**UNITED STATES**

**SECURITIES AND EXCHANGECOMMISSION**

**Washington, D.C.  20549**

 

**FORM 10-K**

 

**(Mark One)**
| **ý** | **ANNUAL REPORT PURSUANT TO  SECTION 13 OR 15(d)**                                                                                                                                                                           |
|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** ** | **OF THE SECURITIES EXCHANGE ACT  OF 1934**                                                                                                                                                                                  |
|       | **For the fiscal year ended  December 31, 2005**                                                                                                                                                                             |
|       |                                                                                                                                                                                                                         |   |
| **o**      | **TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15(d)**                                                                                                                                                                       |
| ** ** | **OF THE SECURITIES EXCHANGE ACT  OF 1934**                                                                                                                                                                                  |
|       | **For the transition period from                  to                ** |
|       | **Commission File Number  001-10924**                                                                                                                                                                                        |

 

**CLAYTONWILLIAMS ENERGY, INC.**

(Exact name of registrant asspecified in its charter)

 

| **Delaware**                                                    | ** ** | **75-2396863**                        |
|-----------------------------------------------------------------|------------|---------------------------------------|
| (State or other jurisdiction of  incorporation or organization) |       | (I.R.S. Employer Identification  No.) |
| ** **                                                      |       |                                  |
| **Six Desta Drive - Suite 6500**                                |       |                                  |
| **Midland, Texas**                                              | ** ** | **79705-5510**                        |
| (Address of principal executive  offices)                       |       | (Zip code)                            |
|                                                            | ** ** | ** **                            |
| Registrant’s telephone number,  including area code:       | ** ** | **(432) 682-6324**                    |
|                                                            |       |                                  |
| Securities registered pursuant  to Section 12(b) of the Act:    |
| ** **                                                      |       |                                  |
| **None**                                                        |
|                                                            |       |                                  |
| Securities registered pursuant  to Section 12(g) of the Act:    |
|                                                            |       |                                  |
| **Common Stock - $.10 Par Value**                               |
| (Title of Class)                                                |

 

Indicate by checkmark if the registrant is a well-known seasoned issuer, as defined in Rule 405of the Securities Act.o Yes                    ýNo

 

Indicate by check mark ifthe registrant is not required to file reports pursuant to Section 13 orSection 15(d) of the Act.o Yes                    ýNo

 

Indicate by check mark whether the registrant (1) has filed all reportsrequired to be filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that theregistrant was required to file such reports), and (2) has been subject to suchfiling requirements for the past 90 days.

Yes   ý                        Noo

 

Indicate by check mark if disclosure of delinquent filers pursuant toItem 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 informationstatements incorporated by reference in Part III of this Form 10-K or anyamendment to this Form 10-K.     ý

 

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer.  See definition of“accelerated filer and large accelerated filer” in Rule 12b-2 of the ExchangeAct.

 

Large accelerated filer  o                               Acceleratedfiler  ý                             Non-acceleratedfiler  o

 

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

 

State the aggregate market value of the voting andnon-voting common equity held by non-affiliates, computed by reference to theprice at which common equity was last sold, as of the last business day of theregistrant’s most recently completed second fiscal quarter.  $186,312,403.

 

There were 10,848,450 shares of Common Stock, $.10 par value, of theregistrant outstanding as of March 14, 2006.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the definitive proxy statement relating tothe 2006 Annual Meeting of Stockholders, which will be filed with theCommission not later than April 30, 2006, are incorporated by reference in PartIII of this Form 10-K.

 

 

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**CLAYTON WILLIAMS ENERGY, INC**

## **TABLE OF CONTENTS**

 
| **Part I**  | ** **                                                            | ** ** |
|-------------|-----------------------------------------------------------------------|------------|
| Item 1.     | Business                                                              |       |
|        | General                                                               |       |
|        | Company Profile                                                       |       |
|        | Exploration and  Development Activities                               |       |
|        | Marketing  Arrangements                                               |       |
|        | Natural  Gas Services                                                 |       |
|        | Competition  and Markets                                              |       |
|        | Regulation                                                            |       |
|        | Environmental  Matters                                                |       |
|        | Title to  Properties                                                  |       |
|        | Operational Hazards and  Insurance                                    |       |
|        | Executive  Officers                                                   |       |
|        | Employees                                                             |       |
|        | Website Address                                                       |       |
| Item 1A.    | Risk Factors                                                          |       |
| Item 1B.    | Unresolved Staff  Comments                                            |       |
|        |                                                                  |       |
| Item 2.     | Properties                                                            |       |
|        | Reserves                                                              |       |
|        | Exploration and  Development Activities                               |       |
|        | Productive Well Summary                                               |       |
|        | Volumes, Prices and  Production Costs                                 |       |
|        | Development,  Exploration and Acquisition Expenditures                |       |
|        | Acreage                                                               |       |
|        | Offices                                                               |       |
|        |                                                                  |       |
| Item 3.     | Legal Proceedings                                                     |       |
|        |                                                                  |       |
| Item 4.     | Submission of Matters to a  Vote of Security Holders                  |       |
|        |                                                                  |       |
| **Part II** | ** **                                                            | ** ** |
| Item 5.     | Market for the Registrant’s  Common Stock and Related            |       |
|        | Stockholder  Matters                                                  |       |
|        | Price Range of Common Stock                                           |       |
|        | Dividend Policy                                                       |       |
|        | Securities  Authorized for Issuance under Equity Compensation Plans   |       |
|        |                                                                  |       |
| Item 6.     | Selected Financial Data                                               |       |
|        |                                                                  |       |
| Item 7.     | Management’s  Discussion and Analysis of Financial Condition and |       |
|        | Results of  Operations                                                |       |
|        | Overview                                                              |       |
|        | Key Factors to Consider                                               |       |
|        | Recent Exploration  and Developmental Activities                      |       |
|        | Proved Oil  and Gas Reserves                                          |       |

 

1

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|                  | Supplemental Information                                                              |       |
|-----------------------|---------------------------------------------------------------------------------------|------------|
|                  | Operating Results                                                                     |       |
|                  | Liquidity and Capital Resources                                                       |       |
|                  | Known Trends and Uncertainties                                                        |       |
|                  | Application of Critical Accounting Policies and  Estimates                            |       |
|                  | Recent Accounting Pronouncements                                                      |       |
|                  |                                                                                  |       |
| Item 7A.              | Quantitative  and Qualitative Disclosure About Market Risks                           |       |
|                  | Oil and Gas Prices                                                                    |       |
|                  | Interest  Rates                                                                       |       |
|                  |                                                                                  |       |
| Item 8.               | Financial  Statements and Supplementary Data                                          |       |
|                  |                                                                                  |       |
| Item 9.               | Changes  in and Disagreements with Accountants on Accounting and Financial Disclosure |       |
|                  |                                                                                  |       |
| Item 9A.              | Controls and  Procedures                                                              |       |
|                  | Disclosure Controls and Procedures                                                    |       |
|                  | Internal Control Over Financial Reporting                                             |       |
|                  | Changes in Internal Control Over Financial Reporting                                  |       |
|                  | Management’s Report on Internal Control Over Financial  Reporting                |       |
|                  |                                                                                  |       |
| Item 9B.              | Other Information                                                                     |       |
|                  |                                                                                  |       |
| **Part III**          | ** **                                                                            | ** ** |
| Items 10-14.          | Information  Incorporated by Reference                                                |       |
|                  |                                                                                  |       |
| **Part IV**           | ** **                                                                            |       |
| Item 15.              | Exhibits,  Financial Statement Schedules and Reports on Form 8-K                      |       |
|                  | Financial  Statements and Schedules                                                   |       |
|                  | Exhibits                                                                              |       |
|                  |                                                                                  |       |
| **Glossary of Terms** |                                                                                  |
|                  |                                                                                  |       |
| **Signatures**        |                                                                                  |       |

 

2

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**This Annual Report on Form 10-K containsforward-looking statements that are based on management’s currentexpectations.  Forward-looking statementsinclude statements regarding our plans, beliefs or current expectations and maybe signified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”,“anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and othersimilar expressions.  Forward-lookingstatements appear throughout this Form 10-K with respect to, among otherthings: profitability; planned capital expenditures; estimates of oil and gasproduction; future project dates; estimates of future oil and gas prices; estimatesof oil and gas reserves; our future financial condition or results ofoperations; and our business strategy and other plans and objectives for futureoperations.  Actual results in futureperiods may differ materially from those expressed or implied by suchforward-looking statements because of a number of risks and uncertaintiesaffecting our business, including those discussed in “Item 1 – Business – RiskFactors” and elsewhere in this report. We disclaim any intention or obligation to update or revise anyforward-looking statements, whether as a result of new information, futureevents or otherwise.**

** **

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

** **

## **PART I**

 

**Item 1 -**                  Business

 

**General**

 

Clayton Williams Energy, Inc., incorporated in Delaware in 1991, is anindependent oil and gas company engaged in the exploration for and productionof 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 WilliamsEnergy, Inc. and its consolidated subsidiaries. On December 31, 2005, our estimated proved reserves were 293.8Bcfe, of which 75% were proveddeveloped.  We have a balanced portfolioof oil and natural gas reserves, with approximately 43% of our proved reserves at December 31, 2005 consisting ofnatural gas and approximately 57%consisting of oil and natural gas liquids. During 2005, we added proved reserves of 17.7 Bcfe throughextensions and discoveries, had upward revisions of previous estimates of7.8 Bcfe, acquired 4.2 Bcfe through acquisitions and sold 3.5 Bcfe ofreserves in place.  We also achievedaverage net production of 86.1 Mmcfeper day in 2005, which implies a reserve life of approximately 9.3 years.  CWEI held interests in 6,605 gross(899.7 net) producing oil and gas wells and owned leasehold interests inapproximately 1.2 million gross (778,000 net) undeveloped acres atDecember 31, 2005.

 

Clayton W. Williams beneficially owns, either individually orthrough his affiliates, approximately 45% of the outstanding shares of ourcommon stock.  Mr. Williams is alsoour Chairman of the Board and Chief Executive Officer.  As a result, Mr. Williams has significantinfluence in matters voted on by our shareholders, including the election ofour Board members.  Mr. Williamsactively participates in all facets of our business and has a significantimpact on both our business strategy and daily operations.

 

In 2006, we plan to spend approximately $184.1 million onexploration and development activities, of which more than 90% relate toexploratory prospects.  Approximately 78%of these planned expenditures in 2006 have been allocated to exploration anddevelopment activities in Louisiana.

 

3

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**Company Profile**

 

***DomesticOperations***

 

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

 

***ExplorationProgram***

 

Our primary business strategy is to grow our oil and gas reservesthrough exploration activities, consisting of generating exploratory prospects,leasing the acreage applicable to the prospects, drilling exploratory wells onthese prospects to determine if recoverable oil and gas reserves exist,drilling developmental wells on prospects, and producing and selling anyresulting oil and gas production.

 

To generate a typical exploratory prospect, we first identifygeographical areas that we believe may contain undiscovered oil and gasreserves.  We then consider many otherbusiness factors related to those geographical areas, including proximity toour other areas of operations, our technical knowledge and experience in thearea, the availability of acreage, and the overall potential for findingreserves.  Most of our currentexploration efforts are concentrated in regions that have been known to produceoil and gas.  These regions include someof the larger producing regions in Texas and Louisiana.

 

In most cases, we then obtain and process seismic data usingsophisticated geophysical technology to attempt to visualize undergroundstructures and stratigraphic traps that may hold recoverable reserves.  Although this technology increases ourexpectations of a successful discovery, it does not and cannot assure us ofsuccess.  Many factors are involved inthe interpretation of seismic data, including the field recording parameters ofthe data, the type of processing, the extent of attribute analyses, theavailability of subsurface geological data, and the depth and complexity of thesubsurface.  Significant judgment isrequired in the evaluation of seismic data, and differences of opinion oftenexist between experienced professionals. These interpretations may turn out to be invalid and may result inunsuccessful drilling results.

 

Obtaining oil and gas reserves through exploration activities involvesa higher degree of risk than through drilling developmental wells or purchasingproved reserves.  We often commitsignificant resources to identify a prospect, lease the drilling rights anddrill a test well before we know if a well will be productive.  To offset this risk, our typical exploratoryprospect is expected to offer a significantly higher reserve potential than atypical lower-risk development prospect might offer.  The reserve potential is determined byestimating the aerial extent of the structural or stratigraphic trap, thevertical thickness of the reservoir in the trap, and the recovery factor of thehydrocarbons in the trap.  The recoveryfactor is affected by a combination of factors including (i) the reservoirdrive mechanism (water drive, depletion drive or a combination of both),(ii) the permeability and porosity of the reservoir, and (iii) thebottom hole pressure (in the case of gas reserves).

 

Due to the high risk/high reward nature of oil and gas exploration, weexpect to spend money on prospects that are ultimately nonproductive.  However, over time, we believe our productiveprospects will generate sufficient cash flow to provide us with an acceptablerate of return on our entire investment, both nonproductive and productive.

 

We are presently concentrating our exploration efforts in SouthLouisiana, North Louisiana and East Texas. Approximately 90% of our planned expenditures for 2006 relate toexploratory prospects, as compared to approximately 73% of actual expendituresin 2005 and 81% of actual expenditures in 2004. During 2005, we spent $134.6 million on exploratory prospects,including $55.7 million on seismic and leasing activities and $78.9million on drilling activities.

 

4

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***DevelopmentProgram***

 

Complimentary to our higher risk/higher potential exploration program isour development program.  We have aninventory of developmental projects available for drilling in the future.  At December 31, 2005, we had proveddeveloped nonproducing reserves and proved undeveloped reserves of 104.8 Bcfe.  We currently estimate that we will berequired to spend approximately $161.9 million in development costs todevelop these reserves.  Substantiallyall of these reserves are associated with leases that are held by production.  Because current drilling activity is notrequired to maintain these leases, we have decided to limit expenditures on ourdevelopmental program in 2006 in order to preserve more capital resources forour exploratory activities in areas where we have leases that will expireunless commercial production is commenced before the end of their current leaseterms.  We expect to allocate a moresignificant portion of our capital expenditures to development activities in yearsafter 2006.

 

***Acquisitionand Divestitures of Proved Properties***

 

In addition to our exploration and development activities, we are alsoengaged in the business of acquiring proved reserves.  Competition for the purchase of provedreserves is intense.  Sellers oftenutilize a bid process to sell properties. This process usually intensifies the competition and makes it extremelydifficult for us to acquire reserves without assuming significant price andproduction risks.  We are activelysearching for opportunities to acquire proved oil and gas properties; however,because the competition is intense, we cannot give any assurance that we willbe successful in our efforts during 2006.

 

In 2005, we acquired a property in Ward County, Texas which consistedof ten producing wells and eight proved undeveloped locations.  This acquisition added approximately 4.2 Bcfeof proved reserves for a purchase price of $5.6 million.

 

On May 21, 2004, we acquired all the outstanding common stock of SouthwestRoyalties, Inc. (“SWR”) through a merger. Prior to the acquisition, SWR was a privately-held, Midland-based energycompany engaged in oil and gas exploration, production, development andacquisition activities in the United States. Most of SWR’s properties are located in the Permian Basin.  Using reserve guidelines established by theSEC, the SWR acquisition added approximately 170.8 Bcfe to our proved oiland gas reserves on the effective date of the acquisition at an aggregatepurchase price of $274.7 million.

 

From time to time, we decide to sell certain of our provedproperties.  In August 2005, we sold ourinterests in two leases in the Breton Sound area in the Gulf of Mexico(offshore Louisiana) for $21.3 million, subject to post-closing adjustments andrealized a gain of $16.8 million on this sale.  In November 2004, we sold our interest in theJo-Mill Unit in Borden County, Texas for cash proceeds of $22.1 million,subject to normal post-closing adjustments. This property was acquired in connection with the SWR acquisition.  We realized a gain on sale of this propertyof $2.1 million.  In December 2004,we sold substantially all of our interests in the Romere Pass Unit inPlaquemines Parish, Louisiana for cash proceeds of $8.2 million, subjectto normal post-closing adjustments.  Weretained drilling rights to five locations in the unit, of which two are provedundeveloped locations and three are exploratory locations.  We realized a loss of $14.1 million onthe sale of this property.

 

**Explorationand Development Activities**

 

In 2005, we spent $184.1 million on exploration and drillingactivities, which was financed primarily by cash flow from operations and inpart by proceeds from sales of oil and gas properties.  We presently plan to spend approximately$184.1 million on exploration and drilling activities during 2006.  We may increase or decrease our plannedactivities, depending upon drilling results, product prices, the availabilityof capital resources, and other factors affecting the economic viability ofsuch activities.

 

5

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***SouthLouisiana***

 

Since 2000, we have been exploring for oil and gas reserves in SouthLouisiana and have developed this area into one of our key sources ofproduction and cash flow.  Most of theprospects we have generated in South Louisiana have been identified based on 3-Dseismic data and technology and have generally consisted of multi-pay, Miocene-agesands.

 

We spent $41.2 million in South Louisiana during 2005 onexploration and development activities, of which $32.8 million was spenton drilling and completion activities and $8.4 million was spent onseismic and leasing activities.

 

Prior to 2005, we had drilled 47 gross (37.7 net) exploratorywells in South Louisiana, of which 20 gross (14.7 net) were completedas producers.  The following table setsforth certain information about our exploratory well activities in SouthLouisiana in 2005.

 
| **Spud Date** | ** ** | **Well Name (Prospect)** | ** ** | **Working  Interest** | ** ** | **Current  Status**    |
|--------------------|------------|------------------------------------|------------|-----------------------|------------|------------------------|
|               |       |                               |       |                  |       |                   |
| February 2005      |       | State Lease 18065 #1  (Alabama)    |       | 100                   | %          | Producing              |
| July 2005          |       | Ransom #1 (Keck)                   |       | 50                    | %          | Producing              |
| August 2005        |       | State Lease 17636 #1  (Natalie)    |       | 30                    | %          | Dry                    |
| August 2005        |       | LL&E #1 (Andrea)               |       | 70                    | %          | Dry                    |
| November 2005      |       | Miami Corp #1 (Tara)               |       | 100                   | %          | Pending completion     |
| December 2005      |       | State lease 195 QQ #1 (Floyd)      |       | 75                    | %          | Completion in progress |

 

More than half of the wells in our South Louisiana exploration programthat were commenced in 2005 were productive and resulted in the addition ofapproximately 8.7 Bcfe of proved reserves in 2005.  However, the LL&E #1 (Andrea) and theState Lease 17636 #1 (Natalie) were unsuccessful and resulted in aggregateabandonment charges of $10.7 million in 2005.

 

We currently plan to spend $56.3 million in South Louisiana in 2006 togenerate and lease new exploratory prospects and to drill wells on existingexploratory prospects.  We have begun asix-well program on our Floyd prospect in Plaquemines Parish targetingmulti-pay objectives ranging in depths from 3,000 to 13,000 feet.  The State Lease 195 QQ #1 was drilled to atotal depth of 12,981 feet and is currently being completed.  The State Lease 195 QQ #2 has been drilled toa total depth of 6,296 feet and is pending completion.  The State Lease 195 QQ #3 has been drilled toa total depth of 9,170 feet, and is also pending completion.  The State Lease 195 QQ #4 is currentlydrilling**.** Under the terms of a farmout agreement, we bear 100% of the costs onthese wells before casing point to earn a 75% working interest in the drilledacreage.

 

We are currently drilling the Borah #1 (Cypress Isle), a 17,000-footexploratory well in St. Martin Parish targeting the MA-11 and MA-12 sands,in which we own a 75% working interest.

 

***North Louisiana***

 

We have begun an exploration program in North Louisiana targeting theCotton Valley/Hosston and Bossier formations. In this area, the Cotton Valley/Hosston formations are encountered atdepths ranging from 8,000 to 12,000 feet, and the Bossier formation isencountered at depths ranging from 11,000 to 15,500 feet.  We believe that these tight sandstoneformations have become more economically viable due to higher product prices,coupled with enhanced drilling and completion techniques.

 

We spent $18.9 million in North Louisiana during 2005 onexploration activities, of which $16.8 million was spent on seismic andleasing activities and $2.1 million was spent on drilling and completionactivities on non-operated wells.

 

6

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We have accumulated more than 115,000 net acres in this area, and todate have participated in six non-operated wells on a small portion of thisacreage, four of which are currently being completed and two are inprogress.  We are currently drilling theHarris #1, a 14,500-foot well in Jackson Parish targeting the Bossierformation, in which we own a 53% working interest.  We plan to spend approximately $87.9 millionin North Louisiana in 2006, consisting of $17.2 million to acquire leasesand conduct seismic and exploration activities, and $70.7 million on drilling.

 

***East Texas(Bossier)***

 

We have also begun acquiring leases in East Texas targeting the Bossierformation which is encountered at depths ranging from 14,000 to 22,000 feetin this area.  To date, we have acquiredapproximately 28,000 net acres and are actively seeking to add to our acreageposition.  We spent $4.9 million onacreage in East Texas in 2005 and plan to spend approximately $20 millionfor additional acreage in 2006.  Weanticipate drilling activity on this acreage to begin in 2007.

 

***Permian Basin***

 

We spent $84.5 million in the Permian Basin during 2005 onexploration and development activities, of which $74.5 million was spenton drilling and completion activities and $10 million was spent on seismicand leasing activities.

 

In 2005, we initiated an exploration program in West Texas seeking toextend the limits of the Wolfcamp formation that is encountered throughout alarge segment of this region.  Weacquired more than 50,000 net acres and have drilled 11 wells across a wideportion of this acreage.  While all ofthe wells were completed as producers, the oil and gas reserves derived fromthis drilling program were inadequate to recover our capitalized costs.  As a result, we recorded an $18.3 millioncharge for impairment of proved properties and a $1.8 million charge forimpairment of unproved property in 2005 related to our Wolfcamp program.

 

We also drilled the Leoncita #1, a 9,300-foot exploratory well in PecosCounty, Texas targeting the Barnett Shale. This well was unsuccessful and resulted in a $4.5 million charge toexploration costs in 2005.

 

In addition, we drilled 24 gross (20.2 net) wells in thePermian Basin and conducted remedial operations on existing wells in 2005.  While some of the drilling activities in 2005did not result in the quantities of oil and gas reserves that we had expected,the Permian Basin continues to be a significant source of production and cashflow for us.  We currently plan to spend$6.7 million on drilling activities in the Permian Basin in 2006.

 

***Montana/Utah***

 

We spent $11.8 million in Montana and Utah during 2005 on seismicand leasing activities.  We initiated anexploration program in Sheridan County, Montana targeting the Bakken Shalewhich is encountered at depths ranging from 7,000 to 8,000 feet in thisarea.  We are currently drilling theRuegsegger 24H #1, an exploratory well which we plan to drill to avertical depth of 7,600 feet, then drill 3,600 feet horizontallythrough the shale formation.  We plan tospend approximately $3.5 million for drilling in this area in 2006.

 

In addition, we are participating in a joint exploration program withindustry partners in the Overthrust play in central Utah in which we own a 33%interest.  In 2006, we plan to spendapproximately $2.5 million to participate in the drilling of a 14,400-footexploratory well to test this acreage.

 

7

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***OtherExploration and Development Activities***

 

During 2005, we spent $22.8 million on exploration and developmentactivities in other areas, including:

 

•              $8 millionin South Texas to drill the Deer-Hamilton #1 well, a 17,000-foot exploratorywell in Nueces County targeting the Vicksburg formation, which wasunsuccessful;

 

•              $2.2 millionof drilling activities related to the Catherine Destefano #1 well, a 14,600-footexploratory well in Robertson County, Texas targeting the Knowles formation,which was unsuccessful; and

 

•              $3.4million in leasing activities in the Neal Shale prospect in Alabama.

 

In 2006, we currently plan to spend $7.2 million in other areas,including:

 

•              $4.1million for leasing and production enhancement activities in the Austin Chalk(Trend); and

 

•              $3.1million for leasing and drilling activities in Colorado and other areas.

 

**Marketing Arrangements**

 

We sell substantially all of our oil production under short-termcontracts based on prices quoted on the New York Mercantile Exchange (“NYMEX”)for spot West Texas Intermediate contracts, less agreed-upon deductions whichvary by grade of crude oil.  The majorityof our gas production is sold under short-term contracts based on pricingformulas which are generally market responsive. From time to time, we may also sell a portion of our gas productionunder short-term contracts at fixed prices. We believe that the loss of any of our oil and gas purchasers would nothave a material adverse effect on our results of operations due to theavailability of other purchasers.

 

**Natural Gas Services**

 

We own an interest in and operate natural gas service facilities in thestates of Texas, Louisiana, Mississippi and New Mexico. These natural gasservice facilities consist of interests in approximately 94 miles ofpipeline, three treating plants, one dehydration facility, three compressorstations, and four wellhead type treating and/or compression facilities.  Most of our operated gas gathering and treatingactivities exist to facilitate the transportation and marketing of our operatedoil and gas production.

 

**Competition and Markets**

 

Competition in all areas of our operations is intense.  We experience competition from major andindependent oil and gas companies and oil and gas syndicates in bidding fordesirable oil and gas properties, as well as in acquiring the equipment, dataand labor required to operate and develop such properties. A number of ourcompetitors have financial resources and acquisition, exploration anddevelopment budgets that are substantially greater than ours, which mayadversely affect our ability to compete with these companies. Competitors maybe able to pay more for productive oil and gas properties and exploratoryprospects and to define, evaluate, bid for and purchase a greater number ofproperties and prospects than our financial or human resources permit.  Our ability to increase reserves in 

 

8

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the future willdepend on our success at selecting and acquiring suitable producing propertiesand prospects for future development and exploration activities.

 

In addition, the oil and gas industry as a whole also competes withother industries in supplying the energy and fuel requirements of industrial,commercial and individual consumers.  Theprice and availability of alternative energy sources could adversely affect ourrevenue.

 

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

 

**Regulation**

 

Our oil and gas exploration, production and related operations aresubject to extensive rules and regulations promulgated by federal, state andlocal agencies. Failure to comply with such rules and regulations can result insubstantial penalties. The regulatory burden on the oil and gas industryincreases our cost of doing business and affects our profitability. Becausesuch rules and regulations are frequently amended or reinterpreted, we areunable to predict the future cost or impact of complying with such laws.

 

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

 

The Federal Energy Regulatory Commission (“FERC”) regulates interstatenatural gas transportation rates and service conditions, which affect themarketing of gas we produce, as well as the revenues we receive for sales ofsuch production.  Since the mid-1980s,the FERC has issued various orders that have significantly altered themarketing and transportation of gas. These orders resulted in a fundamental restructuring of interstatepipeline sales and transportation services, including the unbundling byinterstate pipelines of the sales, transportation, storage and other componentsof the city-gate sales services such pipelines previously performed.  These FERC actions were designed to increasecompetition within all phases of the gas industry.  The interstate regulatory framework mayenhance our ability to market and transport our gas, although it may alsosubject us to greater competition and to the more restrictive pipelineimbalance tolerances and greater associated penalties for violation of suchtolerances.

 

Our sales of oil and natural gas liquids are not presently regulatedand are made at market prices.  The pricewe receive from the sale of those products is affected by the cost of transportingthe products to market.  The FERC hasimplemented regulations establishing an indexing system for transportationrates 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, theseregulations will have on us, but, other factors being equal, the regulationsmay, over time, tend to increase transportation costs which may have the effectof reducing wellhead prices for oil and natural gas liquids.

 

9

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**Environmental Matters**

 

Our operations pertaining to oil and gas exploration, production andrelated activities are subject to numerous and constantly changing federal,state and local laws governing the discharge of materials into the environmentor otherwise relating to environmental protection.  These laws and regulations may require theacquisition of certain permits prior to or in connection with drillingactivities, restrict or prohibit the types, quantities and concentration ofsubstances that can be released into the environment in connection withdrilling and production, restrict or prohibit drilling activities that couldimpact wetlands, endangered or threatened species or other protected areas ornatural resources, require some degree of remedial action to mitigate pollutionfrom former operations, such as pit cleanups and plugging abandoned wells, andimpose substantial liabilities for pollution resulting from our operations.  Such laws and regulations may substantiallyincrease the cost of exploring for, developing, producing or processing oil andgas and may prevent or delay the commencement or continuation of a givenproject and thus generally could have a material adverse effect upon ourcapital expenditures, earnings, or competitive position.  Violation of these laws and regulations couldresult in significant fines or penalties. We have experienced accidental spills, leaks and other discharges ofcontaminants at some of our properties, as have other similarly situated oiland gas companies, and some of the properties that we have acquired, operatedor sold, or in which we may hold an interest but not operational control, mayhave past or ongoing contamination for which we may be held responsible.  Some of our operations are located inenvironmentally sensitive environments, such as coastal waters, wetlands andother protected areas.  Some of ourproperties are located in areas particularly susceptible to hurricanes andother destructive storms, which may damage facilities and cause the release ofpollutants. Our environmental insurance coverage may not fully insure all ofthese risks. Although the costs of remedying such conditions may besignificant, we do not believe these costs will have a material adverse impacton our financial condition and operations.

 

We believe that we are in substantial compliance with currentapplicable environmental laws and regulations, and the cost of compliance withsuch laws and regulations has not been material and is not expected to bematerial during 2006.  We do not believethat we will be required to incur any material capital expenditures to complywith existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations orin the interpretations thereof could have a significant impact on ouroperating, as well as the oil and gas industry in general.  For instance, legislation has been proposedin Congress from time to time that would reclassify certain oil and gasproduction wastes as “hazardous wastes,” which reclassification would makeexploration and production wastes subject to much more stringent handling,disposal and clean-up requirements. State initiatives to further regulate the disposal of oil and gas wastesand naturally occurring radioactive materials, if adopted, could have a similarimpact on us.

 

The United States Oil Pollution Act of 1990 (“OPA ‘90”), and similarlegislation enacted in Texas, Louisiana and other coastal states, addresses oilspill prevention and control and significantly expands liability exposureacross all segments of the oil and gas industry. OPA ‘90 and such similarlegislation and related regulations impose on us a variety of obligationsrelated to the prevention of oil spills and liability for damages resultingfrom such spills.  OPA ‘90 imposes strictand, with limited exceptions, joint and several liabilities upon eachresponsible party for oil removal costs and a variety of public and privatedamages.

 

The Comprehensive Environmental Response, Compensation, and LiabilityAct (“CERCLA”), also known as the “Superfund” law, imposes liability, withoutregard to fault or the legality of the original conduct, on certain classes ofpersons that are considered to have contributed to the release of a “hazardoussubstance” into the environment.  Thesepersons include the owner or operator of the disposal site or the site wherethe release occurred and companies that disposed or arranged for the disposalof the hazardous substances at the site where the release occurred.  Under CERCLA, such persons may be subject tojoint and several liability for the costs of cleaning up the hazardoussubstances that have been released into the environment and for damages tonatural resources, and it is not uncommon for 

 

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neighboringlandowners and other third parties to file claims for personal injury andproperty damage allegedly caused by the hazardous substances released into theenvironment.  We are able to controldirectly the operation of only those wells with respect to which we act asoperator.  Notwithstanding our lack ofdirect control over wells operated by others, the failure of an operator otherthan us to comply with applicable environmental regulations may, in certaincircumstances, be attributed to us.  Weare not aware of any liabilities for which we may be held responsible thatwould materially and adversely affect us.

 

The Resource Conservation and Recovery Act (“RCRA”), and analogousstate laws govern the handling and disposal of hazardous and solid wastes.Wastes that are classified as hazardous under RCRA are subject to stringenthandling, recordkeeping, disposal and reporting requirements. RCRA specificallyexcludes drilling fluids, produced waters, and other wastes associated with theexploration, development, or production of crude oil, natural gas or geothermalenergy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies assolid waste. Moreover, many ordinary industrial wastes, such as paint wastes,waste solvents, laboratory wastes and waste compressor oils, are regulated ashazardous wastes.  Although the costs ofmanaging hazardous waste may be significant, we do not believe that our costsin this regard are materially more burdensome than those for similarly situatedcompanies.

 

The Clean Air Act, and comparable state and local requirements, containprovisions that may result in the imposition of pollution control requirementswith respect to air emissions from certain of our operations. Capitalexpenditures for air pollution equipment may be required in connection withmaintaining or obtaining operating permits and approvals relating to airemissions at facilities owned or operated by us. We do not believe that ouroperations will be materially adversely affected by any such requirements.

 

State water discharge regulations and federal waste dischargepermitting requirements adopted pursuant to the Federal Water Pollution ControlAct prohibit or are expected in the future to prohibit the discharge ofproduced water and sand and some other substances related to the oil and gasindustry, into coastal waters.  Althoughthe costs to comply with such mandates under state or federal law may besignificant, the entire industry will experience similar costs, and we do notbelieve that these costs will have a material adverse impact on our financialcondition and operations.

