CWEI Clayton Williams Energy, Inc.

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2011

or

For the transition period from                 to                

Commission File Number 001-10924

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code:  (432) 682-6324

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

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. o Yes     x No

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

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. x Yes  o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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). x Yes  o 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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter.  $354,519,407.

There were 12,163,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of February 29, 2012.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2012 Annual Meeting of Stockholders, which will be filed with the Commission not later than April 30, 2012, are incorporated by reference in Part III of this Form 10-K.

Table of Contents

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

2

Table of Contents

TABLE OF CONTENTS (Continued)

3

Table of Contents

Forward-Looking Statements

The information in this Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should, could or may occur in the future are forward-looking statements.  These forward-looking statements are based on management’s current expectations and belief, based on currently available information, as to the outcome and timing of future events and their effect on us.  While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate.  All statements concerning our expectations for future operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions.  Our forward-looking statements involve significant risks and uncertainties, many of which are beyond our control, and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections.  Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those described in (1) Part I, “Item 1A - Risk Factors” and other cautionary statements in this Form 10-K, (2) our reports and registration statements filed from time to time with the Securities and Exchange Commission (“SEC”), and (3) other announcements we make from time to time.

Forward-looking statements appear in a number of places and include statements with respect to, among other things:

·                   estimates of our oil and gas reserves;

·                   estimates of our future oil and gas production, including estimates of any increases or decreases in production;

·                   planned capital expenditures and the availability of capital resources to fund those expenditures;

·                   our outlook on oil and gas prices;

·                   our outlook on domestic and worldwide economic conditions;

·                   our access to capital and our anticipated liquidity;

·                   our future business strategy and other plans and objectives for future operations;

·                   the impact of political and regulatory developments;

·                   our assessment of counterparty risks and the ability of our counterparties to perform their future obligations;

·                   estimates of the impact of new accounting pronouncements on earnings in future periods; and

·                   our future financial condition or results of operations and our future revenues and expenses.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties incident to the exploration for and development, production and marketing of oil and gas.  These risks include, but are not limited to:

·                   the possibility of unsuccessful exploration and development drilling activities;

·                   our ability to replace and sustain production;

·                   commodity price volatility;

·                   domestic and worldwide economic conditions;

·                   the availability of capital on economic terms to fund our capital expenditures and acquisitions;

4

Table of Contents

·                   our level of indebtedness;

·                   the impact of the past or future economic recessions on our business operations, financial condition and ability to raise capital;

·                   declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our credit facility and impairments;

·                   the ability of financial counterparties to perform or fulfill their obligations under existing agreements;

·                   the uncertainty inherent in estimating proved oil and gas reserves and in projecting future rates of production and timing of development expenditures;

·                   drilling and other operating risks;

·                   hurricanes and other weather conditions;

·                   lack of availability of goods and services;

·                   regulatory and environmental risks associated with drilling and production activities;

·                   the adverse effects of changes in applicable tax, environmental and other regulatory legislation; and

·                   the other risks described in this Form 10-K.

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

As previously discussed, should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We specifically disclaim all responsibility to publicly update or revise any information contained in a forward-looking statement or any forward-looking statement in its entirety after the date made, whether as a result of new information, future events or otherwise, except as required by law.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Definitions of terms commonly used in the oil and gas industry and in this Form 10-K can be found in the “Glossary of Terms.”

5

Table of Contents

PART I

Item 1 -                                Business

General

Clayton Williams Energy, Inc., incorporated in Delaware in 1991, is an independent oil and gas company engaged in the exploration for and production of oil and natural gas primarily in Texas, Louisiana and New Mexico.  Unless the context otherwise requires, references to the “Company”, “CWEI”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries.  On December 31, 2011, our estimated proved reserves were 64,349 MBOE, of which 61% were proved developed.  Our portfolio of oil and natural gas reserves is weighted in favor of oil, with approximately 77% of our proved reserves at December 31, 2011 consisting of oil and natural gas liquids (“NGLs”) and approximately 23% consisting of natural gas.  During 2011, we added proved reserves of 20,881 MBOE through extensions and discoveries, had downward revisions of 2,007 MBOE, and had sales of minerals-in-place of 156 MBOE.  We also had average net production of 14.9 MBOE per day in 2011, which implies a reserve life of approximately 11.8 years.  CWEI held interests in 6,830 gross (1,098.9 net) producing oil and gas wells and owned leasehold interests in approximately 775,000 gross (387,000 net) undeveloped acres at December 31, 2011.

Clayton W. Williams, Jr. beneficially owns, either individually or through his affiliates, approximately 26% of the outstanding shares of our Common Stock.  In addition, The Williams Children’s Partnership, Ltd. (“WCPL”), a limited partnership of which Mr. Williams’ adult children are the limited partners, owns an additional 25% of the outstanding shares of our Common Stock.  Mr. Williams is also our Chairman of the Board, President and Chief Executive Officer.  As a result, Mr. Williams has significant influence in matters voted on by our shareholders, including the election of our Board members.  Mr. Williams actively participates in all facets of our business and has a significant impact on both our business strategy and daily operations.

Company Profile

Business Strategy

Our goal is to grow oil and gas reserves and increase shareholder value utilizing a flexible, opportunity-driven business strategy.  We do not adhere to rigid guidelines for resource allocations, risk profiles, product mixes, financial measurements or other operating parameters.  Instead, we try to identify exploratory and developmental projects that offer us the best possible opportunities for growth in oil and gas reserves and allocate our available resources to those projects.  Our direction is heavily influenced by Mr. Williams, who has over 50 years of experience and leadership in the oil and gas industry.  Strategically, we are currently focused on the development of oil reserves over gas reserves.  We believe that oil prices will continue to outpace gas prices based on relative energy content for the foreseeable future due to an abundance of domestic natural gas versus a much tighter balance between global supply and demand for crude oil.  We have significant holdings in oil-prone regions in the Permian Basin and the Giddings Area that we believe offer us attractive opportunities for growth in oil reserves, and we currently plan to exploit these resources as long as our margins between oil prices and the costs of drilling, completion and other field services remain acceptable.  In addition to our developmental drilling, we also remain committed to exploring for oil and gas reserves in areas that we believe offer us exceptional opportunities for reserve growth and we continue to search for possible proved property acquisitions.  From year to year, our allocation of investment capital may vary between exploratory and developmental activities depending on our analysis of all available growth opportunities, but our long-term focus on growing oil and gas reserves is consistent with our goal of value enhancement for our shareholders.

Recent Developments

Throughout 2011, we continued our developmental drilling programs in two primary oil-prone regions, the Permian Basin and the Giddings Area, which is located in Robertson, Burleson, Brazos, Lee, Milam, Leon, Fayette and Washington Counties, Texas.  Continued strong oil prices have provided us with what we believe is an acceptable profit margin on our investments in these core areas.  Beginning 2011, we engaged in the emerging Wolfbone play located in the Delaware Basin on the western edge of the Permian Basin.  To date, we have accumulated approximately 63,000 net acres in Reeves County, Texas through leasing and drill-to-earn farmout arrangements and have drilled 43 vertical and 7 horizontal wells on this acreage.

6

Table of Contents

We currently have seven rigs drilling wells in the Reeves County Wolfbone play, one rig drilling Wolfberry wells in the Midland Basin in Andrews County and one rig drilling horizontal wells in the Austin Chalk formation in the Giddings Area in East Central Texas (see Exploration and Development Activities — Core Areas) .

Domestic Operations

We conduct all of our drilling, exploration and production activities in the United States.  All of our oil and gas assets are located in the United States, and all of our revenues are derived from sales to customers within the United States.

Development Program

Our current focus is on developmental drilling.  A developmental well is a well drilled within the proved area of an oil and gas reservoir to a horizon known to be productive.  We have an inventory of developmental projects available for drilling in the future, most of which are located in the oil-prone regions of the Permian Basin and the Giddings Area.  In many cases, our leasehold interests in developmental projects are held by the continuous production of other wells, meaning that our rights to drill these projects are not subject to near-term expiration.  This provides us with a high degree of flexibility in the timing of developing these reserves.  Consistent with our business strategy, approximately $343.1 million, or 93% of our planned expenditures for 2012 relate to developmental drilling, most of which are in oil-prone areas.

