 2010, as well as a higher average oil price of $93.80 per Bbl realized during 2011 as compared to an average oil price of $76.39 per Bbl realized during 2010.

Realized gain (loss) on derivatives. Our realized gain on derivatives increased by approximately $1.8 million to $7.1 million for the year ended December 31, 2011 from $5.3 million for the year ended December 31, 2010. The realized gain from our open natural gas costless collar contracts increased primarily as a result of the decline in natural gas prices during the comparable periods. We realized approximately $1.03 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2011 as compared to $0.89 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2010. Our total natural gas volumes hedged for the year ended December 31, 2011 were also approximately 16% higher than the total natural gas volumes hedged for 2010.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $5.14 million for the year ended December 31, 2011 as compared to an unrealized gain of $3.14 million for the year ended December 31, 2010. During the period from December 31, 2010 to December 31, 2011, the net fair value of our open natural gas costless collar contracts increased from approximately $4.14 million to approximately $9.28 million, resulting in an unrealized gain on derivatives of approximately $5.14 million for the year ended December 31, 2011. This increase in the net fair value of our open natural gas costless collar contracts was due primarily to a decrease in natural gas prices during 2011 as compared to 2010, as well as an increase in the total number of our open contracts at December 31, 2011 as compared to December 31, 2010.

Year Ended December 31, 2010 as Compared to Year Ended December 31, 2009

Oil and natural gas revenues. Our oil and natural gas revenues increased by $15.0 million to $34.0 million, or an increase of about 79%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. Approximately $13.7 million of the increase was primarily due to a 72% increase in our production to 8.6 Bcfe during the year ended December 31, 2010 from 5.0 Bcfe during the year ended December 31, 2009, and approximately $1.3 million of the increase was due to increases in the average prices we received for both oil and natural gas over these respective periods. For the year ended December 31, 2010, we received an average natural gas price of $3.75 per Mcf and an average oil price of $76.39 per Bbl as compared to an average natural gas price of $3.59 per Mcf and an average oil price of $57.72 per Bbl for the year ended December 31, 2009. Our increased production during this period was primarily due to drilling operations in the Haynesville shale.

Realized gain (loss) on derivatives. Our realized gain on derivatives decreased by approximately $2.3 million to $5.3 million for the year ended December 31, 2010 from $7.6 million for the year ended December 31, 2009. This decrease was due primarily to a decrease of about $1.50 per MMBtu in the average price floor of our open natural gas costless collar contracts in 2010 as compared with 2009 and despite the fact that we had almost twice the natural gas volumes hedged in 2010 as compared to 2009.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was $3.14 million for the year ended December 31, 2010, compared to an unrealized loss of $2.38 million for the year ended December 31, 2009. During the period from December 31, 2009 to December 31, 2010, the net fair value of our open natural gas costless collar contracts increased from $1.00 million to $4.14 million, resulting in an unrealized gain on derivatives of $3.14 million for the year ended December 31, 2010. This increase in the net fair value of our open natural gas costless collar contracts was due primarily to lower natural gas prices at December 31, 2010 as compared to December 31, 2009.

Expenses

Production taxes and marketing. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We attempt to take advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay tend to correlate to the changes in our oil and natural gas revenues. Marketing expenses are fees charged by the purchasers of the oil and natural gas we produce and sell and principally include marketing, compression and transportation fees.

Lease operating expenses. Lease operating expenses are the daily costs incurred to produce oil and natural gas, as well as the daily costs incurred to maintain our producing properties. Such costs also include field personnel costs, utilities, chemical additives, salt water disposal, maintenance, repairs and occasional workover expenses related to our oil and natural gas properties.

Depletion, depreciation and amortization. Depletion, depreciation and amortization includes the systematic expensing of the capitalized costs incurred in the acquisition, exploration and development of oil and natural gas. We use the full-cost method of accounting and accordingly, we capitalize all costs associated with the acquisition, exploration and development of oil and natural gas properties, including unproved and unevaluated property costs. Internal costs are capitalized only to the extent they are directly related to acquisition, exploration or development activities and do not include any costs related to production, selling or general corporate administrative activities. Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of

proved oil and natural gas reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion, depreciation and amortization.