 

Claims are sometimes made or threatened against companies engaged inoil and gas exploration and production by owners of surface estates, adjoiningproperties or others alleging damages resulting from environmentalcontamination and other incidents of operations. We have been named as adefendant in a number of such lawsuits. While some jurisdictions in which weoperate limit damages in such cases to the value of land that has beenimpaired, in other jurisdictions in which we operate, courts have alloweddamage claims in excess of land value, including claims for the cost ofremediation of contaminated properties. However, we do not believe thatresolution of these claims will have a material adverse impact on our financialcondition and operations.

 

**Title to Properties**

 

As is customary in the oil and gas industry, we perform a minimal titleinvestigation before acquiring undeveloped properties.  A title opinion is obtained prior to thecommencement of drilling operations on such properties.  We have obtained title opinions onsubstantially all of our producing properties and believe that we havesatisfactory title to such properties in accordance with standards generallyaccepted in the oil and gas industry.  Thesetitle investigations and title opinions, while consistent with industrystandards, may not reveal existing or potential title defects, encumbrances oradverse claims as we are subject from time to time to claims or disputesregarding title to properties.  Ourproperties are subject to customary royalty interests, liens incident tooperating agreements, liens for current taxes and other burdens that we believedo not materially interfere with the use of or affect the value of suchproperties. Substantially all of our oil and gas properties are currentlymortgaged to secure 

 

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borrowings underour revolving credit facility and may be mortgaged under any future creditfacilities entered into by us.

 

**OperationalHazards and Insurance**

 

Our operations are subject to the usual hazards incident to the drillingand production of oil and gas, such as blowouts, cratering, explosions,uncontrollable flows of oil, gas or well fluids, fires and pollution and otherenvironmental risks.  These hazards cancause personal injury and loss of life, severe damage to and destruction ofproperty and equipment, pollution or environmental damage and suspension ofoperation.  In addition, the presence ofunanticipated pressures or irregularities in formations, miscalculations, oraccidents may cause our drilling activities to be unsuccessful and result in atotal loss of our investment.

 

We maintain insurance of various types to cover our operations withpolicy limits and retention liability customary in the industry.  We believe the coverage and types ofinsurance are adequate.  The occurrenceof a significant adverse event, the risks of which are not fully covered byinsurance, could have a material adverse effect on our financial condition andresults of operations.  We cannot giveany assurances that we will be able to maintain adequate insurance in thefuture at rates we consider reasonable.

 

**Executive Officers**

 

The following is a list, as of March 16, 2006 of the name, age andposition with the Company of each person who is an executive officer of theCompany:

 

CLAYTON W. WILLIAMS, age 74, is Chairman ofthe 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 director of certainentities which are controlled directly or indirectly by Mr. Williams.

 

L. PAUL LATHAM, age 54, is Executive VicePresident, Chief Operating Officer and a director of the Company, having servedin such capacities since September 1991. Mr. Latham also serves as an officer and director of certain entitiescontrolled by Mr. Williams.

 

MEL G. RIGGS, age 51, is Senior Vice Presidentand Chief Financial Officer of the Company, having served in such capacitiessince September 1991.  Mr. Riggs hasserved as a director of the Company since May 1994.

 

PATRICK C. REESBY, age 53, is Vice President –New Ventures of the Company, having served in such capacity since 1993.

 

ROBERT C. LYON, age 69, is Vice President –Gas Gathering and Marketing of the Company, having served in such capacitysince 1993.

 

MICHAEL L. POLLARD, age 56, is Vice President –Accounting of the Company, having served in such capacity since 2003.  Prior to that, Mr. Pollard had served asController of the Company since 1993.

 

T. MARK TISDALE, age 49, is Vice President andGeneral Counsel of the Company, having served in such capacity since 1993.

 

GREGORY S. WELBORN, age 32, is Vice President –Land of the Company, having served in such capacity since 2006.

 

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**Employees**

 

At December 31, 2005, we had 174 full-time employees, none of whom issubject to a collective bargaining agreement. In our opinion, our relations with employees are good.

 

**Website Address**

 

The Company maintains an internet website atwww.claytonwilliams.com.  The Companymakes available, free of charge, on its website, the annual report on Form 10-K,quarterly reports on Form 10-Q, current reports on Form 8-K and amendments tothose reports, as soon as reasonably practicable after providing such reportsto the SEC.  The information contained inor 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 arebeyond our control.  Our business,financial condition and results of operations could be materially adverselyaffected by any of these risks.  Therisks described below are not the only ones facing our company.  Additional risks not presently known to us orthat we currently deem immaterial individually or in the aggregate may alsoimpair our business operations.

 

***Our exploration activities subject us to greater risks thandevelopment activities.***

 

For 2006, approximately 90% of our planned capital expenditures relateto exploratory prospects. Exploration is a higher risk activity thandevelopment. Exploration activities involve the drilling of wells in areaswhere there is little or no known production. Development activities relate toincreasing oil or natural gas production from an area that is known to beproductive by drilling additional wells, working over and recompleting existingwells and other production enhancement techniques. Exploration projects areidentified 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 uponexisting production surrounding or adjacent to the proposed drilling site.

 

Because we engage in exploration activities, we have a greater risk ofdrilling dry holes or not finding oil and natural gas that can be producedeconomically. The seismic data and other technology we use does not allow us toknow with certainty prior to drilling a well whether oil or natural gas ispresent or can be produced economically. We charged to expense $40 million in 2005 forabandonment and impairment, most of which was related to unsuccessfulexploratory drilling activities in SouthLouisiana, the Black Warrior Basin of Mississippi and the Cotton Valley/Knowlesarea of East Texas.  We cannotassure you that any of our future exploration efforts will be successful. Ifthese activities are unsuccessful, it will have a significant adverse affect onour results of operations, cash flow and capital resources.

 

***If we do not replace reserves we produce, our financialresults will suffer.***

 

In general, the volume of production from an oil and gas propertydeclines as reserves related to that property are depleted. The decline ratesdepend upon reservoir characteristics. Historically, our oil and gas propertieshave had steep rates of decline and short estimated productive lives. Theimplied life of our proved reserves at December 31, 2005 is approximately 9.3 years, based on 2005 productionlevels.

 

Our oil and gas reserves will decline as they are produced unless weare able to conduct successful exploration and development activities oracquire properties with proved reserves. Because we are 

 

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engaged to a largeextent in exploration activities, our ability to replace produced reserves issubject to a higher level of risk than when we were drilling development wellsin the Austin Chalk (Trend).

 

***Volatility of oil and gas prices significantly affects ourcash flow and capital resources and our ability to produce oil and gaseconomically.***

 

Historically, the markets for oil and gas have been volatile, and webelieve that they are likely to continue to be volatile. Significant changes inoil and gas prices may result from relatively minor changes in the supply ofand demand for oil and natural gas, market uncertainty and other factors thatare beyond our control. We cannot predict, with any degree of certainty, futureoil and natural gas prices. Changes in oil and natural gas prices significantlyaffect our revenues, operating results, profitability and the value of our oiland gas reserves. Those prices also affect the amount of cash flow availablefor capital expenditures, our ability to borrow money or raise additionalcapital and the amount of oil and natural gas that we can produce economically.The amount we can borrow under our senior revolving credit facility is subjectto periodic redeterminations based in part on current prices for oil andnatural gas at the time of the redetermination.

 

Changes in oil and gas prices impact both our estimated future netrevenue and the estimated quantity of proved reserves. Price increases maypermit additional quantities of reserves to be produced economically, and pricedecreases may render uneconomic the production of reserves previouslyclassified as proved. Thus, we may experience material increases and decreasesin reserve quantities solely as a result of price changes and not as a resultof drilling or well performance. We attempt to optimize the price we receivefor our oil and gas production while maintaining a prudent hedging program tomitigate our exposure to declining product prices. Our management may elect toenter into and terminate hedges based on expectations of future marketconditions. If prices continue to rise while our hedges are in place, we willforego revenue we would have otherwise received. If we terminate a hedgebecause we anticipate an increase in product prices that we would not realizewith the hedge in place, and product prices do not increase as anticipated, wemay be exposed to downside risk that would not have existed otherwise.

 

***Our liquidity, including the availability of capitalresources, is uncertain.***

 

Our cash flow forecasts indicate that the amount of funds available tous under our revolving credit facility, when combined with our anticipatedoperating cash flow, will be sufficient to finance our capital expenditures andwill provide us with adequate liquidity at least through 2006.  Although we believe the assumptions andestimates made in our forecasts are reasonable, uncertainties exist which couldcause the borrowing base to be less than expected, cash flow to be less thanexpected, or capital expenditures to be more than expected.  Below is a discussion of uncertainties thatare likely to have a material effect on our liquidity and capital resources ifsuch uncertainties occur.

 

**Adverse changes in reserve estimates or commodityprices could reduce the borrowing base**.  The banks establish the borrowing base atleast twice annually by preparing a reserve report using price-risk assumptionsthey believe are proper under the circumstances.  Any adverse changes in estimated quantitiesof reserves, the pricing parameters being used, or the risk factors beingapplied, since the date of the last borrowing base determination, could lowerthe borrowing base under the revolving credit facility.

 

**Adverse changes in reserve estimates or commodityprices could reduce our cash flow from operating activities**.  We rely on estimates of reserves to forecastour cash flow from operating activities. If the production from those reserves is delayed or is lower thanexpected, our cash flow from operating activities may be lower than weanticipated.  Commodity prices alsoimpact our cash flow from operating activities. Based on December 31, 2005 reserve estimates, we project that a $1.00drop in oil price and a $.50 drop in gas price would reduce our gross revenuesin 2006 by approximately $2.3 million and $8.7 million, respectively.

 

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**Adverse changes in the borrowing base may causeoutstanding debt to equal or exceed the borrowing base**.  In this event, we will not be able to borrowany additional funds, and we will be required to repay the excess or convertthe debt to a term note.  Withoutavailability under the revolving credit facility, we may be unable to meet ourobligations as they mature.

 

**Delays in bringing successful wells on production mayreduce our liquidity**. As a general rule, we experience a significant lag time between theinitial cash outlay on a prospect and the inclusion of any value for suchprospect in the borrowing base under the revolving credit facility.  Until a well is on production, the banks mayassign only a minimal borrowing base value to the well, and cash flows from thewell are not available to fund our operating expense.  Delays in bringing wells on production mayreduce the borrowing base significantly, depending on the amounts borrowed andthe length of the delays.

 

***Hedging transactions may limit our potential gains andinvolve other risks.***

 

From time to time, we use commodity derivatives, consisting of “swaps,”“collars” and “floors,” to attempt to optimize the price we receive for thesale of our oil and natural gas production. When using swaps to hedge our oiland natural gas production, we receive a fixed price for the hedged commodityand pay a floating market price as defined in each contract (generally NYMEXfutures prices), resulting in a net amount due to or from the counterparty atthe settlement date. Collars are a combination of options that provide us witha put option (fixed floor price) in exchange for a call option (fixed ceiling price).If the market price for the hedged commodity exceeds the fixed ceiling price orfalls below the fixed floor price, then we receive the fixed price and pay themarket price. If the market price is between the fixed floor and the fixedceiling prices, then no payments are due from either party. In addition, we maypurchase put options in which we pay the counterparty the fair value of theoption at the purchase date and receive from the counterparty the excess, ifany, of the fixed floor price over the floating market price.

 

The decision to initiate or terminate commodity hedges is made bymanagement based on its expectation of future market price movements. We haveno set goals for the percentage of our production we hedge and we do not useany formulas or triggers in deciding when to initiate or terminate a hedge.  If we enter into swaps or collars and thefloating market price at the settlement date is higher than the fixed price orthe fixed ceiling price, we will forego revenue we would have otherwisereceived. If we terminate a swap, collar or floor because we anticipate futureincreases in market prices, we may be exposed to downside risk that would nothave existed otherwise.

 

***Information concerning our reserves and future net revenuesestimates is inherently uncertain.***

 

The accuracy of proved reserves estimates and estimated future netrevenues from such reserves is a function of the quality of availablegeological, geophysical, engineering and economic data and is subject tovarious assumptions, including assumptions required by the SEC relating to oiland gas prices, drilling and operating expenses, and other matters. Although webelieve that our estimated proved reserves represent reserves that we arereasonably certain to recover, actual future production, oil and gas prices,revenues, taxes, development expenditures, operating expenses and quantities ofrecoverable oil and gas reserves will most likely vary from the assumptions andestimates used to determine proved reserves. Any significant variance couldmaterially affect the estimated quantities and value of our oil and gasreserves, which in turn could adversely affect our cash flow, results ofoperations and the availability of capital resources. In addition, we mayadjust estimates of proved reserves to reflect production history, results ofexploration and development, prevailing oil and gas prices and other factors,many of which are beyond our control. Downward adjustments to our estimatedproved reserves could require us to write down the carrying value of our oiland gas properties, which would reduce our earnings and our stockholders’equity.

 

The present value of proved reserves will not necessarily equal thecurrent fair market value of our estimated oil and gas reserves. In accordancewith the reserve reporting requirements of the SEC, the 

 

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estimateddiscounted future net cash flows from proved reserves are generally based onprices and costs as of the date of the estimate. Actual future prices and costsmay be materially higher or lower than those as of the date of the estimate.The timing of both the production and the expenses with respect to thedevelopment and production of oil and gas properties will affect the timing offuture net cash flows from proved reserves and their present value.

 

The estimated proved reserve information is based upon reserve reportsprepared by independent engineers. From time to time, estimates of our reservesare also made by our banks in establishing the borrowing base under our seniorrevolving credit facility and by our engineers for use in developing businessplans and making various decisions. Such estimates may vary significantly fromthose of the independent engineers and have a material effect upon our businessdecisions and available capital resources.

 

***Acquisitions are subject to the risks and uncertainties ofevaluating reserves and potential liabilities and may be disruptive anddifficult to integrate into our business.***

 

We plan to continue growing our reserves and drilling inventory throughacquisitions. Acquired properties can be subject to significant unknownliabilities. Prior to completing an acquisition, it is generally not feasibleto conduct a detailed review of each individual property to be acquired in anacquisition. Even a detailed review or inspection of each property may notreveal all existing or potential liabilities associated with owning oroperating the property. Moreover, some potential liabilities, such asenvironmental liabilities related to groundwater contamination, may not bediscovered even when a review or inspection is performed.

 

Our initial reserve estimates for acquired properties may beinaccurate. Downward adjustments to our estimated proved reserves, includingreserves added through acquisitions, could require us to write down thecarrying value of our oil and gas properties, which would reduce our earningsand our stockholders’ equity.

 

Our failure to integrate acquired businesses successfully into ourexisting business could result in our incurring unanticipated expenses andlosses. In addition, we may have to assume cleanup or reclamation obligationsor other unanticipated liabilities in connection with these acquisitions. Thescope and cost of these obligations may ultimately be materially greater thanestimated at the time of the acquisition.

 

The process of integrating acquired operations into our existingoperations may result in unforeseen operating difficulties and may requiresignificant management attention and financial resources that would otherwisebe available for the ongoing development or expansion of existing operations.

 

***Drilling oil and natural gas wells is a high-risk activityand 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 encountercommercially productive oil or natural gas reservoirs. We may not recover allor any portion of our investment in new wells. The presence of unanticipatedpressures or irregularities in formations, miscalculations or accidents maycause our drilling activities to be unsuccessful and result in a total loss ofour investment. In addition, we often are uncertain as to the future cost ortiming of drilling, completing and operating wells. Further, our drillingoperations may be curtailed, delayed or canceled as a result of a variety offactors, including:

 

•    unexpecteddrilling conditions;

 

•    titleproblems;

 

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•    pressureor irregularities in formations;

 

•    equipmentfailures or accidents;

 

•    adverseweather conditions;

 

•    compliancewith environmental and other governmental requirements, which may increase ourcosts or restrict our activities; and

 

•    costsof, or shortages or delays in the availability of, drilling rigs, tubularmaterials and equipment and services.

 

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

 

Our operations are subject to the usual hazards incident to thedrilling and production of oil and gas, such as windstorms, blowouts,cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires,severe weather and pollution and other environmental risks. These hazards cancause personal injury and loss of life, severe damage to and destruction ofproperty and equipment, pollution or environmental damage, clean-upresponsibilities, regulatory investigation and penalties, and suspension ofoperation, operations which could result in substantial loss. We maintaininsurance against some, but not all, of the risks described above. Suchinsurance may not be adequate to cover losses or liabilities. Also, we cannotassure you of the continued availability of insurance at premium levels thatjustify its purchase.

 

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

 

The marketability of our oil and natural gas production depends inlarge part on the availability, proximity and capacity of pipeline systemsowned by third parties. The unavailability of or lack of available capacity onthese systems and facilities could result in the shut-in of producing wells orthe delay or discontinuance of drilling plans for properties. Although we havesome contractual control over the transportation of our product, materialchanges in these business relationships could materially affect our operations.Federal and state regulation of oil and natural gas production andtransportation, tax and energy policies, changes in supply and demand, pipelinepressures, damage to or destruction of pipelines and general economicconditions could adversely affect our ability to produce, gather and transportoil and natural gas.

 

***A shortage of available drilling rigs, equipment andpersonnel 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 or personnel. Duringthese periods, the costs and delivery times of drilling rigs, equipment andsupplies are substantially greater. In addition, demand for, and wage rates of,qualified drilling rig crews rise with increases in the number of active rigsin service. Shortages of drilling rigs, equipment, supplies or personnel mayincrease drilling costs or delay or restrict our exploration and developmentoperations, which in turn could impair our financial condition and results ofoperations.

 

***Our industry is highly competitive.***

 

Competition in all areas of our operations is intense. We experiencecompetition from major and independent oil and gas companies and oil and gassyndicates in bidding for desirable oil and gas properties, as well as inacquiring the equipment, data and labor required to operate and develop suchproperties. A number of our competitors have financial resources andacquisition, exploration and development budgets that are substantially greaterthan ours, which may adversely affect our ability to compete with thesecompanies. Competitors may be able to pay more for productive oil and gasproperties and exploratory prospects and to define, evaluate, bid for andpurchase a greater number of 

 

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properties andprospects than our financial or human resources permit. Our ability to increasereserves in the future will depend on our success at selecting and acquiringsuitable producing properties and prospects for future development andexploration activities.

 

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

 

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

 

***Our success depends on key members of our management and ourability to attract and retain experienced technical and other professionalpersonnel.***

 

Our success is highly dependent on our senior management personnel,none of whom are currently subject to an employment contract. The loss of oneor more of these individuals could have a material adverse effect on ourbusiness. Furthermore, competition for experienced technical and otherprofessional personnel is intense. If we cannot retain our current personnel orattract additional experienced personnel, our ability to compete could beadversely affected.

 

***We are primarily controlled by our principal stockholder.***

 

Clayton W. Williams beneficially owns, either individually or throughhis affiliates, approximately 45% of the outstanding shares of our commonstock. Mr. Williams is also the Chairman of the Board and Chief ExecutiveOfficer. As a result, Mr. Williams has significant influence in matters votedon by our shareholders, including the election of board members, and inmanagement decisions. Mr. Williams actively participates in all facets of ourbusiness and has a significant impact on both our business strategy and dailyoperations. The retirement, incapacity or death of Mr. Williams, or any changein the power to vote his shares, could result in negative market or industry perceptionand could have a material adverse effect on our business.

 

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

 

We sell our oil and natural gas production to various customers, serveas operator in the drilling, completion and operation of oil and gas wells, andenter into derivatives with various counterparties. As appropriate, we obtainletters of credit to secure amounts due from our principal oil and gaspurchasers and follow other procedures to monitor credit risk from joint ownersand derivatives counterparties. We cannot assure you that we will not sufferany economic loss related to credit risks in the future.

 

***Compliance with environmental and other governmentregulations could be costly and could negatively impact production.***

 

Our oil and gas exploration, production and related operations aresubject to extensive rules and regulations promulgated by federal, state andlocal agencies. Failure to comply with such rules and regulations can result insubstantial penalties. The regulatory burden on the oil and gas industryincreases our cost of doing business and affects our profitability. Becausesuch rules and regulations are frequently amended or reinterpreted, we areunable to predict the future cost or impact of complying with such laws.

 

All of the states in which we operate generally require permits fordrilling operations, drilling bonds and reports concerning operations andimpose other requirements relating to the exploration and production of oil andgas. Such states also have statutes or regulations addressing conservationmatters, 

 

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includingprovisions for the unitization or pooling of oil and gas properties, theestablishment of maximum rates of production from oil and gas wells and thespacing, plugging and abandonment of such wells. The statutes and regulationsof certain states also limit the rate at which oil and gas can be produced fromour properties.

 

The Federal Energy Regulatory Commission (“FERC”) regulates interstatenatural gas transportation rates and service conditions, which affect themarketing of gas we produce, as well as the revenues we receive for sales ofsuch production. Since the mid-1980s, the FERC has issued various orders that havesignificantly altered the marketing and transportation of gas. These ordersresulted in a fundamental restructuring of interstate pipeline sales andtransportation services, including the unbundling by interstate pipelines ofthe sales, transportation, storage and other components of the city-gate salesservices such pipelines previously performed. These FERC actions were designedto increase competition within all phases of the gas industry. The interstateregulatory framework may enhance our ability to market and transport our gas,although it may also subject us to greater competition and to the morerestrictive pipeline imbalance tolerances and greater associated penalties forviolation of such tolerances.

 

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

 

***Our exploration and production activities are subject toextensive environmental regulations, and to laws that can give rise tosubstantial liabilities from environmental contamination.***

 

Our operations are subject to extensive federal, state and localenvironmental laws and regulations, which impose limitations on the dischargeof pollutants into the environment, establish standards for the management,treatment, storage, transportation and disposal of hazardous materials and ofsolid and hazardous wastes, and impose obligations to investigate and remediatecontamination in certain circumstances. Liabilities to investigate or remediate contamination, as well as otherliabilities concerning hazardous materials or contamination such as claims forpersonal injury or property damage, may arise at many locations, includingproperties in which we have an ownership interest but no operational control,properties we formerly owned or operated and sites where our wastes have beentreated or disposed of, as well as at properties that we currently own oroperate.  Such liabilities may arise evenwhere the contamination does not result from any noncompliance with applicableenvironmental laws.  Under a number ofenvironmental laws, such liabilities may also be joint and several, meaningthat we could be held responsible for more than our share of the liabilityinvolved, or even the entire share. Environmental requirements generally have become more stringent inrecent 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 applicableenvironmental laws and regulations could result in significant civil orcriminal penalties and remediation costs. Some of our properties, including properties in which we have anownership interest but no operating control, may be affected by environmentalcontamination that may require investigation or remediation.  Some of our operations are located inenvironmentally sensitive environments, such as coastal waters, wetlands andother protected areas.  Some of ouroperations are in areas particularly susceptible to damage by hurricanes orother destructive storms, which could result in damage to facilities and dischargeof pollutants.  In addition, claims aresometimes made or threatened against companies engaged in oil and gasexploration and production by owners of surface estates, adjoining propertiesor others alleging damage resulting from environmental contamination and otherincidents of operation, and such claims have been asserted against us as wellas companies we have acquired. Compliance with, and liabilities 

 

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for remediationunder, these laws and regulations, and liabilities concerning contamination orhazardous materials, may adversely affect our business, financial condition andresults of operations.

 

**Item1B -**       Unresolved StaffComments

 

Not applicable.

 

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**Item 2-**          Properties

 

Our properties consist primarily of oil and gas wells and our ownershipin leasehold acreage, both developed and undeveloped.  At December 31, 2005, we had interests in6,605 gross (899.7 net) oil and gas wells and owned leasehold interests inapproximately 1.2 million gross (778,000 net) undeveloped acres.

 

**Reserves**

 

The following table sets forth certain information as of December 31,2005 with respect to our estimated proved oil and gas reserves pursuant to SECguidelines, present value of proved reserves and standardized measure ofdiscounted future net cash flows.

 
| ** **                                                | ** ** | **Proved Developed**       | ** ** | **Proved  Undeveloped** | ** ** | **Total  Proved** | ** ** |
|-----------------------------------------------------------|------------|----------------------------|------------|-------------------------|------------|-------------------|------------|
| **Producing**                                             | ** ** | **Nonproducing**           |
| ** **                                                | ** ** | **(Dollars in thousands)** | ** ** |
|                                                      |       |                       |       |                    |       |              |       |   |   |
| Gas (MMcf)                                                |       | 74,209                     |       | 17,157                  |       | 35,392            |       | 126,758 |   |
| Oil and natural  gas liquids (MBbls)                      |       | 19,120                     |       | 2,382                   |       | 6,333             |       | 27,835 |   |
| Total (MMcfe)                                             |       | 188,929                    |       | 31,449                  |       | 73,390            |       | 293,768 |   |
| Present value of  proved reserves (a)                     |       |                       |       |                    |       |              |       | $ | 1,117,886 |   |
| Standardized  measure of discounted future net cash flows |       |                       |       |                    |       |              |       | $ | 753,712 |   |

 

----

(a)           We believe that the present value of provedreserves (a non-GAAP measure) is a useful supplemental disclosure to thestandardized measure of discounted future net cash flows. While thestandardized measure of discounted future net cash flows is dependent on theunique tax situation of each company, the present value of proved reserves isbased on prices and discount factors that are consistent for all companies andcan be used within the industry and by securities analysts to evaluate provedreserves on a more comparable basis. Standardized measure of discounted futurenet cash flows differs from the present value of proved reserves by the amountof estimated future income taxes and net abandonment costs.  Estimated future income taxes and future netabandonment costs (discounted at 10%) as of December 31, 2005 were $352.6 millionand $11.6 million, respectively.

 

The following table sets forth certain information as of December 31,2005 regarding our proved oil and gas reserves in each of our principalproducing areas.

 
| ** **            | ** ** | **Proved Reserves** | ** ** | **Percent of  Total Gas  Equivalent** | ** ** | **Present  Value of  Proved  Reserves** | ** ** | **Percent  of Present  Value of  Proved  Reserves** | ** ** |
|-----------------------|------------|---------------------|------------|---------------------------------------|------------|-----------------------------------------|------------|-----------------------------------------------------|------------|
| **Oil (a)  (MBbls)**  | ** ** | **Gas  (MMcf)**     | ** ** | **Total Gas  Equivalent  (MMcfe)**    |
| ** **            | ** ** | ** **          | ** ** | ** **                            | ** ** | ** **                              | ** ** | ** **                                          | ** ** | **(In thousands)** | ** ** | ** ** | ** ** |
|                  |       |                |       |                                  |       |                                    |       |                                                |       |   |   |   |   |
| Permian Basin  (b)    |       | 18,504              |       | 79,466                                |       | 190,490                                 |       | 64.8                                                | %          | $ | 575,616 |   | 51.5 | % |
| Louisiana             |       | 1,667               |       | 20,883                                |       | 30,885                                  |       | 10.5                                                | %          | 226,603 |   | 20.3 | % |
| Austin Chalk  (Trend) |       | 7,467               |       | 6,234                                 |       | 51,036                                  |       | 17.4                                                | %          | 178,972 |   | 16.0 | % |
| Cotton Valley         |       |                |       |                                  |       |                                    |       |                                                |       |   |   |   |   |
| Reef Complex          |       | —              |       | 15,396                                |       | 15,396                                  |       | 5.3                                                 | %          | 97,388 |   | 8.7 | % |
| Other                 |       | 197                 |       | 4,779                                 |       | 5,961                                   |       | 2.0                                                 | %          | 39,307 |   | 3.5 | % |
| Total                 |       | 27,835              |       | 126,758                               |       | 293,768                                 |       | 100.0                                               | %          | $ | 1,117,886 |   | 100.0 | % |

 

----

(a)           Includes natural gasliquids.

(b)           Primarily West Texas andNew Mexico.

 

21

----

 

The estimates of proved reserves at December 31, 2005 and the presentvalue of proved reserves were derived from reports prepared by WilliamsonPetroleum Consultants, Inc., independent petroleum engineers and Ryder Scott Company,L.P., petroleum consultants.  Thefollowing table summarizes the reserve estimates derived from each report.

 
| ** **                                   | ** ** | **Proved Developed**       | ** ** | **Proved  Undeveloped** | ** ** | **Total  Proved** | ** ** |
|----------------------------------------------|------------|----------------------------|------------|-------------------------|------------|-------------------|------------|
| **Producing**                                | ** ** | **Nonproducing**           |
| ** **                                   | ** ** | **(Dollars in thousands)** | ** ** |
| **Williamson  Petroleum Consultants, Inc.:** | ** ** | ** **                 | ** ** | ** **              | ** ** | ** **        | ** ** | ** ** | ** ** |
|                                         |       |                       |       |                    |       |              |       |   |   |
| Gas (MMcf)                                   |       | 34,090                     |       | 10,036                  |       | 10,660            |       | 54,786 |   |
| Oil and natural  gas liquids (MBbls)         |       | 8,256                      |       | 833                     |       | 2,375             |       | 11,464 |   |
|                                         |       |                       |       |                    |       |              |       |   |   |
| **Ryder  Scott Company, L.P.:**              | ** ** | ** **                 | ** ** | ** **              | ** ** | ** **        | ** ** | ** ** | ** ** |
|                                         |       |                       |       |                    |       |              |       |   |   |
| Gas (MMcf)                                   |       | 40,119                     |       | 7,121                   |       | 24,732            |       | 71,972 |   |
| Oil and natural  gas liquids (MBbls)         |       | 10,864                     |       | 1,549                   |       | 3,958             |       | 16,371 |   |

 

Estimated recoverable proved reserves have been determined withoutregard to any economic impact that may result from our hedging activities.  These calculations were prepared usingstandard geological and engineering methods generally accepted by the petroleumindustry and in accordance with SEC financial accounting and reportingstandards.  The estimated present valueof proved reserves does not give effect to indirect expenses such as generaland administrative expenses, debt service and future income tax expense or todepletion, depreciation and amortization.

 

In accordance with applicable financial accounting and reportingstandards of the SEC, the estimates of our proved reserves and the presentvalue of proved reserves set forth herein are made using oil and gas salesprices estimated to be in effect as of the date of such reserve estimates andare held constant throughout the life of the properties. Estimated quantitiesof proved reserves and their present value are affected by changes in oil andgas prices.  The average prices utilizedfor the purposes of estimating our proved reserves and the present value ofproved reserves as of December 31, 2005 were $57.85 per Bbl of oil andnatural gas liquids and $10.65 per Mcf of gas, as compared to $41.48 per Bbl ofoil and $5.59 per Mcf of gas as of December 31, 2004.  We estimate that a $1.00 per Bbl change inoil price and a $.50 per Mcf change in gas price from those utilized incalculating the present value of proved reserves would change the present valueby approximately $13.2 million and $32.7 million, respectively.

 

The reserve information shown is estimated.  The accuracy of any reserve estimate is afunction of the quality of available geological, geophysical, engineering andeconomic data, the precision of the engineering and geological interpretationand judgment.  The estimates of reserves,future cash flows and present value are based on various assumptions, includingthose prescribed by the SEC, and are inherently imprecise.  Although we believe these estimates arereasonable, actual future production, cash flows, taxes, developmentexpenditures, operating expenses and quantities of recoverable oil and naturalgas reserves may vary substantially from these estimates.  Also, the use of a 10% discount factor forreporting purposes may not necessarily represent the most appropriate discountfactor, given actual interest rates and risks to which our business or the oiland natural gas industry in general are subject.

 

Since January 1, 2005, we have not filed an estimate of our net provedoil and gas reserves with any federal authority or agency other than the SEC.