Exploration Program

To a lesser degree, we are also engaged in finding reserves through exploratory drilling.  Our exploration program consists of generating exploratory prospects, leasing the acreage related to the prospects, drilling exploratory wells on these prospects to determine if recoverable oil and gas reserves exist, drilling developmental wells on prospects, and producing and selling any resulting oil and gas production.

Many of our exploration activities, particularly those related to our Deep Bossier prospects in the Giddings Area and our prospects in South Louisiana, target gas reserves.  Since we believe gas prices are likely to be less favorable than oil prices in the near term, we currently plan to spend only $27.4 million, or 7% of our planned expenditures for 2012, on exploration activities.

Acquisition and Divestitures of Proved Properties

In addition to our exploration and development activities, we seek to acquire proved reserves, but competition for the purchase of proved reserves is intense.  Sellers often utilize a bid process to sell properties.  This process usually intensifies the competition and makes it extremely difficult for us to acquire reserves without assuming significant price and production risks. We are actively searching for opportunities to acquire proved oil and gas properties, but we cannot give any assurance that we will be successful in our efforts to acquire proved properties in 2012.

In October 2011, our wholly owned subsidiary, Southwest Royalties, Inc. (“SWR”), entered into merger agreements with 24 limited partnerships of which SWR is the general partner (the “SWR Partnerships”) pursuant to which each of the SWR Partnerships that approves the merger will merge into SWR, and the partnership interests of the SWR Partnerships, other than those interests owned by SWR, will be converted into the right to receive cash.  SWR will not receive any cash payment for its partnership interests in the SWR Partnerships; however, as a result of each merger, SWR will acquire 100% of the assets and liabilities of each SWR Partnership that approves the merger.  Each of the mergers is subject to customary closing conditions, including approval by the limited partners of each of the SWR Partnerships.  The merger consideration will be 100% cash, and is expected to be approximately $40.2 million in the aggregate.  We expect to obtain the funds to finance the aggregate merger consideration by conveying a volumetric production payment (“VPP”) on certain properties acquired in the proposed mergers to a third party.  The final terms of the VPP will not be determined until immediately prior to the closing of the mergers.  The closing of the mergers is not conditioned on our receiving proceeds from the VPP or any other financing condition.

From time to time, we sell certain of our proved properties when we believe it is more advantageous to dispose of the selected properties than to continue to hold them.  We consider many factors in deciding to sell properties, including the need for liquidity, the risks associated with continuing to own the properties, our expectations for future development on the properties, the fairness of the price offered, and other factors related to the condition and location of the properties.

7

Table of Contents

Desta Drilling

Through our wholly owned subsidiary, Desta Drilling, L.P. (“Desta Drilling”), we operate 14 drilling rigs, 12 of which we own, and two of which we lease under long-term contracts.  We believe that owning our own rigs helps control our cost structure and provides us flexibility to take advantage of drilling opportunities on a timely basis.  The Desta Drilling rigs are primarily reserved for our use, but are available to conduct contract drilling operations for third parties from time to time.  We were using nine of our rigs to drill wells in our developmental drilling programs, three rigs were working for third parties and the remaining two rigs were being refurbished or upgraded as of February 27, 2012.

Exploration and Development Activities

Overview

Since the second quarter of 2009, we have been primarily committed to drilling developmental oil wells in the Permian Basin and the Giddings Area.  We currently plan to spend approximately $370.5 million on exploration and development activities during 2012, with approximately 93% of these estimated expenditures expected to be spent on developmental drilling.  We may increase or decrease our planned activities, depending upon drilling results, operating margins, the availability of capital resources, and other factors affecting the economic viability of such activities.

Core Areas

Permian Basin

The Permian Basin is a sedimentary basin in West Texas and Southeastern New Mexico known for its large oil and gas deposits from the Permian geologic period.  The Permian Basin covers an area approximately 250 miles wide and 350 miles long and contains commercial accumulations of oil and gas in multiple stratigraphic horizons at depths ranging from 1,000 feet to over 25,000 feet.  The Permian Basin is characterized by an extensive production history, mature infrastructure, long reserve life, multiple producing horizons and enhanced recovery potential.  Although many fields in the Permian Basin have been heavily exploited in the past, higher product prices and improved technology (including deep horizontal drilling) continue to attract high levels of drilling and recompletion activities.  We gained a significant position in the Permian Basin in 2004 when we acquired Southwest Royalties, Inc.  This acquisition provided us with an inventory of potential drilling and recompletion activities.

We spent $299.1 million in the Permian Basin during 2011 on drilling and completion activities and $46.6 million on leasing and seismic activities.  We drilled and completed 100 gross (88.5 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during 2011.  We currently plan to spend approximately $319.5 million on drilling, completion and leasing activities during 2012.  Following is a discussion of our principal assets in the Permian Basin.

Wolfbone

We are actively growing our acreage position in the Wolfbone play located in the Delaware Basin on the western edge of the Permian Basin.  A Wolfbone well is a well that commingles production from the Bone Springs and Wolfcamp formations which are typically encountered at depths of 8,000 to 13,000 feet.  These Permian aged formations in the Delaware Basin are comprised of limestone and sandstone.  In March 2011, we entered into a farm-in agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”) in southern Reeves County, Texas with a term of five years.  For each well that we drill in the farm-in area that meets certain specified requirements (each, a “carried well”), Chesapeake will retain a 25% carried interest, bearing none of the costs to drill and complete a carried well, and we will earn an undivided 75% interest in 640 net acres within the farm-in area. If we drill 100 wells in the farm-in area, we will earn an undivided 75% interest in the entire farm-in area that has not otherwise been assigned to us during the term. Under the farm-in agreement, we are obligated to drill or commence drilling operations on at least 20 carried wells prior to March 1, 2012. We have currently drilled enough wells to meet this obligation. Following satisfaction of our initial drilling obligations, we have the right, but not the obligation, to drill at least 20 additional carried wells each year during the remainder of the term. If we fail to drill at least 20 carried wells during any year after expiration of the initial drilling period, the farm-in agreement will terminate without any liability to us. Excess wells drilled during any year may be applied towards our drilling obligations in the next year.  As of December 31, 2011, we have drilled 33 carried wells under this agreement.

We spent approximately $156.6 million on drilling and completion activities and $43.2 million for leasing activities in the Wolfbone play during 2011.  We plan to spend approximately $219.5 million on drilling and completion activities and $50 million on leasing activities in the Wolfbone play during 2012.  To date, we have

8

Table of Contents

accumulated approximately 63,000 net acres in Reeves County.  We are currently utilizing seven rigs in this area and may increase the rig count to eight through 2012.

Wolfberry

Another focal point in the Permian Basin is the drilling of Wolfberry wells in the Midland Basin.  Wolfberry is a term applied to the combined production from the Spraberry and Wolfcamp formations, which are generally found at depths of 7,500 to 10,500 feet.  These formations are comprised of a sequence of basinal, interbedded shales and carbonates.  We spent approximately $114.7 million on Wolfberry drilling and completion activities and approximately $1.6 million spent primarily on leasing activities during 2011.  We currently plan to keep one of our rigs drilling Wolfberry wells and plan to spend approximately $37.2 million during 2012 for drilling, completion and leasing activities.

Fuhrman-Mascho Field

We resumed a drilling program in the Fuhrman-Mascho Field in Andrews County, Texas beginning in July 2009.  Wells in the Fuhrman-Mascho Field produce from the San Andres formation, a reservoir comprised of fractured carbonate sediments found at a depth of approximately 4,300 feet.  We currently plan to drill eight additional wells in the first half of 2012.

Other

We also have an inventory of developmental drilling and enhanced recovery opportunities throughout the Permian Basin in established fields such as the Flying M in Lea County, New Mexico, East Huntley in Garza County, Texas, South Huntley in Garza County, Texas, Halley in Winkler County, Texas, Mag Sealy in Ward County, Texas, Ward Estes in Ward County, Texas, Foster/Gist in Ector County, Texas and Amacker Tippett in Upton County, Texas.

Giddings Area

Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Giddings Area.  Most of our wells in the Giddings Area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas.  Hydrocarbons are also encountered in the Giddings Area from other formations, including the Cotton Valley, Deep Bossier, Eagle Ford Shale, and Taylor formations.  In 2011, we spent approximately $61.6 million in the Giddings Area on drilling and leasing activities and currently plan to spend approximately $41.4 million on similar drilling activities in this area in 2012.  Following is a discussion of our principal assets in the Giddings Area.