Accretion of asset retirement obligations. Asset retirement obligations relate to the future costs associated with plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. We recognize the fair value of an asset retirement obligation in the period it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the balance sheet. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in our statement of operations.

Full-cost ceiling impairment. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center ceiling, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. The cost center ceiling is defined as the sum of (a) the present value discounted at 10 percent of future net revenues of proved oil and natural gas reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) income tax effects related to the properties involved. Future net revenues from proved non-producing and proved undeveloped reserves are reduced by the estimated costs of developing these reserves. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes.

General and administrative expenses. General and administrative expenses include, but are not limited to, compensation and benefits for our employees, costs of renting and maintaining our headquarters, office service contracts, board of directors fees, franchise taxes, stock-based compensation expense and accounting, legal and other professional fees.

Other Income (Expense)

Net gain (loss) on asset sales and inventory impairment. This other income (expense) item includes the net gain or loss we experience on infrequent asset sales or impairment charges associated with certain equipment held in inventory. This item also includes infrequent sales of oil and natural gas properties that we consider to be extraordinary when considered in relation to the normal course of our business.

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

Interest and other income. Interest income includes interest earned periodically on the cash and cash equivalents we hold in money market accounts composed of United States Treasury securities offering daily liquidity and the interest earned periodically on our certificates of deposit. Other income includes income we receive for providing salt water disposal and natural gas transportation services to other working interest participants in wells that we operate.

Total income tax provision (benefit). Total income tax provision (benefit) includes the net current and deferred portions of our estimated income tax liabilities. We file a United States federal income tax return and state tax returns in those states where we conduct oil and natural gas operations. The current portion of our income tax provision (benefit) reflects actual income tax payments made or refunds received by us as a result of filing these income tax returns. The deferred portion of our income tax provision is the result of temporary timing differences between the financial statement carrying values and the tax bases of our assets and liabilities.

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


	Year Ended December 31,
	2011			2010			2009
(In thousands, except expenses per Mcfe)
Expenses:
Production taxes and marketing	$	6,278		$	1,982		$	1,077
Lease operating		7,244			5,284			4,725
Depletion, depreciation and amortization		31,754			15,596			10,743
Accretion of asset retirement obligations		209			155			137
Full-cost ceiling impairment		35,673			–			25,244
General and administrative		13,394			9,702			7,115

Total expenses		94,552			32,719			49,041
Operating (loss) income		(15,308	)		9,761			(24,752	)
Other (expense) income:
Net loss on asset sales and inventory impairment		(154	)		(224	)		(379	)
Interest expense		(683	)		(3	)		–
Interest and other income		315			364			781

Total other (expense) income		(522	)		137			402
(Loss) income before income taxes		(15,830	)		9,898			(24,350	)
Total income tax (benefit) provision		(5,521	)		3,521			(9,925	)
Net (loss) income	$	(10,309	)	$	6,377		$	(14,425	)
Expenses per Mcfe:
Production taxes and marketing	$	0.41		$	0.23		$	0.22
Lease operating	$	0.47		$	0.61		$	0.94
Depletion, depreciation and amortization	$	2.06		$	1.81		$	2.15
General and administrative	$	0.87		$	1.13		$	1.42

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Production taxes and marketing. Our production taxes and marketing expenses increased by $4.3 million to $6.3 million, or an increase of approximately 217% for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in our production taxes and marketing expenses reflects the increases in both our oil and natural gas production and revenues by 79% and 97%, respectively, during the year ended December 31, 2011 as compared to the year ended December 31, 2010. The majority of this increase was due to higher marketing, transportation and compression charges on portions of our non-operated Haynesville shale production in 2011 as compared to 2010. Some of this increase was also due to Haynesville shale wells completed in 2011, several of which were turned to sales or produced their first significant production volumes during 2011. Although we or our outside operating partners have applied for exemptions from initial production taxes on these recently completed Haynesville shale wells, and although we expect these applications will be approved by the state of Louisiana, some of these wells had not yet been approved for production tax exemptions at December 31, 2011. Thus, we have paid and/or accrued for the associated production taxes on these wells during the year ended December 31, 2011, although we expect these production taxes will be refunded to us in future periods. We will adjust our production taxes and marketing

expenses accordingly when and if these production tax exemptions are approved. The remainder of the increase in production taxes and marketing expenses for the year ended December 31, 2011 was due to production taxes paid on production from our initial Eagle Ford shale wells in south Texas.