 

22

----

** **

**Explorationand Development Activities**

 

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

 
| ** **              | ** ** | **Year Ended December 31,**                               | ** ** |
|-------------------------|------------|-----------------------------------------------------------|------------|
| ** **              | ** ** | **2005**                                                  | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **              | ** ** | **Gross**                                                 | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| ** **              | ** ** | **(Excludes wells in progress at the end of any period)** | ** ** |
| ** **              |       |                                                      |       |   |   |   |   |   |   |   |   |   |   |
| **Development  Wells:** |       |                                                      |       |   |   |   |   |   |   |   |   |   |   |
| Oil                     |       | 49                                                        |       | 26.4 |   | 39 |   | 11.7 |   | 6 |   | 5.0 |   |
| Gas                     |       | 10                                                        |       | 3.2 |   | 2 |   | 1.3 |   | 2 |   | 2.0 |   |
| Dry                     |       | 1                                                         |       | .2 |   | 2 |   | .9 |   | — |   | — |   |
| Total                   |       | 60                                                        |       | 29.8 |   | 43 |   | 13.9 |   | 8 |   | 7.0 |   |
| ** **              |       |                                                      |       |   |   |   |   |   |   |   |   |   |   |
| **Exploratory  Wells:** |       |                                                      |       |   |   |   |   |   |   |   |   |   |   |
| Oil                     |       | 2                                                         |       | 1.8 |   | 1 |   | .3 |   | — |   | — |   |
| Gas                     |       | 7                                                         |       | 4.5 |   | 7 |   | 4.9 |   | 9 |   | 4.9 |   |
| Dry                     |       | 10                                                        |       | 6.1 |   | 13 |   | 7.1 |   | 18 |   | 12.3 |   |
| Total                   |       | 19                                                        |       | 12.4 |   | 21 |   | 12.3 |   | 27 |   | 17.2 |   |
| **Total  Wells:**       |       |                                                      |       |   |   |   |   |   |   |   |   |   |   |
| Oil                     |       | 51                                                        |       | 28.2 |   | 40 |   | 12.0 |   | 6 |   | 5.0 |   |
| Gas                     |       | 17                                                        |       | 7.7 |   | 9 |   | 6.2 |   | 11 |   | 6.9 |   |
| Dry                     |       | 11                                                        |       | 6.3 |   | 15 |   | 8.0 |   | 18 |   | 12.3 |   |
| Total                   |       | 79                                                        |       | 42.2 |   | 64 |   | 26.2 |   | 35 |   | 24.2 |   |

 

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

 

As of December 31, 2005, we do not own any drilling rigs, and allof our current drilling activities are conducted by independent drillingcontractors.  We have entered into aletter agreement with a contract drilling company which calls for the formationof a joint venture in 2006 to acquire 12 new drilling rigs.  We will own a 50% interest in the jointventure.

 

## **Productive WellSummary**

 

The following table sets forth certain information regarding ourownership, as of December 31, 2005, of productive wells in the areasindicated.

 
| ** **            | ** ** | **Oil**   | ** ** | **Gas** | ** ** | **Total** | ** ** |
|-----------------------|------------|-----------|------------|---------|------------|-----------|------------|
| ** **            | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|                  |       |      |       |    |       |      |       |   |   |   |   |   |   |
| Permian Basin         |       | 5,496     |       | 520.0   |       | 705       |       | 91.0 |   | 6,201 |   | 611.0 |   |
| Louisiana             |       | 5         |       | 2.7     |       | 19        |       | 14.7 |   | 24 |   | 17.4 |   |
| Austin Chalk  (Trend) |       | 298       |       | 227.8   |       | 16        |       | 8.8 |   | 314 |   | 236.6 |   |
| Cotton Valley         |       | —    |       | —  |       | 12        |       | 11.1 |   | 12 |   | 11.1 |   |
| Other                 |       | 20        |       | 15.8    |       | 34        |       | 7.8 |   | 54 |   | 23.6 |   |
| Total                 |       | 5,819     |       | 766.3   |       | 786       |       | 133.4 |   | 6,605 |   | 899.7 |   |

 

23

----

 

**Volumes,Prices and Production Costs**

 

The following table sets forth certain information regarding theproduction volumes of, average sales prices received from, and averageproduction costs associated with our sales of oil and gas for the periodsindicated.

 
| ** **                        | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------|------------|-----------------------------|------------|
| ** **                        | ** ** | **2005**                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Oil and  Gas Production Data:** |       |                        |       |   |   |   |   |
| Gas (MMcf)                        |       | 16,408                      |       | 17,938 |   | 24,697 |   |
| Oil (MBbls)                       |       | 2,258                       |       | 2,094 |   | 1,505 |   |
| Natural gas  liquids (MBbls)      |       | 246                         |       | 249 |   | 234 |   |
| Total (MMcfe)                     |       | 31,432                      |       | 31,996 |   | 35,131 |   |
| ** **                        |       |                        |       |   |   |   |   |
| **Average  Realized Prices (a):** |       |                        |       |   |   |   |   |
| Gas ($Mcf)                        |       | $                           | 7.49       |   | $ | 5.60 |   | $ | 4.69 |   |
| Oil ($Bbl)                        |       | $                           | 53.37      |   | $ | 40.65 |   | $ | 27.74 |   |
| Natural gas  liquids ($/Bbl)      |       | $                           | 33.57      |   | $ | 27.90 |   | $ | 21.09 |   |
| ** **                        |       |                        |       |   |   |   |   |
| **Average  Production Costs**     |       |                        |       |   |   |   |   |
| Production  ($/Mcfe) (b)          |       | $                           | 1.83       |   | $ | 1.29 |   | $ | .80 |   |

 

----

(a)           Includes the effects of hedging transactions designated as cash flowhedges under applicable accounting standards. In 2005 and 2004, no derivatives were designated as cash flow hedges.

(b)           Includes direct lifting costs (labor, repairs and maintenance, materialsand supplies), workover costs, administrative costs of production offices,insurance and property and severance taxes.

 

**Development,Exploration and Acquisition Expenditures**

 

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

 
| ** **              | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------|------------|-----------------------------|------------|
| ** **              | ** ** | **2005**                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **              | ** ** | **(In thousands)**          | ** ** |
| ** **              | ** ** | ** **                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Property  Acquisitions: |       |                        |       |   |   |   |   |
| Proved                  |       | $                           | 5,567      |   | $ | 237,042 |   | $ | — |   |
| Unproved                |       | 50,238                      |       | 33,826 |   | 7,982 |   |
| Developmental  Costs    |       | 42,292                      |       | 27,469 |   | 12,465 |   |
| Exploratory  Costs      |       | 86,304                      |       | 73,655 |   | 49,277 |   |
| Total                   |       | $                           | 184,401    |   | $ | 371,992 |   | $ | 69,724 |   |

 

24

----

** **

**Acreage**

 

The following table sets forth certain information regarding ourdeveloped and undeveloped leasehold acreage as of December 31, 2005 in theareas indicated.  This table excludesoptions to acquire leases and acreage in which our interest is limited toroyalty, overriding royalty and similar interests.

 
| ** **          | ** ** | **Developed** | ** ** | **Undeveloped** | ** ** | **Total** | ** ** |
|---------------------|------------|---------------|------------|-----------------|------------|-----------|------------|
| ** **          | ** ** | **Gross**     | ** ** | **Net**         | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|                |       |          |       |            |       |      |       |   |   |   |   |   |   |
| Permian Basin       |       | 80,331        |       | 44,533          |       | 338,124   |       | 149,874 |   | 418,455 |   | 194,407 |   |
| Trend/Cotton Valley |       | 108,280       |       | 106,267         |       | 62,051    |       | 34,140 |   | 170,331 |   | 140,407 |   |
| Louisiana           |       | 9,672         |       | 7,418           |       | 166,559   |       | 156,115 |   | 176,231 |   | 163,533 |   |
| Other (a)           |       | 11,566        |       | 3,996           |       | 618,981   |       | 438,011 |   | 630,547 |   | 442,007 |   |
| Total               |       | 209,849       |       | 162,214         |       | 1,185,715 |       | 778,140 |   | 1,395,564 |   | 940,354 |   |

 

----

(a)           Net undeveloped acres are attributable to thefollowing areas:  Montana – 183,136;Mississippi – 96,657; Alabama - 50,133; Arizona - 39,445;Colorado - 28,980; East Texas - 19,041; Utah - 8,301;and other – 12,318.

 

**Offices**

 

We lease from a related partnership approximately 52,000 square feet ofoffice space in Midland, Texas for our corporate headquarters.  We also lease approximately 10,000 squarefeet of office space in Houston, Texas from an unaffiliated third party.

 

**Item 3-**          Legal Proceedings

 

We are a defendant in several lawsuits that have arisen in the ordinarycourse of business. While the outcome of these lawsuits cannot be predictedwith certainty, management does not expect any of these to have a materialadverse effect on our consolidated financial condition or results ofoperations.

 

**Item4 -**          Submission of Mattersto a Vote of Security Holders

 

No matter was submitted to a vote of our security holders during thefourth quarter of our fiscal year ended December 31, 2005.

 

25

----

 

**PART II**

 

**Item5 -**          Market for theRegistrant’s Common Stock and Related Stockholder Matters

 

## **Price Range of Common Stock**

 

Our Common Stock is quoted on the Nasdaq Stock Market’s National Marketunder the symbol “CWEI”.  As of March 6,2006, there were approximately 1,900beneficial stockholders as reflected in security position listings.  The following table sets forth, for theperiods indicated, the high and low sales prices for our Common Stock, asreported on the Nasdaq National Market:

 
| ** **                     | ** ** | **High** | ** ** | **Low** | ** ** |
|--------------------------------|------------|----------|------------|---------|------------|
| Year Ended  December 31, 2005: |       |     |       |    |       |
| Fourth Quarter                 |       | $        | 44.96      |    | $          | 32.18 |   |
| Third Quarter                  |       | 43.25    |       | 29.60   |       |
| Second Quarter                 |       | 31.93    |       | 21.66   |       |
| First Quarter                  |       | 33.89    |       | 20.62   |       |
|                           |       |     |       |    |       |
| Year Ended  December 31, 2004: |       |     |       |    |       |
| Fourth Quarter                 |       | $        | 24.69      |    | $          | 18.65 |   |
| Third Quarter                  |       | 26.95    |       | 17.53   |       |
| Second Quarter                 |       | 35.85    |       | 22.26   |       |
| First Quarter                  |       | 38.90    |       | 28.20   |       |

 

The quotations in the table above reflect inter-dealer prices withoutretail markups, markdowns or commissions and may not necessarily reflect actualtransactions.  The closing price of ourcommon stock at March 14, 2006 was $39.18 per share.

 

## **Dividend Policy**

 

We have never paid any cash dividends on our Common Stock, and ourBoard of Directors does not currently anticipate paying any cash dividends tothe common stockholders in the foreseeable future.  In addition, the terms of our secured bankcredit facilities prohibit the payment of cash dividends.

 

**Securities Authorized for Issuance under Equity CompensationPlans**

 

The following table provides information regarding options or warrantsauthorized for issuance under our equity compensation plans as of December 31,2005.

 
| ** **                                                  | ** ** | **Number of  securities to be  issued upon  exercise of  outstanding  options** | ** ** | **Weighted  average exercise  price of  outstanding  options** | ** ** | **Number of  securities  remaining  Available for  future issuance** | ** ** |
|-------------------------------------------------------------|------------|---------------------------------------------------------------------------------|------------|----------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|
| Equity compensation plans approved by security  holders (a) |       | 1,338,551                                                                       |       | $                                                              | 19.53      |                                                                 | 148,066    |   |
| Equity compensation plans not approved by security  holders |       | —                                                                          |       | —                                                         |       | —                                                               |       |
| Total                                                       |       | 1,338,551                                                                       |       | $                                                              | 19.53      |                                                                 | 148,066    |   |

 

----

(a)           Consists of the 1993 StockCompensation Plan and the Outside Directors Stock Option Plan.

 

26

----

 

**Item6 -**          Selected FinancialData

 

The following table sets forth selected consolidated financial data forCWEI as of the dates and for the periods indicated.  The consolidated financial data for each ofthe years in the five-year period ended December 31, 2005 was derived fromour audited financial statements.  Thedata set forth in this table should be read in conjunction with *“Management’s Discussion and Analysis of Financial Conditionand Results of Operations”* and the accompanying consolidatedfinancial statements, including the notes thereto.

 
| ** **                                                                                 | ** ** | **Year Ended December 31,**          | ** ** |
|--------------------------------------------------------------------------------------------|------------|--------------------------------------|------------|
| ** **                                                                                 | ** ** | **2005**                             | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| ** **                                                                                 | ** ** | **(In thousands, except per share)** | ** ** |
| **Statement  of Operations Data:**                                                         |       |                                 |       |   |   |   |   |   |   |   |   |
| Revenues:                                                                                  |       |                                 |       |   |   |   |   |   |   |   |   |
| Oil and gas  sales                                                                         |       | $                                    | 252,599    |   | $ | 193,127 |   | $ | 163,032 |   | $ | 86,302 |   | $ | 105,118 |   |
| Natural gas  services                                                                      |       | 12,080                               |       | 9,083 |   | 8,758 |   | 5,568 |   | 8,820 |   |
| Gain on sales of  property and equipment                                                   |       | 18,920                               |       | 4,120 |   | 267 |   | 2,241 |   | 10,986 |   |
| Total revenues                                                                             |       | 283,599                              |       | 206,330 |   | 172,057 |   | 94,111 |   | 124,924 |   |
| Costs and  expenses:                                                                       |       |                                 |       |   |   |   |   |   |   |   |   |
| Production                                                                                 |       | 57,404                               |       | 41,163 |   | 28,239 |   | 21,857 |   | 20,427 |   |
| Exploration:                                                                               |       |                                 |       |   |   |   |   |   |   |   |   |
| Abandonment and  impairments                                                               |       | 39,957                               |       | 67,956 |   | 35,120 |   | 21,571 |   | 29,412 |   |
| Seismic and  other                                                                         |       | 10,780                               |       | 7,124 |   | 8,755 |   | 8,578 |   | 12,868 |   |
| Natural gas  services                                                                      |       | 11,212                               |       | 8,538 |   | 8,279 |   | 4,853 |   | 7,467 |   |
| Depreciation,  depletion and amortization                                                  |       | 47,509                               |       | 44,040 |   | 40,284 |   | 29,656 |   | 37,459 |   |
| Impairment of  property and equipment                                                      |       | 18,266                               |       | — |   | 170 |   | 349 |   | 18,170 |   |
| Accretion of  abandonment obligations                                                      |       | 1,158                                |       | 1,044 |   | 651 |   | — |   | — |   |
| General and  administrative                                                                |       | 15,410                               |       | 11,689 |   | 10,934 |   | 8,615 |   | 7,456 |   |
| Loss on sales of  property and equipment                                                   |       | 209                                  |       | 14,337 |   | 68 |   | 1,880 |   | — |   |
| Other                                                                                      |       | 1,353                                |       | — |   | — |   | — |   | — |   |
| Total costs and  expenses                                                                  |       | 203,258                              |       | 195,891 |   | 132,500 |   | 97,359 |   | 133,259 |   |
| Operating income  (loss)                                                                   |       | 80,341                               |       | 10,439 |   | 39,557 |   | (3,248 | ) | (8,335 | ) |
| Other income  (expense):                                                                   |       |                                 |       |   |   |   |   |   |   |   |   |
| Interest expense                                                                           |       | (14,498                              | )          | (7,877 | ) | (3,138 | ) | (4,006 | ) | (2,925 | ) |
| Gain (loss) on  derivatives                                                                |       | (70,059                              | )          | (25,329 | ) | (1,593 | ) | (1,581 | ) | 2,227 |   |
| Other income                                                                               |       | 4,022                                |       | 1,354 |   | (1,662 | ) | 1,755 |   | 66 |   |
| Total other  income (expense)                                                              |       | (80,535                              | )          | (31,852 | ) | (6,393 | ) | (3,832 | ) | (632 | ) |
| Income (loss) before  income taxes                                                         |       | (194                                 | )          | (21,413 | ) | 33,164 |   | (7,080 | ) | (8,967 | ) |
| Income tax  expense (benefit)                                                              |       | (451                                 | )          | (7,385 | ) | 10,515 |   | (1,742 | ) | (3,421 | ) |
| Income (loss)  from continuing operations                                                  |       | 257                                  |       | (14,028 | ) | 22,649 |   | (5,338 | ) | (5,546 | ) |
| Cumulative  effect of accounting change, net of tax                                        |       | —                               |       | — |   | 207 |   | — |   | (164 | ) |
| Income from  discontinued operations, including gain on sale of $1,196 in 2002, net of tax |       | —                               |       | — |   | — |   | 1,335 |   | 406 |   |
| NET INCOME  (LOSS)                                                                         |       | $                                    | 257        |   | $ | (14,028 | ) | $ | 22,856 |   | $ | (4,003 | ) | $ | (5,304 | ) |
| Net income  (loss) per common share:                                                       |       |                                 |       |   |   |   |   |   |   |   |   |
| Basic:                                                                                     |       |                                 |       |   |   |   |   |   |   |   |   |
| Income (loss)  from continuing operations                                                  |       | $                                    | (.02       | ) | $ | (1.37 | ) | $ | 2.43 |   | $ | (.58 | ) | $ | (.60 | ) |
| Net income  (loss)                                                                         |       | $                                    | (.02       | ) | $ | (1.37 | ) | $ | 2.45 |   | $ | (.43 | ) | $ | (.58 | ) |
| Diluted:                                                                                   |       |                                 |       |   |   |   |   |   |   |   |   |
| Income (loss)  from continuing operations                                                  |       | $                                    | (.02       | ) | $ | (1.37 | ) | $ | 2.38 |   | $ | (.58 | ) | $ | (.60 | ) |
| Net income  (loss)                                                                         |       | $                                    | (.02       | ) | $ | (1.37 | ) | $ | 2.40 |   | $ | (.43 | ) | $ | (.58 | ) |
| Weighted average  common shares outstanding:                                               |       |                                 |       |   |   |   |   |   |   |   |   |
| Basic                                                                                      |       | 10,804                               |       | 10,213 |   | 9,329 |   | 9,241 |   | 9,219 |   |
| Diluted                                                                                    |       | 11,241                               |       | 10,213 |   | 9,509 |   | 9,241 |   | 9,219 |   |
| **Other  Data:**                                                                           |       |                                 |       |   |   |   |   |   |   |   |   |
| Net cash  provided by operating activities                                                 |       | $                                    | 163,475    |   | $ | 126,980 |   | $ | 119,750 |   | $ | 34,514 |   | $ | 67,059 |   |

 
| ** **                 | ** ** | **December 31,**   | ** ** |
|----------------------------|------------|-------------------------|------------|
| ** **                 | ** ** | **2005**                | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| ** **                 | ** ** | **(In thousands)** | ** ** |
| **Balance  Sheet Data:**   |       |                    |       |   |   |   |   |   |   |   |   |
| Working capital  (deficit) |       | $                       | (35,812    | ) | $ | (27,566 | ) | $ | (13,119 | ) | $ | (18,843 | ) | $ | (17,779 | ) |
| Total  assets              |       | 587,335                 |       | 462,235 |   | 224,433 |   | 218,992 |   | 183,279 |   |
| Long-term  debt            |       | 235,700                 |       | 177,519 |   | 53,295 |   | 94,949 |   | 62,000 |   |
| Stockholders’  equity |       | 120,291                 |       | 117,596 |   | 100,781 |   | 68,781 |   | 82,280 |   |
|                            |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

27

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** **

**Item7 -**          Management’sDiscussion and Analysis of Financial Condition and Results of Operations

 

The following discussion is intended to provide information relevant toan understanding of our financial condition, changes in our financial conditionand our results of operations and cash flows and should be read in conjunctionwith our consolidated financial statements and notes thereto included elsewherein this Form 10-K.

 

**Overview**

 

We are an oil and natural gas exploration, development, acquisition,and production company.  Our basicbusiness model is to find and develop oil and gas reserves through explorationand development activities, and sell the production from those reserves at aprofit.  To be successful, we must, overtime, be able to find oil and gas reserves and then sell the resultingproduction at a price that is sufficient to cover our finding costs, operatingexpenses, administrative costs and interest expense, plus offer us a return onour capital investment.  From time totime, we may also acquire producing properties if we believe the acquiredassets offer us the potential for reserve growth through additionaldevelopmental or exploratory drilling activities.

 

We believe that the economic climate in the domestic oil and gasindustry continues to be suitable for our business model.  Oil and gas prices have remained strong.  Supply and demand fundamentals continue tosuggest that energy prices will remain high for the near term, providing uswith the economic incentives necessary for us to assume the risks we face inour search for oil and gas reserves.  However, we are alsoexperiencing significant cost increases in almost all areas of our businessactivities, especially in drilling and production costs.  High demand for oilfield services isresulting in shortage in equipment and trained personnel, resulting in rateincreases.  While profit margins stillremain favorable, operating metrics per Mcfe, such as finding costs, productioncosts and overhead costs, are rising.

 

Finding quality domestic oil and gas reserves through exploration is asignificant challenge and involves a high degree of risk.  We replaced approximately 56% of our 2005production through extensions and discoveries in 2005, most of which werederived from exploration activities. However, our Wolfcamp exploration program in West Texas failed to findsufficient reserves to cover our carrying costs, resulting in an $18.3 millionimpairment in 2005.  Our ability to growour reserves is highly dependent on our overall exploration successes.  We will also continue to look foropportunities to complement our exploration program through the purchase ofproved reserves.

 

**Key Factors to Consider**

 

The following summarizes the key factors considered by management inthe review of our financial condition and operating performance for 2005 andthe outlook for 2006.

 

**•****       **In July 2005, wesignificantly improved our liquidity by issuing $225 million of aggregateprincipal amount of 73⁄4% Senior Notes due 2013. We repaid all amounts outstanding at that time under our secured bankcredit facilities with net proceeds from the Senior Notes of approximately $217million, and had approximately $138.5 million of borrowing capacityavailable under our revolving credit facility at December 31, 2005.

 

•        We recorded a $70.1 million loss onderivatives during 2005. Cash settlements to counterparties accounted for $29.7million of this loss, and changes in mark-to-market valuations accounted for$40.4 million.  Since we do not presently designate our derivatives ascash flow hedges under applicable accounting standards, we recognize the fulleffect of 

 

28

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changing prices on mark-to-market valuations as a current charge orcredit to our results of operations.

 

•        Exploration costs related to abandonmentsand impairments totaled $40 million for 2005, most of which was in the CottonValley Reef Complex, South Texas, Louisiana and West Texas.

 

•        Our proved oil and gas reserves atDecember 31, 2005 was 293.8 Bcfe compared to 299 Bcfe at December 31,2004.  We added 17.7 Bcfe throughextensions and discoveries, purchased 4.2 Bcfe of reserves and added7.8 Bcfe from net revisions.

 

•        We currently plan to spend$184.1 million in 2006 on exploration and development activities, of whichapproximately 90% relates to exploratory prospects.  We cannot predict our drilling success onexploratory prospects, and our future results of operations and financialcondition could be adversely affected by unsuccessful exploratory drillingresults.

 

•        In October2005, we entered into a letter agreement with a contract drilling company whichcalls for the formation of a joint venture to acquire 12 new drillingrigs.  We will own a 50% interest in thejoint venture, which is expected to be formed in March 2006.

** **

**Recent Exploration andDevelopmental Activities**

 

***South Louisiana***

 

More than half of the wells in our South Louisiana exploration programthat were commenced in 2005 were productive and resulted in the addition ofapproximately 8.7 Bcfe of proved reserves in 2005.  However, the LL&E #1 (Andrea) and theState Lease 17636 #1 (Natalie) were unsuccessful and resulted in aggregate abandonmentcharges of $10.7 million in 2005.

 

We currently plan to spend $56.3 million in South Louisiana in 2006 togenerate and lease new exploratory prospects and to drill wells on existingexploratory prospects.  We have begun asix-well program on our Floyd prospect in Plaquemines Parish targetingmulti-pay objectives ranging in depths from 3,000 to 13,000 feet.  The State Lease 195 QQ #1 was drilled to atotal depth of 12,981 feet and is currently being completed.  The State Lease 195 QQ #2 has been drilled toa total depth of 6,296 feet and is pending completion.  The State Lease 195 QQ #3 has been drilled toa total depth of 9,170 feet, and is also pending completion.  The State Lease 195 QQ #4 is currentlydrilling.  Under the terms of a farmoutagreement, we bear 100% of the costs on these wells before casing point to earna 75% working interest in the drilled acreage.

 

***North Louisiana***

 

We have begun an exploration program in North Louisiana targeting theCotton Valley/Hosston and Bossier formations. In this area, the Cotton Valley/Hosston formations are encountered atdepths ranging from 8,000 to 12,000 feet, and the Bossier formation isencountered at depths ranging from 11,000 to 15,500 feet.  We believe that these tight sandstoneformations have become more economically viable due to higher product prices,coupled with enhanced drilling and completion techniques.  We have accumulated more than 115,000 netacres in this area, and to date have participated in six non-operated wells ona small portion of this acreage, four of which are currently being completedand two are in progress.  We arecurrently drilling the Harris #1, a 14,500-foot well in Jackson Parishtargeting the Bossier formation, in which we own a 53% working interest.  We plan to spend approximately $87.9 millionin North Louisiana in 2006, consisting of $17.2 million to acquire leasesand conduct seismic and exploration activities, and $70.7 million on drilling.

 

29

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*** ***

***East Texas (Bossier)***

 

We have also begun acquiring leases in East Texas targeting the Bossierformation which is encountered at depths ranging from 14,000 to 22,000 feetin this area.  To date, we have acquiredapproximately 28,000 net acres and are actively seeking to add to our acreageposition.  We plan to spend approximately$20 million for acreage in East Texas in 2006 and expect to begin drilling onthis acreage in 2007.

 

***Permian Basin***

 

In 2005, we initiated an exploration program in West Texas seeking toextend the limits of the Wolfcamp formation that is encountered throughout alarge segment of this region.  Weacquired more than 50,000 net acres and have drilled 11 wells across a wideportion of this acreage.  While all ofthe wells were completed as producers, the oil and gas reserves derived fromthis drilling program were inadequate to recover our capitalized costs.  As a result, we recorded an $18.3 millioncharge for impairment of proved properties and a $1.8 million charge forimpairment of unproved properties in 2005 related to our Wolfcamp program.

 

We also drilled the Leoncita #1, a 9,300-foot exploratory well in PecosCounty, Texas targeting the Barnett Shale. This well was unsuccessful and resulted in a $4.5 million charge toexploration costs in 2005.

 

In addition, we drilled 24 gross (20.2 net) wells in thePermian Basin and conducted remedial operations on existing wells in 2005.  While some of the drilling activities in 2005did not result in the quantities of oil and gas reserves that we had expected,the Permian Basin continues to be a significant source of production and cashflow for us.  We currently plan to spend$6.7 million on drilling activities in the Permian Basin in 2006.

 

***Montana/Utah***

 

In 2005, we initiated an exploration program in Sheridan County,Montana targeting the Bakken Shale which is encountered at depths ranging from 7,000to 8,000  feet in this area.  We arecurrently drilling the Ruegsegger 24H #1, a horizontal well at a verticaldepth of 7,600 feet and a 3,600 foot lateral.

 

We are participating in a joint exploration program with industrypartners in the Overthrust play in central Utah in which we own a 33%interest.  In 2006, we plan to spendapproximately $2.5 million to participate in the drilling of a 14,400-footexploratory well to test this acreage.

 

***Other***

 

We currently plan to spend $7.2 million in 2006 to explore for oiland gas in other areas, including the Austin Chalk (Trend), Colorado andAlabama.

 

30

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** **

**Proved Oil and GasReserves**

 

Thefollowing table summarizes changes in our proved reserves during 2005 on a Bcfebasis.

 
| ** **                               | ** ** | **Bcfe** | ** ** |
|------------------------------------------|------------|----------|------------|
| Total proved reserves, December 31, 2004 |       | 299.0    |       |
| Purchases of reserves in place           |       | 4.2      |       |
| Extensions and discoveries               |       | 17.7     |       |
| Revisions of previous estimates          |       | 7.8      |       |
| Sales of reserves in place               |       | (3.5     | )          |
| Production                               |       | (31.4    | )          |
| Total proved reserves, December 31, 2005 |       | 293.8    |       |

 

During2005, we replaced 94% of the 31.4 Bcfe that we produced in 2005, computed bydividing the sum of all reserve additions (purchases of reserves in place,extensions and discoveries, and revisions of previous estimates), by 2005production.  We use this reservereplacement ratio as a benchmark for determining the sources through which wehave expanded or contracted our base of proved reserves. Following is adiscussion of the important factors related to each source of reserve additionsduring 2005.

 

*Purchases ofreserves in place.*  We purchased 4.2Bcfe of reserves in 2005 relating to properties in West Texas.  Although we are continually looking foracquisitions, we cannot predict the likelihood of adding any reserves in 2006through purchases of reserves in place.

 

*Extensions anddiscoveries.*  Our extensions anddiscoveries during 2005 consist of proved reserves attributable directly to thedrilling of discovery wells primarily in South Louisiana and the PermianBasin.  Of the 17.7 Bcfe ofadditions, 4.8 Bcfe are proved undeveloped reserves that will require theexpenditure of approximately $5.9 million before the reserves canultimately be converted to cash flow. Due to the nature of exploratory drilling, we cannot predict the extentto which we will add any reserves in 2006 through extensions and discoveries.

 

*Revisions of previous estimates.* We added 7.8 Bcfe of proved reserves through revisions of previousestimates. Upward revisions of 17.5 Bcfe were attributable to the effects ofhigher product prices on the estimated quantities of proved reserves which wereoffset by downward revisions of approximately 9.7 Bcfe attributable to wellperformance, primarily from properties in West Texas.

 

As we discuss under *“Application of Critical Accounting Policies and Estimates”*elsewhere in this Item 7, reserve estimates are inherently imprecise.  Proved undeveloped reserves are generally theleast accurate due to limitations on available information.  This increases the risk that the reserveadditions in 2005 that are classified as proved undeveloped reserves could besubject to downward revisions in the future as economic conditions change andas more information is obtained through drilling.