Austin Chalk

We have concentrated our recent drilling activities in the Giddings Area on the Austin Chalk formation, an upper Cretaceous geologic formation in the Gulf Coast region of the United States that stretches across numerous fields in Texas and Louisiana.  The Austin Chalk formation is generally encountered at depths of 5,500 to 7,000 feet.  Horizontal drilling is the primary technique used in the Austin Chalk formation to enhance productivity by intersecting multiple zones.  Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas.  The existing spacing between some of our wells in this area affords us the opportunity to tap additional oil and gas reserves by drilling new wells between existing wells, a technique referred to as in-fill drilling.  These in-fill wells are considered lower risk as compared to exploratory wells.  We initiated a water fracturing program on certain wells in June 2011 to enhance productivity on certain wells.  We are currently working one of our drilling rigs in the Giddings Area to drill horizontal wells in the Austin Chalk formation and plan to keep the rig count at this level through 2012.

Eagle Ford Shale

The Eagle Ford Shale is a formation immediately beneath the Austin Chalk formation.  During 2010, we drilled and completed four producing wells in Burleson and Lee Counties, Texas using various fracturing techniques with varying results.  In October 2011, we completed the Hosek #1 well in Wilson County and may drill additional wells in this area in 2012.

Deep Bossier

We have an extensive acreage position in the Giddings Area that is also prospective for Deep Bossier sands which are encountered at depths ranging from 14,000 to 22,000 feet.  Prior to 2011, we drilled three Deep Bossier wells, none of which were commercially productive.  In 2011, we drilled the Hamill Foundation #1, an exploratory well, in Leon County, Texas.  Based on results of a stimulation procedure, we determined that the well was uneconomic and recorded a pre-tax charge of $16.8 million for the abandonment of this well.  We do not have any further plans in this area.

9

Table of Contents

South Louisiana

In the first quarter of 2011, we drilled the State Lease 19924 #1, an exploratory well in St. Mary Parish, Louisiana, which was a dry hole.  In the third quarter of 2011, we drilled and completed the State Lease 19706 #1, a developmental well in Plaquemines Parish, Louisiana, which is currently waiting on pipeline.  We also drilled the Pruitt ET AL #1 in the third quarter of 2011, an exploratory well in Acadia Parish, Louisiana which was a dry hole.

Known Trends and Uncertainties

We have an extensive acreage position within the Permian Basin with a large portion of that acreage currently held by production.  We are continuously seeking other opportunities for growth in the Permian Basin, and believe that our holdings in this region provide us with many viable possibilities for exploration and development activities beyond our current drilling programs.

Our developmental drilling programs are very sensitive to oil prices and drilling costs.  We attempt to control costs through drilling efficiencies by the use of our own rigs, purchasing casing and tubing at periods when we believe prices are suitable and working with service providers to receive acceptable unit costs.  We plan to continue these programs as long as oil prices remain favorable.  In order to continue drilling in these areas, we must be able to realize an acceptable margin between our expected cash flow from new production and our cost to drill new wells.  If any combination of falling oil prices and rising drilling costs occur in future periods, we may discontinue a program until margins return to acceptable levels.

Marketing Arrangements

We sell substantially all of our oil production under short-term contracts based on crude oil price bulletins from major oil purchasers for West Texas Intermediate contracts, less agreed-upon deductions that vary by grade of crude oil.  The majority of our gas production is sold under short-term contracts based on pricing formulas that are generally market responsive.  From time to time, we may also sell a portion of our gas production under short-term contracts at fixed prices.  We believe that the loss of any of our oil and gas purchasers would not have a material adverse effect on our results of operations due to the availability of other purchasers.

Natural Gas Services

We own an interest in and operate natural gas service facilities in the states of Texas and Louisiana,. These natural gas service facilities consist of interests in approximately 102 miles of pipeline, three treating plants, one dehydration facility, and seven wellhead type treating and/or compression stations.  Most of our operated gas gathering and treating activities exist to facilitate the transportation and marketing of our operated oil and gas production.

In 2011, we began the construction of a gas gathering and treating system to facilitate the transportation and marketing of our Wolfbone oil and gas production in Reeves County.  We spent approximately $7.8 million during 2011 and currently expect to spend $20 million during 2012.

Competition and Markets

Competition in all areas of our operations is intense.  We experience competition from major and independent oil and gas companies and oil and gas syndicates in bidding for desirable oil and gas properties, as well as in acquiring the equipment, data and labor required to operate and develop such properties. A number of our competitors have financial resources and acquisition, exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete with these companies. Competitors may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.  Our ability to increase reserves in the future will depend on our success at selecting and acquiring suitable producing properties and prospects for future development and exploration activities.

In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.  The price and availability of alternative energy sources could adversely affect our revenue.

The market for our oil, gas and natural gas liquids production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and natural gas liquids, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.

10

Table of Contents

Regulation

Generally.   Our oil and gas exploration, production and related operations and activities are subject to extensive rules and regulations promulgated by federal, state and local governmental agencies. Failure to comply with such rules and regulations can result in substantial penalties. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

Regulations affecting production.   All of the states in which we operate generally require permits for drilling operations, require drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas.  Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production.

These laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil and natural gas within their jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation of production, but there can be no assurance they will not do so in the future.

In the event we conduct operations on federal, state or Indian oil and natural gas leases, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and on-site security regulations and other appropriate permits issued by the Bureau of Land Management or other relevant federal or state agencies.

Regulations affecting sales.   The sales prices of oil, natural gas liquids and natural gas are not presently regulated, but rather are set by the market.  We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.

The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production.  The price and terms of access to pipeline transportation are subject to extensive federal and state regulation.  The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation.  These initiatives also may affect the intrastate transportation of natural gas under certain circumstances.  The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We do not believe that we will be affected by any such FERC action in a manner materially different from other natural gas producers in our areas of operation.

The price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market.  Interstate transportation rates for oil, natural gas liquids and other products are regulated by the FERC.  The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase.  We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.

Market manipulation and market transparency regulations.   Under the Energy Policy Act of 2005 (“EP Act 2005”), the FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation of natural gas by “any entity” in order to enforce the anti-market manipulation provisions in the EP Act 2005. The Federal Trade Commission (“FTC”) has similar regulatory oversight of oil markets in order to prevent market manipulation.  The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act.  With regard to our physical purchases and sales of natural gas, natural gas liquids and crude oil, our gathering of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the FERC, the FTC, and/or the CFTC.  These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties.  Should we violate the anti-market manipulation

11

Table of Contents

laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

The FERC has issued certain market transparency rules for the natural gas industry pursuant to its EP Act 2005 authority, which may affect some or all of our operations.  The FERC issued a final rule in 2007, as amended by subsequent orders on rehearing (“Order 704”), which requires wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including natural gas producers, gatherers, processors and marketers, to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices, as explained in Order 704. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704.

Gathering regulations.   Section 1(b) of the federal Natural Gas Act (“NGA”) exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA.  We own certain natural gas pipelines that we believe meet the traditional tests that the FERC has used to establish a pipeline’s status as a gatherer not subject to the FERC jurisdiction.  The distinction between the FERC-regulated transmission facilities and federally unregulated gathering facilities is, however, the subject of substantial, on-going litigation, so the classification and regulation of our gathering lines may be subject to change based on future determinations by the FERC, the courts, or the United States Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation.  Our gathering operations are also subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another.  The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas.  In addition, our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner materially differently than other companies in our areas of operation.