Lease operating expenses. Our lease operating expenses increased by $2.0 million to $7.2 million, or an increase of about 37%, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. During these respective periods, however, our oil and natural gas production increased 79% from 8.6 Bcfe to 15.4 Bcfe. As a result, our lease operating expenses per unit of production decreased by 23% to $0.47 per Mcfe for the year ended December 31, 2011 as compared to $0.61 per Mcfe for the year ended December 31, 2010. During the year ended December 31, 2011, both our total Haynesville shale production, as well as the percentage of our Haynesville production for which we were the operator increased, as compared to the year ended December 31, 2010. The unit lease operating costs associated with the Haynesville production are much less than those associated with our Cotton Valley natural gas production, primarily due to the greater salt water disposal costs associated with the Cotton Valley production and given the early stages of production associated with many of these Haynesville wells.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $16.2 million to $31.8 million, or an increase of about 104%, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in our depletion, depreciation and amortization expenses was due primarily to an increase of approximately 79% in our oil and natural gas production from 8.6 Bcfe to 15.4 Bcfe during the respective time periods. Our depletion, depreciation and amortization expenses on a unit-of-production basis increased to $2.06 for the year ended December 31, 2011, or an increase of about 14%, from $1.81 per Mcfe for the year ended December 31, 2010. This per unit increase reflects increases in drilling and completion costs for wells drilled to the Haynesville shale during 2011, as well as higher drilling and completion costs on a per Mcfe basis associated with oil reserves added in the Eagle Ford shale in south Texas.

Accretion of asset retirement obligations. Our accretion of asset retirement obligations expenses increased by approximately $54,000 to approximately $209,000, or an increase of about 35%, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in our accretion of asset retirement obligations was due primarily to the addition of new wells through our drilling of operated wells and our participation in the drilling of non-operated wells, although, on the whole, this item is an insignificant component of our overall expenses.

Full-cost ceiling impairment. During the quarter ended March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairment charge of $35.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $12.7 million, which is reflected in our expenses for the year ended December 31, 2011. No impairment to the net carrying value of our oil and natural gas properties on the balance sheet resulting from the full-cost ceiling limitation was recorded at December 31, 2010.

General and administrative. Our general and administrative expenses increased by $3.7 million to $13.4 million, or an increase of about 38%, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in our general and administrative expenses was due primarily to increased cash and non-cash compensation expenses and increased accounting expenses for the year ended December 31, 2011 as compared to the year ended December 31, 2010. We recorded approximately $2.4 million in non-cash compensation expense for the year ended December 31, 2011 as compared to approximately $0.9 million recorded for the year ended December 31, 2010. This increase was primarily

due to a change in accounting method for valuing our outstanding stock options. We awarded no new stock options during 2011. As a result of our increased oil and natural gas production, however, our general and administrative expenses decreased by 27% on a unit-of-production basis to $0.87 per Mcfe for the year ended December 31, 2011 as compared to $1.13 per Mcfe for the year ended December 31, 2010.

Net gain (loss) on asset sales and inventory impairment. We incurred a loss on asset sales and inventory impairment of approximately $154,000 for the year ended December 31, 2011, as compared to a loss of approximately $224,000 for the year ended December 31, 2010. During the year ended December 31, 2011, this loss was primarily related to the sale of pipe and other equipment and the impairment of certain equipment held in inventory, consisting primarily of drilling rig parts. During the year ended December 31, 2010, we wrote off the Boise South pipeline asset in Orange County, Texas and recognized a net loss of approximately $174,000. We also recognized an impairment of approximately $50,000 to some of our equipment held in inventory following a determination that the market value of the equipment, consisting primarily of drilling rig parts, was less than the cost.