 

31

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**Supplemental Information**

 

The following unaudited information is intended to supplement theconsolidated financial statements included in this Form 10-K with data that isnot readily available from those statements.

 
| ** **                                                | ** ** | **As of or for the Year Ended December 31,** | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------------------------------------------------------|------------|
| ** **                                                | ** ** | **2005**                                                                             | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Oil and  Gas Production Data:**                         | ** ** | ** **                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (MMcf)                                                |       | 16,408                                                                               |       | 17,938 |   | 24,697 |   |
| Oil (MBbls)                                               |       | 2,258                                                                                |       | 2,094 |   | 1,505 |   |
| Natural gas  liquids (MBbls)                              |       | 246                                                                                  |       | 249 |   | 234 |   |
| Total (MMcfe)                                             |       | 31,432                                                                               |       | 31,996 |   | 35,131 |   |
|                                                      |       |                                                                                 |       |   |   |   |   |
| **Average  Realized Prices (a):**                         | ** ** | ** **                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas ($/Mcf):                                              |       |                                                                                 |       |   |   |   |   |
| Before hedging  losses                                    |       | $                                                                                    | 7.49       |   | $ | 5.60 |   | $ | 5.35 |   |
| Hedging losses                                            |       | —                                                                               |       | — |   | (.66 | ) |
| Net realized  price                                       |       | $                                                                                    | 7.49       |   | $ | 5.60 |   | $ | 4.69 |   |
| Oil ($/Bbl):                                              |       |                                                                                 |       |   |   |   |   |
| Before hedging  losses                                    |       | $                                                                                    | 53.37      |   | $ | 40.65 |   | $ | 29.94 |   |
| Hedging losses                                            |       | —                                                                               |       | — |   | (2.20 | ) |
| Net realized  price                                       |       | $                                                                                    | 53.37      |   | $ | 40.65 |   | $ | 27.74 |   |
|                                                      |       |                                                                                 |       |   |   |   |   |
| Natural gas  liquids ($/Bbl):                             |       | $                                                                                    | 33.57      |   | $ | 27.90 |   | $ | 21.09 |   |
| ** **                                                |       |                                                                                 |       |   |   |   |   |
| **Average  Daily Production:**                            |       |                                                                                 |       |   |   |   |   |
| Gas (Mcf):                                                |       |                                                                                 |       |   |   |   |   |
| Permian Basin                                             |       | 15,893                                                                               |       | 9,458 |   | 1,668 |   |
| Louisiana                                                 |       | 10,865                                                                               |       | 12,089 |   | 17,570 |   |
| Austin Chalk  (Trend)                                     |       | 2,435                                                                                |       | 3,155 |   | 3,667 |   |
| Cotton Valley  Reef Complex                               |       | 15,155                                                                               |       | 23,131 |   | 42,493 |   |
| Other                                                     |       | 605                                                                                  |       | 1,312 |   | 2,265 |   |
| Total                                                     |       | 44,953                                                                               |       | 49,145 |   | 67,663 |   |
| Oil (Bbls):                                               |       |                                                                                 |       |   |   |   |   |
| Permian Basin                                             |       | 3,245                                                                                |       | 2,410 |   | 723 |   |
| Louisiana                                                 |       | 994                                                                                  |       | 1,055 |   | 608 |   |
| Austin Chalk  (Trend)                                     |       | 1,892                                                                                |       | 2,215 |   | 2,715 |   |
| Other                                                     |       | 55                                                                                   |       | 57 |   | 77 |   |
| Total                                                     |       | 6,186                                                                                |       | 5,737 |   | 4,123 |   |
| Natural Gas  Liquids (Bbls):                              |       |                                                                                 |       |   |   |   |   |
| Permian Basin                                             |       | 255                                                                                  |       | 213 |   | 171 |   |
| Louisiana/Other                                           |       | 97                                                                                   |       | 185 |   | 171 |   |
| Austin Chalk  (Trend)                                     |       | 322                                                                                  |       | 284 |   | 299 |   |
| Total                                                     |       | 674                                                                                  |       | 682 |   | 641 |   |
|                                                      |       |                                                                                 |       |   |   |   |   |
| **Total  Proved Reserves:**                               | ** ** | ** **                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (MMcf)                                                |       | 126,758                                                                              |       | 138,278 |   | 62,916 |   |
| Oil and natural  gas liquids (MBbls)                      |       | 27,835                                                                               |       | 26,793 |   | 10,335 |   |
| Total gas  equivalent (MMcfe)                             |       | 293,768                                                                              |       | 299,036 |   | 124,926 |   |
| Standardized  measure of discounted future net cash flows |       | $                                                                                    | 753,712    |   | $ | 500,198 |   | $ | 252,980 |   |

 

32

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| **Total  Proved Reserves by Area:**       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Gas (MMcf):                               |       |       |       |       |       |       |       |
| Permian Basin                             |       | 79,466     |       | 85,243     |       | 4,325      |       |
| Louisiana                                 |       | 20,883     |       | 26,844     |       | 24,465     |       |
| Austin Chalk  (Trend)                     |       | 6,234      |       | 6,225      |       | 5,593      |       |
| Cotton Valley  Reef Complex               |       | 15,396     |       | 19,116     |       | 25,616     |       |
| Other                                     |       | 4,779      |       | 850        |       | 2,917      |       |
| Total                                     |       | 126,758    |       | 138,278    |       | 62,916     |       |
| Oil and Natural  Gas Liquids (MBbls):     |       |       |       |       |       |       |       |
| Permian Basin                             |       | 18,504     |       | 17,113     |       | 1,980      |       |
| Louisiana                                 |       | 1,667      |       | 1,942      |       | 1,485      |       |
| Austin Chalk  (Trend)                     |       | 7,467      |       | 7,586      |       | 6,688      |       |
| Other                                     |       | 197        |       | 152        |       | 182        |       |
| Total                                     |       | 27,835     |       | 26,793     |       | 10,335     |       |
| Total Gas  Equivalent (MMcfe):            |       |       |       |       |       |       |       |
| Permian Basin                             |       | 190,490    |       | 187,921    |       | 16,205     |       |
| Louisiana                                 |       | 30,885     |       | 38,496     |       | 33,375     |       |
| Austin Chalk  (Trend)                     |       | 51,036     |       | 51,741     |       | 45,721     |       |
| Cotton Valley  Reef Complex               |       | 15,396     |       | 19,116     |       | 25,616     |       |
| Other                                     |       | 5,961      |       | 1,762      |       | 4,009      |       |
| Total                                     |       | 293,768    |       | 299,036    |       | 124,926    |       |
|                                      |       |       |       |       |       |       |       |
| **Exploration  Costs (in thousands):**    |       |       |       |       |       |       |       |
| Abandonment and  impairment costs:        |       |       |       |       |       |       |       |
| South Louisiana                           |       | $          | 12,405     |       | $          | 32,760     |       | $ | 17,904 |   |
| Cotton Valley  Reef Complex               |       | 7,405      |       | 205        |       | 8,694      |       |
| Nevada, Arizona,  California and Utah     |       | —     |       | 2,513      |       | 4,172      |       |
| Mississippi (b)                           |       | 4,306      |       | 29,547     |       | 3,773      |       |
| Permian Basin                             |       | 7,411      |       | 2,378      |       | 361        |       |
| Other (c)                                 |       | 8,430      |       | 553        |       | 216        |       |
| Total                                     |       | 39,957     |       | 67,956     |       | 35,120     |       |
|                                      |       |       |       |       |       |       |       |
| Seismic and  other                        |       | 10,780     |       | 7,124      |       | 8,755      |       |
| Total  exploration costs                  |       | $          | 50,737     |       | $          | 75,080     |       | $ | 43,875 |   |
|                                      |       |       |       |       |       |       |       |
| **Oil and  Gas Costs ($/Mcfe Produced):** |       |       |       |       |       |       |       |
| Production                                |       | $          | 1.83       |       | $          | 1.29       |       | $ | .80 |   |
| Depletion                                 |       | $          | 1.42       |       | $          | 1.28       |       | $ | 1.10 |   |
|                                      |       |       |       |       |       |       |       |
| **Net  Wells Drilled (d):**               |       |       |       |       |       |       |       |
| Exploratory  wells                        |       | 12.4       |       | 12.3       |       | 17.2       |       |
| Developmental  wells                      |       | 29.8       |       | 13.9       |       | 7.0        |       |

 

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(a)           Includes theeffects of hedging transactions designated as cash flow hedges under applicableaccounting standards.  In 2005 and 2004,no derivatives were designated as cash flow hedges.

(b)           Includes a $13.7million impairment of unproved acreage in the Black Warrior Basin in 2004 and$2.1 million in 2003.

(c)           Includes an$8 million charge in South Texas for the Deer-Hamilton #1.

(d)           Excludes wellsbeing drilled or completed at the end of each period.

 

33

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**Operating Results**

 

The following discussion compares our results for the year ended December31, 2005 to the two previous years.  Allreferences to 2005, 2004 and 2003 within this section refer to the respectiveannual periods.

 

***Oil and gas operating results***

 

Our oil and gas sales reached a record high again in 2005, exceeding theprevious record in 2004.  Both oil andgas prices continued to exceed previous year levels.  Comparing 2005 to 2004, oil and gas salesincreased $59.5 million, of which price variances accounted for a$61.3 million increase and production variances accounted for a $1.8 milliondecrease.  Comparing 2004 to 2003, oiland gas sales increased $30.1 million, of which price variances accountedfor a $45.2 million increase and production variances accounted for a$15.1 million decrease.

 

Production in 2005 (on a Mcfe basis) was 2% lower than 2004 and 11%lower than 2003.  We increased our oilproduction in 2005 due primarily to additional well production from our SWRacquisition in May 2004, offset by lost production as a result of HurricaneKatrina.  Our gas production decreased 9% in 2005 from2004 due primarily to lost gas production from Hurricane Katrina and to higherthan expected production declines in the Cotton Valley Reef Complex area due toformation performance.

 

In 2005, our realized gas price was 34% higher than 2004 and 60% higherthan 2003, while our realized oil price was 31% higher than 2004 and 92% higherthan 2003.  Historically, the markets foroil and gas have been volatile, and they are likely to continue to be volatile.  We have very little control over the priceswe receive for our production at the wellhead since most of our physicalmarketing arrangements are market-sensitive.

 

We cannot predict with accuracy future prices for oil and gas althoughcurrently we believe the fundamentals are in place for a continued strong oiland gas commodities market.  However, wehave not designated our current commodity derivatives, and do not currentlyintend to designate future commodity derivatives, as cash flow hedges under SFAS 133.  This means that, in future periods as oil andgas prices fluctuate, our derivatives will be marked to market through ourstatement of operations as other income (loss) instead of through accumulatedother comprehensive income on our balance sheet. Additionally, all realizedgains or losses on these derivatives in future periods will be reported inother income (loss) instead of oil and gas sales.  This accounting treatment affects the timingand classification of income (loss) from derivatives, but it has no effect oncash flow from operating activities. Since we cannot predict future oil and gas prices, we cannot predict theeffect that this accounting treatment will have on oil and gas sales or otherincome (loss) in future periods.

 

Oil and gas production costs on an Mcfe basis in 2005 were 42% higherthan 2004 and 129% higher than 2003.  Theincrease in operating costs in 2005 and 2004 was due in part to higher oilfield service costs and an increasein workover activities.  Also contributing to the added expense was theaddition of higher cost oilproperties acquired in connection with the SWR merger, as well as increasedproduction tax costs related to higher product prices.  It is likely that these factors willcontinue to contribute to higher production costs in future periods.

 

Depletion on an Mcfe basis increased 11% from 2004 and 29% from2003.  Comparing 2005 to 2004, depletionexpense increased $3.5 million, of which rate variances accounted for a$4.2 million increase and production variances accounted for a $700,000decrease.  Comparing 2004 to 2003,depletion expense increased $2.5 million, of which rate variancesaccounted for a $6 million increase and production variances accounted fora $3.5 million decrease.  Depletionrates for each depletable group are a function of net capitalized costs andestimated reserve quantities.  The ratesfor 2006 are expected to be similar to the 2005 rates.

 

34

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General andadministrative (“G&A”) expenses, excluding non-cash stock-based employeecompensation, were 8% higher than 2004 and 27% higher than 2003 due primarilyto higher personnel costs, professional fees and insurance costs.  G&A expenses for 2005 include a non-cashcharge of $2.6 million for stock-based employee compensation required byFinancial Accounting Standards Board Interpretation No. 44.  A non-cash credit (reduction of expense) of$245,000 was required for the 2004 period and a charge of $797,000 was neededfor 2003.  In addition, we recognized$680,000 of non cash compensation expense for the estimated value of afterpayout working interests conveyed to incentive partnerships formed in 2005.

 

***Exploration costs***

 

In 2005, we charged to expense $50.7 million of exploration costs,as compared to $75.1 million in 2004 and $43.9 million in 2003.  Since we follow the successful efforts methodof accounting, our results of operations are adversely affected during anyaccounting period in which significant seismic costs, exploratory dry hole costs,and unproved acreage impairments are expensed. Most of these costs were incurred in south Louisiana and Mississippi.

 

We plan to spend approximately $184.1 million on exploration anddevelopment activities in 2006.  Sinceexploratory drilling involves a high degree of risk, it is likely that asignificant portion of this will be charged to exploration costs in 2006.  However, we cannot predict our success ratesand, accordingly, cannot predict our exploration costs related to abandonmentand impairment costs.

 

***Gains and losses on property sales***

 

Gain on sale of property and equipment for2005 was $18.9 million.  In August 2005, we sold our interests intwo leases in the Breton Sound area in the Gulf of Mexico (offshore Louisiana)for $21.3 million, subject to post-closing adjustments and realized a gainof $16.8 million on this sale.  Infiscal 2004 we recorded a gain of $4.1 million, including the sale of theJo-Mill Unit in Borden County, Texas. Loss on sale of property and equipment for 2004 was $14.3 millionincluding the sale of the Romere Pass Unit in Plaquemines Parish,Louisiana.  Under EITF 03-13, “Applyingthe Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whetherto Report Discontinued Operations,” we determined that these sales do notqualify for discontinued operations reporting. We adopted EITF 03-13 during the fourth quarter of 2004.

 

***Interest expense***

 

Interest expense was $14.5 million in 2005 as compared to$7.9 million in 2004 and $3.1 million in 2003.  Included in 2005 was a non-cashcharge of $1.8 million of debt issue costs related to the early repayment ofour senior term credit facility.  In July 2005, we repaidall outstanding balances on our bank indebtedness using proceeds from theissuance of $225 million of Senior Notes which bear interest at a fixedrate of 7.75%.  Higher effective interest rates on our revolving credit facility and oursenior term credit facility also contributed to the increase in interestexpense.

 

***Loss on derivatives***

 

We recorded a loss on derivatives of $70.1 million in 2005 comparedto a loss of $25.3 million in 2004 and a loss of $1.6 million in2003.  We did not designate anyderivative contracts in 2005 or 2004 as cash flow hedges; therefore all cashsettlements and changes resulting from mark-to-market valuations have beenrecorded as losses on derivatives.  Cashsettlements were $29.7 million in 2005, as compared to $18.2 millionin 2004, and non-cash mark-to-market losses were$40.4 million in 2005, as compared to $7.1 million in 2004.

 

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***Other***

 

At December 31, 2005, our cumulative tax loss carryforwards wereapproximately $7.1 million.  Basedupon current commodity prices and production volumes, as well as theavailability of tax planning strategies (such as elective capitalization ofintangible drilling costs), we believe that it is more likely than not that wewill be able to utilize these tax loss carryforwards before they expire(beginning in 2008).  Accordingly, novaluation allowance exists at December 31, 2005.  A valuation allowance at December 31, 2002was reversed during 2003.

 

**Liquidity and Capital Resources**

 

***Overview***

 

Ourprimary financial resource is our base of oil and gas reserves.  We pledgeour producing oil and gas properties to a group of banks to secure ourrevolving credit facility and, until July 2005, our senior term creditfacility.  The banks establish a borrowing base by making an estimate ofthe collateral value of our oil and gas properties.  We borrow funds onthe revolving credit facility as needed to supplement our operating cash flowas a financing source for our capital expenditure program.  Our ability tofund our capital expenditure program is dependent upon the level of productprices and the success of our exploration program in replacing our existing oiland gas reserves.  If product prices decrease, our operating cash flow maydecrease and the banks may require additional collateral or reduce ourborrowing base, thus reducing funds available to fund our capital expenditureprogram.  The effects of product prices on cash flow can be mitigatedthrough the use of commodity derivatives.  If we are unable to replace ouroil and gas reserves through our exploration program, we may also suffer areduction in our operating cash flow and access to funds under the revolvingcredit facility.  Under extreme circumstances, product price reductions orexploration drilling failures could allow the banks to seek to foreclose on ouroil and gas properties, thereby threatening our financial viability.

 

In July 2005, we reduced our dependence onthe borrowing base established for the revolving credit facility by issuing$225 million of aggregate principal amount of 73⁄4% Senior Notes due 2013(the “Senior Notes”) and using the net proceeds to repay all amounts outstandingon the revolving credit facility and the senior term credit facility.

 

In this section, we will describe our current plans for capitalspending, identify the capital resources available to finance our capitalspending, and discuss the principal factors that can affect our liquidity andcapital resources.

 

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***Capital Expenditures***

 

***Exploration and Development***

Our planned expenditures for exploration anddevelopment activities during 2006 total $184.1 million, as summarized byarea in the following table.

 
| ** **            | ** ** | **Total  Planned  Expenditures  Year Ended  December 31, 2006** | ** ** | **Percentage  of Total** | ** ** |
|-----------------------|------------|--------------------------------------------------------------------------------|------------|-------------------------------|------------|
| ** **            | ** ** | **(In thousands)**                                                        | ** ** | ** **                    | ** ** |
|                  |       |                                                                           |       |                          |       |
| North Louisiana       |       | $                                                                              | 87,900     |                          | 48         | % |
| South Lousiana        |       | 56,300                                                                         |       | 30                            | %          |
| East Texas  (Bossier) |       | 20,000                                                                         |       | 11                            | %          |
| Permian Basin         |       | 6,700                                                                          |       | 4                             | %          |
| Utah/Montana          |       | 6,000                                                                          |       | 3                             | %          |
| Austin Chalk  (Trend) |       | 4,100                                                                          |       | 2                             | %          |
| Other                 |       | 3,100                                                                          |       | 2                             | %          |
|                  |       | $                                                                              | 184,100    |                          | 100        | % |

 

Our actual expenditures during fiscal 2006may be substantially higher or lower than these estimates since our plans forexploration and development activities may change during the year.  Otherfactors, such as prevailing product prices and the availability of capitalresources, could also increase or decrease the ultimate level of expendituresduring fiscal 2006.

 

Approximately 90%of our planned expenditures for 2006 relate to exploratory prospects, including$36.6 million of completion costs on exploratory wells to be drilled inNorth Louisiana and South Louisiana that are classified as exploratory wellsbut are considered likely to require the expenditure of completion costs.  Exploratory prospects involve a higher degreeof risk than developmental prospects.  Tooffset this higher risk, we generally strive to achieve a higher reservepotential and rate of return on investments in exploratory prospects.  We do not attempt to forecast our successrate on exploratory drilling. Accordingly, these current estimates may not include all costs that may berequired to complete our successful exploratory wells and construct therequired production facilities for these wells. Also, we are actively searching for other opportunities to increase ouroil and gas reserves, including the evaluation of new prospects for exploratoryand developmental drilling activities and potential acquisitions of proved oiland gas properties.  Other factors, suchas prevailing product prices and the availability of capital resources, couldalso increase or decrease the ultimate level of expenditures during 2006.

 

We project thatmost of the cash needed to finance our planned expenditures for exploration anddevelopment activities in fiscal 2006 will be provided by operatingactivities.  To the extent that actual costs exceed our cash provided byoperating activities, we plan to utilize the revolving credit facility tofinance such excess.

 

***Drilling RigJoint Venture***

InOctober 2005, we entered into a letter agreement with Lariat Services,Inc. (“Lariat”), a contract drilling company, which calls for the formation ofa joint venture to acquire at least 12 new drilling rigs.  We and Lariat willeach own a 50% interest in the joint venture.  Lariat will serve as theoperations manager of the joint venture, and we will be responsible forfinancing the purchase of the rigs.  The total acquisition cost, includingconstruction and equipping of the rigs, is expected to be approximately$75 million.

 

The joint venturehas received a proposal from a lender to provide financing for up to$75 million, depending on the appraised values of the drilling rigs uponcompletion of construction.  During 2006,while the drilling rigs are being constructed, the proposal contemplates that****we provide the lender a $19.5 million

 

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standby letter ofcredit as additional credit support.  Onor before December 31, 2006, we would terminate the letter of credit andprovide an unconditional guaranty to the lender of the repayment andperformance by the joint venture limited to $19.5 million of the outstanding balance of the loan facility.  Under the terms of the proposal, we wouldalso be required to contract with the joint venture to use the drilling rigs inour drilling program for a term of at least three years and to pay for idle,non-working rigs in amounts ranging from $8,000 to $11,000 per day.  We expect to complete negotiations with thelender and to close the financing in March 2006.

 

At December 31,2005, we had made advances on behalf of the joint venture of approximately$10.3 million for interim construction costs of the rigs and relatedequipment.  The joint venture is toreimburse us for all advances once it has received the proceeds from thefinancing.

 

We are currentlyevaluating our investment in this joint venture to determine if we are theprimary beneficiary under FIN 46R.  If wedetermine that we are the primary beneficiary, we will be required to fullyconsolidate this entity in 2006.

 

***EquipmentOrders***

Asof December 31, 2005, we had placed firm orders for tubing, casing,pumping units and other equipment to be used in its exploration and development activities totalingapproximately $8.6 million.

 

***Cash Flow Provided by Operating Activities***

 

Substantially all of our cash flow fromoperating activities is derived from the production of our oil and gasreserves.  We use this cash flow to fundour on-going exploration and development activities in search of new oil andgas reserves.  Variations in cash flowfrom operating activities may impact our level of exploration and developmentexpenditures.

 

Cash flow provided by operating activitiesfor the year ended December 31, 2005 was 29% higher than 2004 due to thecombined effects of several drivers.  The positive benefits of a 31%increase in oil and gas sales, driven primarily by higher oil and gas prices, wereoffset in part by increases in production costs and interest expense.  Ourprimary source of cash from operating activities is our oil and gas sales, netof production costs.  Our cash flow provided by operating activities issubject to material variation from changes in oil and gas production levels andproduct prices.  Interest expenseincreased in 2005 due primarily to higher levels of indebtedness.

 

***Credit Facility***

 

A group of banks have provided us with arevolving credit facility on which we have historically relied for both ourshort-term liquidity (working capital) and our long-term financing needs. The funds available to us at any time under this revolving credit facility arelimited to the amount of the borrowing base established by the banks.  Aslong as we have sufficient availability under this credit facility to meet ourobligations as they come due, we will have sufficient liquidity and will beable to fund any short-term working capital deficit.

 

At the beginning of 2005, we had anoutstanding balance under the revolving credit facility of $147.5 million,and the borrowing base was $195 million, providing us with available funds of$46.7 million after accounting for outstanding letters of credit. During the year ended December 31, 2005, we generated cash flow fromoperating activities of $163.5 million and received proceeds from sales ofproperty and equipment of $23.3 million.  We also spent$220 million on capital expenditures and other investments and paid$27.7 million to settle derivatives with financing elements.  Withthe issuance of the Senior Notes in July 2005, we borrowed $217 million,net of financing costs, repaid the balance on the revolving credit facility andrepaid the remaining $30 million balance on the senior term credit facility. 

 

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Simultaneously, the borrowing base wasreduced from $195 million to $132.5 million to give effect to the issuance ofthe Senior Notes.  In December 2005 the borrowing base was increased to$150 million.  The available funds underour revolving credit facility were $138.5 million at December 31, 2005,and our available cash at December 31, 2005 decreased by $10.4 million fromDecember 31, 2004.

 

Using the revolving credit facility for bothour short-term liquidity and long-term financing needs can cause unusualfluctuations in our reported working capital, depending on the timing of cashreceipts and expenditures.  On a daily basis, we use most of our availablecash to pay down our outstanding balance on the revolving credit facility,which is classified as a non-current liability since we currently have norequired principal reductions.  As we use cash to pay a non-currentliability, our reported working capital decreases.  Conversely, as we drawon the revolving credit facility for funds to pay current liabilities (such aspayables for drilling and operating costs), our reported working capitalincreases.  Also, volatility in oil and gas prices can cause significantfluctuations in reported working capital as we record changes in the fair valueof derivatives from period to period.  For these reasons, the workingcapital covenant related to the revolving credit facility requires us to(i) include the amount of funds available under this facility as a currentasset, (ii) exclude current assets and liabilities related to the fairvalue of derivatives, and (iii) exclude current maturities of vendorfinance obligations, if any, when computing the working capital ratio at anybalance sheet date.

 

Working capital computed for loan compliancepurposes differs from our working capital in accordance with generally acceptedaccounting principles (GAAP).  Since compliance with financial covenantsis a material requirement under the credit facilities, we consider the loancompliance working capital to be useful as a measure of our liquidity becauseit includes the funds available to us under the revolving credit facility andis not affected by the volatility in working capital caused by changes in fairvalue of derivatives.  Our reported working capital deficit increased from$27.6 million at December 31, 2004 to $35.8 million atDecember 31, 2005 due primarily to a combination of factors, includingdecreases in accounts payable, increases in inventory and increases in currentliabilities related to the fair value of derivatives.  After giving effectto the adjustments, our working capital computed for loan compliance purposeswas a positive $136.2 million at December 31, 2005, as compared to apositive $32.9 million at December 31, 2004.  The followingtable reconciles our GAAP working capital to the working capital computed forloan compliance purposes at December 31, 2005 and December 31, 2004.

 
| ** **                                                                             | ** ** | **December 31,  2005** | ** ** | **December 31,  2004** | ** ** |
|----------------------------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                                                             | ** ** | **(In thousands)**     | ** ** |
| Working capital  (deficit) per GAAP                                                    |       | $                           | (35,812    | )                           | $          | (27,566 | ) |
| Add funds  available under the revolving credit facility                               |       | 138,496                     |       | 46,725                      |       |
| Exclude fair  value of derivatives classified as current assets or current liabilities |       | 33,479                      |       | 13,693                      |       |
| Working capital  per loan covenant                                                     |       | $                           | 136,163    |                        | $          | 32,852 |   |

 

Since we use this revolving credit facilityfor both short-term liquidity and long-term financing needs, it is importantthat we comply in all material respects with the loan agreement, includingfinancial covenants that are computed quarterly.  The working capitalcovenant requires us to maintain positive working capital using thecomputations described above.  Another financial covenant under the creditfacility requires us to maintain a ratio of indebtedness to cash flow of nomore than 3 to 1.  While we were in compliance with all financial andnon-financial covenants at December 31, 2005, our increased leverage andreduced liquidity may result in our failing to comply with one or more of thesecovenants in the future.  If we fail to meet any of these loan covenants,we would ask the banks to allow us sufficient time to obtain additional capitalresources through alternative means.  If a suitable arrangement could notbe reached with the banks, the banks could accelerate the indebtedness and seekto foreclose on the pledged assets.  However, the issuance

 

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of the Senior Notes described belowsignificantly increases our liquidity and reduces our dependence on therevolving credit facility.

 

The banks redetermine the borrowing baseunder the revolving credit facility at least twice a year, in May andNovember.  If at any time, the borrowing base is less than the amount ofoutstanding indebtedness, we will be required to (i) pledge additionalcollateral, (ii) prepay the excess in not more than five equal monthlyinstallments, or (iii) elect to convert the entire amount of outstandingindebtedness to a term obligation based on amortization formulas set forth inthe loan agreement.

 

***73⁄4% Senior Notes due2013***

 

In July 2005, we issued, in a privateplacement, $225 million of aggregate principal amount of SeniorNotes.  The Senior Notes were issued at face value and will bear interestat 73⁄4% per year, payable semi-annually on February 1 and August 1 ofeach year, beginning February 1, 2006.  After the payment of typicaltransaction expenses, net proceeds of approximately $217 million were usedto repay amounts outstanding on our secured credit facilities and for generalcorporate purposes, including the funding of planned exploration anddevelopment activities.

 

At any time prior to August 1, 2008, wemay redeem up to 35% of the aggregate principal amount of the Senior Notes withthe proceeds of certain equity offerings at a redemption price of 107.75% ofthe principal amount, plus accrued and unpaid interest.  In addition,prior to August 1, 2009, we may redeem some or all of the Senior Notes ata redemption price equal to 100% of the principal amount of the Senior Notes tobe redeemed, plus a make-whole premium, plus any accrued and unpaidinterest.  On and after August 1, 2009, we may redeem some or all ofthe Senior Notes at redemption prices (expressed as percentages of principalamount) equal to 103.875% for the twelve-month period beginning onAugust 1, 2009, 101.938% for the twelve-month period beginning onAugust 1, 2010, and 100.00% beginning on August 1, 2011, for anyperiod thereafter, in each case plus accrued and unpaid interest.

 

The Indenture governing the Senior Notes restrictsour ability and the ability of our restricted subsidiaries to: (i) borrow money; (ii) issue redeemable and preferred stock;(iii) pay distributions or dividends; (iv) make investments;(v) create liens without securing the Notes; (vi) enter into agreementsthat restrict dividends from subsidiaries; (vii) sell certain assets ormerge with or into other companies; (viii) enter into transactions withaffiliates; (ix) guarantee indebtedness; and (x) enter into new linesof business.  These covenants are subject to a number of importantexceptions and qualifications.

 

Since the Senior Notes have an eight-yearmaturity and bear interest at a fixed rate of 73⁄4%, we expect our effectiveannual interest rate to increase in future periods.

 

***Alternative Capital Resources***

 

Although our base of oil and gas reserves, ascollateral for the revolving credit facility, has historically been our primarycapital resource, we have in the past, and we believe we could in the future,use alternative capital resources, such as asset sales, vendor financingarrangements, and/or public or private issuances of common stock.  We could also issue subordinated debt orpreferred stock in a public or a private placement if we choose to raise capitalthrough either of these markets.  Whilewe believe we would be able to obtain funds through one or more of thesealternatives, if needed, there can be no assurance that these capital resourceswould be available on terms acceptable to us.

 

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***Contractual Obligations and Contingent Commitments***

 

The following table summarizes ourcontractual obligations as of December 31, 2005 by payment due date.

 
| ** **                        | ** ** | **Payments Due by Period** | ** ** |
|-----------------------------------|------------|-------------------------------------------|------------|
| ** **                        | ** ** | **Total**                                 | ** ** | **Less than  1 Year** | ** ** | **1-3 Years** | ** ** | **3-5 Years** | ** ** | **More than 5  Years** | ** ** |
| ** **                        | ** ** | **(In thousands)**                   | ** ** |
| Contractual  obligations:         |       |                                      |       |   |   |   |   |   |   |   |   |
| 73⁄4% Senior Notes (a)         |       | $                                         | 225,000    |   | $ | — |   | $ | — |   | $ | — |   | $ | 225,000 |   |
| Secured bank  credit facility (a) |       | 10,700                                    |       | — |   | 10,700 |   | — |   | — |   |
| Drilling  contracts               |       | 16,258                                    |       | 10,858 |   | 5,400 |   | — |   | — |   |
| Purchase commitments              |       | 8,587                                     |       | 8,587 |   | — |   | — |   | — |   |
| Abandonment  obligations          |       | 19,447                                    |       | — |   | 9,051 |   | — |   | 10,396 |   |
| Lease  obligations                |       | 1,847                                     |       | 1,141 |   | 694 |   | 12 |   | — |   |
| Other                             |       | 19                                        |       | 19 |   | — |   | — |   | — |   |
| Total  contractual obligations    |       | $                                         | 281,858    |   | $ | 20,605 |   | $ | 25,845 |   | $ | 12 |   | $ | 235,396 |   |

 

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(a)           In addition to theprincipal payments presented, we expect to make annual interest payments of$17.4 million on the Senior Notes and approximately $803,000 on thesecured bank credit facility (based on the balances and rates at December 31,2005).

 

Excluded from the table above is ourmark-to-market liability related to commodity and interest ratederivatives.  Our derivative obligations,based on mark-to-market valuations at December 31, 2005, would mature asfollows:  2006 - $33.5 million; 2007- $29.4 million; and 2008 - $20.2 million.

 

**KnownTrends and Uncertainties**

 

***Oiland Gas Production***

As with allcompanies engaged in oil and gas exploration and production, we face thechallenge of natural production decline since oil and gas reserves are adepletable resource.  With each unit ofoil and gas we produce, we are depleting our proved reserve base, so we must beable to conduct successful exploration and development activities or acquireproperties with proved reserves in order to grow our reserve base.  Our production has been on a gradual declinesince 2003 due to the effects of natural production decline, offset in part byreserve additions through exploration and development and acquisitions.  At the present time, we continue to haveapproximately 7,000 Mcfe of production shut-in due to hurricane damage tofacilities suffered in 2005 that we expect to return to production in2006.  We also expect to add productionfrom our exploration and development activities in North and South Louisiana.While we cannot predict the results of our exploration and developmentactivities, we believe that oil and gas production levels in 2006 will becomparable to those in 2005.

 

***Equipmentand Personnel Shortages***

Commodity pricesfor natural gas, natural gas liquids and oil have been on an upward trend since2004.  Higher prices have led toincreased activity in the industry, which in turn has resulted in significantcost increases in almost all areas of our business activities, especially indrilling and production costs.  Drillingrig counts are at historically high levels and qualified rig crews are in shortsupply.  Equipment and labor shortageswere further strained by hurricane damage in the Gulf of Mexico in August andSeptember 2005.

 

Drilling rigs haverecently been in short supply throughout the industry, and we do not foresee anend to this shortage in the near future. In order to secure rig availability for our exploration and developmentdrilling, we have entered into a joint venture to acquire 12 drilling rigs (see*“Liquidity and Capital*

 

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*Resources– Capital Expenditures – Drilling Rig Joint Venture”*) and have entered into an 18-month  contract with another drilling contractor forone rig to be utilized in North Louisiana.

 

Raw materialshortages and strong global demand for steel have continued to tighten steelsupplies and have caused supplies of casing, tubing and other surface andsubsurface equipment to decrease and costs to increase.  During 2005, we increased our equipmentinventory by $38.6 million in an effort to secure the levels of inventory weneed to conduct our drilling programs.

 

We cannotaccurately predict the duration and extent of these equipment and personnelshortages; however, any significant escalation in shortages can have an adverseaffect on our financial condition, results of operations and cash flows.

 

**Applicationof Critical Accounting Policies and Estimates**

 

***Summary***

 

In this section,we will identify the critical accounting policies we follow in preparing ourfinancial statements and disclosures. Many of these policies require us to make difficult, subjective andcomplex judgments in the course of making estimates of matters that areinherently imprecise.  We explain thenature of these estimates, assumptions and judgments, and the likelihood thatmaterially different amounts would be reported in our financial statementsunder different conditions or using different assumptions.

 

The followingtable lists our critical accounting policies, the estimates and assumptionsthat can have a significant impact on the application of these accountingpolicies, and the financial statement accounts affected by these estimates andassumptions.

 
| **Accounting Policies**                              | ** ** | **Estimates or Assumptions**                                                                                                                                   | ** ** | **Accounts Affected**                                                                                                                                                                                                                                |
|-----------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                                      |       |                                                                                                                                                                     |       |                                                                                                                                                                                                                                                      |
| Successful  efforts accounting for oil and gas properties |       | •   Reserve estimates

•   Valuation of unproved properties

•   Judgment  regarding status of inprogress exploratory wells |       | •   Oil and gas properties

•   Accumulated DD&A*

•   Provision for DD&A

•    Impairment of  unproved properties

•    Abandonment  costs (dry hole costs) |
|                                                      |       |                                                                                                                                                                     |       |                                                                                                                                                                                                                                                      |
| Impairment of  proved properties                          |       | •   Reserve  estimates and related present value of future net revenues                                                                                   |       | •   Oil and gas properties

•   Accumulated DD&A

•   Impairment of proved  properties                                                                                                                   |
|                                                      |       |                                                                                                                                                                     |       |                                                                                                                                                                                                                                                      |
| Valuation  allowance for net deferred tax assets          |       | •   Estimates  related to utilizing net operating loss (NOL) carryforwards                                                                                |       | •   Deferred tax assets

•   Deferred tax liabilities

•   Deferred income taxes                                                                                                                             |
|                                                      |       |                                                                                                                                                                     |       |                                                                                                                                                                                                                                                      |
| Asset retirement  obligations                             |       | •   Estimates of  the present value of future abandonment costs                                                                                           |       | •   Abandonment  obligations (non-current liability)

•   Oil and gas properties

•   Accretion of discount expense                                                                                          |

 

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*    DD&A means depreciation,depletion and amortization.