Environmental Matters

Our operations pertaining to oil and gas exploration, production and related activities are subject to numerous and constantly changing federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection.  These laws and regulations may require the acquisition of certain permits prior to commencing certain activities or in connection with our operations; restrict or prohibit the types, quantities and concentration of substances that we can release into the environment; restrict or prohibit activities that could impact wetlands, endangered or threatened species or other protected areas or natural resources; require some degree of remedial action to mitigate pollution from former operations, such as pit cleanups and plugging abandoned wells; and impose substantial liabilities for pollution resulting from our operations.  Such laws and regulations may substantially increase the cost of our operations and may prevent or delay the commencement or continuation of a given project and thus generally could have an adverse effect upon our capital expenditures, earnings or competitive position.  Violation of these laws and regulations could result in significant fines or penalties.  We have experienced accidental spills, leaks and other discharges of contaminants at some of our properties, as have other similarly situated oil and gas companies, and some of the properties that we have acquired, operated or sold, or in which we may hold an interest but not operational control, may have past or ongoing contamination for which we may be held responsible.  Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas.  Some of our properties are located in areas particularly susceptible to hurricanes and other destructive storms, which may damage facilities and cause the release of pollutants. Our environmental insurance coverage may not fully insure all of these risks. Although the costs of remedying such conditions may be significant, we do not believe these costs would have a material adverse impact on our financial condition and operations.

We believe that we are in substantial compliance with current applicable environmental laws and regulations, and the cost of compliance with such laws and regulations has not been material and is not expected to be material during 2012.  We do not believe that we will be required to incur material capital expenditures to comply with existing environmental requirements.  Nevertheless, changes in existing environmental laws and regulations or in the interpretations thereof could have a significant impact on our operations, as well as the oil and gas industry in general.  For instance, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or clean-up requirements could have an adverse impact on our operations.

12

Table of Contents

Hazardous Substances.   The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain 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 or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred.  Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  We are able to control directly the operation of only those wells with respect to which we act as operator.  Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us.  We are not aware of any liabilities for which we may be held responsible that would materially and adversely affect us.

Waste Handling.   The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid wastes.  RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes.  However, these wastes may be regulated by the U.S. Environmental Protection Agency (“EPA”) or state agencies as solid wastes.  Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes.  Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

Air Emissions.   The federal Clean Air Act and comparable state laws and regulations impose restrictions on emissions of air pollutants from various industrial sources, including compressor stations and natural gas processing facilities, and also impose various monitoring and reporting requirements.  Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limits, or utilize specific emission control technologies to limit emissions.  The EPA is currently considering adopting rules that would apply new air emission control standards to well completion activities and certain production equipment, such as glycol dehydrators and storage vessels, which could become effective in the Spring of 2012.  Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions.  Capital expenditures for air pollution equipment may be required in connection with maintaining or obtaining operating permits and approvals relating to air emissions at facilities owned or operated by us. We do not believe that our operations will be materially adversely affected by any such requirements.

Water Discharges.   The Federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.  In addition, the United States Oil Pollution Act of 1990 (“OPA”) and similar legislation enacted in Texas, Louisiana and other coastal states impose oil spill prevention and control requirements and significantly expand liability for damages resulting from oil spills.  OPA imposes strict and, with limited exceptions, joint and several liabilities upon each responsible party for oil spill response and removal costs and a variety of public and private damages.

Global Warming and Climate Change.   In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes.  Based on these findings, the EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011.  The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules.  The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring after January 2011.

13

Table of Contents

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

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

Hydraulic Fracturing.  Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.  We commonly use hydraulic fracturing as part of our operations.  Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel.  In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process.  At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices.  The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices.  The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014.  Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014.  Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing.  These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Endangered species.   The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species.  Some of our well drilling operations are conducted in areas where protected species are known to exist.  In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species.  It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected

14

Table of Contents

species.  The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas.

Pipeline Safety.  Some of our pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Pipeline Safety Improvement Act of 2002, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, and further amended by the Pipeline Safety, Regulation Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act amendments”). The DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGLs, oil and condensate transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined to include areas with specified population densities, buildings containing populations with limited mobility, areas where people may gather along the route of a pipeline (such as athletic fields or campgrounds), environmentally sensitive areas, and commercially navigable waterways. Under the DOT’s regulations, integrity management programs are required to include baseline assessments to identify potential threats to each pipeline segment, implementation of mitigation measures to reduce the risk of pipeline failure, periodic reassessments, reporting and recordkeeping.  These regulatory requirements may be expanded in the future upon completion of studies required by the 2011 Pipeline Safety Act amendments.

OSHA and Other Laws and Regulations.  We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Claims are sometimes made or threatened against companies engaged in oil and gas exploration, production and related activities by owners of surface estates, adjoining properties or others alleging damages resulting from environmental contamination and other incidents of operations. We have been named as a defendant in a number of such lawsuits. While some jurisdictions in which we operate limit damages in such cases to the value of land that has been impaired, in other jurisdictions in which we operate, courts have allowed damage claims in excess of land value, including claims for the cost of remediation of contaminated properties. However, we do not believe that resolution of these claims will have a material adverse impact on our financial condition and operations.

Title to Properties

As is customary in the oil and gas industry, we perform a minimal title investigation before acquiring undeveloped properties.  A title opinion is obtained prior to the commencement of drilling operations on such properties.  We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry.  These title investigations and title opinions, while consistent with industry standards, may not reveal existing or potential title defects, encumbrances or adverse claims as we are subject from time to time to claims or disputes regarding title to properties.  Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. Substantially all of our oil and gas properties are currently mortgaged to secure borrowings under our revolving credit facility and may be mortgaged under any future credit facilities entered into by us.

Operational Hazards and Insurance

Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks.  These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation.  In addition, the presence of unanticipated pressures or irregularities in formations, miscalculations, or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment.

We maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry.  We believe the coverage and types of insurance are adequate.  The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations.  We cannot give any assurances that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

15

Table of Contents

Operating Segments

For financial information about our operating segments, see Note 15 to the accompanying consolidated financial statements.

Executive Officers

The following is a list, as of March 5, 2012 of the name, age and position with the Company of each person who is an executive officer of the Company:

CLAYTON W. WILLIAMS, JR., age 80, is Chairman of the Board, President, Chief Executive Officer and a director of the Company, having served in such capacities since September 1991.  For more than the past five years, Mr. Williams has also been the chief executive officer and a director of certain entities that are controlled directly or indirectly by Mr. Williams.  Mr. Williams beneficially owns, either individually or through his affiliates, approximately 26% of the outstanding shares of our Common Stock.

MEL G. RIGGS, age 57, is Executive Vice President and Chief Operating Officer of the Company, having served in such capacities since January 2011.  Prior to that, Mr. Riggs had served as Senior Vice President - Finance and Chief Financial Officer of the Company since 1991.  Mr. Riggs has also served as a director of the Company since May 1994.

MICHAEL L. POLLARD, age 61, is Senior Vice President — Finance and Chief Financial Officer of the Company, having served in such capacity since January 2011.  Prior to that, Mr. Pollard had served as Vice President - Accounting of the Company since 2003.

PATRICK C. REESBY, age 59, is Vice President — New Ventures of the Company, having served in such capacity since 1993.

ROBERT C. LYON, age 75, is Vice President — Gas Gathering and Marketing of the Company, having served in such capacity since 1993.

T. MARK TISDALE, age 55, is Vice President and General Counsel of the Company, having served in such capacity since 1993.

GREGORY S. WELBORN, age 38, is Vice President — Land of the Company, having served in such capacity since 2006.  Prior to that, Mr. Welborn was self-employed.  Mr. Welborn is the son-in-law of Clayton W. Williams, Jr.

ROBERT L. THOMAS, age 55, is Vice President — Accounting of the Company, having served in such capacity since January 2011.  Prior to that, Mr. Thomas had served as General Accounting Manager of the Company since 2003.

Employees

At December 31, 2011, we had 505 full-time employees, of which 275 were employed by Desta Drilling.  None of our employees are subject to a collective bargaining agreement.  In our opinion, relations with employees are good.

Website Address

We maintain an internet website at www.claytonwilliams.com.  We make available, free of charge, on our website, our annual reports 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.  The information contained in or incorporated in our website is not part of this report.

Item 1A -       Risk Factors

There are many factors that affect our business, some of which are beyond our control.  Our business, financial condition and results of operations could be materially adversely affected by any of these risks.  The nature of our business activities further subjects us to certain hazards and risks.  The risks described below are a summary of some of the material risks relating to our business.  Other risks are described in “ Item 1 - Business ” and “ Item 7A - Quantitative and Qualitative Disclosures About Market Risks . ”   Additional risks not presently known to us or that we currently deem immaterial individually or in the aggregate may also impair our business operations.  If any of these risks actually occur, it could materially harm our business, financial condition or results of operations and impair our ability to implement business plans or complete development projects as scheduled.  In that case, the market price of our Common Stock could decline.