Interest expense. For the year ended December 31, 2011, we incurred total interest expense of approximately $2.0 million. We capitalized approximately $1.3 million of our interest expense on certain qualifying projects for the year ended December 31, 2011 and expensed the remaining $683,000 to operations. During the year ended December 31, 2011, we incurred incremental net borrowings of $88.0 million under our credit agreement to finance a portion of our working capital requirements and capital expenditures. Our total outstanding borrowings at December 31, 2011 were $113.0 million, and the interest rate on these borrowings was approximately 5.3% per annum. In early January 2012, we converted this $113.0 million base rate advance to a Eurodollar-based advance, which then bore interest at 3.5% per annum. In December 2010, we borrowed $25.0 million under our credit agreement to finance a portion of our working capital requirements and capital expenditures, which remained outstanding at December 31, 2010. We incurred interest expense of approximately $3,000 for the year ended December 31, 2010.

Interest and other income. Our interest and other income decreased by approximately $50,000 to approximately $314,000, or a decrease of about 14%, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The decrease in our interest and other income was due primarily to a decrease in the average balances of our cash and cash equivalents and certificates of deposit on which we received interest income between the two periods. Our cash and cash equivalents and certificates of deposit decreased to approximately $11.6 million at December 31, 2011 from approximately $23.4 million at December 31, 2010, as we used cash and incremental borrowings to acquire additional leasehold acreage in the Eagle Ford shale play in south Texas and in the core area of the Haynesville shale play in northwest Louisiana and to fund our operated and non-operated drilling and completion activities in both areas.

Total income tax provision (benefit). We recorded a total income tax benefit of approximately $5.5 million for the year ended December 31, 2011 as compared to a total income tax provision of approximately $3.5 million for the year ended December 31, 2010. The total income tax benefit for the year ended December 31, 2011 reflected deferred income taxes almost entirely, with the exception of a state of Louisiana income tax refund of approximately $46,000 recorded during this period. During the first quarter ended March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairment charge of $35.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $12.7 million. We recorded a total income tax provision of approximately $3.5 million for the year ended December 31, 2010. The total income tax provision for the year ended December 31, 2010 included a deferred income tax provision of approximately $4.9 million and a current income tax benefit of approximately $1.4 million, which was attributable to a refund of U.S. federal income taxes received by us. For the year ended

December 31, 2010, the deferred income tax provision was consistent with our income before income taxes, which included approximately $3.1 million in unrealized hedging gains. We had a net loss for the year ended December 31, 2011, and our effective tax rate for the year ended December 31, 2010 was 35.57%.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Production taxes and marketing. Our production taxes and marketing expenses increased by $0.9 million to $2.0 million, or an increase of about 84%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase in our production taxes and marketing expenses was due primarily to the increase in our oil and natural gas revenues from $19.0 million to $34.0 million, or an increase of about 79%, during the respective time periods. On a unit-of-production basis, our production taxes and marketing expenses remained relatively constant year-over-year, increasing to $0.23 per Mcfe for the year ended December 31, 2010 from $0.22 per Mcfe for the year ended December 31, 2009.

Lease operating expenses. Our lease operating expenses increased by $0.6 million to $5.3 million, or an increase of about 12%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. During these respective periods, however, our oil and natural gas production increased 72% to 8.6 Bcfe from 5.0 Bcfe. As a result, our lease operating expenses per unit of production decreased by 35% to $0.61 per Mcfe for the year ended December 31, 2010 as compared to $0.94 per Mcfe for the year ended December 31, 2009. In 2010, the percentage of our production attributed to the Haynesville shale continued to increase. The unit lease operating costs associated with the Haynesville production are much less than those associated with our Cotton Valley natural gas production, primarily due to the greater salt water disposal costs associated with the Cotton Valley production.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $4.9 million to $15.6 million, or an increase of about 45%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase in our depletion, depreciation and amortization expenses was due primarily to the increase in our oil and natural gas production to 8.6 Bcfe from 5.0 Bcfe during the respective time periods. The finding and development costs associated with our Haynesville shale reserves have been less than finding and development costs associated with our reserves producing from the Cotton Valley and other formations. As a result, our depletion, depreciation and amortization expenses on a unit-of-production basis decreased as our Haynesville production increased; these expenses decreased to $1.81 per Mcfe during the year ended December 31, 2010 from $2.15 per Mcfe during the year ended December 31, 2009.