 

***Significant Estimates and Assumptions***

 

***Oil and gas reserves***

Reserve engineering is a subjective process of estimating undergroundaccumulations of oil and gas that cannot be measured in an exact manner.  The accuracy of a reserve estimate depends onthe quality of

 

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available geological and engineering data, the precision of theinterpretation of that data, and judgment based on experience andtraining.  Annually, we engageindependent petroleum engineering firms to evaluate our oil and gasreserves.  As a part of this process, ourinternal reservoir engineer and the independent engineers exchange informationand attempt to reconcile any material differences in estimates and assumptions.  While we believe this reconciliation processimproves the accuracy of the reserve estimates by reducing the likelihood of amaterial error in judgment, it is possible that in exchanging information, ourinternal reservoir engineer could influence the independent engineer’sestimates and assumptions.

 

The techniques used in estimating reserves usually depend on the natureand extent of available data, and the accuracy of the estimates varyaccordingly.  As a general rule, thedegree of accuracy of reserve estimates varies with the reserve classificationand the related accumulation of available data, as shown in the followingtable.

 
| **Type of Reserves** | ** ** | **Nature of Available Data**   | ** ** | **Degree of Accuracy** |
|--------------------------------|------------|-----------------------------------------------|------------|----------------------------------|
| Proved undeveloped             |       | Data from offsetting wells,  seismic data     |       | Least accurate                   |
|                           |       |                                          |       |                             |
| Proved developed nonproducing  |       | Logs, core samples, well tests, pressure data |       | More accurate                    |
|                           |       |                                          |       |                             |
| Proved developed producing     |       | Production history, pressure data over time   |       | Most accurate                    |

 

Assumptions as tofuture commodity prices and operating and capital costs also play a significantrole in estimating oil and gas reserves and the estimated present value of thecash flows to be received from the future production of those reserves.  Volumes of recoverable reserves are affectedby the assumed prices and costs due to what is known as the economic limit(that point in the future when the projected costs and expenses of producingrecoverable reserves exceed the projected revenues from the reserves).  But more significantly, the standardizedmeasure of discounted future net cash flows is extremely sensitive to pricesand costs, and may vary materially based on different assumptions.  SEC financial accounting and reportingstandards require that pricing parameters be tied to the price received for oiland natural gas on the effective date of the reserve report.  This requirement can result in significantchanges from period to period given the volatile nature of oil and gas productprices, as illustrated in the following table.

 
| ** **         | ** ** | **Proved  Reserves**       | ** ** | **Average  Price** | ** ** | **Standardized  Measure  of Discounted** | ** ** |
|--------------------|------------|----------------------------|------------|--------------------|------------|-----------------------------------------------|------------|
| ** **         | ** ** | **Oil (a)  (MMBbls)** | ** ** | **Gas  (Bcf)**     | ** ** | **Oil (a)  ($/Bbl)**                     | ** ** | **Gas  ($/Mcf)** | ** ** | **Future  Net Cash Flows** | ** ** |
| ** **         | ** ** | ** **                 | ** ** | ** **         | ** ** | ** **                                    | ** ** | ** ** | ** ** | **(In millions)** | ** ** |
| As of December 31: |       |                       |       |               |       |                                          |       |   |   |   |   |
| 2005               |       | 27.8                       |       | 126.8              |       | $                                             | 57.85      |   | $ | 10.65 |   | $ | 753.7 |   |
| 2004               |       | 26.8                       |       | 138.3              |       | $                                             | 41.48      |   | $ | 5.59 |   | $ | 500.2 |   |
| 2003               |       | 10.3                       |       | 62.9               |       | $                                             | 30.45      |   | $ | 5.61 |   | $ | 253.0 |   |

 

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(a)     Includesnatural gas liquids

 

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***Valuation of unproved properties***

Placing a fair market value on unproved properties (also known as prospects)is very subjective since there is no quoted market for undeveloped exploratoryprospects.  The negotiated price of anyprospect between a willing seller and willing buyer depends on the specificfacts regarding the prospect, including:

 

•       The location of the prospect in relationto known fields and reservoirs, available markets and transportation systemsfor oil and gas production in the vicinity, and other critical services;

 

•       The nature and extent of geological andgeophysical data on the prospect;

 

•       The terms of the leases holding theacreage in the prospect, such as ownership interests, expiration terms, delayrental obligations, depth limitations, drilling and marketing restrictions, andsimilar terms;

 

•       The prospect’s risk-adjusted potential forreturn on investment, giving effect to such factors as potential reserves to bediscovered, drilling and completion costs, prevailing commodity prices, andother economic factors; and

 

•       The results of drilling activity in closeproximity to the prospect that could either enhance or condemn the prospect’schances of success.

 

***AssetRetirement Obligations***

We are required bySFAS 143 “Accounting for Asset Retirement Obligations” to estimate the presentvalue of the amount we will incur to plug, abandon and remediate our producingproperties at the end of their productive lives, in accordance with applicablestate laws.  We compute our liability forasset retirement obligations by calculating the present value of estimatedfuture cash flows related to each property. This requires us to use significant assumptions, including currentestimates of plugging and abandonment costs, annual inflation of these costs,the productive lives of wells and our risk-adjusted interest rate. Changes inany of these assumptions can result in significant revisions to the estimatedasset retirement obligations.

 

***Valuationallowance for NOL Carryforwards***

In computing ourprovision for income taxes, we must assess the need for a valuation allowanceon deferred tax assets, which consist primarily of net operating loss (“NOL”)carryforwards.  For federal income taxpurposes, these NOL carryforwards, if unused, expire 15 to 20 years from theyear of origination.  Generally, weassess our ability to fully utilize these carryforwards by comparing expectedfuture book income to expected future taxable income based on the assumptionthat we will produce our existing reserves, as scheduled for production in ourreserve report, under current economic conditions.  If future book income does not exceed futuretaxable income by amounts sufficient to utilize NOLs before they expire, wemust impair the resulting deferred tax asset. These computations are inherently imprecise due to the extensive use ofestimates and assumptions.  As a result,we may make additional impairments to allow for such uncertainties.

 

***Effectsof Estimates and Assumptions on Financial Statements***

 

Generally acceptedaccounting principles do not require, or even permit, the restatement ofpreviously issued financial statements due to changes in estimates unless suchestimates were unreasonable or did not comply with applicable SEC accountingrules.  We are required to use our bestjudgment in making estimates and assumptions, taking into consideration thebest and most current data available to us at the time of the estimate.  At each accounting period, we make a newestimate using new data, and continue the cycle.  You should be aware that estimates preparedat various times may be substantially different due to new or additionalinformation.  While an estimate made atone point in time may differ from an estimate made at a later date, both may beproper due to the differences in available information or assumptions.  In this section, we will discuss the effectsof different estimates on our financial statements.

 

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***Provisionfor DD&A***

We compute our provision for DD&A on a unit-of-productionmethod.  Each quarter, we use thefollowing formulas to compute the provision for DD&A for each of ourproducing properties (or appropriate groups of properties based on geographicaland geological similarities):

 

•       DD&A Rate = Unamortized Cost   ̧  Beginning of Period Reserves

 

•       Provision for DD&A = DD&ARate   ́  Current Period Production

 

Reserve estimates have a significant impact on the DD&A rate.  If reserve estimates for a property or groupof properties are revised downward in future periods, the DD&A rate forthat property or group of properties will increase as a result of the revision.  Alternatively, if reserve estimates arerevised upward, the DD&A rate will decrease.

 

***Impairmentof Unproved Properties***

Each quarter, we review our unproved oil and gas properties to determineif there has been, in our judgment, an impairment in value of each prospectthat we consider individually significant. To the extent that the carrying cost of a prospect exceeds its estimatedvalue, we make a provision for impairment of unproved properties, and recordthe provision as abandonments and impairments within exploration costs on ourstatement of operations.  If the value isrevised upward in a future period, we do not reverse the prior provision, andwe continue to carry the prospect at a net cost that is lower than itsestimated value.  If the value is reviseddownward in a future period, an additional provision for impairment is made inthat period.

 

***Impairmentof Proved Properties***

Each quarter, we assess our producing properties for impairment.  If we determine there has been an impairmentin any of our producing properties (or appropriate groups of properties basedon geographical and geological similarities), we will estimate the value ofeach affected property.  In accordancewith applicable accounting standards, the value for this purpose is a fairvalue instead of a standardized reserve value as prescribed by the SEC.  We attempt to value each property usingreserve classifications and pricing parameters similar to what a willing sellerand willing buyer might use.  Theseparameters may include escalations of prices instead of constant pricing, andthey may also include the risk-adjusted value of reserves that do not qualifyas proved reserves.  To the extent thatthe carrying cost for the affected property exceeds its estimated value, wemake a provision for impairment of proved properties.  If the value is revised upward in a futureperiod, we do not reverse the prior provision, and we continue to carry theproperty at a net cost that is lower than its estimated value.  If the value is revised downward in a futureperiod, an additional provision for impairment is made in that period.  Accordingly, the carrying costs of producingproperties on our balance sheet will vary from (and often will be less than)the present value of proved reserves for these properties.

 

***JudgmentRegarding Status of In-Progress Wells***

On a quarterly basis, wereview the status of each in-progress well to determine the proper accountingtreatment under the successful efforts method of accounting.  Cumulative costs on in-progress wells remaincapitalized until their productive status becomes known.  If an in-progress exploratory well is foundto be unsuccessful (often referred to as a dry hole) prior to the issuance ofour financial statements, we write-off all costs incurred through the balancesheet date to abandonments and impairments expense, a component of explorationcosts.  Costs incurred on that dry holeafter the balance sheet date are charged to exploration costs in the period incurred.

 

Occasionally, we areunable to make a final determination about the productive status of a wellprior to issuance of our financial statements. In these cases, we leave the well classified as in-progress until wehave had sufficient time to conduct additional completion or testing operationsand to evaluate the pertinent G&G and engineering data obtained.  At the time when we are able to make a finaldetermination of a well’s productive status, the well is removed from thein-progress status and the proper accounting treatment is recorded.

 

45

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***Valuationallowance for NOL carryforwards***

Each quarter, we assessour ability to utilize NOL carryforwards. An increase in the valuation allowance from one period to the next willresult in a decrease in our net deferred tax assets and a decrease inearnings.  Similarly, a decrease in thevaluation allowance will result in an increase in our net deferred tax assetsand an increase in earnings.

 

This process requiresestimates and assumptions which are complex and may vary materially from ouractual ability to utilize NOL carryforwards in the future.  Also, the current tax laws in this area arecomplicated due to the impact of alternative minimum tax on the utilization ofNOL carryforwards.  As a mitigatingfactor, as long as we are actively drilling for new production, we have sometax planning strategies available to us, such as elective capitalization ofintangible drilling costs, to help us utilize these NOL carryforwards beforethey expire.

 

***AssetRetirement Obligations***

Our asset retirementobligation is recorded as a liability at its estimated present value as of theasset’s inception, with an offsetting increase to oil and gas properties.Periodic accretion of discount of the estimated liability is recorded as anexpense in the statement of operations. During 2005, we increased our estimated asset retirement obligations by$2 million, or approximately 10% of the asset retirement obligations atDecember 31, 2004, based on a review of current plugging and abandonmentcosts. Revisions to the asset retirement obligation are recorded with anoffsetting change to producing properties, resulting in prospective changes todepreciation, depletion and amortization expense and accretion of discount.Because of the subjectivity of assumptions and the relatively long lives ofmost of our wells, the costs to ultimately retire our wells may varysignificantly from prior estimates.

 

**RecentAccounting Pronouncements**

 

In June 2005, the Emerging Issues Task Force (“EITF”)reached consensus on Issue 04-5, subject to ratification by the FinancialAccounting Standards Board (“FASB”), regarding when a limited partnershipshould be consolidated by its general partner. The proposed framework presumes that a sole general partner in a limitedpartnership controls the limited partnership. The presumption of control can be overcome if the limited partners have(i) the substantive ability to remove the sole general partner or otherwisedissolve the limited partnership or (ii) substantive participating rights.  The EITF has concluded that a general partnerlacks control if the limited partners can remove the general partner with asimple majority vote.  We are the generalpartner of several oil and gas limited partnerships and proportionatelyconsolidate interest in these partnerships. We are currently reviewing the applicable provisions of the partnershipagreements to determine the impact that EITF 04-5 may have on ourconsolidated financial statements.  Forexisting partnerships, EITF 04-5 will be effective for our consolidatedfinancial statements issued after January 1, 2006.  EITF 04-5 is effective for newly createdor modified limited partnerships subsequent to June 29, 2005.  If we determine that the limited partners donot have the substantive ability to remove the general partner in accordancewith EITF Issue 04-5, we will be required to fully consolidate the limitedpartnerships, with the interest we do not own reflected as minority interest.  This would have no impact to our future netincome from the current method of accounting for oil and gas limitedpartnerships using proportionate consolidation.

 

In December 2004, the FASB issued Statement ofFinancial Accounting Standards No. 123 (revised 2004) “Share-BasedPayments” (“SFAS 123R”). SFAS 123R requires that the cost from all share-based paymenttransactions, including stock options, be recognized in the financialstatements at fair value.  We currentlyuse the intrinsic-value method to account for these share-based payments.  For public companies, SFAS 123R iseffective for fiscal years beginning after June 15, 2005.  We will adopt the provisions of thisstatement in the first quarter of 2006.  Wehave accounted for options which were repriced in 1999 as variable stock optionswhereby compensation expense has been recognized through December 31, 2005for unexercised options.  In accordancewith SFAS 123R, we will cease accounting for these options as variablestock options upon the adoption date. Since all of our outstanding options are fully vested atDecember 31,

 

46

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2005, no future compensation expense will berecognized under SFAS 123R unless the options are modified.  Accordingly, future compensation expense tobe recognized under SFAS 123R will be determined by the grant date fairvalue of future awards.

 

In April 2005, the FASB issued Staff PositionNo. 19-1 (“FSP 19-1”). FSP 19-1 amends the present guidance in SFAS 19, paragraphs 31and 34, regarding when exploratory drilling costs pending determination ofproved reserves can be carried as an asset of an oil and gas company that usesthe successful efforts accounting method. We were required to adopt FSP 19-1, including its disclosures,effective July 1, 2005.  The adoption ofFSP 19-1 did not have a significant impact on our results ofoperations.  At December 31, 2005and December 31, 2004, we had capitalized $10.3 million and$5.4 million, respectively, of exploratory drilling costs applicable towells that were pending determination of proved reserves.  Substantially all of the December 31,2004 capitalized costs were subsequently classified as non-productive.

## ** **

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## **Item7A** -             Quantitative and QualitativeDisclosure About Market Risks

 

Our business is impacted by fluctuationsin commodity prices and interest rates. The following discussion is intended to identify the nature of thesemarket risks, describe our strategy for managing such risks, and to quantifythe potential affect of market volatility on our financial condition andresults of operations.

 

**Oil and Gas Prices**

 

Our financial condition, results ofoperations, and capital resources are highly dependent upon the prevailingmarket prices of, and demand for, oil and natural gas.  These commodity prices are subject to widefluctuations and market uncertainties due to a variety of factors that arebeyond our control.  These factors includethe level of global demand for petroleum products, foreign supply of oil andgas, the establishment of and compliance with production quotas byoil-exporting countries, weather conditions, the price and availability ofalternative fuels, and overall economic conditions, both foreign anddomestic.  We cannot predict future oiland gas prices with any degree of certainty. Sustained weakness in oil and gas prices may adversely affect ourfinancial condition and results of operations, and may also reduce the amountof net oil and gas reserves that we can produce economically.  Any reduction in reserves, includingreductions due to price fluctuations, can reduce the borrowing base under ourrevolving credit facility and adversely affect our liquidity and our ability toobtain capital for our exploration and development activities.  Similarly, any improvements in oil and gasprices can have a favorable impact on our financial condition, results ofoperations and capital resources.  Basedon December 31, 2005 reserve estimates, we project that a $1.00 drop inthe price per Bbl of oil and a $.50 drop in the price per Mcf of gas wouldreduce our gross revenues for the year ending December 31, 2006 by $11 million.

 

From time to time, we utilizecommodity derivatives, consisting primarily of swaps, floors and collars toattempt to optimize the price received for our oil and natural gasproduction.  When using swaps to hedgeour oil and natural gas production, we receive a fixed price for the respectivecommodity and pay a floating market price as defined in each contract(generally NYMEX futures prices), resulting in a net amount due to or from thecounterparty.  When purchasing floors, wereceive a fixed price (put strike price) if the market price falls below theput strike price for the respective commodity. If the market price is greater than the put strike price, no paymentsare due from either party.  Costlesscollars are a combination of puts and calls, and contain a fixed floor price(put strike price) and ceiling price (call strike price).  If the market price for the respectivecommodity exceeds the call strike price or falls below the put strike price,then we receive the fixed price and pay the market price.  If the market price is between the call andthe put strike prices, no payments are due from either party.  The commodity derivatives we use differ fromfutures contracts in that there is not a contractual obligation that requiresor permits the future physical delivery of the hedged products.  We do not enter into commodity derivativesfor trading purposes.  In addition tocommodity derivatives, we may, from time to time, sell a portion of our gasproduction under short-term contracts at fixed prices.

 

The decision to initiate orterminate commodity hedges is made by management based on its expectation offuture market price movements.  We haveno set goals for the percentage of our production we hedge and we do not useany formulas or triggers in deciding when to initiate or terminate ahedge.  If we enter into swaps or collarsand the floating market price at the settlement date is higher than the fixedprice or the fixed ceiling price, we will forego revenue we would haveotherwise received.  If we terminate aswap, collar or floor because we anticipate future increases in market prices,we may be exposed to downside risk that would not have existed otherwise.

 

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The following summarizes information concerning theCompany’s net positions in open commodity derivatives applicable to periodssubsequent to December 31, 2005.  Thesettlement prices of commodity derivatives are based on NYMEX futures prices.

 

***Collars:***

*** ***
| ** **          | ** ** | **Gas**                | ** ** | **Oil**   | ** ** |
|---------------------|------------|------------------------|------------|-----------|------------|
| ** **          | ** ** | **MMBtu ****(a)** | ** ** | **Floor** | ** ** | **Ceiling** | ** ** | **Bbls** | ** ** | **Floor** | ** ** | **Ceiling** | ** ** |
| Production  Period: |       |                   |       |      |       |   |   |   |   |   |   |   |   |
| 1st Quarter  2006   |       | 561,000                |       | $         | 4.00       |   | $ | 5.21 |   | 157,000 |   | $ | 23.00 |   | $ | 25.32 |   |
| 2nd Quarter  2006   |       | 551,000                |       | $         | 4.00       |   | $ | 5.21 |   | 156,000 |   | $ | 23.00 |   | $ | 25.32 |   |
| 3rd Quarter  2006   |       | 456,000                |       | $         | 4.00       |   | $ | 5.21 |   | 150,000 |   | $ | 23.00 |   | $ | 25.32 |   |
| 4th Quarter  2006   |       | 456,000                |       | $         | 4.00       |   | $ | 5.21 |   | 150,000 |   | $ | 23.00 |   | $ | 25.32 |   |
| 2007                |       | 1,831,000              |       | $         | 4.00       |   | $ | 5.18 |   | 562,000 |   | $ | 23.00 |   | $ | 25.20 |   |
| 2008                |       | 1,279,000              |       | $         | 4.00       |   | $ | 5.15 |   | 392,000 |   | $ | 23.00 |   | $ | 25.07 |   |
|                |       | 5,134,000              |       |      |       |   |   | 1,567,000 |   |   |   |   |   |

 

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(a)        OneMMBtu equals one Mcf at a Btu factor of 1,000.

 

We use a sensitivityanalysis technique to evaluate the hypothetical effect that changes in themarket value of oil and gas may have on the fair value of our commodityderivatives.  A $1 per barrel changein the price of oil and a $.50 per MMBtu change in the price of gas wouldchange the fair value of our outstanding commodity derivatives atDecember 31, 2005 by approximately $3.7 million.

** **

**Interest Rates**

 

All of our outstanding bankindebtedness at December 31, 2005 is subject to market rates of interest asdetermined from time to time by the banks pursuant to our creditfacilities.  We may designate borrowingsunder our revolving credit facility as either “Base Rate Loans” or “EurodollarLoans.”  Base Rate Loans bear interest ata fluctuating rate that is linked to the discount rates established by theFederal Reserve Board.  Eurodollar Loansbear interest at a fluctuating rate that is linked to LIBOR.  Any increases in these interest rates canhave an adverse impact on our results of operations and cash flow.

 

We are a party to interest rateswaps that were acquired in connection with the SWR acquisition.  Under these derivatives, we pay a fixed ratefor the notional principal balances and receive a floating market rate based onLIBOR.  The following summarizesinformation concerning our net positions in open interest rate swaps applicableto periods subsequent to December 31, 2005.

 

***Interest Rate Swaps:***

*** ***
| ** **                            | ** ** | **Principal  Balance** | ** ** | **Fixed  Libor  Rates** | ** ** |
|---------------------------------------|------------|------------------------|------------|-------------------------|------------|
| Period:                               |       |                   |       |                    |       |
| January 1, 2006  to November 1, 2006  |       | $                      | 55,000,000 |                    | 4.29       | % |
| November 1, 2006  to November 1, 2007 |       | $                      | 50,000,000 |                    | 5.19       | % |
| November 1, 2007  to November 1, 2008 |       | $                      | 45,000,000 |                    | 5.73       | % |

 

## **Item8**-          Financial Statements andSupplementary Data

 

For the financial statements and supplementary data required by thisItem 8, see the Index to Consolidated Financial Statements includedelsewhere in this Form 10-K.

 

 

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**Item 9-****                                                       Changesin and Disagreements with Accountants on Accounting and Financial Disclosure**

 

None.

 

**Item 9A -****                                              Controls and Procedures**

 

**DisclosureControls and Procedures**

 

InSeptember 2002, our Board of Directors adopted a policy designed to establishdisclosure controls and procedures that are adequate to provide reasonableassurance that our management will be able to collect, process and discloseboth financial and non-financial information, on a timely basis, in our reportsto the SEC and other communications with our stockholders.  Disclosure controls and procedures includeall processes necessary to ensure that material information is recorded,processed, summarized and reported within the time periods specified in theSEC’s rules and forms, and is accumulated and communicated to our management,including our chief executive and chief financial officers, to allow timelydecisions regarding required disclosures.

 

Withrespect to our disclosure controls and procedures:

 

•                                          managementhas evaluated the effectiveness of our disclosure controls and procedures as ofthe end of the period covered by this report;

 

•                                          thisevaluation was conducted under the supervision and with the participation ofour management, including our chief executive and chief financial officers; and

 

•                                          itis the conclusion of our chief executive and chief financial officers thatthese disclosure controls and procedures are effective in ensuring thatinformation that is required to be disclosed by the Company in reports filed orsubmitted with the SEC is recorded, processed, summarized and reported withinthe time periods specified in the rules and forms established by the SEC.

 

**Internal Control Over FinancialReporting**

 

Managementdesigned our internal control over financial reporting to provide reasonableassurance regarding the reliability of our financial reporting and thepreparation of our financial statements for external purposes in accordancewith generally accepted accounting principles. Our internal control over financial reporting includes those policiesand procedures that:

 

•                                          pertainto the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of our assets;

•                                          providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally acceptedaccounting principles, and that our receipts and expenditures are being madeonly in accordance with authorizations of management and our Board ofDirectors; and

•                                          providereasonable assurance regarding prevention or timely detection of anyunauthorized acquisition, use or disposition of our assets that could have amaterial effect on the financial statements.

 

Becauseof its inherent limitations, internal control over financial reporting may notprevent or detect misstatements.  Also,projections of any evaluation of effectiveness to future periods are subject to

 

50

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the risk that controls may becomeinadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate.

 

**Changes inInternal Control Over Financial Reporting**

 

Nochanges in internal control over financial reporting were made during thequarter ended December 31, 2005 that have materially affected, or arereasonably likely to materially affect, our internal control over financialreporting.

 

**Management’sReport on Internal Control Over Financial Reporting**

 

Ourmanagement is responsible for establishing and maintaining adequate internalcontrol over financial reporting as defined in Rules 13a-15(f) and 15d-15(f)under the Securities Exchange Act of 1934. Management assessed the effectiveness of our internal control overfinancial reporting as of December 31, 2005. In making this assessment, management used the criteria set forth by theCommittee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control-Integrated Framework. Based on this assessment, management has concluded that, as of December31, 2005, our internal control over financial reporting is effective based onthose criteria.

 

KPMGLLP has issued an attestation report on management’s assessment of internalcontrol over financial reporting, the contents of which are printed below.

 

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** **

**Report of Independent Registered Public Accounting Firm**

 

The Board of Directors and Stockholders

Clayton Williams Energy, Inc.:

 

We have audited management’s assessment,included in the accompanying Management’s Report on Internal Control OverFinancial Reporting, that Clayton Williams Energy, Inc. (Company) maintainedeffective internal control over financial reporting as of December 31, 2005,based on criteria established in Internal Control—Integrated Framework issuedby the Committee of Sponsoring Organizations of the Treadway Commission (COSO).The Company’s management is responsible for maintaining effective internalcontrol over financial reporting and for its assessment of the effectiveness ofinternal control over financial reporting. Our responsibility is to express anopinion on management’s assessment and an opinion on the effectiveness of theCompany’s internal control over financial reporting based on our audit.

 

We conducted our audit inaccordance with the standards of the Public Company Accounting Oversight Board(United States). Those standards require that we plan and perform the audit toobtain reasonable assurance about whether effective internal control overfinancial reporting was maintained in all material respects. Our audit includedobtaining an understanding of internal control over financial reporting,evaluating management’s assessment, testing and evaluating the design andoperating effectiveness of internal control, and performing such otherprocedures as we considered necessary in the circumstances. We believe that ouraudit provides a reasonable basis for our opinion.

 

A company’s internal control overfinancial reporting is a process designed to provide reasonable assuranceregarding the reliability of financial reporting and the preparation offinancial statements for external purposes in accordance with generallyaccepted accounting principles.  Acompany’s internal control over financial reporting includes those policies andprocedures that (1) pertain to the maintenance of records that, in reasonabledetail, accurately and fairly reflect the transactions and dispositions of theassets of the company; (2) provide reasonable assurance that transactions arerecorded as necessary to permit preparation of financial statements inaccordance with generally accepted accounting principles, and that receipts andexpenditures of the company are being made only in accordance withauthorizations of management and directors of the company; and (3) providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company’s assets that could have amaterial effect on the financial statements.

 

Because of its inherentlimitations, internal control over financial reporting may not prevent ordetect misstatements.  Also, projectionsof any evaluation of effectiveness to future periods are subject to the risk thatcontrols may become inadequate because of changes in conditions, or that thedegree of compliance with the policies or procedures may deteriorate.

 

In our opinion, management’sassessment that the Company maintained effective internal control overfinancial reporting as of December 31, 2005, is fairly stated, in all materialrespects, based on criteria established in Internal Control—IntegratedFramework issued by the Committee of Sponsoring Organizations of the TreadwayCommission (COSO). Also, in our opinion, the Company maintained, in allmaterial respects, effective internal control over financial reporting as ofDecember 31, 2005, based on criteria established in Internal Control—IntegratedFramework issued by the Committee of Sponsoring Organizations of the TreadwayCommission (COSO).

 

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We also have audited, in accordancewith the standards of the Public Company Accounting Oversight Board (UnitedStates), the consolidated balance sheets of Clayton Williams Energy, Inc. andsubsidiaries as of December 31, 2005 and 2004, and the relatedconsolidated  statements of operations,stockholders’ equity, and cash flows for each of the years in the three-yearperiod ended December 31, 2005, and our report dated March 15, 2006, expressedan unqualified opinion on those consolidated financial statements.

 

KPMG LLP

 

 

Dallas, Texas

March 15, 2006

 

 

**Item 9B -               OtherInformation**

 

None.

 

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** **

**PART III**

 

**Item 10 -                Directors and ExecutiveOfficers of the Registrant**

 

Information required by this Item isincorporated by reference to our definitive proxy statement, which will befiled with the SEC no later than April 30, 2006.

 

**Item 11 -                ExecutiveCompensation**

 

Information required by this Item isincorporated by reference to our definitive proxy statement, which will befiled with the SEC no later than April 30, 2006.

 

**Item 12 -                Security Ownership of CertainBeneficial Owners and Management**

 

Information required by this Item isincorporated by reference to our definitive proxy statement, which will befiled with the SEC no later than April 30, 2006.

 

**Item 13 -                Certain Relationships andRelated Transactions**

 

Information required by this Item isincorporated by reference to our definitive proxy statement, which will befiled with the SEC no later than April 30, 2006.

 

**Item 14 -                PrincipalAccountant Fees and Services**

 

Information required by this Item isincorporated by reference to our definitive proxy statement, which will befiled with the SEC no later than April 30, 2006.

 

**PART IV**

 

**Item 15 -                Exhibitsand Financial Statement Schedules**

 

**FinancialStatements and Schedules**

 

For a list of the consolidated financial statements and financialstatement schedules filed as part of this Form 10-K, see the Index toConsolidated Financial Statements on page F-1.