16

Table of Contents

Oil and natural gas prices are volatile. Declines in commodity prices have adversely affected, and in the future may adversely affect, our financial condition, liquidity, results of operations, cash flows, access to the capital markets, and ability to grow.

Our revenues, operating results, liquidity, cash flows, profitability and value of proved reserves depend substantially upon the market prices of oil and natural gas.  Commodity prices affect our cash flow available for capital expenditures and our ability to access funds under our revolving credit facility and through the capital markets.  The amount available for borrowing under our revolving credit facility is subject to a borrowing base, which is determined at least semi-annually by our lenders taking into account the estimated value of our proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time.  Declines in commodity prices have historically adversely affected the estimated value of our proved reserves and, in turn, the market values used by our lenders to determine our borrowing base.  If commodity prices decline in the future, the decline could have adverse effects on our reserves and borrowing base.

The commodity prices we receive for our oil and natural gas depend upon factors beyond our control, including among others:

·                   changes in the supply of and demand for oil and natural gas;

·                   market uncertainty;

·                   the level of consumer product demands;

·                   hurricanes and other weather conditions;

·                   domestic governmental regulations and taxes;

·                   the price and availability of alternative fuels;

·                   political and economic conditions in oil producing countries;

·                   the foreign supply of oil and natural gas;

·                   the price of oil and natural gas imports; and

·                   overall domestic and foreign economic conditions.

These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts.  Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other.

We may not be able to replace production with new reserves.

In general, the volume of production from an oil and gas property declines as reserves related to that property are depleted. The decline rates depend upon reservoir characteristics.  In past years, our oil and gas properties have had steep rates of decline and short estimated productive lives.

Exploring for, developing, or acquiring reserves is capital intensive and uncertain.  We may not be able to economically find, develop, or acquire additional reserves.  Also, we may not be able to make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. We cannot give assurance that our future exploration, development, and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.

We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.

Our business is capital intensive and requires us to spend substantial amounts of capital for exploration and development activities.  If low oil and natural gas prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in

17

Table of Contents

our ability to internally fund our exploration and development activities.  If our borrowing base under the revolving facility is redetermined to a lower amount, this could adversely affect our ability to supplement cash flow from operations as a source of funding for these activities.  After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot give assurance that additional debt or equity financing will be available or cash flows provided by operations will be sufficient to meet our capital expenditures requirements.

We have substantial indebtedness.  Our leverage and the covenants in our debt agreements could negatively impact our financial condition, liquidity, results of operations and business prospects.

As of December 31, 2011, the principal amount of our outstanding consolidated debt was approximately $529.5 million, which included approximately $180 million outstanding under our revolving credit facility and $349.5 million in outstanding principal amount of our 7.75% Senior Notes due 2019 (“2019 Senior Notes”), net of unamortized discount.  Our revolving credit facility and the indenture governing our 2019 Senior Notes (“Indenture”) impose significant restrictions on our ability to take certain actions, including our ability to incur additional indebtedness, sell certain assets, merge, make investments or loans, issue redeemable or preferred stock, pay distributions or dividends, create liens, guarantee other indebtedness and enter into new lines of business.

Our level of indebtedness and the restrictive covenants in our debt agreements could have important consequences on our business and operations.  Among other things, these may:

·                   require us to use a significant portion of our cash flow to pay principal and interest on the debt, which will reduce the amount available to fund working capital, capital expenditures, and other general corporate purposes;

·                   adversely affect the credit ratings assigned by third-party rating agencies, which have in the past and may in the future, downgrade their ratings of our debt and other obligations due to changes in our debt level or our financial condition;

·                   limit our access to the capital markets;

·                   increase our borrowing costs and impact the terms, conditions and restrictions contained in our debt agreements, including the addition of more restrictive covenants;

·                   limit our flexibility in planning for and reacting to changes in our business as covenants and restrictions contained in our existing and possible future debt arrangements may require that we meet certain financial tests and place restrictions on the incurrence of additional indebtedness;

·                   place us at a disadvantage compared to similar companies in our industry that have less debt; and

·                   make us more vulnerable to economic downturns and adverse developments in our business.

A higher level of debt will increase the risk that we may default on our financial obligations.  Our ability to meet our debt obligations and other expenses will depend on our future performance.  Our future performance will be affected by oil and gas prices, financial, business, domestic and worldwide economic conditions, governmental and environmental regulations and other factors, many of which we are unable to control.  If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets, or sell shares of our stock on terms that we do not find attractive, if it can be done at all.

The credit risk of financial institutions could adversely affect us.

The credit risk of financial institutions could adversely affect us.  We have entered into transactions with counterparties in the financial services industry, including commercial banks, insurance companies, and their affiliates.  These transactions expose us to credit risk in the event of default of our counterparty, principally with respect to hedging agreements but also insurance contracts and bank lending commitments.  Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us.

18

Table of Contents

Our hedging transactions could result in financial losses or could reduce our income.  To the extent we have hedged a significant portion of our expected production and actual production is lower than we expected or the costs of goods and services increase, our profitability would be adversely affected.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we have entered into and may in the future enter into hedging transactions for a significant portion of our expected oil and gas production.  These transactions could result in both realized and unrealized hedging losses.

The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities.  For example, the derivative instruments we utilize are primarily based on New York Mercantile Exchange (“NYMEX”) futures prices, which may differ significantly from the actual crude oil and gas prices we realize in our operations.  Furthermore, we have adopted a policy that requires, and our credit facility also mandates, that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we will continue to have direct commodity price exposure on the portion of our production volumes not covered by these derivative transactions.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions.  If our actual future production is higher than we estimated, we will have greater commodity price exposure than we intended. If our future actual production is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution in our profitability and liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

In addition, our hedging transactions are subject to the following risks:

·                   we may be limited in receiving the full benefit of increases in oil and gas prices as a result of these transactions;

·                   a counterparty may not perform its obligation under the applicable derivative instrument or seek bankruptcy protection;

·                   there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

·                   the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

Our proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of our oil and gas reserves, and our revenue, profitability and cash flow to be materially different from our estimates.

The accuracy of estimated proved reserves and estimated future net cash flows from such reserves is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, and other matters.  Although we believe that our estimated proved reserves represent reserves that we are reasonably certain to recover, actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates used to determine proved reserves.  Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn could adversely affect our cash flow, results of operations and the availability of capital resources.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.  Downward adjustments to our estimated proved reserves could require us to impair the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders’ equity.

The present value of proved reserves will not necessarily equal the current fair market value of our estimated oil and gas reserves.  In accordance with the new reserve reporting requirements of the SEC, we are required to establish economic production for reserves on an average historical price.  Actual future prices and costs may be materially higher or lower than those required by the SEC.  The timing of both the production and expenses with respect to the

19

Table of Contents

development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value.

The estimated proved reserve information is based upon reserve reports prepared by independent engineers.  From time to time, estimates of our reserves are also made by the lenders under our revolving credit facility in establishing the borrowing base under the credit facility and by our engineers for use in developing business plans and making various decisions.  Such estimates may vary significantly from those of the independent engineers and have a material effect upon our business decisions and available capital resources.

Our producing properties are largely concentrated in two major geographic areas, the Permian Basin in West Texas and Southeastern New Mexico and the Giddings Area in East Central Texas. Concentrations of reserves in limited geographic areas may disproportionately expose us to operational, regulatory and geological risks.

Our core producing properties are geographically concentrated in the Permian Basin of West Texas and Southeastern New Mexico and the Giddings Area in East Central Texas.  As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, or interruption of the processing or transportation of oil, natural gas or natural gas liquids.

In addition, a significant portion of our proved reserves in the Permian Basin are derived from the Wolfberry play in Andrews County, Texas and the Austin Chalk formation in the Giddings Area.  This concentration of assets within a few producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

Our proved undeveloped locations are scheduled to be drilled over several years, subjecting us to uncertainties that could materially alter the occurrence or timing of our drilling activities.