Accretion of asset retirement obligations. Our accretion of asset retirement obligations expenses increased by approximately $18,000 to approximately $155,000, or an increase of about 13%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase in our accretion of asset retirement obligations was due primarily to the addition of new wells through our drilling of operated wells and our participation in the drilling of non-operated wells, although, on the whole, this item is an insignificant component of our overall expenses.

Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties on the balance sheet resulting from the full-cost ceiling limitation was recorded at December 31, 2010. At December 31, 2009, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $16.3 million. As a result, we recorded an impairment charge of $25.2 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $8.9 million. A corresponding charge of $25.2 million was also recorded to the consolidated statement of operations for the year ended December 31, 2009.

General and administrative. Our general and administrative expenses increased by $2.6 million to $9.7 million, or an increase of about 36%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. Approximately $1.0 million of this increase was due to legal and other due diligence fees resulting from an unsuccessful effort to acquire oil and natural gas producing properties and associated acreage. The remainder of the increase was due primarily to increased compensation expenses resulting from both increased salaries and retention and performance bonuses paid to certain employees during the year ended December 31, 2010. As a result of our increased oil and natural gas production, however, our general and administrative expenses decreased by 20% on a unit-of-production basis to $1.13 per Mcfe for the year ended December 31, 2010 as compared to $1.42 per Mcfe for the year ended December 31, 2009.

Net gain (loss) on asset sales and inventory impairment. During the year ended December 31, 2010, we wrote off the Boise South Pipeline asset in Orange County, Texas and recognized a net loss of approximately $174,000. We also recognized an impairment of approximately $50,000 to some of our equipment held in inventory following a determination that the market value of the equipment, consisting primarily of drilling rig parts, was less than the cost. During the year ended December 31, 2009, we recognized impairments to these drilling rig parts and tubular goods held in inventory and sold rod parts held in inventory, recognizing a net loss of approximately $379,000.

Interest expense. In December 2010, we borrowed $25.0 million under our credit agreement to finance a portion of our working capital requirements and capital expenditures. We incurred approximately $3,000 in interest expense for the year ended December 31, 2010. At December 31, 2010, the interest rate on the outstanding borrowings was approximately 1.6% per annum. We had no borrowings under the credit agreement in 2009, and as a result, we incurred no interest expense for the year ended December 31, 2009.

Interest and other income. Our interest and other income decreased by approximately $0.4 million to approximately $0.4 million, or a decrease of about 53%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The decrease in our interest and other income was due primarily to a decrease in the average balances of our cash and cash equivalents and certificates of deposit on which we receive interest income during the year ended December 31, 2010 as compared to the year ended December 31, 2009. Our cash and cash equivalents and certificates of deposit decreased to $23.4 million at December 31, 2010 from $119.9 million at December 31, 2009, as we used cash during this period primarily to acquire additional leasehold acreage in the Eagle Ford shale play in south Texas and in the core area of the Haynesville shale play in northwest Louisiana and to fund our operated and non-operated drilling and completion activities in both areas.

Total income tax provision (benefit). We recorded a total income tax provision of approximately $3.5 million for the year ended December 31, 2010 as compared to a total income tax benefit of approximately $9.9 million recorded for the year ended December 31, 2009. For the year ended December 31, 2010, we recorded a current income tax benefit of approximately $1.4 million, which was attributable to a refund of U.S federal income taxes received by us, and we also recorded a deferred income tax provision of $4.9 million consistent with the increase in our income before income taxes for that year. For the year ended December 31, 2009, we recorded a current income tax benefit of approximately $2.3 million, primarily attributable to a net refund of U.S. federal income taxes and a refund of income taxes from the state of Louisiana. We also recorded a deferred income tax benefit of approximately $7.6 million, primarily attributable to the full-cost ceiling impairment recorded in 2009. Our effective tax rate for the year ended December 31, 2010 was 35.57%, and we had a net loss for the year ended December 31, 2009.

Liquidity and Capital Resources

Prior to the consummation of our initial public offering on February 7, 2012, our primary sources of liquidity were capital contributions from private investors, our cash flows from operations, borrowings under our credit agreement and the proceeds from a significant sale of a portion of our assets in 2008. Our primary use of capital has been, and will continue to be during 2012 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties. We continually evaluate potential capital sources, including equity and debt financings and additional borrowings, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital. At December 31, 2011, we had cash and certificates of deposits totaling approximately $11.6 million.