 

**Exhibits**

 

            Thefollowing exhibits are filed as a part of this Report, with each exhibit thatconsists of or includes a management contract or compensatory plan orarrangement being identified with a “†”:

 
| **Exhibit** | ** ** | ** **                                                                                                                                                                                                                                       |
|-------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number**  | ** ** | **Description of Exhibit**                                                                                                                                                                                                             |
| ** **  | ** ** | ** **                                                                                                                                                                                                                                       |
| **2.1       |       | Agreement  and Plan of Merger among Clayton Williams Energy, Inc. and Southwest  Royalties, Inc. dated May 3, 2004, filed as Exhibit 2.1 to the Company’s  Current Report on Form 8-K filed with the Commission on June 3, 2004†† |
|        |       |                                                                                                                                                                                                                                             |
| **3.1       |       | Second  Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to  the Company’s Form S-2 Registration Statement, Commission File No. 333-13441                                                                         |

 

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| **Exhibit**  | ** ** | ** **                                                                                                                                                                                                                                                                              |
|--------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number**   | ** ** | **Description of Exhibit**                                                                                                                                                                                                                                                    |
|         |       |                                                                                                                                                                                                                                                                                    |
| **3.2        |       | Certificate  of Amendment of Second Restated Certificate of Incorporation of Clayton  Williams Energy, Inc., filed as Exhibit 3.1 to the Company’s Form 10-Q for  the period ended September 30, 2000††                                                                  |
|         |       |                                                                                                                                                                                                                                                                                    |
| **3.3        |       | Corporate  Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to  the Company’s Current Report on Form 8-K filed with the Commission on June 1,  2005††                                                                                           |
|         |       |                                                                                                                                                                                                                                                                                    |
| **4.1        |       | Stock  Purchase Agreement dated May 19, 2004 by and among Clayton Williams Energy,  Inc. and various institutional investors, filed as Exhibit 4 to the Company’s  Current Report on Form 8-K filed with the Commission on June 2, 2004††                                |
|         |       |                                                                                                                                                                                                                                                                                    |
| **4.2        |       | Indenture,  dated July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary  Guarantors and Wells Fargo Bank, National Association, as Trustee, filed as  Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the  Commission on July 22, 2005†† |
|         |       |                                                                                                                                                                                                                                                                                    |
| **4.3        |       | Registration  Rights Agreement dated July 20, 2005, among Clayton Williams Energy, Inc.,  the Subsidiary Guarantors and J.P. Morgan Securities Inc., filed as Exhibit  4.2 to the Company’s Current Report on Form 8-K filed with the Commission on  July 22, 2005††     |
|         |       |                                                                                                                                                                                                                                                                                    |
| **10.1       |       | Amended  and Restated Credit Agreement dated as of May 21, 2004 among Clayton Williams  Energy, Inc., et al, and Bank One, NA, et al, filed as Exhibit 10.1 to the  Company’s Current Report on Form 8-K/A filed with the Commission on June 23,  2004††                 |
|         |       |                                                                                                                                                                                                                                                                                    |
| **10.2       |       | First  Amendment to Amended and Restated Credit Agreement dated July 18, 2005, filed  as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the  Commission on July 20, 2005††                                                                          |
|         |       |                                                                                                                                                                                                                                                                                    |
| *10.3        |       | Second  Amendment to Amended and Restated Credit Agreement dated December 30,  2005                                                                                                                                                                                                |
|         |       |                                                                                                                                                                                                                                                                                    |
| **10.4       |       | Senior Term Credit  Agreement dated as of May 21, 2004 among Clayton Williams Energy, Inc., et  al, and Bank One, NA, et al, filed as Exhibit 10.2 to the Company’s Current  Report on Form 8-K/A filed with the Commission on June 23, 2004                                       |
|         |       |                                                                                                                                                                                                                                                                                    |
| **10.5† |       | 1993  Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8  Registration Statement, Commission File No. 033-68318                                                                                                                                              |
|         |       |                                                                                                                                                                                                                                                                                    |
| **10.6† |       | First  Amendment to 1993 Stock Compensation Plan, filed as Exhibit 10.11 to the  Company’s Form 10-K for the period ended December 31, 1995††                                                                                                                            |
|         |       |                                                                                                                                                                                                                                                                                    |
| **10.7† |       | Second  Amendment to the 1993 Stock Compensation Plan, filed as Exhibit 10.2 to the  Company’s Form S-8 Registration Statement, Commission File No. 33-68318                                                                                                                       |
|         |       |                                                                                                                                                                                                                                                                                    |
| **10.8† |       | Third  Amendment to 1993 Stock Compensation Plan, filed as Exhibit 10.4 to the  Company’s Form S-8 Registration Statement, Commission File No. 333-47232                                                                                                                           |

 

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| **Exhibit**   | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                     |
|---------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number**    | ** ** | **Description of Exhibit**                                                                                                                                                                                                                                                                                                                                           |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.9†  |       | Fourth  Amendment to 1993 Stock Compensation Plan, filed as Exhibit 10.5 to the  Company’s Form S-8 Registration Statement, Commission File No. 333-47232                                                                                                                                                                                                                 |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.10† |       | Fifth  Amendment to 1993 Stock Compensation Plan                                                                                                                                                                                                                                                                                                                               |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.11† |       | Outside  Directors Stock Option Plan, filed as Exhibit 10.1 to the Company’s Form S-8  Registration Statement, Commission File No. 33-68316                                                                                                                                                                                                                               |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.12† |       | First  Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.13 to  the Company’s Form 10-K for the period ended December 31, 1995††                                                                                                                                                                                                            |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| *10.13†  |       | Second  Amendment to Outside Directors Stock Option Plan                                                                                                                                                                                                                                                                                                                       |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.14† |       | Bonus  Incentive Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration  Statement, Commission File No. 33-68320                                                                                                                                                                                                                                              |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.15† |       | First  Amendment to Bonus Incentive Plan, filed as Exhibit 10.9 to the Company’s  Form 10-K for the period ended December 31, 1997††                                                                                                                                                                                                                            |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.16† |       | Scudder  Trust Company Prototype Defined Contribution Plan adopted by Clayton Williams  Energy, Inc. effective as of August 1, 2004; filed as Exhibit 10.12 to the  Company’s Form 10-K for the period ended December 31, 2005††                                                                                                                           |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.17† |       | Executive  Incentive Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s  Form S-8 Registration Statement, Commission File No. 33-92834                                                                                                                                                                                                                       |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.18† |       | First  Amendment to Executive Incentive Stock Compensation Plan, filed as  Exhibit 10.16 to the Company’s Form 10-K for the period ended  December 31, 1996††                                                                                                                                                                                         |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.19       |       | Consolidation  Agreement dated May 13, 1993 among Clayton Williams Energy, Inc., Warrior Gas  Co. and the Williams Entities, filed as Exhibit 10.1 to the Company’s  Form S-1 Registration Statement, Commission File No. 033-43350                                                                                                                                  |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.20       |       | Amendment  to Consolidation Agreement dated August 7, 2000 among Clayton Williams  Energy, Inc., Warrior Gas Co., Clayton W. Williams, Jr. and the Williams  Companies, filed as Exhibit 10.1 to the Company’s Form 10-Q for the period  ended September 30, 2000††                                                                                             |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.21       |       | Agreement  dated April 23, 1993 between the Company and Robert C. Lyon, filed as  Exhibit 10.42 to the Company’s Form S-1 Registration Statement,  Commission File No. 033-43350                                                                                                                                                                                     |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.22       |       | Second  Amended and Restated Service Agreement effective March 1, 2005 among Clayton  Williams Energy, Inc. and its subsidiaries, Clayton Williams Ranch Holdings,  Inc., ClayDesta L.P., Clayton Williams Partnership, Ltd. and CWPLCO, Inc.,  filed as Exhibit 99.1 to the Company’s Current Report on Form 8-K filed with  the Commission on March 3, 2005†† |
|          |       |                                                                                                                                                                                                                                                                                                                                                                           |
| **10.23† |       | East  Texas/Chalk Working Interest Trust Agreement dated May 30, 2001, filed as  Exhibit 10.21 to the Company’s Form 10-K for the period ended December 31,  2001††                                                                                                                                                                                             |

 

56

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| **Exhibit**   | ** ** | ** **                                                                                                                                                                                                             |
|---------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number**    | ** ** | **Description of Exhibit**                                                                                                                                                                                   |
|          |       |                                                                                                                                                                                                                   |
| **10.24† |       | Louisiana  Working Interest Trust Agreement dated May 30, 2001, filed as  Exhibit 10.22 to the Company’s Form 10-K for the period ended December  31, 2001††                                       |
|          |       |                                                                                                                                                                                                                   |
| **10.25† |       | New  Mexico Working Interest Trust Agreement dated May 30, 2001, filed as  Exhibit 10.23 to the Company’s Form  10-K for the period ended December 31, 2001††                                      |
|          |       |                                                                                                                                                                                                                   |
| **10.26† |       | South  Texas Working Interest Trust Agreement dated May 30, 2001, filed as  Exhibit 10.24 to the Company’s Form  10-K for the period ended December 31, 2001††                                     |
|          |       |                                                                                                                                                                                                                   |
| **10.27† |       | West  Texas I Working Interest Trust Agreement dated May 30, 2001, filed as  Exhibit 10.25 to the Company’s Form 10-K for the period ended December  31, 2001††                                    |
|          |       |                                                                                                                                                                                                                   |
| **10.28† |       | West  Texas II Working Interest Trust Agreement dated May 30, 2001, filed as  Exhibit 10.26 to the Company’s Form 10-K for the period ended December  31, 2001††                                   |
|          |       |                                                                                                                                                                                                                   |
| **10.29† |       | Agreement  of Limited Partnership of CWEI South Louisiana I, L.P. dated October 1, 2002,  filed as Exhibit 10.27 to the Company’s Form 10-K for the period  ended December 31, 2002††         |
|          |       |                                                                                                                                                                                                                   |
| **10.30† |       | Agreement  of Limited Partnership of CWEI Cotton Valley I, L.P. dated October 1, 2002,  filed as Exhibit 10.28 to the Company’s Form 10-K for the period  ended December 31, 2002††           |
|          |       |                                                                                                                                                                                                                   |
| **10.31† |       | Agreement  of Limited Partnership of CWEI Romere Pass, L.P. dated October 1, 2002, filed  as Exhibit 10.29 to the Company’s Form 10-K for the period ended  December 31, 2002††               |
|          |       |                                                                                                                                                                                                                   |
| **10.32† |       | Agreement  of Limited Partnership of CWEI Longfellow Ranch I, L.P. dated April 1,  2003, filed as Exhibit 10.32 to the Company’s Form 10-K for the period ended  December 31, 2003††          |
|          |       |                                                                                                                                                                                                                   |
| **10.33† |       | Agreement  of Limited Partnership of CWEI South Louisiana II, L.P. effective as of  January 1, 2004, filed as Exhibit 10.29 to the Company’s Form 10-K for  the period ended December 31, 2004††   |
|          |       |                                                                                                                                                                                                                   |
| **10.34† |       | Agreement  of Limited Partnership of CWEI Mississippi I, L.P. effective as of  January 1, 2004, filed as Exhibit 10.30 to the Company’s Form 10-K for  the period ended December 31, 2004††        |
|          |       |                                                                                                                                                                                                                   |
| **10.35† |       | Agreement  of Limited Partnership of Rocky Arroyo, L.P. effective as of January 2,  2005, filed as Exhibit 10.31 to the Company’s Form 10-K for the period ended  December 31, 2004††              |
|          |       |                                                                                                                                                                                                                   |
| **10.36† |       | Agreement  of Limited Partnership of CWEI Mississippi II, L.P. effective as of  January 2, 2005, filed as Exhibit 10.32 to the Company’s Form 10-K for  the period ended December 31, 2004††       |
|          |       |                                                                                                                                                                                                                   |
| **10.37† |       | Agreement  of Limited Partnership of CWEI West Pyle/McGonagill, L.P. effective as of  January 2, 2005, filed as Exhibit 10.33 to the Company’s Form 10-K for  the period ended December 31, 2004†† |

 

57

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| **Exhibit**   | ** ** | ** **                                                                                                                                                                                                                                   |
|---------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number**    | ** ** | **Description of Exhibit**                                                                                                                                                                                                         |
|          |       |                                                                                                                                                                                                                                         |
| **10.38† |       | Agreement  of Limited Partnership of CWEI Destefano, L.P. effective as of  January 2, 2005, filed as Exhibit 10.34 to the Company’s Form 10-K for  the period ended December 31, 2004††                                  |
|          |       |                                                                                                                                                                                                                                         |
| **10.39† |       | Agreement of Limited  Partnership of CWEI South Louisiana III, L.P. effective as of March 1, 2005,  filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with  the Commission on April 14, 2005††          |
|          |       |                                                                                                                                                                                                                                         |
| **10.40† |       | Agreement  of Limited Partnership of CWEI North Louisiana, L.P. effective as of March 1,  2005, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed  with the Commission on April 14, 2005††              |
|          |       |                                                                                                                                                                                                                                         |
| **10.41† |       | Agreement  of Limited Partnership of Floyd Prospect, L.P. effective as of March 1, 2005,  filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with  the Commission on June 3, 2005††                      |
|          |       |                                                                                                                                                                                                                                         |
| **10.42† |       | Amendment  to Agreement dated April 23, 1993 between the Company and  Robert C. Lyon, filed as Exhibit 10.35 to the Company’s Form 10-K  for the period ended December 31, 2004                                               |
|          |       |                                                                                                                                                                                                                                         |
| **10.43† |       | Second  Amendment to Agreement dated April 23, 1993 between the Company and  Robert C. Lyon, filed as Exhibit 10.36 to the Company’s Form 10-K  for the period ended December 31, 2004                                        |
|          |       |                                                                                                                                                                                                                                         |
| **10.44† |       | Form  of stock option agreement for 1993 Stock Compensation Plan, filed as Exhibit  10.32 to the Company’s Form  10-K for the period ended December 31, 2004                                                                            |
|          |       |                                                                                                                                                                                                                                         |
| **10.45† |       | Form  of stock option agreement for Outside Directors Stock Option Plan, filed as  Exhibit 10.38 to the Company’s Form 10-K for the period ended December 31,  2004                                                                     |
|          |       |                                                                                                                                                                                                                                         |
| **10.46       |       | Letter  agreement dated October 20, 2005 between Clayton Williams Energy, Inc. and  Lariat Services, Inc., filed as Exhibit 10.1 to the Company’s Current Report  on Form 8-K filed with the Commission on October 27, 2005†† |
|          |       |                                                                                                                                                                                                                                         |
| **21          |       | Subsidiaries  of the Registrant, filed as Exhibit 21 to the Company’s Form S-4  Registration Statement, Commission File No 333-128065                                                                                              |
|          |       |                                                                                                                                                                                                                                         |
| *23.1         |       | Consent  of KPMG LLP                                                                                                                                                                                                                         |
|          |       |                                                                                                                                                                                                                                         |
| *23.2         |       | Consent  of Williamson Petroleum Consultants, Inc.                                                                                                                                                                                           |
|          |       |                                                                                                                                                                                                                                         |
| *23.3         |       | Consent  of Ryder Scott Company, L.P.                                                                                                                                                                                                        |
|          |       |                                                                                                                                                                                                                                         |
| *24.1         |       | Power  of Attorney                                                                                                                                                                                                                           |
|          |       |                                                                                                                                                                                                                                         |
| *31.1         |       | Certification by the President and Chief Executive  Officer of the Company pursuant to Rule 13a – 14(a) of the  Securities Exchange Act of 1934                                                                               |
|          |       |                                                                                                                                                                                                                                         |
| *31.2         |       | Certification by the Chief Financial Officer of the  Company pursuant to Rule 13a – 14(a) of the Securities Exchange Act  of 1934                                                                                             |

 

58

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| *32.1 |   | Certifications by the Chief Executive Officer and  Chief Financial Officer of the Company pursuant to  18 U.S.C. § 1350 |
|-------|--------|---------------------------------------------------------------------------------------------------------------------------------------------|

 

----

| *            |   | Filed herewith                                                                                                  |
|--------------|--------|-----------------------------------------------------------------------------------------------------------------|
| **           |   | Incorporated by reference to  the filing indicated                                                              |
| †       |   | Identifies an Exhibit that  consists of or includes a management contract or compensatory plan or  arrangement. |
| †† |   | Filed under the Company’s Commission  File No. 001-10924.                                                  |

 

59

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# *** ***

# ***GLOSSARY OF TERMS***

 

The following are abbreviations and definitions ofterms commonly used in the oil and gas industry and this Form 10-K.

 

*3-Dseismic*.  An advancedtechnology method of detecting accumulations of hydrocarbons identified by thecollection and measurement of the intensity and timing of sound wavestransmitted into the earth as they reflect back to the surface.

 

*Bbl*.  One barrel, or 42 U.S. gallons of liquidvolume.

 

*Bcf*.  One billion cubic feet.

 

*Bcfe*.  One billion cubic feet of natural gasequivalents.

 

*Completion*.  The installation of permanent equipment forthe production of oil or gas.

 

*CreditFacility.*  A line ofcredit provided by a group of banks, secured by oil and gas properties.

 

*DD&A.*  Refers to depreciation, depletion andamortization of the Company’s property and equipment.

 

*Developmentwell*.  A well drilledwithin the proved area of an oil or gas reservoir to the depth of astratigraphic horizon known to be productive.

 

*Dryhole*.  A well found tobe incapable of producing hydrocarbons in sufficient quantities to justifycompletion as an oil or gas well.

 

*Exploratorywell*.  A well drilledto find and produce oil or natural gas reserves not classified as proved, tofind a new productive reservoir in a field previously found to be productive ofoil or natural gas in another reservoir or to extend a known reservoir.

 

*Extensionsand discoveries*.  As toany period, the increases to proved reserves from all sources other than theacquisition of proved properties or revisions of previous estimates.

 

*Grossacres or wells*.  Refersto the total acres or wells in which the Company has a working interest.

 

*Horizontaldrilling*.  A drillingtechnique that permits the operator to contact and intersect a larger portionof the producing horizon than conventional vertical drilling techniques andmay, depending on the horizon, result in increased production rates and greaterultimate recoveries of hydrocarbons.

 

*MBbls*.  One thousand barrels.

 

*Mcf*.  One thousand cubic feet.

 

*Mcfe*.  One thousand cubic feet of natural gasequivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflectsthe relative energy content.

 

*MMbtu.*  One million British thermal units.  One British thermal unit is the heat requiredto raise the temperature of a one-pound mass of water from 58.5 to 59.5 degreesFahrenheit.

 

*MMcf*.  One million cubic feet.

 

*MMcfe.*  One million cubic feet of natural gasequivalents.

 

60

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*Naturalgas liquids*.  Liquidhydrocarbons that have been extracted from natural gas, such as ethane,propane, butane and natural gasoline.

 

*Net acres orwells*.  Refers to gross acres or wellsmultiplied, in each case, by the percentage working interest owned by theCompany.

 

*Net production*.  Oil and gas production that is owned by theCompany, less royalties and production due others.

 

*NYMEX*.  New York Mercantile Exchange, the exchange onwhich commodities, including crude oil and natural gas futures contracts, aretraded.

 

*Oil*.  Crude oil or condensate.

 

*Operator*.  The individual or company responsible for theexploration, development and production of an oil or gas well or lease.

 

*Presentvalue of proved reserves*. The present value of estimated future revenues, discounted at 10%annually, to be generated from the production of proved reserves determined inaccordance with Securities and Exchange Commission guidelines, net of estimatedproduction and future development costs, using prices and costs as of the dateof estimation without future escalation, without giving effect to(i) estimated future abandonment costs, net of the estimated salvage valueof related equipment, (ii) nonproperty related expenses such as generaland administrative expenses, debt service and future income tax expense, or(iii) depreciation, depletion and amortization.

 

*Proved developednonproducing reserves*.  Reservesthat consist of (i) proved reserves from wells which have been completed andtested but are not producing due to lack of market or minor completion problemswhich are expected to be corrected and (ii) proved reserves currently behindthe pipe in existing wells and which are expected to be productive due to boththe well log characteristics and analogous production in the immediate vicinityof the wells.

 

*Proved developedproducing reserves.*  Proved reservesthat can be expected to be recovered from currently producing zones under thecontinuation of present operating methods.

 

*Proved developedreserves.*  The combination ofproved developed producing and proved developed nonproducing reserves.

 

*Provedreserves*.  Theestimated quantities of crude oil, natural gas, and natural gas liquids whichgeological and engineering data demonstrate with reasonable certainty to berecoverable in future years from known reservoirs under existing economic andoperating conditions, i.e., prices and costs as of the date the estimate ismade.  Prices include consideration ofchanges in existing prices provided only by contractual arrangements, but noton escalations based upon future conditions.

 

*Provedundeveloped reserves (PUD)*. Proved reserves that are expected to be recovered from new wells onundrilled acreage, or from existing wells where a relatively major expenditureis required for recompletion.

 

*Royalty*.  An interest in an oil and gas lease thatgives the owner of the interest the right to receive a portion of theproduction from the leased acreage (or of the proceeds of the sale thereof),but generally does not require the owner to pay any portion of the costs ofdrilling or operating the wells on the leased acreage.  Royalties may be either landowner’sroyalties, which are reserved by the owner of the leased acreage at the timethe lease is granted, or overriding royalties, which are usually reserved by anowner of the leasehold in connection with a transfer to a subsequent owner.

 

61

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*SEC*.  The United States Securities and ExchangeCommission.

 

*Standardized measure of discounted future netcash flows*. Present value of proved reserves, as adjusted to give effect to(i) estimated future abandonment costs, net of the estimated salvage valueof related equipment, and (ii) estimated future income taxes.

 

*Undeveloped acreage*.  Leased acreage on which wells have not beendrilled or completed to a point that would permit the production of commercialquantities of oil and gas, regardless of whether such acreage contains provedreserves.

 

*Working interest*. An interest in an oil and gas lease that gives the owner of the interestthe right to drill for and produce oil and gas on the leased acreage andrequires the owner to pay a share of the costs of drilling and productionoperations.  The share of production towhich a working interest is entitled will be smaller than the share of coststhat the working interest owner is required to bear to the extent of anyroyalty burden.

 

*Workover*.  Operations on a producing well to restore orincrease production.

 

61

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## **SIGNATURES**

 

In accordance withthe requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,the registrant has duly caused this report to be signed on its behalf by theundersigned, thereunto duly authorized.

 

 

| CLAYTON WILLIAMS ENERGY, INC. |
|-------------------------------|
| (Registrant)                  |
|                          |
| By:                           | /s/ CLAYTON W. WILLIAMS * |
|                          | Clayton W. Williams |
|                          | Chairman of the Board, President  and Chief Executive Officer |

 

 

In accordance withthe requirements of the Securities Exchange Act of 1934, this report has beensigned below by the following persons on behalf of the registrant and in thecapacities and on the dates indicated.

 

 
| **Signature**             | ** ** | **Title**                            | ** ** | **Date**       |
|---------------------------|------------|--------------------------------------|------------|----------------|
|                      |       |                                 |       |           |
| /s/ CLAYTON W. WILLIAMS * |       | Chairman of the Board,               |       | March 15, 2006 |
| Clayton W. Williams       |       | President and Chief Executive        |       |           |
|                      |       | Officer and Director                 |       |           |
|                      |       |                                 |       |           |
| /s/ L. PAUL LATHAM        |       | Executive Vice President,            |       | March 15, 2006 |
| L. Paul Latham            |       | Chief Operating Officer and          |       |           |
|                      |       | Director                             |       |           |
|                      |       |                                 |       |           |
| /s/ MEL G. RIGGS          |       | Senior Vice President -              |       | March 15, 2006 |
| Mel G. Riggs              |       | Finance, Secretary, Treasurer,       |       |           |
|                      |       | Chief Financial Officer and Director |       |           |
|                      |       |                                 |       |           |
| /s/ MICHAEL L. POLLARD    |       | Vice President – Accounting and |       | March 15, 2006 |
| Michael L. Pollard        |       | Principal Accounting Officer         |       |           |
|                      |       |                                 |       |           |
| /s/ STANLEY S. BEARD *    |       | Director                             |       | March 15, 2006 |
| Stanley S. Beard          |       |                                 |       |           |
|                      |       |                                 |       |           |
| /s/ DAVIS L. FORD *       |       | Director                             |       | March 15, 2006 |
| Davis L. Ford             |       |                                 |       |           |
|                      |       |                                 |       |           |
| /s/ ROBERT L. PARKER *    |       | Director                             |       | March 15, 2006 |
| Robert L. Parker          |       |                                 |       |           |
|                      |       |                                 |       |           |
| /s/ JORDAN R. SMITH *     |       | Director                             |       | March 15, 2006 |
| Jordan R. Smith           |       |                                 |       |           |
|                      |       |                                 |       |           |
|                           |
| *                         | By:        | /s/ L. PAUL LATHAM                   |       |           |   |   |
| L. Paul Latham            |       |                                 |       |           |
| *Attorney-in-Fact*        | * *   | * *                             | * *   | * *       |
|                           |            |                                      |            |                |  |  |

 

62

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**CLAYTON WILLIAMS ENERGY, INC.**

** **

**INDEX TO CONSOLIDATED FINANCIAL STATEMENTS**

**AND FINANCIAL STATEMENT SCHEDULES**

 
| Report of Independent Registered Public Accounting Firm |   |
|---------------------------------------------------------|--------|
|                                                    |   |
| Consolidated Balance Sheets                             |   |
|                                                    |   |
| Consolidated Statements of Operations                   |   |
|                                                    |   |
| Consolidated Statements of Stockholders’ Equity    |   |
|                                                    |   |
| Consolidated Statements of Cash Flows                   |   |
|                                                    |   |
| Notes to Consolidated Financial Statements              |   |
|                                                    |   |
| Financial Statement Schedule                            |   |
| Schedule II—Valuation and Qualifying  Accounts     |   |

 

F-1

----

 

**REPORT OF INDEPENDENT REGISTERED**

**PUBLIC ACCOUNTING FIRM**

 

The Board of Directors and Stockholders

Clayton Williams Energy, Inc.:

 

We have audited the accompanying consolidatedbalance sheets of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2005 and 2004, and therelated consolidated statementsof operations, stockholders’ equity, and cash flows for each of the years inthe three-year period ended December 31, 2005. In connection with our audits ofthe consolidated financial statements, we also have audited the accompanyingfinancial statement schedule.  These consolidated financial statements andfinancial statement schedule are the responsibility of the Company’smanagement. Our responsibility is to express an opinion on these consolidated financial statements andthe financial statement schedule based on our audits.

 

We conducted our audits in accordance with the standards of the PublicCompany Accounting Oversight Board (United States).  Those standards require that we plan andperform the audit to obtain reasonable assurance about whether the financialstatements are free of material misstatement.  An audit includes examining, on a test basis,evidence supporting the amounts and disclosures in the financial statements. Anaudit also includes assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financialstatement presentation.  We believe thatour audits provide a reasonable basis for our opinion.

 

In our opinion, the consolidatedfinancial statements referred to above present fairly, in all materialrespects, the financial position of Clayton Williams Energy, Inc. and subsidiaries as of December 31,2005 and 2004, and the results of theiroperations and their cash flowsfor each of the years in the three-year period ended December 31, 2005, inconformity with U.S. generally accepted accounting principles.  Also in our opinion, the related financialstatement schedule, when considered in relation to the basic consolidatedfinancial statements taken as a whole, present fairly, in all material respects,the information set forth therein.

 

As discussed in Note 5 of the consolidated financial statements,effective January 1, 2003, the Company changed its method of accounting forabandonment obligations in accordance with Statement of Financial AccountingStandards No. 143 “Accounting for Asset Retirement Obligations”.

 

We also have audited, in accordance with the standards of the PublicCompany Accounting Oversight Board (United States), the effectiveness ofClayton Williams Energy, Inc.’s internal control over financial reporting as ofDecember 31, 2005, based on criteria established in Internal Control—IntegratedFramework issued by the Committee of Sponsoring Organizations of the TreadwayCommission, and our report dated March 15, 2006, expressed an unqualifiedopinion on management’s assessment of, and the effective operations of,internal control over financial reporting.

 

 

KPMG LLP

 

Dallas, Texas

March 15, 2006

 

F-2

----

 

**CLAYTON WILLIAMS ENERGY, INC.**

**CONSOLIDATED BALANCE SHEETS**

**(Dollars in thousands)**

** **

**ASSETS**

 
| ** **                                                 | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------|------------|------------------|------------|
| ** **                                                 | ** ** | **2005**         | ** ** | **2004** | ** ** |
| CURRENT ASSETS                                             |       |             |       |   |   |
| Cash and cash equivalents                                  |       | $                | 5,935      |   | $ | 16,359 |   |
| Accounts receivable:                                       |       |             |       |   |   |
| Oil and gas sales                                          |       | 28,317           |       | 25,573 |   |
| Joint interest and other, net                              |       | 6,972            |       | 4,653 |   |
| Affiliates                                                 |       | 254              |       | 553 |   |
| Inventory                                                  |       | 43,753           |       | 5,202 |   |
| Deferred income taxes                                      |       | 439              |       | 625 |   |
| Fair value of derivatives                                  |       | 191              |       | 2,333 |   |
| Prepaids and other                                         |       | 2,581            |       | 1,401 |   |
|                                                       |       | 88,442           |       | 56,699 |   |
| PROPERTY AND EQUIPMENT                                     |       |             |       |   |   |
| Oil and gas properties, successful efforts  method         |       | 1,037,862        |       | 909,095 |   |
| Natural gas gathering and processing  systems              |       | 18,034           |       | 17,286 |   |
| Other                                                      |       | 12,396           |       | 11,839 |   |
|                                                       |       | 1,068,292        |       | 938,220 |   |
| Less accumulated depreciation, depletion  and amortization |       | (594,225         | )          | (539,860 | ) |
| Property and equipment, net                                |       | 474,067          |       | 398,360 |   |
|                                                       |       |             |       |   |   |
| OTHER ASSETS                                               |       |             |       |   |   |
| Debt issue costs                                           |       | 8,557            |       | 3,575 |   |
| Advances to drilling rig joint venture                     |       | 10,329           |       | — |   |
| Fair value of derivatives                                  |       | 127              |       | — |   |
| Other                                                      |       | 5,813            |       | 3,601 |   |
|                                                       |       | 24,826           |       | 7,176 |   |
|                                                       |       | $                | 587,335    |   | $ | 462,235 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

F-3

----

** **

**LIABILITIES AND STOCKHOLDERS’ EQUITY**

 
| ** **                                                                                                                                                           | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------|------------|
| ** **                                                                                                                                                           | ** ** | **2005**         | ** ** | **2004** | ** ** |
| CURRENT LIABILITIES                                                                                                                                                  |       |             |       |   |   |
| Accounts payable:                                                                                                                                                    |       |             |       |   |   |
| Trade                                                                                                                                                                |       | $                | 59,861     |   | $ | 51,014 |   |
| Oil and gas sales                                                                                                                                                    |       | 18,236           |       | 11,223 |   |
| Affiliates                                                                                                                                                           |       | 2,857            |       | 2,954 |   |
| Current maturities of long-term debt                                                                                                                                 |       | 19               |       | 31 |   |
| Fair value of derivatives                                                                                                                                            |       | 33,670           |       | 16,026 |   |
| Accrued liabilities and other                                                                                                                                        |       | 9,611            |       | 3,017 |   |
|                                                                                                                                                                 |       | 124,254          |       | 84,265 |   |
| NON-CURRENT LIABILITIES                                                                                                                                              |       |             |       |   |   |
| Long-term debt                                                                                                                                                       |       | 235,700          |       | 177,519 |   |
| Deferred income taxes                                                                                                                                                |       | 37,042           |       | 36,897 |   |
| Fair value of derivatives                                                                                                                                            |       | 49,705           |       | 28,958 |   |
| Other                                                                                                                                                                |       | 20,343           |       | 17,000 |   |
|                                                                                                                                                                 |       | 342,790          |       | 260,374 |   |
|                                                                                                                                                                 |       |             |       |   |   |
| COMMITMENTS AND CONTINGENCIES                                                                                                                                        |       |             |       |   |   |
|                                                                                                                                                                 |       |             |       |   |   |
| STOCKHOLDERS’ EQUITY                                                                                                                                            |       |             |       |   |   |
| Preferred stock, par value $.10 per share,  authorized – 3,000,000 shares; none issued                                                                          |       | —           |       | — |   |
| Common stock, par value $.10 per share,  authorized – 30,000,000 shares; issued and outstanding – 10,815,575 shares in  2005 and 10,787,013 shares in 2004 |       | 1,082            |       | 1,078 |   |
| Additional paid-in capital                                                                                                                                           |       | 107,108          |       | 104,674 |   |
| Retained earnings                                                                                                                                                    |       | 12,101           |       | 11,844 |   |
|                                                                                                                                                                 |       | 120,291          |       | 117,596 |   |
|                                                                                                                                                                 |       | $                | 587,335    |   | $ | 462,235 |   |
|                                                                                                                                                                      |            |                  |            |  |  |  |  |  |  |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

F-4

----

** **

**CLAYTON WILLIAMS ENERGY, INC.**

**CONSOLIDATED STATEMENTS OF OPERATIONS**

**(In thousands, except per share)**

** **
| ** **                                          | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------|------------|-----------------------------|------------|
| ** **                                          | ** ** | **2005**                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| REVENUES                                            |       |                        |       |   |   |   |   |
| Oil and gas sales                                   |       | $                           | 252,599    |   | $ | 193,127 |   | $ | 163,032 |   |
| Natural gas services                                |       | 12,080                      |       | 9,083 |   | 8,758 |   |
| Gain on sales of property and equipment             |       | 18,920                      |       | 4,120 |   | 267 |   |
| Total revenues                                      |       | 283,599                     |       | 206,330 |   | 172,057 |   |
|                                                |       |                        |       |   |   |   |   |
| COSTS AND EXPENSES                                  |       |                        |       |   |   |   |   |
| Production                                          |       | 57,404                      |       | 41,163 |   | 28,239 |   |
| Exploration:                                        |       |                        |       |   |   |   |   |
| Abandonments and impairments                        |       | 39,957                      |       | 67,956 |   | 35,120 |   |
| Seismic and other                                   |       | 10,780                      |       | 7,124 |   | 8,755 |   |
| Natural gas services                                |       | 11,212                      |       | 8,538 |   | 8,279 |   |
| Depreciation, depletion and amortization            |       | 47,509                      |       | 44,040 |   | 40,284 |   |
| Impairment of property and equipment                |       | 18,266                      |       | — |   | 170 |   |
| Accretion of abandonment obligations                |       | 1,158                       |       | 1,044 |   | 651 |   |
| General and administrative                          |       | 15,410                      |       | 11,689 |   | 10,934 |   |
| Loss on sales of property and equipment             |       | 209                         |       | 14,337 |   | 68 |   |
| Other                                               |       | 1,353                       |       | — |   | — |   |
| Total costs and expenses                            |       | 203,258                     |       | 195,891 |   | 132,500 |   |
|                                                |       |                        |       |   |   |   |   |
| Operating income                                    |       | 80,341                      |       | 10,439 |   | 39,557 |   |
|                                                |       |                        |       |   |   |   |   |
| OTHER INCOME (EXPENSE)                              |       |                        |       |   |   |   |   |
| Interest expense                                    |       | (14,498                     | )          | (7,877 | ) | (3,138 | ) |
| Loss on derivatives                                 |       | (70,059                     | )          | (25,329 | ) | (1,593 | ) |
| Other                                               |       | 4,022                       |       | 1,354 |   | (1,662 | ) |
| Total other income (expense)                        |       | (80,535                     | )          | (31,852 | ) | (6,393 | ) |
|                                                |       |                        |       |   |   |   |   |
| Income (loss) before income taxes                   |       | (194                        | )          | (21,413 | ) | 33,164 |   |
| Income tax expense (benefit)                        |       | (451                        | )          | (7,385 | ) | 10,515 |   |
| Income (loss) from continuing operations            |       | 257                         |       | (14,028 | ) | 22,649 |   |
| Cumulative effect of accounting change, net  of tax |       | —                      |       | — |   | 207 |   |
|                                                |       |                        |       |   |   |   |   |
| NET INCOME (LOSS)                                   |       | $                           | 257        |   | $ | (14,028 | ) | $ | 22,856 |   |
|                                                |       |                        |       |   |   |   |   |   |   |   |
| Net income (loss) per common share:                 |       |                        |       |   |   |   |   |
| Basic:                                              |       |                        |       |   |   |   |   |
| Income (loss) from continuing operations            |       | $                           | .02        |   | $ | (1.37 | ) | $ | 2.43 |   |
| Net income (loss)                                   |       | $                           | .02        |   | $ | (1.37 | ) | $ | 2.45 |   |
|                                                |       |                        |       |   |   |   |   |
| Diluted:                                            |       |                        |       |   |   |   |   |
| Income (loss) from continuing operations            |       | $                           | .02        |   | $ | (1.37 | ) | $ | 2.38 |   |
| Net income (loss)                                   |       | $                           | .02        |   | $ | (1.37 | ) | $ | 2.40 |   |
|                                                |       |                        |       |   |   |   |   |
| Weighted average common shares outstanding:         |       |                        |       |   |   |   |   |
| Basic                                               |       | 10,804                      |       | 10,213 |   | 9,329 |   |
| Diluted                                             |       | 11,241                      |       | 10,213 |   | 9,509 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