We have assigned proved undeveloped reserves to certain of our drilling locations as an estimation of our future multi-year development activities on our existing acreage.  These identified locations represent a significant part of our growth strategy. At December 31, 2011, our estimated proved undeveloped reserves were 39% of total estimated proved reserves.  Our ability to drill and develop these locations depends on a number of uncertainties, including (1) our ability to timely drill wells on lands subject to complex development terms and circumstances; (2) the availability of capital, equipment, services and personnel; (3) seasonal conditions; (4) regulatory and third-party approvals; (5) oil and natural gas prices; and (6) drilling and recompletion costs and results. Because of these uncertainties, we may defer drilling on, or never drill, some or all of these potential locations.  If we defer drilling more than five years from the date proved undeveloped reserves were first assigned to a drilling location, we may be required under SEC guidelines to downgrade the category of the applicable reserves from proved undeveloped to probable.  Any reclassification of reserves from proved to unproved could reduce our ability to borrow money and could reduce the value of our debt and equity securities.

Price declines may result in impairments of our asset carrying values.

Commodity prices have a significant impact on the present value of our proved reserves.  Accounting rules require us to impair, as a non-cash charge to earnings, the carrying value of our oil and gas properties in certain situations.  We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets.  To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable, and an impairment may be required.  Any impairment charges we record in the future could have a material adverse effect on our results of operations in the period incurred.

Our exploration activities subject us to greater risks than development activities.

Generally, our oil and gas exploration activities pose a higher economic risk to us than our development activities. Exploration activities involve the drilling of wells in areas where there is little or no known production. Development activities relate to increasing oil or natural gas production from an area that is known to be productive by drilling additional wells, working over and recompleting existing wells and other production enhancement techniques. Exploration projects are identified through subjective analysis of geological and geophysical data, including the use of 3-D seismic and other available technology. By comparison, the identification of development prospects is significantly based upon existing production surrounding or adjacent to the proposed drilling site.

20

Table of Contents

To the extent we engage in exploration activities, we have a greater risk of drilling dry holes or not finding oil and natural gas that can be produced economically. The seismic data and other technology we use does not allow us to know with certainty prior to drilling a well whether oil or natural gas is present or can be produced economically.  We cannot assure you that any of our future exploration efforts will be successful. If these activities are unsuccessful, it will have a significant adverse affect on our results of operations, cash flow and capital resources.

Drilling oil and natural gas wells is a high-risk activity and subjects us to a variety of factors that we cannot control.

Drilling oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive oil or natural gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment. In addition, we often are uncertain as to the future cost or timing of drilling, completing and operating wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

·                   unexpected drilling conditions;

·                   title problems;

·                   pressure or irregularities in formations;

·                   equipment failures or accidents;

·                   adverse weather conditions;

·                   compliance with environmental and other governmental requirements, which may increase our costs or restrict our activities; and

·                   costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment and services.

Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult to integrate into our business.

Our on-going business strategy includes growing our reserves and drilling inventory through acquisitions.  Acquired properties can be subject to significant unknown liabilities. Prior to completing an acquisition, it is generally not feasible to conduct a detailed review of each individual property to be acquired in an acquisition.  Even a detailed review or inspection of each property may not reveal all existing or potential liabilities associated with owning or operating the property. Moreover, some potential liabilities, such as environmental liabilities related to groundwater contamination, may not be discovered even when a review or inspection is performed.

Our initial reserve estimates for acquired properties may be inaccurate. Downward adjustments to our estimated proved reserves, including reserves added through acquisitions, could require us to write-down the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders’ equity.

Our failure to integrate acquired properties successfully into our existing business could result in our incurring unanticipated expenses and losses.  In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions.  The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

The process of integrating acquired properties into our existing business may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of our existing business.

21

Table of Contents

We may not be insured against all of the operating hazards to which our business is exposed.

Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as windstorms, lightning strikes, blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids (including fluids used in hydraulic fracturing activities), fires, severe weather and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations, all of which could result in a substantial loss. We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot give assurance of the continued availability of insurance at premium levels that justify its purchase.

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

The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. 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, maintenance and repair and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

Future shortages of available drilling rigs, equipment and personnel may delay or restrict our operations.

The oil and natural gas industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies and personnel. During these periods, the costs and delivery times of drilling rigs, equipment and supplies are substantially greater. In addition, demand for, and wage rates of, qualified drilling rig crews rise with increases in the number of active rigs in service. Shortages of drilling rigs, equipment, supplies or personnel may increase drilling costs or delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

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

Market conditions or the unavailability of satisfactory oil and natural gas processing or transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas, the proximity of reserves to pipelines and terminal facilities, competition for such facilities and the inability of such facilities to gather, transport or process our production due to shutdowns or curtailments arising from mechanical, operational or weather related matters, including hurricanes and other severe weather conditions. Our ability to market our production depends in substantial part on the availability and capacity of gathering and transportation systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could adversely effect our business, financial condition and results of operations. We may be required to shut-in or otherwise curtail production from wells due to lack of a market or inadequacy or unavailability of oil, natural gas liquids or natural gas pipeline or gathering, transportation or processing capacity. If that were to occur, then we would be unable to realize revenue from those wells until suitable arrangements were made to market our production.

Because we have no current plans to pay dividends on our Common Stock, investors must look solely to stock appreciation for a return on their investment in us.

We have never paid any cash dividends on our Common Stock and our Board does not currently anticipate paying any cash dividends to our stockholders in the foreseeable future.  We currently intend to retain all future earnings to fund the development and growth of our business.  Any payment of future dividends will be at the discretion of our Board 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 deems relevant.  Covenants contained in our revolving credit facility and the Indenture restrict the payment of dividends.  Investors must rely on sales of their Common Stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our Common Stock.

22

Table of Contents

Our industry is highly competitive.

Competition in all areas of our operations is intense. We experience competition from major and independent oil and gas companies and oil and gas syndicates in bidding for desirable oil and gas properties, as well as in acquiring the equipment, data and labor required to operate and develop such properties. A number of our competitors have financial resources and acquisition, exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete with these companies. Competitors may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to increase reserves in the future will depend on our success at selecting and acquiring suitable producing properties and prospects for future development and exploration activities.

In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenue.

The market for our oil, gas and natural gas liquids production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and natural gas liquids, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.

Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.

Our success is highly dependent on our senior management.  The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel is intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected.

We are primarily controlled by Clayton W. Williams, Jr. and his children’s limited partnership.

Clayton W. Williams, Jr. beneficially owns, either individually or through his affiliates, approximately 26% of the outstanding shares of our Common Stock. Mr. Williams is also our Chairman of the Board, President and Chief Executive Officer.  As a result, Mr. Williams has significant influence in matters voted on by our shareholders, including the election of our Board members, and in all other facets of our business, including both our business strategy and daily operations.

WCPL, a limited partnership in which Mr. Williams’ adult children are the limited partners, owns an additional 25% of the outstanding shares of our Common Stock.  Mel G. Riggs, our Executive Vice President and Chief Operating Officer, is the sole general partner of WCPL and has the power to vote or direct the voting of the shares held by WCPL.  In voting these shares, Mr. Riggs will not be acting in his capacity as an officer and director of the Company and will consider the interests of WCPL and Mr. Williams’ children.  They may have interests that differ from the interests of our other shareholders.

The retirement, incapacity or death of Mr. Williams, or any change in the power to vote shares beneficially owned by Mr. Williams or held by WCPL, could result in negative market or industry perception and could have a material adverse effect on our business.

By extending credit to our customers, we are exposed to potential economic loss.

We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties. As appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. We cannot give assurance that we will not suffer any economic loss related to credit risks in the future.

Compliance with laws and regulations governing our activities could be costly and could negatively impact production.

Our oil and gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in

23

Table of Contents

substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.

All of the states in which we operate generally require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain states also limit the rate at which oil and gas can be produced from our properties.

The FERC regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance our ability to market and transport our gas, although it may also subject us to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

Our sales of oil and natural gas liquids are not presently regulated and are made at market prices.  The price we receive from the sale of those products is affected by the cost of transporting the products to market. The FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rate to inflation, subject to certain conditions and limitations. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.

Under the EP Act 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our natural gas operations have not been regulated by the FERC under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional entities to FERC annual reporting.  Additional rules and legislation pertaining to those and other matters may be considered or adopted by the FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

Our oil and gas exploration and production, and related activities are subject to extensive environmental regulations, and to laws that can give rise to substantial liabilities from environmental contamination.