In December 2011, we amended and restated our senior secured revolving credit agreement for which Comerica Bank serves as administrative agent. This amendment increased the maximum facility amount from $150.0 million to $400.0 million. Borrowings are limited to the lesser of $400.0 million or the borrowing base. At December 31, 2011, the borrowing base was $125.0 million, and we had $113.0 million of outstanding indebtedness, excluding $1.3 million in outstanding letters of credit. Subsequent to year end, we used the net proceeds from our initial public offering to repay the outstanding indebtedness under our credit agreement in full and our borrowing base was reduced to $100.0 million. On February 28, 2012, our borrowing base increased to $125.0 million pursuant to a borrowing base redetermination made by the lenders at our request. We may request additional redeterminations in accordance with our credit agreement as we increase our proved reserves. The new amended and restated credit agreement matures in December 2016. In March 2012, we borrowed $15.0 million under the credit agreement to finance a portion of our working capital requirements. At March 30, 2012, our borrowings bore interest at a variable rate of 1.75% plus a Eurodollar-based rate per annum, which equated to approximately 2.0% per annum.

We actively review acquisition opportunities on an ongoing basis. While we believe our cash and cash equivalents, together with our cash flows and future potential borrowings under our credit agreement, will be adequate to fund our capital expenditure requirements and any acquisitions of interests and acreage for 2012, funding for future acquisitions of interests and acreage or our future capital expenditure requirements for 2013 and subsequent years may require additional sources of financing, which may not be available. As a result of our anticipated increases in production and reserves, we expect to have a sufficient increase in our cash flows from operations during the year ending December 31, 2012, as compared to our cash flows from operations in prior periods, as well as a sufficient increase in the borrowing base under our credit agreement to help fund our 2012 capital expenditure budget. A majority of our anticipated increase in cash flows during the year ending December 31, 2012 is expected to come from our exploration activities on unproved properties at December 31, 2011 in the Eagle Ford shale play assuming such exploration activities are successful. These anticipated increases in our cash flows from operations are based upon current oil and natural gas prices and the hedges we currently have in place. If our exploration activities result in less cash flows than anticipated, we may seek additional sources of capital, including through borrowings under our credit agreement (assuming availability under our borrowing base). In addition to future borrowings under our credit agreement, we may also seek to raise additional funds by selling shares of our common stock or securities convertible or exercisable into our common stock (including debt securities or other preferential securities) in the public markets or otherwise. It is likely that any such sales would dilute the ownership interest of our existing shareholders. It is also possible that, to the extent we are not able to obtain additional sources, we may modify our planned capital expenditure budget for 2012 accordingly. Exploration activities are subject to a number of risks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows from operations and borrowing base under our credit agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That

May Exceed Our Cash Flows From Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth,” “Risk Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business” and “Risk Factors — Our Identified Drilling Locations Are Scheduled Out Over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.”

Our cash flows for the years ended December 31, 2011, 2010 and 2009 are presented below:


	Year Ended December 31,
	2011			2010			2009
(In thousands)
Net cash provided by operating activities	$	61,868		$	27,273		$	1,791
Net cash used in investing activities		(160,087	)		(147,334	)		(49,415	)
Net cash provided by financing activities		87,444			36,891			1,086

Net change in cash and cash equivalents	$	(10,775	)	$	(83,170	)	$	(46,538	)