F-5

----

 

**CLAYTON WILLIAMS ENERGY, INC.**

# ***CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY***

**(In thousands)**

** **
| ** **                                                                      | ** ** | ** **        | ** ** | ** **     | ** ** | ** **   | ** ** | ** **   | ** ** | **Accumulated** | ** ** | ** **  | ** ** |
|---------------------------------------------------------------------------------|------------|-------------------|------------|----------------|------------|--------------|------------|--------------|------------|-----------------|------------|-------------|------------|
| ** **                                                                      | ** ** | ** **        | ** ** | ** **     | ** ** | ** **   | ** ** | ** **   | ** ** | **Other**       | ** ** | **Total**   | ** ** |
| ** **                                                                      | ** ** | ** **        | ** ** | ** **     | ** ** | ** **   | ** ** | ** **   | ** ** | **Compre-**     | ** ** | **Compre-** | ** ** |
| ** **                                                                      | ** ** | **Common Stocks** | ** ** | **Additional** | ** ** | **Retained** | ** ** | **hensive**  | ** ** | **hensive**     | ** ** |
| ** **                                                                      | ** ** | **No. of**        | ** ** | **Par**        | ** ** | **Paid-In**  | ** ** | **Earnings** | ** ** | **Income**      | ** ** | **Income**  | ** ** |
| ** **                                                                      | ** ** | **Shares**        | ** ** | **Value**      | ** ** | **Capital**  | ** ** | **(Loss)**   | ** ** | **(Loss)**      | ** ** | **(Loss)**  | ** ** |
| BALANCE,                                                                        |       |              |       |           |       |         |       |         |       |            |       |        |       |
| December 31, 2002                                                               |       | 9,277             |       | $              | 928        |         | $          | 72,787       |       | $               | 3,016      |        | $          | (7,950 | ) |   |   |
| Net income                                                                      |       | —            |       | —         |       | —       |       | 22,856       |       | —          |       | $           | 22,856     |   |
| Change in fair value of derivatives designated  as cash flow hedges, net of tax |       | —            |       | —         |       | —       |       | —       |       | 7,950           |       | 7,950       |       |
| Total comprehensive income                                                      |       |              |       |           |       |         |       |         |       |            |       | $           | 30,806     |   |
| Issuance of stock through compensation  plans                                   |       | 91                |       | 9              |       | 1,185        |       | —       |       | —          |       |        |       |
|                                                                            |       |              |       |           |       |         |       |         |       |            |       |        |       |
| BALANCE,                                                                        |       |              |       |           |       |         |       |         |       |            |       |        |       |
| December 31, 2003                                                               |       | 9,368             |       | 937            |       | 73,972       |       | 25,872       |       | —          |       |        |       |
| Net loss and total comprehensive loss                                           |       | —            |       | —         |       | —       |       | (14,028      | )          | —          |       | $           | (14,028    | ) |
| Issuance of stock throughcompensation plans                                     |       | 38                |       | 3              |       | 853          |       | —       |       | —          |       |        |       |
| Issuance of common stock, net of offering  costs of $1,773                      |       | 1,381             |       | 138            |       | 29,849       |       | —       |       | —          |       |        |       |
|                                                                            |       |              |       |           |       |         |       |         |       |            |       |        |       |
| BALANCE,                                                                        |       |              |       |           |       |         |       |         |       |            |       |        |       |
| December 31, 2004                                                               |       | 10,787            |       | $              | 1,078      |         | $          | 104,674      |       | $               | 11,844     |        | $          | — |   |   |   |
| Net income and total comprehensive income                                       |       | —            |       | —         |       | —       |       | 257          |       | —          |       | $           | 257        |   |
| Restricted stock issued as compensation                                         |       | 9                 |       | 1              |       | 270          |       | —       |       | —          |       |        |       |
| Issuance of stock through compensation  plans                                   |       | 19                |       | 3              |       | 2,164        |       | —       |       | —          |       |        |       |
| BALANCE,                                                                        |       |              |       |           |       |         |       |         |       |            |       |        |       |
| December 31, 2005                                                               |       | 10,815            |       | $              | 1,082      |         | $          | 107,108      |       | $               | 12,101     |        | $          | — |   |   |   |

 

The accompanying notes are an integral partof these consolidated financial statements.

 

F-6

----

** **

**CLAYTON WILLIAMS ENERGY, INC.**

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

**(Inthousands)**

** **
| ** **                                                                           | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                           | ** ** | **2005**                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| CASH FLOWS FROM OPERATING ACTIVITIES                                                 |       |                        |       |   |   |   |   |
| Net income (loss)                                                                    |       | $                           | 257        |   | $ | (14,028 | ) | $ | 22,856 |   |
| Adjustments to reconcile net income (loss)  to cash provided by operating activities |       |                        |       |   |   |   |   |
| Depreciation, depletion and amortization                                             |       | 47,509                      |       | 44,040 |   | 40,284 |   |
| Impairment of property and equipment                                                 |       | 18,266                      |       | — |   | 170 |   |
| Exploration costs                                                                    |       | 39,957                      |       | 67,956 |   | 35,120 |   |
| Gain (loss) on sales of property and  equipment, net                                 |       | (18,711                     | )          | 10,217 |   | (199 | ) |
| Deferred income taxes                                                                |       | (526                        | )          | (7,645 | ) | 10,172 |   |
| Non-cash employee compensation                                                       |       | 2,998                       |       | 536 |   | 1,312 |   |
| Loss on derivatives                                                                  |       | 40,406                      |       | 7,104 |   | 1,546 |   |
| Settlements on derivatives with financing  elements                                  |       | 27,731                      |       | 9,890 |   | — |   |
| Amortization of debt issue costs                                                     |       | 2,631                       |       | — |   | — |   |
| Accretion of abandonment obligations                                                 |       | 1,158                       |       | 1,044 |   | 651 |   |
| Cumulative effect of accounting change, net  of tax                                  |       | —                      |       | — |   | (207 | ) |
|                                                                                 |       |                        |       |   |   |   |   |
| Changes in operating working capital:                                                |       |                        |       |   |   |   |   |
| Accounts receivable                                                                  |       | (4,764                      | )          | 581 |   | (1,787 | ) |
| Accounts payable                                                                     |       | 1,707                       |       | 8,881 |   | 8,655 |   |
| Other                                                                                |       | 4,856                       |       | (1,596 | ) | 1,177 |   |
| Net cash provided by operating activities                                            |       | 163,475                     |       | 126,980 |   | 119,750 |   |
|                                                                                 |       |                        |       |   |   |   |   |
| CASH FLOWS FROM INVESTING ACTIVITIES                                                 |       |                        |       |   |   |   |   |
| Additions to property and equipment                                                  |       | (172,987                    | )          | (123,991 | ) | (62,889 | ) |
| Investment in Southwest Royalties, Inc.                                              |       | —                      |       | (168,204 | ) | — |   |
| Proceeds from sales of property and  equipment                                       |       | 23,252                      |       | 35,020 |   | 239 |   |
| Change in equipment inventory                                                        |       | (36,519                     | )          | — |   | — |   |
| Other                                                                                |       | (10,411                     | )          | 269 |   | (2,120 | ) |
| Net cash used in investing activities                                                |       | (196,665                    | )          | (256,906 | ) | (64,770 | ) |
|                                                                                 |       |                        |       |   |   |   |   |
| CASH FLOWS FROM FINANCING ACTIVITIES                                                 |       |                        |       |   |   |   |   |
| Proceeds from long-term debt                                                         |       | 235,700                     |       | 172,500 |   | — |   |
| Repayments of long-term debt                                                         |       | (177,531                    | )          | (60,530 | ) | (45,483 | ) |
| Proceeds from sale of common stock                                                   |       | 292                         |       | 30,018 |   | 281 |   |
| Settlements on derivatives with financing  elements                                  |       | (27,731                     | )          | (9,890 | ) | — |   |
| Payment of debt issue costs                                                          |       | (7,964                      | )          | (4,156 | ) | — |   |
| Other                                                                                |       | —                      |       | 2,889 |   | — |   |
| Net cash provided by (used in) financing Activities                                  |       | 22,766                      |       | 130,831 |   | (45,202 | ) |
|                                                                                 |       |                        |       |   |   |   |   |
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                                 |       | (10,424                     | )          | 905 |   | 9,778 |   |
|                                                                                 |       |                        |       |   |   |   |   |
| CASH AND CASH EQUIVALENTS                                                            |       |                        |       |   |   |   |   |
| Beginning of period                                                                  |       | 16,359                      |       | 15,454 |   | 5,676 |   |
| End of period                                                                        |       | $                           | 5,935      |   | $ | 16,359 |   | $ | 15,454 |   |
|                                                                                 |       |                        |       |   |   |   |   |   |   |   |
| SUPPLEMENTAL DISCLOSURES                                                             |       |                        |       |   |   |   |   |
| Cash paid for interest, net of amounts  capitalized                                  |       | $                           | 4,343      |   | $ | 7,246 |   | $ | 2,941 |   |
| Cash paid for income taxes                                                           |       | $                           | 365        |   | $ | 90 |   | $ | — |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

F-7

----

** **

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**1.****             Nature of Operations**

 

Clayton Williams Energy, Inc. (a Delawarecorporation) and its subsidiaries (collectively, the “Company”) is anindependent oil and gas company engaged in the exploration for and developmentand production of oil and natural gas primarily in Texas, Louisiana and New Mexico. Approximately 45% of the Company’s outstanding common stock isbeneficially owned by its Chairman of the Board and Chief Executive Officer,Clayton W. Williams (“Mr. Williams”).  Oil and gas exploration and production is theonly business segment in which the Company operates.

 

Substantially all of the Company’soil and gas production is sold under short-term contracts which aremarket-sensitive.  Accordingly, theCompany’s financial condition, results of operations and capital resources arehighly dependent upon prevailing market prices of, and demand for, oil andnatural gas. These commodity prices are subject to wide fluctuations and marketuncertainties due to a variety of factors that are beyond the control of theCompany.  These factors include the levelof global demand for petroleum products, foreign supply of oil and gas, theestablishment of and compliance with production quotas by oil-exportingcountries, weather conditions, the price and availability of alternative fuels,and overall economic conditions, both foreign and domestic.

 

**2.****             Summary of Significant Accounting Policies**

 

*Estimates and Assumptions*

The preparation of financial statements in conformity with accountingprinciples generally accepted in the United States requires management of theCompany to make estimates and assumptions that affect the reported amounts of assets and liabilities anddisclosure of contingent assets and liabilities at the date of the financialstatements and the reported amounts of revenues and expenses during thereporting period.  Actual resultscould differ materially from those estimates. The accountingpolicies most affected by management’s estimates and assumptions are asfollows:

 

•      The reliance on estimates of proved reserves tocompute the provision for depreciation, depletion and amortization, and todetermine the amount of any impairment of proved properties;

 

•      The valuation of unproved acreage and proved oiland gas properties to determine the amount of any impairments of oil and gasproperties;

 

•      Judgment regarding the productive status ofin-progress exploratory wells to determine the amount of any provision forabandonment;

 

•      Estimates regarding abandonment obligations; and

 

•      Estimates regarding the future utilization of netoperating loss carryforwards.

 

*Principles of Consolidation*

The consolidated financialstatements include the accounts of Clayton Williams Energy, Inc. and itssubsidiaries.  The Company accounts forits undivided interest in oil and gas limited partnerships using theproportionate consolidation method, whereby its share of assets, liabilities,revenues and expenses are consolidated with other operations.  All significant intercompany transactions andbalances associated with the consolidated operations have been eliminated.

 

*Oil and Gas Properties*

The Company follows thesuccessful efforts method of accounting for its oil and gas properties, wherebycosts of productive wells, developmental dry holes and productive leases arecapitalized into appropriate groups of properties based on geographical andgeological similarities.  Thesecapitalized costs are amortized using the unit-of-production method based onestimated proved reserves.  Proceeds fromsales

 

F-8

----

 

of properties are credited to property costs, and a gainor loss is recognized when a significant portion of an amortization base issold or abandoned.

 

Exploration costs, includinggeological and geophysical expenses and delay rentals, are charged to expenseas incurred.  Exploratory drilling costs,including the cost of stratigraphic test wells, are initially capitalized butcharged to exploration expense if and when the well is determined to benonproductive.  The determination of anexploratory well’s ability to produce must be made within one year from thecompletion of drilling activities.  Theacquisition costs of unproved acreage are initially capitalized and are carriedat cost, net of accumulated impairment provisions, until such leases aretransferred to proved properties or charged to exploration expense asimpairments of unproved properties.

 

*Natural Gas and Other Propertyand Equipment*

Natural gas gathering andprocessing systems consist primarily of gas gathering pipelines, compressorsand gas processing plants.  Otherproperty and equipment consists primarily of field equipment and facilities,office equipment, leasehold improvements and vehicles.  Major renewals and betterments arecapitalized while the costs of repairs and maintenance are charged to expenseas incurred.  The costs of assets retiredor otherwise disposed of and the applicable accumulated depreciation areremoved from the accounts, and any gain or loss is included in other income inthe accompanying consolidated statements of operations.

 

Depreciation of natural gasgathering and processing systems and other property and equipment is computedon the straight-line method over the estimated useful lives of the assets,which generally range from 3 to 12 years.

 

*Valuation of Property andEquipment*

The Company follows theprovisions of Statement of Financial Accounting Standards No. 144 “Accountingfor Impairment or Disposal of Long-Lived Assets” (“SFAS 144”).  SFAS 144 requires that the Company’slong-lived assets, including its oil and gas properties, be assessed forpotential impairment in their carrying values whenever events or changes incircumstances indicate such impairment may have occurred.  An impairment is recognized when the estimatedundiscounted future net cash flows of the asset are less than its carryingvalue.  Any such impairment is recognizedbased on the differences in the carrying value and estimated fair value of theimpaired asset.

 

SFAS 144 provides for futurerevenue from the Company’s oil and gas production to be estimated based uponprices at which management reasonably estimates such products will besold.  These estimates of future productprices may differ from current market prices of oil and gas.  Any downward revisions to management’sestimates of future production or product prices could result in an impairmentof the Company’s oil and gas properties in subsequent periods.

 

Unproved oil and gas propertieswith individually significant acquisition costs are periodically assessed, andany impairment in value is charged to exploration costs.  The amount of impairment recognized onunproved properties which are not individually significant is determined byamortizing the costs of such properties within appropriate groups based on theCompany’s historical experience, acquisition dates and average leaseterms.  At December 31, 2005, the Company’sunproved oil and gas properties had an aggregate net book value of$79.9 million, including $10.3 million of exploratory drilling costsfor which the determination of proved reserves had not been made.  None of these costs are attributable to wellsfor which drilling activities have been completed for more than one year.  The valuation of unproved properties issubjective and requires management of the Company to make estimates andassumptions which, with the passage of time, may prove to be materiallydifferent from actual realizable values.

 

F-9

----

 

*Abandonment Obligations*

The Company follows theprovisions of Statement of Financial Accounting Standards No. 143 “Accountingfor Asset Retirement Obligations” (“SFAS 143”), as amended.  SFAS 143 requires the Company to recognize aliability for the present value of all legal obligations associated with theretirement of tangible, long-lived assets and capitalize an equal amount as acost of the asset.  The cost associatedwith the abandonment obligation, along with any estimated salvage value, is includedin the computation of depreciation, depletion and amortization.

 

*Income Taxes*

The Company follows the assetand liability method prescribed by Statement of Financial Accounting StandardsNo. 109 “Accounting for Income Taxes” (“SFAS 109”).  Under this method of accounting for incometaxes, deferred tax assets and liabilities are recognized for the future taxconsequences attributable to differences between the financial statementcarrying amounts of existing assets and liabilities and their respective taxbases.  Deferred tax assets andliabilities are measured using enacted tax rates expected to apply to taxableincome in the years in which those temporary differences are expected to berecovered or settled.  Under SFAS 109,the effect on deferred tax assets and liabilities of a change in enacted taxrates is recognized in income in the period that includes the enactment date.

 

*Hedging Activities*

From time to time, the Companyutilizes derivative instruments, consisting of swaps, floors and collars, toattempt to reduce its exposure to changes in commodity prices and interestrates.  The Company accounts for itsderivatives in accordance with Statement of Financial Accounting Standards No.133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”),as amended.  SFAS 133 requires that allderivative instruments be recognized as assets or liabilities in the balancesheet, measured at fair value.  Theaccounting for changes in the fair value of a derivative depends on both theintended purpose and the formal designation of the derivative.  Designation is established at the inceptionof a derivative, but subsequent changes to the designation are permitted.  For derivatives designated as cash flowhedges and meeting the effectiveness guidelines of SFAS 133, changes in fairvalue are recognized in other comprehensive income until the hedged item isrecognized in earnings.  Hedgeeffectiveness is measured quarterly based on relative changes in fair valuebetween the derivative contract and the hedged item over time.  Any change in fair value resulting fromineffectiveness is recognized immediately in earnings.  Changes in fair value of derivativeinstruments which are not designated as cash flow hedges or do not meet theeffectiveness guidelines of SFAS 133 are recorded in earnings as the changesoccur.  If designated as cash flowhedges, actual gains or losses on settled commodity derivatives are recorded asoil and gas revenues in the period the hedged production is sold, while actualgains or losses on interest rate derivatives are recorded in interest expensefor the applicable period.  Actual gainsor losses from derivatives not designated as cash flow hedges are recorded inother income (expense) as gain (loss) on derivatives.

 

*Inventory*

Inventory consists primarily oftubular goods and other well equipment which the Company plans to utilize inits ongoing exploration and development activities and is carried at the lowerof cost or market value.

 

*Capitalization of Interest*

Interest costs associated withthe Company’s inventory of unproved oil and gas property lease acquisitioncosts are capitalized during the periods for which exploration activities arein progress.  During the years endedDecember 31, 2005, 2004 and 2003, the Company capitalized interest totalingapproximately $2.2 million, $877,000 and $1.1 million, respectively.

 

F-10

----

 

*Cash and Cash Equivalents*

The Company considers all cashand highly liquid investments with original maturities of three months or lessto be cash equivalents.

 

*Net Income (Loss) Per CommonShare*

Basic earnings per share arecomputed by dividing net income by the weighted average number of common sharesoutstanding for the period.  Dilutedearnings per share reflect the potential dilution that could occur if dilutivestock options were exercised, calculated using the treasury stock method.  The diluted earnings per share calculationsfor 2005 and 2003 include an increase in potential shares attributable to dilutivestock options.  Stock options were notconsidered in the diluted earnings per share calculations for 2004 as theeffect would be anti-dilutive.

 

*Stock-Based Compensation*

The Company accounts for stock-basedcompensation utilizing the intrinsic value method prescribed by AccountingPrinciples Board Opinion No. 25 “Accounting for Stock Issued toEmployees” (“APB 25”) and related interpretations.  The following pro forma information, asrequired by Statement of Financial Accounting Standards No. 123 “Accounting forStock-Based Compensation” (“SFAS 123”), as amended by Statement ofFinancial Accounting Standards No. 148 (“SFAS 148”), presents net incomeand earnings per share information as if the stock options issued sinceDecember 31, 1994 were accounted for using the fair value method.  The fair value of stock options issued foreach year was estimated at the date of grant using the Black-Scholes optionpricing model.  The estimated fair valueof the stock options issued in 2005, 2004 and 2003 was approximately$4.5 million, $5.9 million and $3 million; respectively.  The following weighted average assumptionswere used in this model.

 
| ** **              | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-------------------------|------------|----------|------------|----------|------------|----------|------------|
|                    |       |     |       |     |       |     |       |
| Risk-free interest rate |       | 3.9      | %          | 2.5      | %          | 2.5      | %          |
| Stock price volatility  |       | 67       | %          | 69       | %          | 70       | %          |
| Expected life in years  |       | 10       |       | 10       |       | 10       |       |
| Dividend yield          |       | —   |       | —   |       | —   |       |

 

The SFAS 123 pro forma informationfor the years ended December 31, 2005, 2004 and 2003 is as follows:

 
| ** **                                                                                                         | ** ** | **2005**                             | ** ** | **2004** | ** ** | **2003** | ** ** |
|--------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------|------------|----------|------------|----------|------------|
| ** **                                                                                                         | ** ** | **(In thousands, except per share)** | ** ** |
| Net income (loss), as reported                                                                                     |       | $                                    | 257        |     | $          | (14,028  | )          | $ | 22,856 |   |
| Add: Stock-based employee compensation expense  (credit) included in net income (loss), net of tax                 |       | 1,233                                |       | (159     | )          | 518      |       |
| Deduct: Stock-based employee compensation expense  determined under fair value based method (SFAS 123), net of tax |       | (2,920                               | )          | (3,840   | )          | (2,602   | )          |
| Net income (loss), pro forma                                                                                       |       | $                                    | (1,430     | )        | $          | (18,027  | )          | $ | 20,772 |   |
|                                                                                                               |       |                                 |       |     |       |     |       |
| Basic:                                                                                                             |       |                                 |       |     |       |     |       |
| Net income (loss) per common share, as  reported                                                                   |       | $                                    | .02        |     | $          | (1.37    | )          | $ | 2.45 |   |
| Net income (loss) per common share, pro forma                                                                      |       | $                                    | (.13       | )        | $          | (1.77    | )          | $ | 2.23 |   |
|                                                                                                               |       |                                 |       |     |       |     |       |
| Diluted:                                                                                                           |       |                                 |       |     |       |     |       |
| Net income (loss) per common share, as  reported                                                                   |       | $                                    | .02        |     | $          | (1.37    | )          | $ | 2.40 |   |
| Net income (loss) per common share, pro  forma                                                                     |       | $                                    | (.13       | )        | $          | (1.77    | )          | $ | 2.18 |   |

 

F-11

----

 

*Revenue Recognition and GasBalancing*

The Company utilizes the salesmethod of accounting for oil, natural gas and natural gas liquids revenueswhereby revenues, net of royalties, are recognized as the production is sold topurchasers.  The amount of gas sold maydiffer from the amount to which the Company is entitled based on its revenueinterests in the properties.  The Companydid not have any significant gas imbalance positions at December 31, 2005or 2004.  Revenues from natural gas servicesare recognized as services are provided.

 

*ComprehensiveIncome*

Statement of FinancialAccounting Standards No. 130 “Reporting Comprehensive Income” (“SFAS 130”)established standards for reporting and displaying of comprehensive income andits components (revenue, expenses, gains and losses) in a full set ofgeneral-purpose financial statements. There were no differences between net income and comprehensive income in2005 and 2004.  A portion of the changesin fair value of derivatives required under SFAS 133 was reported incomprehensive income during 2003.

 

*Concentration Risks*

The Company sells its oil andnatural gas production to various customers, serves as operator in thedrilling, completion and operation of oil and gas wells, and enters into derivativeswith various counterparties.  Whenmanagement deems appropriate, the Company obtains letters of credit to secureamounts due from its principal oil and gas purchasers and follows otherprocedures to monitor credit risk from joint owners and derivativescounterparties.  Allowances for doubtfulaccounts at December 31, 2005 and 2004 relate to amounts due from jointinterest owners.

 

*Reclassifications*

Certain reclassifications ofprior year financial statement amounts have been made to conform to currentyear presentations.

 

*Recent AccountingPronouncements*

In June 2005, the EmergingIssues Task Force (“EITF”) reached consensus on Issue 04-5 regarding when alimited partnership should be consolidated by its general partner.  The proposed framework presumes that a solegeneral partner in a limited partnership controls the limited partnership.  The presumption of control can be overcome ifthe limited partners have (i) the substantive ability to remove the sole generalpartner or otherwise dissolve the limited partnership or (ii) substantiveparticipating rights.  The EITF hasconcluded that a general partner lacks control if the limited partners canremove the general partner with a simple majority vote.  The Company is the general partner of severaloil and gas limited partnerships and presently consolidates its proportionateinterest in the accounts of these partnerships. The Company is currently reviewing the applicable provisions of thepartnership agreements to determine the impact that EITF 04-5 may have onits consolidated financial statements. For existing partnerships, EITF 04-5 will be effective forconsolidated financial statements issued by the Company after January 1, 2006.  EITF 04-5 is effective for newly createdor modified limited partnerships subsequent to June 29, 2005.  If the Company determines that the limitedpartners do not have the substantive ability to remove the general partner inaccordance with EITF Issue 04-5, the Company will be required to fullyconsolidate the limited partnerships results, with the interest not owned bythe Company reflected as minority interest. This would have no impact to the Company’s future net income from thecurrent method of accounting for oil and gas limited partnerships usingproportionate consolidation.

 

In December 2004, the FASBissued Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-BasedPayments” (“SFAS 123R”). SFAS 123R requires that the cost from all share-based paymenttransactions, including stock options, be recognized in the financialstatements at fair value.  The Companycurrently uses the intrinsic-value method to account for these share-basedpayments.  For public companies, SFAS 123Ris effective for fiscal years beginning after June 15, 2005.  The Company will adopt the provisions of thisstatement in the first quarter of 2006. The Company has accounted for options which

 

F-12

----

 

were repriced in 1999 asvariable stock options whereby compensation expense has been recognized throughDecember 31, 2005 for unexercised options based on changes in the marketvalue of the Company’s common stock.  Inaccordance with SFAS 123R, the Company will cease accounting for theseoptions as variable stock options upon the adoption date.  Since all of the Company’s outstandingoptions are fully vested at December 31, 2005, no future compensationexpense will be recognized under SFAS 123R unless the options aremodified.  Accordingly, futurecompensation expense to be recognized under SFAS 123R will be determinedbased on the grant date fair value of future awards.

 

In April 2005, the FASB issuedStaff Position No. 19-1 (“FSP 19-1”). FSP 19-1 amends the present guidance in SFAS 19, paragraphs 31and 34, regarding when exploratory drilling costs pending determination ofproved reserves can be carried as an asset of an oil and gas company that usesthe successful efforts accounting method. The Company was required to adopt FSP 19-1, including itsdisclosures, effective July 1, 2005.  Theadoption of FSP 19-1 did not have a significant impact on the Company’sresults of operations.  AtDecember 31, 2005 and December 31, 2004, the Company had capitalized$10.3 million and $5.4 million, respectively, of exploratory drillingcosts applicable to wells that were pending determination of provedreserves.  Substantially all of theDecember 31, 2004 capitalized costs were subsequently classified asnon-productive.

 

**3.****            ****Acquisition ofSouthwest Royalties**

 

On May 21, 2004, the Companyacquired all the outstanding common stock of Southwest Royalties, Inc. (“SWR”)through a merger.  Prior to theacquisition, SWR was a privately-held, Midland-based energy company engaged inoil and gas exploration, production, development and acquisition activities inthe United States.  Most of SWR’sproperties are located in the Permian Basin of west Texas and southeastern NewMexico.

 

In connection with theacquisition of SWR, the Company paid $57.1 million to holders of SWR commonstock and common stock warrants and assumed and refinanced approximately$113.9 million of SWR bank debt at closing.  In addition, the Company incurredapproximately $9.4 million of merger-related costs, including (i) theassumption of SWR’s obligations to its officers and employees pursuant tochange of control arrangements and (ii) investment banking, legal, accountingand other direct transaction costs related to the acquisition of SWR.

 

The Company has accounted forthe acquisition of SWR using the purchase method of accounting for businesscombinations.  Under this method ofaccounting, the Company is deemed to be the acquirer for accountingpurposes.  SWR’s assets and liabilitieswere revalued under the purchase method of accounting and recorded at theirestimated fair values.

 

Pursuant to SFAS 149, whichamended SFAS 133, the derivative instruments assumed in connection withthe SWR acquisition are deemed to contain a significant financing element, andall cash flow associated with these positions are reported as a financing activityin the statement of cash flows.

 

F-13

----

 

The following table sets forththe calculation of the purchase price for SWR and the related allocation of thepurchase price to the assets acquired (in thousands):

 
| Purchase price:                                       |   |    |    |
|-------------------------------------------------------|--------|---------|---------|
| Acquisition of outstanding common stock and  warrants |   | $       | 57,139  |   |
| Long-term debt assumed and refinanced                 |   | 113,949 |    |
| Assumption of other non-current liabilities           |   | 31,024  |    |
| Transaction costs incurred                            |   | 9,355   |    |
| Current liabilities assumed                           |   | 26,546  |    |
| Deferred income taxes                                 |   | 36,655  |    |
|                                                  |   | $       | 274,668 |   |

 
| Allocation of purchase price:   |   |    |    |
|---------------------------------|--------|---------|---------|
| Current assets                  |   | $       | 23,436  |   |
| Proved oil and gas properties   |   | 229,238 |    |
| Unproved oil and gas properties |   | 18,130  |    |
| Other property and equipment    |   | 3,494   |    |
| Other assets                    |   | 370     |    |
|                            |   | $       | 274,668 |   |

 

The revaluation of SWR’s assetsand liabilities under the purchase method of accounting created significantdifferences between the carrying value for financial reporting purposes andthose used for income tax reporting purposes, resulting in federal and statedeferred tax liabilities of $36.6 million on the effective date of theacquisition.

 

The following table reflects theunaudited pro forma results of operations for the years ended December 31,2004 and 2003 as though the acquisition of SWR had occurred on January 1,2003.  The pro forma amounts are notnecessarily indicative of the results that may be reported in the future.

 
| ** **                                              | ** ** | **Year Ended**                            | ** ** |
|---------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                              | ** ** | **December 31,**                          | ** ** |
| ** **                                              | ** ** | **2004**                                  | ** ** | **2003** | ** ** |
| ** **                                              | ** ** | **(In thousands, except per share data)** | ** ** |
| Revenues                                                |       | $                                         | 230,163    |   | $ | 226,297 |   |
| Net income (loss) from continuing operations            |       | $                                         | (25,233    | ) | $ | 19,434 |   |
|                                                    |       |                                      |       |   |   |
| Net income (loss) from continuing operations per share: |       |                                      |       |   |   |
| Basic                                                   |       | $                                         | (2.34      | ) | $ | 1.81 |   |
| Diluted                                                 |       | $                                         | (2.34      | ) | $ | 1.78 |   |
|                                                         |            |                                           |            |  |  |  |  |  |

 

F-14

----

 

**4.****            ****Long-Term Debt**

 

Long-term debt at December 31,2005 and 2004 consists of the following:

 
| ** **                      | ** ** | **2005**           | ** ** | **2004** | ** ** |
|---------------------------------|------------|--------------------|------------|----------|------------|
| ** **                      | ** ** | **(In thousands)** | ** ** |
| 73⁄4% Senior Notes due 2013  |       | $                  | 225,000    |     | $          | — |   |
| Secured bank credit facilities: |       |               |       |     |       |
| Revolving loan, due May 2007    |       | 10,700             |       | 147,500  |       |
| Senior term loan, due May 2008  |       | —             |       | 30,000   |       |
| Other                           |       | 19                 |       | 50       |       |
|                            |       | 235,719            |       | 177,550  |       |
| Less current maturities         |       | (19                | )          | (31      | )          |
|                            |       | $                  | 235,700    |     | $          | 177,519 |   |
|                                 |            |                    |            |          |            |  |  |  |  |

 

Aggregatematurities of long-term debt at December 31, 2005 are as follows:  2006 — $19,000; 2007 - $10.7 million;and 2013 - $225 million.