Our operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances.  Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate.  Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws.  Under a number of environmental laws, such liabilities may also be joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share.  Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.

We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future.  Failure to comply with extensive applicable environmental laws and regulations could result in significant civil or criminal penalties and remediation costs, as well as the issuance of administrative or judicial orders limiting operations or prohibiting certain activities.  Some of our properties, including properties in which we have an ownership interest but no operating control, may be affected by environmental contamination that may require investigation or remediation.  Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas.  Some of our operations are in areas particularly susceptible to damage by hurricanes or other destructive storms, which could result in damage to facilities and discharge of pollutants.  In addition, claims are sometimes made or threatened against companies engaged in oil

24

Table of Contents

and gas exploration and production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation, and such claims have been asserted against us as well as companies we have acquired.  Compliance with, and liabilities for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our business, financial condition and results of operations.

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

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies.  These changes include, but are not limited to (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures.  It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective.  The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact the value of an investment in our Common Stock.

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

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011.  The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules.  The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring after January 1, 2011.

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

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

Derivatives legislation enacted by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of risks associated with our business.

The U.S. Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.  The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010 and requires the CFTC and the SEC to promulgate rules and regulations

25

Table of Contents

implementing the new legislation within 360 days from the date of enactment.  In its rulemaking under the Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents.  Certain bona fide hedging transactions or positions would be exempt from these position limits.  It is not possible at this time to predict when the CFTC will finalize these regulations.  The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivatives activities, although the application of those provisions to us is uncertain at this time.  The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.  The new legislation and any new regulations could significantly increase the cost of derivatives contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties.  If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.  Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas.  Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.  Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.  We commonly use hydraulic fracturing as part of our operations.  Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel.  In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process.  At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices.  The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices.  The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014.  Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014.  Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing.  These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

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

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from various sources for use in our operations. During 2011, West Texas and Southeastern New Mexico experienced the lowest inflows of water in recent history. As a result of this severe drought, some local water districts may begin restricting the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we

26

Table of Contents

may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

A terrorist attack, anti-terrorist efforts or other armed conflict could adversely affect our business by decreasing our revenues and increasing our costs.

A terrorist attack, anti-terrorist efforts or other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a decrease in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of oil and natural gas production are destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Recently proposed rules regulating air emissions from oil and gas operations could cause us to incur increased capital expenditures and operating costs

On July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations.  Specifically, the EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities.  The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process.  The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment.  In addition, the rules would establish new leak detection requirements for natural gas processing plants.  The EPA is currently considering public comments submitted on the proposed rules and has indicated that it expects to take final action on the proposed rules by April 3, 2012.  If finalized, these rules could require a number of modifications to our operations including the installation of new equipment.  Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely affect our business.

Item 1B -                     Unresolved Staff Comments

Not applicable.

Item 2 -                              Properties

Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped.  At December 31, 2011, we had interests in 6,830 gross (1,098.9 net) oil and gas wells and owned leasehold interests in approximately 775,000 gross (387,000 net) undeveloped acres.

Reserves

The following table sets forth our estimated quantities of proved reserves as of December 31, 2011, all of which are located within the United States.

(a)          None of our oil and gas reserves are derived from non-traditional sources.

(b)          Oil reserves include crude oil, condensate and natural gas liquids.

(c)           Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil.

27

Table of Contents

The present value of future net cash flows from proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10% (“PV-10 Value”), totaled $1.4 billion at December 31, 2011.  The commodity prices used to estimate proved reserves and their related PV-10 Value at December 31, 2011 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from January 2011 through December 2011.  The benchmark averages for 2011 were $96.19 per barrel of oil and NGL and $4.12 per MMBtu of natural gas.  These benchmark average prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $87.61 per barrel of oil and NGL and $5.31 per Mcf of natural gas over the remaining life of our proved reserves.  Operating costs were not escalated.

PV-10 Value is not a generally accepted accounting principle (“GAAP”) financial measure, but we believe it is useful as a supplemental disclosure to the standardized measure of discounted future net cash flows presented in our consolidated financial statements.  To compute our standardized measure of discounted future net cash flows at December 31, 2011, we began with the PV-10 Value of our proved reserves and deducted the present value of estimated future income taxes of $407.4 million and net abandonment costs of $29.5 million, discounted at 10%.  At December 31, 2011, our standardized measure of discounted future net cash flows totaled $938.5 million.  While the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each company, the PV-10 value of proved reserves is based on prices and discount factors that are consistent for all companies and can be used within the industry and by securities analysts to evaluate proved reserves on a more comparable basis.

The following table summarizes certain information as of December 31, 2011 regarding our estimated proved reserves in each of our principal producing areas.

(a)                Oil reserves include crude oil, condensate and natural gas liquids.

(b)                Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil.

The following table summarizes changes in our estimated proved reserves during 2011.

Extensions and discoveries.   Extensions and discoveries in 2011 added 20,881 MBOE of proved reserves, replacing 384% of our 2011 production.  These additions resulted primarily from our Reeves County and Andrews County drilling programs in the Permian Basin.  Of the total reserve additions, proved developed reserves accounted for 7,243 MBOE, while the remaining 13,638 MBOE were proved undeveloped reserves.

28

Table of Contents

Revisions.  Net downward revisions of 2,007 MBOE consisted of downward revisions of 6,979 MBOE related to performance and upward revisions of 4,972 MBOE related to pricing.  Upward revisions of 4,972 MBOE were attributable to the effects of higher product prices on the estimated quantities of proved reserves.  Downward performance revisions related primarily to the Permian Basin and included the reclassification of 1,190 MBOE of Permian Basin reserves from proved undeveloped to probable.

Sales of minerals-in-place.  In December 2011, we sold our interests in certain properties located in South Louisiana resulting in a decrease of 156 MBOE.

The following table summarizes changes in our estimated proved undeveloped reserves during 2011.

We added 13,638 MBOE of proved undeveloped reserves from extensions and discoveries related to Permian Basin and Giddings Area drilling locations, including 2,132 MBOE of upgrades from probable to proved undeveloped.  Downward revisions of 1,463 MBOE resulted primarily from the reclassification of 1,190 MBOE of Permian Basin reserves from undeveloped to probable in accordance with SEC standards that require proved undeveloped reserves to be developed within five years from their date or origin. We also converted 3,683 MBOE of proved undeveloped reserves at December 31, 2011 to proved developed reserves during 2011 at a cost of approximately $68.6 million.  We expect to develop approximately 63% of our proved undeveloped reserves in 2012 at a cost of approximately $175.5 million.

Alternative Pricing Cases

In addition to the estimated proved reserves disclosed above in accordance with the commodities pricing required by the new reserves rule (“SEC Case”), the following table compares certain information regarding our SEC proved reserves to a Futures Pricing Case.

(a)                Oil reserves include crude oil, condensate and natural gas liquids.

(b)                Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil.

Futures Pricing Case.  The Futures Pricing Case discloses our estimated proved reserves using future market-based commodities prices instead of the average historical prices used in the SEC Case.  Under the Futures Pricing Case, we used futures prices, as quoted on the NYMEX on December 31, 2011, as benchmark prices for 2012 through 2016, and continued to use the 2016 futures price for all subsequent years.  These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $83.69 per Bbl of oil and NGLs and $5.83 per Mcf of natural gas over the remaining life of the proved reserves.

Reserve Estimation Procedures

Overview

We have established a system of internal controls over our reserve estimation process, which we believe provides us reasonable assurance that reserve estimates have been prepared in accordance with SEC and Financial Accounting Standards Board (“FASB”) standards.  These controls include oversight by trained technical personnel

29

Table of Contents

employed by us and by the use of qualified independent petroleum engineers to evaluate our proved reserves on an annual basis.  Substantially all of our estimated proved reserves as of December 31, 2011 were derived from engineering evaluation reports prepared by Williamson Petroleum Consultants, Inc. (“Williamson”) and Ryder Scott Company, L.P. (“Ryder Scott”).  Of our total SEC Case estimated proved reserves, Williamson evaluated 70.5% and Ryder Scott evaluated 29.2% on a BOE basis.