Cash Flows Provided by Operating Activities

Net cash provided by operating activities increased by $34.6 million to $61.9 million for the year ended December 31, 2011 as compared to net cash provided by operating activities of $27.3 million for the year ended December 31, 2010. Net cash provided by oil and natural gas operations increased significantly to $49.3 million for the year ended December 31, 2011 from $25.0 million for the year ended December 31, 2010. This increase reflects primarily the 79% increase in our oil and natural gas production to 15.4 Bcfe from 8.6 Bcfe between the respective periods. A portion of the increase in net cash provided by operating activities also reflects the approximate five-fold increase in our oil production for the year ended December 31, 2011 as compared to the year ended December 31, 2010, as well as a higher average oil price of $93.80 per Bbl realized during 2011 as compared to an average oil price of $76.39 per Bbl realized during 2010. Some of this increase in net cash provided by operating activities is also due to changes in our operating assets and liabilities totaling approximately $10.3 million between December 31, 2010 and December 31, 2011. Our accounts payable and accrued liabilities increased to approximately $44.3 million at December 31, 2011 from approximately $27.0 million at December 31, 2010 due to our increased operating activity in south Texas. Our accounts receivable increased to $13.2 million at December 31, 2011 as compared to $11.6 million at December 31, 2010 due primarily to the increase in our oil and natural gas production and associated revenues.

Net cash provided by operating activities increased by $25.5 million to $27.3 million for the year ended December 31, 2010 as compared to net cash provided by operating activities of $1.8 million for the year ended December 31, 2009. The increase in cash flows provided by operations reflects an increase in our production to 8.6 Bcfe from 5.0 Bcfe and an increase in the average prices we received for oil and natural gas production for the year ended December 31, 2010 as compared to the year ended December 31, 2009. Our accounts payable and accrued liabilities were approximately $26.8 million at December 31, 2010 as a result of operated horizontal wells that we were drilling and/or completing in the Haynesville and Eagle Ford shale plays and in the Cotton Valley formation during the fourth quarter of 2010. Our accounts payable and accrued liabilities were $7.3 million at December 31, 2009 as we were drilling and completing only one operated horizontal Haynesville shale well at that time.

Our operating cash flows are sensitive to a number of variables, including changes in our production and volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil

and natural gas. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Quantitative and Qualitative Disclosures About Market Risk” below. See also “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.”

Cash Flows Used in Investing Activities

Net cash used in investing activities increased by $12.8 million to $160.1 million for the year ended December 31, 2011 from $147.3 million for the year ended December 31, 2010. This increase in net cash used in investing activities reflected a decrease of $2.6 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2011 as compared to the year ended December 31, 2010, offset almost exactly by an increase of approximately $3.0 million in expenditures for other property and equipment, which includes new pipeline infrastructure associated with our initial wells in the Eagle Ford shale. Although our capital expenditures were relatively flat year-over-year, approximately 75% of our capital expenditures were allocated to drilling and completion operations and 25% to the acquisition of additional acreage for the year ended December 31, 2011, as compared to approximately 43% allocated to drilling and completion operations and 57% allocated to acquisition of additional acreage for the year ended December 31, 2010. Our oil and natural gas properties capital expenditures for the year ended December 31, 2011 were primarily due to expenditures associated with our operated and non-operated drilling and completion activities in the Eagle Ford and Haynesville shale plays and our acreage acquisition in Karnes, DeWitt, Wilson and Gonzales Counties, Texas that we believe to be prospective for the Eagle Ford shale.

Net cash used in investing activities increased by $97.9 million to $147.3 million for the year ended December 31, 2010 from $49.4 million for the year ended December 31, 2009. This increase in net cash used in investing activities reflects primarily an increase of $104.8 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increased oil and natural gas properties capital expenditures for the year ended December 31, 2010 were due to the acquisition of leasehold acreage in the Eagle Ford shale play and the acquisition of additional leasehold acreage in the Haynesville shale play, as well as expenditures associated with our operated and non-operated drilling and completion activities in both plays as compared to the year ended December 31, 2009.

Expenditures for the acquisition, exploration and development of oil and natural gas properties are the primary use of our capital resources. We anticipate investing $313.0 million in capital for acquisition, exploration and development activities in 2012 as follows:


	Amount (in millions)
Exploration and development drilling and associated infrastructure	$	284.5
Leasehold acquisition		24.0
Other capital expenditures, 2-D and 3-D seismic data and recompletions of existing wells		4.5

Total	$	313.0

For further information regarding our anticipated capital expenditure budget in 2012, see “Business—General.”

Our 2012 capital expenditures may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil or natural gas prices decline or costs increase significantly, we could defer a significant portion of our anticipated capital expenditures until later periods to conserve cash or to focus on those projects that we believe have the

highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations and other factors both within and outside our control.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities w

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