Qualifications of Technical Manager and Consultants

Ron D. Gasser, our Engineering Manager, is the person within our Company who is primarily responsible for overseeing the preparation of the reserve estimates.  Mr. Gasser joined our Company in 2002 as a Senior Engineer working on acquisitions/divestitures and special projects and was promoted to his current position as Engineering Manager in 2006.  Mr. Gasser has 29 years experience as a petroleum engineer, including 26 years directly involved in the estimation and evaluation of oil and gas reserves.  Mr. Gasser holds a Bachelor of Science degree in Petroleum Engineering from Texas Tech University.  He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers.

Williamson is an independent petroleum engineering consulting firm registered in the State of Texas, and John D. Savage, Executive Vice President — Engineering Manager of Williamson, is the technical person primarily responsible for evaluating the proved reserves covered by their report.  Mr. Savage has 30 years experience in evaluating oil and gas reserves, including 28 years experience as a consulting reservoir engineer.  Mr. Savage holds a Bachelor of Science degree in Petroleum Engineering from Texas A&M University.  He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers and the Society of Independent Professional Earth Scientists.

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years.  William K. Fry, Vice President of Ryder Scott, is the technical person primarily responsible for evaluating the proved reserves covered by their report.  Mr. Fry has over 30 years of experience in the estimation and evaluation of petroleum reserves.  Mr. Fry holds a Bachelor of Science degree in Mechanical Engineering from Kansas State University.  He is a Registered Professional Engineer in the State of Texas.

Technology Used to Establish Proved Reserves

Under current SEC standards, 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 proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.  Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has 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 employ technologies that have been demonstrated to yield results with consistency and repeatability.  The technological data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data.  Generally, oil and gas reserves are estimated using, as appropriate, one or more of these available methods: production decline curve analysis, analogy to similar reservoirs or volumetric calculations.  Reserves attributable to producing wells with sufficient production history are estimated using appropriate decline curves or other performance relationships.  Reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technological data to assess the reservoir continuity.  In some instances, particularly in connection with exploratory discoveries, analogous performance data is not available, requiring us to rely primarily on volumetric calculations to determine reserve quantities.  Volumetric calculations are primarily based on data derived from geologic-based seismic interpretation, open-hole logs and completion flow data.  When using production decline curve analysis or analogy to estimate proved reserves, we limit our estimates to the quantities of oil and gas derived through volumetric calculations.

About 98% of our additions to proved reserves in 2011 were derived from wells drilled in the Permian Basin and the Giddings Area.  A significant amount of technological data is available in these areas, which allows us to estimate with reasonable certainty the proved reserves and production decline rates attributable to most of our reserve additions through analogy to historical performance from wells in the same reservoirs.  None of our

30

Table of Contents

additions to proved reserves for 2011 were estimated solely on volumetric calculations.

Processes and Controls

Mr. Gasser and his engineering staff maintain a reserves database covering substantially all of our oil and gas properties utilizing Aries TM , a widely-used reserves and economics software package licensed by a unit of Halliburton Company.  Some of our properties are not evaluated since they are individually and collectively insignificant to our total proved reserves and related PV-10 Value.  Our engineering staff assimilates all technological and operational data necessary to evaluate our reserves and updates the reserves database throughout the year.  Technological data is described above under “Technology Used to Establish Proved Reserves.”   Operational data includes ownership interests, product prices, operating expenses and future development costs.

Using the most appropriate method available, Mr. Gasser applies his professional judgment, based on his training and experience, to project a production profile for each evaluated property.  Mr. Gasser consults with other engineers and geoscientists within our company as needed to validate the accuracy and completeness of his estimates and to determine if any of the technological data upon which his estimates were based are incorrect or outdated.

The engineering staff consults with our accounting department to validate the accuracy and completeness of certain operational data maintained in the reserves database, including ownership interests, average commodity prices, price differentials, and operating costs.

Although we believe that the estimates of reserves prepared by our engineering staff have been prepared in accordance with professional engineering standards consistent with SEC and FASB guidelines, we engage independent petroleum engineering consultants to prepare annual evaluations of our estimated reserves.  After Mr. Gasser and our engineering staff have made an internal evaluation of our estimated reserves, we provide copies of the Aries TM  reserves database to Ryder Scott as it relates to properties owned by Southwest Royalties, Inc., one of our wholly owned subsidiaries, and to Williamson as it relates to properties owned by CWEI and Warrior Gas Company, another of our wholly owned subsidiaries.  In addition, we provide to the consultants for their analysis all pertinent data needed to properly evaluate our reserves.  The services provided by Williamson and Ryder Scott are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties.  For more information about the evaluations performed by Williamson and Ryder Scott, see copies of their respective reports filed as exhibits to this Form 10-K.

Both Williamson and Ryder Scott use the Aries TM  reserves database which we provide to them as a starting point for their evaluations.  This process reduces the risk of errors that can result from data input and also results in significant cost savings to us.  The petroleum engineering consultants generally rely on the technical and operational data provided to them without independent verification; however, in the course of their evaluation, if any issue comes to their attention that questions the validity or sufficiency of that data, the consultants will not rely on the questionable data until they have resolved the issue to their satisfaction.  The consultants analyze each production decline curve to determine if they agree with our interpretation of the underlying technical data.  If they arrive at a different conclusion, the consultants revise the estimates in the database to reflect their own interpretations.

After Williamson and Ryder Scott complete their respective evaluations, they return a modified Aries TM  reserves database to our engineering staff for review.  Mr. Gasser identifies all material variances between our initial estimates and those of the consultants and discusses the variances with Williamson or Ryder Scott, as applicable, in order to resolve the discrepancies.  If any variances relate to inaccurate or incomplete data, corrected or additional data is provided to the consultants and the related estimates are revised.  When variances are caused solely by judgment differences between Mr. Gasser and the consultants, we accept the estimates of the consultants.

The final reserve estimates are then analyzed by our financial accounting group under the direction of Michael L. Pollard, our Senior Vice President and Chief Financial Officer.  The group reconciles changes in reserve estimates during the year by source, consisting of changes due to extensions and discoveries, purchases/sales of mineral-in-place, revisions of previous estimates and production.  Revisions of previous estimates are further analyzed by changes related to pricing and changes related to performance.  All material fluctuations in reserve quantities identified through this analysis are discussed with Mr. Gasser.  Although unlikely, if an error in the estimated reserves is discovered through this review process, Mr. Gasser will submit the facts related to the error to the appropriate consultant for correction prior to the public release of the estimated reserves.

31

Table of Contents

Other Information Concerning our Proved Reserves

The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment.  The estimates of reserves, future cash flows and PV-10 Value are based on various assumptions and are inherently imprecise.  Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.  Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

Since January 1, 2009, we have not filed an estimate of our net proved oil and gas reserves with any federal authority or agency other than the SEC.

Delivery Commitments

As of December 31, 2011, we had no commitments to provide fixed and determinable quantities of oil or natural gas in the near future under contracts or agreements, other than through customary marketing arrangements which require us to nominate estimated volumes of natural gas production for sale during periods of one month or less.

Exploration and Development Activities

We drilled, or participated in the drilling of, the following numbers of wells during the periods indicated.

The information contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately be recovered by us.

32

Table of Contents

Productive Well Summary

The following table sets forth certain information regarding our ownership, as of December 31, 2011, of productive wells in the areas indicated.

Volumes, Prices and Production Costs

All of our oil and gas properties are located in one geographical area, specifically the United States.  The following table sets forth certain information regarding the production volumes of, average sales prices received from, and average production costs associated with all of our sales of oil and gas production for the periods indicated.

(a)                No derivatives were designated as cash flow hedges in the table above.  All gains or losses on settled derivatives were included in other income (expense) - gain (loss) on derivatives.

(b)                Excludes property taxes and severance taxes.

Only two fields, the Giddings field (Austin Chalk) in the Giddings Area and the Spraberry Trend field in the Permian Basin, accounted for 15% or more of our total proved reserves (on a BOE basis) as of December 31, 2011.  The following table discloses our oil, gas and natural gas liquids production from these fields for the periods indicated.

33

Table of Contents

Development, Exploration and Acquisition Expenditures

The following table sets forth certain information regarding the costs we incurred in our development, exploration and acquisition activities during the periods indicated.

Acreage

The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2011 in the areas indicated.  This table excludes options to acquire leases and acreage in which our interest is limited to royalty, overriding royalty and similar interests.