 

*73⁄4%Senior Notes due 2013*

In July 2005, theCompany issued, in a private placement, $225 million of aggregateprincipal amount of 73⁄4% Senior Notes due 2013 (“Senior Notes”).  The Senior Notes were issued at face valueand bear interest at 73⁄4% per year, payable semi-annually on February 1 andAugust 1 of each year, beginning February 1, 2006.  After the payment of typical transactionexpenses, net proceeds of approximately $217 million were used to repayall amounts outstanding under the secured bank credit facilities and forgeneral corporate purposes, including the funding of planned exploration anddevelopment activities.

 

At any time priorto August 1, 2008, the Company may redeem up to 35% of the aggregate principalamount of the Senior Notes with the proceeds of certain equity offerings at aredemption price of 107.75% of the principal amount, plus accrued and unpaidinterest.  In addition, prior to August1, 2009, the Company may redeem some or all of the Senior Notes at a redemptionprice equal to 100% of the principal amount of the Senior Notes to be redeemed,plus a make-whole premium, plus any accrued and unpaid interest.  On and after August 1, 2009, the Company mayredeem some or all of the Senior Notes at redemption prices (expressed aspercentages of principal amount) equal to 103.875% for the twelve-month periodbeginning on August 1, 2009, 101.938% for the twelve-month periodbeginning on August 1, 2010, and 100.00% beginning on August 1, 2011, for anyperiod thereafter, in each case plus accrued and unpaid interest.

 

The Indenturegoverning the Senior Notes restricts the ability of the Company and itsrestricted subsidiaries to: (i) borrow money; (ii) issue redeemable and preferred stock;(iii) pay distributions or dividends; (iv) make investments;(v) create liens without securing the Senior Notes; (vi) enter intoagreements that restrict dividends from subsidiaries; (vii) sell certainassets or merge with or into other companies; (viii) enter intotransactions with affiliates; (ix) guarantee indebtedness; and(x) enter into new lines of business.

 

*Secured BankCredit Facility*

The Company’s secured bank credit facility provides for a revolvingloan facility in an amount not to exceed the lesser of the borrowing base, asestablished by the banks, or that portion of the borrowing base determined bythe Company to be the elected borrowing limit.  The borrowing base, whichis based on the discounted present value of future net revenues from oil andgas production, is subject to redetermination at any time, but at leastsemi-annually in May and November, and is made at the discretion of thebanks.  If, at any time, the redetermined borrowing base is less than theamount of outstanding indebtedness, the Company will be required to (i) pledgeadditional collateral, (ii) prepay the excess in not more than five

 

F-15

----

 

equalmonthly installments, or (iii) elect to convert the entire amount of outstandingindebtedness to a term obligation based on amortization formulas set forth inthe loan agreement.  Substantially all of the Company’s oil and gasproperties are pledged to secure advances under the credit facility.  AtDecember 31, 2005, the borrowing base established by the banks was$150 million, with no monthly commitment reductions.  After allowingfor outstanding letters of credit totaling $804,000, the Company had$138.5 million available under the credit facility at December 31,2005.

 

The revolvingcredit facility provides for interest at rates based on the agent bank’s primerate plus margins ranging from .25% to 1%, or if elected by the Company, basedon LIBOR plus margins ranging from 1.5% to 2.25%.  The Company also pays a commitment fee on theunused portion of the revolving credit facility.  Initially, the senior term credit facilityprovided for interest at rates based on the agent bank’s prime rate plus amargin of 3.5%, or if elected by the Company based on LIBOR plus a marginof 5%.  Subsequently, the prime ratemargin was reduced to 2.5%, and the LIBOR margin was reduced to 4%.  Interest and fees are payable at leastquarterly.  The effective annual interestrate on borrowings under the credit facility, including bank fees for the yearended December 31, 2005 was 7.5%. Included in interest expense for 2005 is a non-cash charge to write off$1.8 million of debt issue costs related to the early repayment of thesenior term credit facility and the reduction in the borrowing base on the revolvingcredit facility.

 

The loan agreementapplicable to the revolving credit facility contains financial covenants thatare computed quarterly.  The workingcapital covenant requires the Company to maintain a ratio of current assets tocurrent liabilities of at least 1 to 1. Another financial covenant under the credit facility requires theCompany to maintain a ratio of indebtedness to cash flow of no more than 3to 1.  The computations of currentassets, current liabilities, cash flow and indebtedness are defined in the loanagreement.  The Company was in compliancewith all financial and non-financial covenants at December 31, 2005.

 

**5.****             Other Non-Current Liabilities**

 

Othernon-current liabilities at December 31, 2005 and 2004 consist of thefollowing:

 
| ** **              | ** ** | **2005**           | ** ** | **2004** | ** ** |
|-------------------------|------------|--------------------|------------|----------|------------|
| ** **              | ** ** | **(In thousands)** | ** ** |
| Abandonment obligations |       | $                  | 19,447     |     | $          | 16,147 |   |
| Other                   |       | 896                |       | 853      |       |
|                    |       | $                  | 20,343     |     | $          | 17,000 |   |

 

*AbandonmentObligations*

Upon adoption ofSFAS 143 on January 1, 2003, the Company increased abandonmentobligations by $4.1 million, increased asset costs by $1.5 million,reduced accumulated depreciation, depletion and amortization by$2.9 million, and recorded an after-tax credit of $207,000 for thecumulative effect of adoption on prior years.

 

F-16

----

 

Changesin abandonment obligations for 2005 and 2004 are as follows:

 
| ** **                                                | ** ** | **2005**           | ** ** | **2004** | ** ** |
|-----------------------------------------------------------|------------|--------------------|------------|----------|------------|
| ** **                                                | ** ** | **(In thousands)** | ** ** |
| Beginning of year                                         |       | $                  | 16,147     |     | $          | 8,849 |   |
| Abandonment obligations related to the acquisition of SWR |       | —             |       | 8,512    |       |
| Additional abandonment obligations from new wells         |       | 796                |       | 411      |       |
| Sales of properties                                       |       | (617               | )          | (2,711   | )          |
| Accretion expense                                         |       | 1,158              |       | 1,044    |       |
| Revisions of previous estimates                           |       | 1,963              |       | 42       |       |
| End of year                                               |       | $                  | 19,447     |     | $          | 16,147 |   |

 

**6.****             Income Taxes**

 

Deferredtax assets and liabilities are the result of temporary differences between thefinancial statement carrying values and the tax bases of assets andliabilities.  Significant components ofnet deferred tax assets (liabilities) at December 31, 2005 and 2004 are asfollows:

 
| ** **                                  | ** ** | **2005**           | ** ** | **2004** | ** ** |
|---------------------------------------------|------------|--------------------|------------|----------|------------|
| ** **                                  | ** ** | **(In thousands)** | ** ** |
| Deferred tax assets:                        |       |               |       |     |       |
| Net operating loss carryforwards            |       | $                  | 2,497      |     | $          | 7,915 |   |
| Accrued stock-based compensation            |       | —             |       | 240      |       |
| Fair value of derivatives                   |       | 28,906             |       | 14,930   |       |
| Credits related to alternative minimum tax  |       | 395                |       | 279      |       |
| Statutory depletion carryforwards           |       | 3,861              |       | 3,209    |       |
| Other                                       |       | 5,748              |       | 5,058    |       |
|                                        |       | 41,407             |       | 31,631   |       |
| Deferred tax liabilities:                   |       |               |       |     |       |
| Property and equipment                      |       | (78,010            | )          | (67,903  | )          |
| Net deferred tax liabilities                |       | $                  | (36,603    | )        | $          | (36,272 | ) |
|                                        |       |               |       |     |       |
| Components of net deferred tax liabilities: |       |               |       |     |       |
| Current assets                              |       | $                  | 439        |     | $          | 625 |   |
| Non-current liabilities                     |       | (37,042            | )          | (36,897  | )          |
|                                        |       | $                  | (36,603    | )        | $          | (36,272 | ) |

 

F-17

----

 

For the years endedDecember 31, 2005, 2004 and 2003, the Company’s effective income tax rates were different thanthe statutory federal income tax rates for the following reasons:

** **
| ** **                                            | ** ** | **2005**           | ** ** | **2004** | ** ** | **2003** | ** ** |
|-------------------------------------------------------|------------|--------------------|------------|----------|------------|----------|------------|
| ** **                                            | ** ** | **(In thousands)** | ** ** |
|                                                  |       |               |       |     |       |     |       |
| Income tax expense (benefit) at statutory rate of 35% |       | $                  | (68        | )        | $          | (7,495   | )          | $ | 11,608 |   |
| Tax depletion in excess of basis                      |       | (613               | )          | (447     | )          | (210     | )          |
| Revision of previous tax estimates                    |       | 102                |       | (51      | )          | (12      | )          |
| Change in valuation allowance                         |       | —             |       | —   |       | (871     | )          |
| State income taxes, net of federal tax effect         |       | (40                | )          | 608      |       | —   |       |
| Other                                                 |       | 168                |       | —   |       | —   |       |
| Income tax expense (benefit)                          |       | $                  | (451       | )        | $          | (7,385   | )          | $ | 10,515 |   |
|                                                  |       |               |       |     |       |     |       |
| Current                                               |       | $                  | 75         |     | $          | 260      |       | $ | 343 |   |
| Deferred                                              |       | (526               | )          | (7,645   | )          | 10,172   |       |
| Income tax expense (benefit)                          |       | $                  | (451       | )        | $          | (7,385   | )          | $ | 10,515 |   |

 

The Company derives an income tax benefit when employees and directorsexercise options granted under the Company’s stock compensation plans (seeNote 10).  Employee stock optionsthat are classified as fixed stock options under APB 25 do not result in acharge against book income when the option price is equal to or greater thanthe market price at date of grant. Therefore, any tax benefit from the exercise of fixed stock optionsresults in a permanent difference, which is recorded to additional paid-incapital when the tax benefit is realized.

 

In connection with the SWRmerger, the Company acquired $29.3 million of tax loss carryforwards that aresubject to limitations under Internal Revenue Code Section 382 from aprior change in control that occurred in April 2002 and from the change incontrol of SWR that occurred in connection with the Company’s acquisition ofSWR in May 2004.  The Company hascompleted a review of the facts surrounding these changes in control andpresently believes that it will be able to utilize all of SWR’s tax losscarryforwards.

 

At December 31, 2005, theCompany’s cumulative tax loss carryforwards were approximately$7.1 million.  Based upon currentcommodity prices and production volumes, as well as the availability of taxplanning strategies (such as elective capitalization of intangible drillingcosts), the Company believes that it is more likely than not that the Companywill be able to utilize these tax loss carryforwards before they expire(beginning in 2008).  Accordingly, no valuation allowance has beenprovided at December 31, 2005.

 

**7.****             Derivatives**

 

*CommodityDerivatives*

From time to time,the Company utilizes commodity derivatives, consisting of swaps, floors andcollars, to attempt to optimize the price received for its oil and gasproduction.  When using swaps to hedgeoil and natural gas production, the Company receives a fixed price for therespective commodity and pays a floating market price as defined in eachcontract (generally NYMEX futures prices), resulting in a net amount due to orfrom the counterparty.  In floor transactions,the Company receives a fixed price (put strike price) if the market price fallsbelow the put strike price for the respective commodity.  If the market price is greater than the putstrike price, no payments are due from either party.  Costless collars are a combination of putsand calls, and contain a fixed floor price (put strike price) and ceiling price(call strike price).  If the market pricefor the respective commodity exceeds the call strike price or falls below

 

F-18

----

 

the put strikeprice, then the Company receives the fixed price and pays the marketprice.  If the market price is betweenthe call and the put strike prices, no payments are due from either party.

 

The followingsummarizes information concerning the Company’s net positions in open commodityderivatives applicable to periods subsequent to December 31, 2005.  The settlement prices of commodityderivatives are based on NYMEX futures prices.

 

**Collars:**

 

| ** **         | ** ** | **Gas**       | ** ** | **Oil**   | ** ** |
|--------------------|------------|---------------|------------|-----------|------------|
| ** **         | ** ** | **MMBtu (a)** | ** ** | **Floor** | ** ** | **Ceiling** | ** ** | **Bbls** | ** ** | **Floor** | ** ** | **Ceiling** | ** ** |
| Production Period: |       |          |       |      |       |   |   |   |   |   |   |   |   |
| 1st Quarter 2006   |       | 561,000       |       | $         | 4.00       |   | $ | 5.21 |   | 157,000 |   | $ | 23.00 |   | $ | 25.32 |   |
| 2nd Quarter 2006   |       | 551,000       |       | $         | 4.00       |   | $ | 5.21 |   | 156,000 |   | $ | 23.00 |   | $ | 25.32 |   |
| 3rd Quarter 2006   |       | 456,000       |       | $         | 4.00       |   | $ | 5.21 |   | 150,000 |   | $ | 23.00 |   | $ | 25.32 |   |
| 4th Quarter 2006   |       | 456,000       |       | $         | 4.00       |   | $ | 5.21 |   | 150,000 |   | $ | 23.00 |   | $ | 25.32 |   |
| 2007               |       | 1,831,000     |       | $         | 4.00       |   | $ | 5.18 |   | 562,000 |   | $ | 23.00 |   | $ | 25.20 |   |
| 2008               |       | 1,279,000     |       | $         | 4.00       |   | $ | 5.15 |   | 392,000 |   | $ | 23.00 |   | $ | 25.07 |   |
|               |       | 5,134,000     |       |      |       |   |   | 1,567,000 |   |   |   |   |   |

 

----

(a)   One MMBtu equals one Mcf at a Btu factor of 1,000.

 

The Company is a party to interest rate swaps that were acquired inconnection with the SWR acquisition. Under these derivatives, the Company pays a fixed rate for the notionalprincipal balances and receives a floating market rate based on LIBOR.  The following summarizes informationconcerning the Company’s net positions in open interest rate swaps applicableto periods subsequent to December 31, 2005.

 

**Interest Rate Swaps:**

 

| ** **                           | ** ** | ** **    | ** ** | **Fixed** | ** ** |
|--------------------------------------|------------|---------------|------------|-----------|------------|
| ** **                           | ** ** | **Principal** | ** ** | **Libor** | ** ** |
| ** **                           | ** ** | **Balance**   | ** ** | **Rates** | ** ** |
| Period:                              |       |          |       |      |       |
| January 1, 2006 to November 1, 2006  |       | $             | 55,000,000 |      | 4.29       | % |
| November 1, 2006 to November 1, 2007 |       | $             | 50,000,000 |      | 5.19       | % |
| November 1, 2007 to November 1, 2008 |       | $             | 45,000,000 |      | 5.73       | % |

 

F-19

----

 

*Accounting For Derivatives*

The Company accounts for itsderivatives in accordance with SFAS 133, as amended.  The followingtable sets forth, for the year ended December 31, 2003, the components ofaccumulated other comprehensive income, as reported in stockholders’ equity,all of which is related to derivatives designated as cash flow hedges underSFAS 133.  There was no activity inthis account during 2004 or 2005.

 
| ** **                                | ** ** | **Accumulated Other**           | ** ** |
|-------------------------------------------|------------|---------------------------------|------------|
| ** **                                | ** ** | **Comprehensive Income (Loss)** | ** ** |
| ** **                                | ** ** | **Commodity**                   | ** ** | **Interest Rate** | ** ** | ** ** | ** ** |
| ** **                                | ** ** | **Derivatives**                 | ** ** | **Derivatives** | ** ** | **Total** | ** ** |
| ** **                                | ** ** | **(In thousands)**              | ** ** |
|                                      |       |                            |       |
| Balance, December 31, 2002                |       | (7,290                          | )          | (660 | ) | (7,950 | ) |
| Loss on derivatives, net of tax           |       | (5,429                          | )          | (50 | ) | (5,479 | ) |
| Reclassifications to earnings, net of tax |       | 12,719                          |       | 710 |   | 13,429 |   |
| Net changes during the period             |       | 7,290                           |       | 660 |   | 7,950 |   |
| Balance, December 31, 2003                |       | $                               | —     |   | $ | — |   | $ | — |   |
|                                           |            |                                 |            |  |  |  |  |  |  |  |

 

The Company did not designate any ofits currently open positions in commodity hedges as cash flow hedges;therefore, all changes in the fair value of these contracts prior to maturity,plus any realized gains or losses at maturity, are recorded as other income(expense) in the Company’s statements of operations.  For 2005, loss on derivatives related toundesignated contracts consisted of net realized losses of $29.7 millionand losses related to changes in mark-to-market valuations of$40.4 million.  For 2004, loss onderivates related to undesignated contracts consisted of net realized losses of$18.2 million and losses related to changes in mark-to-market valuationsof $7.1 million.

 

**8.****            ****Financial Instruments**

 

Cash and cash equivalents,receivables, accounts payable and accrued liabilities were each estimated tohave a fair value approximating the carrying amount due to the short maturityof those instruments.  Indebtedness underthe secured bank credit facility was estimated to have a fair valueapproximating the carrying amount since the interest rate is generally marketsensitive.

 

The fair values of derivativesas of December 31, 2005 and 2004 are set forth below.

 
| ** **                | ** ** | **2005**           | ** ** | **2004**   | ** ** |
|---------------------------|------------|--------------------|------------|------------|------------|
| ** **                | ** ** | **(In thousands)** | ** ** |
| Assets (liabilities):     | ** ** | ** **         | ** ** | ** ** | ** ** |
| Commodity derivatives     |       | $                  | (82,635    | )          | $          | (41,162 | ) |
| Interest rate derivatives |       | (422               | )          | (1,489     | )          |
| Net assets (liabilities)  |       | $                  | (83,057    | )          | $          | (42,651 | ) |
|                           |            |                    |            |            |            |  |  |  |

 

**9.****             Common Stock**

 

In a series of seven monthly transactions fromFebruary 2005 through August 2005, the Company issued a total of9,268 shares of restricted common stock to Mr. Williams in lieu of netcash compensation aggregating $270,000.

 

In May 2004, the Company sold 1,380,869 shares of its common stock tocertain institutional investors at a price of $23.00 per share in a privateplacement for proceeds of approximately

 

F-20

----

 

$31.8 million.  After the payment of typical transactionexpenses, net proceeds of approximately $30 million were used to repay aportion of the bank indebtedness incurred to finance the acquisition of SWR(see Note 3).

 

**10.****          Compensation Plans**

 

*1993 Plan*

The Company has reserved1,798,200 shares of common stock for issuance under the 1993 Stock CompensationPlan (“1993 Plan”). The 1993 Plan providesfor the issuance of nonqualified stock options with an exercise price which isnot less than the market value of the Company’s common stock on the date ofgrant.  All options granted throughDecember 31, 2005 expire 10 years from the date of grant and become exercisablebased on varying vesting schedules.

 

The following table reflectsactivity in the 1993 Plan for 2005, 2004 and 2003.

 

| ** **          | ** ** | **2005**   | ** ** | **2004**     | ** ** | **2003**   | ** ** |
|---------------------|------------|------------|------------|--------------|------------|------------|------------|
| ** **          | ** ** | ** ** | ** ** | **Weighted** | ** ** | ** ** | ** ** | **Weighted** | ** ** | ** ** | ** ** | **Weighted** | ** ** |
| ** **          | ** ** | ** ** | ** ** | **Average**  | ** ** | ** ** | ** ** | **Average** | ** ** | ** ** | ** ** | **Average** | ** ** |
| ** **          | ** ** | **Shares** | ** ** | **Price**    | ** ** | **Shares** | ** ** | **Price** | ** ** | **Shares** | ** ** | **Price** | ** ** |
| Beginning of year   |       | 1,117,136  |       | $            | 17.75      |       | 821,042    |   | $ | 14.66 |   | 680,850 |   | $ | 12.29 |   |
| Granted             |       | 200,000    |       | $            | 29.39      |       | 300,000    |   | $ | 26.06 |   | 200,000 |   | $ | 19.74 |   |
| Exercised           |       | (3,585     | )          | $            | 5.50       |       | (3,906     | ) | $ | 5.50 |   | (59,808 | ) | $ | 4.03 |   |
| End of year         |       | 1,313,551  |       | $            | 19.56      |       | 1,117,136  |   | $ | 17.75 |   | 821,042 |   | $ | 14.66 |   |
|                |       |       |       |         |       |       |       |   |   |   |   |   |   |
| Exercisable         |       | 1,313,551  |       | $            | 19.56      |       | 1,117,136  |   | $ | 17.75 |   | 821,042 |   | $ | 14.66 |   |
| Available for grant |       | 101,766    |       |         |       | 301,766    |       |   |   | 601,766 |   |   |   |

 

The following table summarizes informationwith respect to options outstanding at December 31, 2005, all of which arecurrently exercisable.

 
| ** **                | ** ** | **Outstanding and Exercisable Options** | ** ** |
|---------------------------|------------|-----------------------------------------|------------|
| ** **                | ** ** | ** **                              | ** ** | ** ** | ** ** | **Weighted** | ** ** |
| ** **                | ** ** | ** **                              | ** ** | **Weighted** | ** ** | **Average** | ** ** |
| ** **                | ** ** | ** **                              | ** ** | **Average** | ** ** | **Remaining** | ** ** |
| ** **                | ** ** | ** **                              | ** ** | **Exercise** | ** ** | **Life in** | ** ** |
| ** **                | ** ** | **Shares**                              | ** ** | **Price** | ** ** | **Years** | ** ** |
| Range of exercise prices: |       |                                    |       |   |   |   |   |
| $5.50                     |       | 162,551                                 |       | $ | 5.50 |   | 2.3 |   |
| $14.50 - $29.39           |       | 1,151,000                               |       | $ | 21.54 |   | 5.3 |   |
|                      |       | 1,313,551                               |       | $ | 19.56 |   | 4.2 |   |

 

*Directors Plan*

The Company has reserved 86,300 shares ofcommon stock for issuance under the Outside Directors Stock Option Plan (“DirectorsPlan”).  Since inception of the DirectorsPlan, the Company has issued options covering 40,000 shares of common stock atoption prices ranging from $3.25 to $28.93 per share.  All outstanding options expire 10 years fromthe grant date and are fully exercisable upon issuance.  At December 31, 2005, options topurchase 25,000 shares were outstanding, and 46,300 shares remain available forfuture grants.

 

*Bonus Incentive Plan*

The Company has reserved 115,500shares of common stock for issuance under the Bonus Incentive Plan.  The plan provides that the Board of Directorseach year may award bonuses in cash, common stock of

 

F-21

----

 

the Company, or a combinationthereof.  At December 31, 2005,106,190 shares remain available for issuance under this plan.

 

*Executive Stock CompensationPlan*

The Company has a compensationplan which permits the Company to pay all or part of selected executives’salaries and bonuses in shares of common stock in lieu of cash.  The Company reserved an aggregate of 500,000shares of common stock for issuance under this plan.  During 2005, 2004 and 2003, the Companyissued 1,728, 18,609, and 15,275 shares, respectively, of common stock toMr. Williams in lieu of cash salary and bonuses aggregating $36,000,$463,000, and $270,000, respectively. The amounts of such compensation areincluded in general and administrative expense in the accompanying consolidatedfinancial statements.  The planterminated in February 2005.

 

*401(k) Plan*

Employees who have met certainage and length of employment requirements are eligible to participate in a401(k) plan sponsored by the Company. Each participant may make annual contributions to the plan in amountsnot to exceed the lesser of (i) 100% of the participant’s pre-tax annualearnings and (ii) the maximum amount of annual contributions allowed bylaw.  The Company may, in its solediscretion, provide a matching contribution equal to a percentage of theparticipants’ contributions.  The planpermits the Company to make its matching contributions in common stock of theCompany.  There are no vestingrequirements in the plan.  During 2005,2004 and 2003, the Company contributed $379,000, $318,000 and $247,000,respectively, in market value of common stock to the 401(k) plan.

 

*After-Payout Working InterestIncentive Plans*

In September 2002, the CompensationCommittee of the Board of Directors adopted an incentive plan for officers, keyemployees and consultants, excluding Mr. Williams, who promote the Company’sdrilling and acquisition programs.  Management’s objective in adoptingthis plan is to further align the interests of the participants with those ofthe Company by granting the participants an after-payout working interest inthe production developed, directly or indirectly, by the participants. The plan provides for the creation of a series of limited partnerships to whichthe Company, as general partner, contributes a portion of its working interestin wells drilled within certain areas, and the key employee and consultants, aslimited partners, contribute cash.  The Company pays all costs andreceives all revenues until payout of its costs, plus interest.  Atpayout, the limited partners receive at least 99% of all subsequent revenuesand pay at least 99% of all subsequent expenses attributable to thepartnerships’ interests.

 

From 3% to 6% of the Company’sworking interests in certain specified wells drilled by the Company subsequentto October 2002 are subject to this arrangement.  The Company consolidates its proportionateshare of the assets, liabilities, revenues, expenses and oil and gas reservesof these partnerships in its consolidated financial statements.  In April 2004, one of the partnershipsachieved payout, and the Company’s interest in the partnership was reduced to1%.  Aggregate cash distributions ofapproximately $292,000 were paid to the limited partners during 2005.  During 2005, the Company recognized $680,000of non-cash compensation expense for the estimated value of the after-payoutinterests contributed to the partnerships formed during the year.

 

**11.****          Transactions with Affiliates**

 

The Company and other entities(the “Williams Entities”) controlled by Mr. Williams are parties to anagreement (the “Service Agreement”) pursuant to which the Company furnishesservices to, and receives services from, such entities.  Under the Service Agreement, the Companyprovides legal, payroll, benefits administration, and financial and accountingservices to the Williams Entities, as well as technical services with respectto certain oil and gas properties owned by the Williams Entities.  The Williams Entities provide tax preparationservices, tax planning services, and business entertainment to or for thebenefit of the

 

F-22

----

 

Company.  The following table summarizes the charges toand from the Williams Entities for the years ended December 31, 2005, 2004 and2003.

 
| ** **                                   | ** ** | **2005**           | ** ** | **2004** | ** ** | **2003** | ** ** |
|----------------------------------------------|------------|--------------------|------------|----------|------------|----------|------------|
| ** **                                   | ** ** | **(In thousands)** | ** ** |
| Amounts received from the Williams Entities: |       |               |       |     |       |     |       |
| Service Agreement:                           |       |               |       |     |       |     |       |
| Services                                     |       | $                  | 224        |     | $          | 314      |       | $ | 288 |   |
| Insurance premiums and benefits              |       | 667                |       | 691      |       | 682      |       |
| Reimbursed expenses                          |       | 356                |       | 388      |       | 357      |       |
|                                         |       | $                  | 1,247      |     | $          | 1,393    |       | $ | 1,327 |   |
| Amounts paid to the Williams Entities:       |       |               |       |     |       |     |       |
| Rent (a)                                     |       | $                  | 582        |     | $          | 493      |       | $ | 402 |   |
| Service Agreement:                           |       |               |       |     |       |     |       |
| Business entertainment (b)                   |       | 113                |       | 113      |       | 79       |       |
| Other services                               |       | 150                |       | 85       |       | 45       |       |
| Reimbursed expenses                          |       | 122                |       | 105      |       | 73       |       |
|                                         |       | $                  | 967        |     | $          | 796      |       | $ | 599 |   |

 

----

(a)   Rentamounts were paid to the Partnership discussed in Note 12.  The Company owns 31.9% of the Partnership andaffiliates of the Company own 23.3%.

(b)   Consistsof hunting and fishing rights pertaining to land owned by affiliates ofMr. Williams.

 

Accounts receivable fromaffiliates and accounts payable to affiliates include, among other things,amounts for customary charges by the Company as operator of certain wells inwhich affiliates own an interest.

 

**12.****          Investments**

 

In May 2001, the Companyinvested approximately $1.6 million as a limited partner in ClayDestaBuildings, L.P. (“CDBLP”).  The generalpartner of CDBLP is owned and controlled by Mr. Williams.  CDBLP purchased and presently operates twocommercial office buildings in Midland, Texas, one of which is the location ofthe Company’s corporate headquarters. The Company’s ownership interest in CDBLP is 31.9% before payout (asdefined in the partnership agreement) and 33.4% after payout.  The Company is not liable for anyindebtedness of CDBLP.  Since the Companydoes not control CDBLP or manage the operations of these buildings, and sinceCDBLP does not meet the characteristics of a variable interest entity underFIN 46R, the Company utilizes the equity method of accounting for itsinvestment in CDBLP.  For the years ended December 31, 2005, 2004 and2003, the Company recorded pretax income of $10,000, $60,000, and $47,000,respectively, from the partnership.

 

In October 2003, the Companyinvested $1.5 million in a privately-held company organized by a thirdparty to acquire and expand a CO2 distribution system in Pecos County,Texas.  Of the total investment, 50% was for the purchase of common stock,representing 6.3% of the equity interests of the investee.  The balancewas a subordinated loan to the investee bearing interest at 6% per year. The Company accounts for the stock portion of its investment at cost.  In December 2005, the Company exchanged itsequity investment and note receivable for common stock of the entity’s parentcompany.  The Company recorded the valueof common stock received based upon the cash consideration paid for otherinterests acquired in the exchange offer.  The Company recognized a gain of approximately$1.2 million upon the exchange, which is included in other income in theaccompanying statement of operations.

 

F-23

----

** **

**13.****          Commitments and Contingencies**

 

*Leases*

TheCompany leases office space from affiliates and nonaffiliates undernoncancelable operating leases.  Rentalexpense pursuant to the office leases amounted to $779,000, $678,000 and$578,000 for the years ended December 31, 2005, 2004 and 2003, respectively.

 

Futureminimum payments under noncancelable leases at December 31, 2005, are asfollows:

 
| ** **                   | ** ** | **Leases**         | ** ** | ** **    | ** ** |
|------------------------------|------------|--------------------|------------|---------------|------------|
| ** **                   | ** ** | **Capital (a)**    | ** ** | **Operating** | ** ** | **Total** | ** ** |
| ** **                   | ** ** | **(In thousands)** | ** ** |
| 2006                         |       | $                  | 398        |          | $          | 743 |   | $ | 1,141 |   |
| 2007                         |       | 307                |       | 247           |       | 554 |   |
| 2008                         |       | 122                |       | 18            |       | 140 |   |
| Thereafter                   |       | —             |       | 12            |       | 12 |   |
| Total minimum lease payments |       | $                  | 827        |          | $          | 1,020 |   | $ | 1,847 |   |

 

----

(a)           Relatesto vehicle leases.

 

*Drilling Rig Joint Venture*

InOctober 2005, the Company entered into a letter agreement with LariatServices, Inc. (“Lariat”), a contract drilling company, which calls for theformation of a joint venture to acquire at least 12 new drilling rigs. The Company and Lariat will each own a 50% interest in the joint venture. Lariat will serve as the operations manager of the joint venture, and the Companywill be responsible for financing the purchase of the rigs.  The totalacquisition cost, including construction and equipping of the rigs, is expectedto be approximately $75 million.

 

The joint venturehas received a proposal from a lender to provide financing for up to$75 million, depending on the appraised values of the drilling rigs uponcompletion of construction.  During 2006,while the drilling rigs are being constructed, the proposal contemplates that****theCompany provide the lender a $19.5 million standby letter of creditas additional credit support.  On orbefore December 31, 2006, the Company would terminate the letter of credit andprovide an unconditional guaranty to the lender of the repayment and performanceby the joint venture limited to $19.5million of the outstanding balance of the loan facility.  Under the terms of the proposal, the Companywould also be required to contract with the joint venture to use the drillingrigs in its drilling program for a term of at least three years and to pay foridle, non-working rigs in amounts ranging from $8,000 to $11,000 per day.  The Company expects to complete negotiationswith the lender and to close the financing in March 2006.

 

AtDecember 31, 2005, the Company had made advances on behalf of the jointventure of approximately $10.3 million for interim construction costs ofthe rigs and related equipment.  Thejoint venture is to reimburse the Company for all advances once it has receivedthe proceeds from the financing.

 

TheCompany is currently evaluating its investment in this joint venture todetermine if the Company is the primary beneficiary under FIN 46R.  If the Company determines that it is theprimary beneficiary, the Company will be required to fully consolidate thisentity in 2006.

 

*Equipment Orders*

As ofDecember 31, 2005, the Company has placed firm orders for tubing, casing,pumping units and other equipment to be used in its exploration and developmentactivities totaling approximately $8.6 million.

 

F-24

----

 

*Legal Proceedings*

TheCompany is a defendant in several lawsuits that have arisen in the ordinarycourse of business. While the outcome of these lawsuits cannot be predictedwith certainty, management does not expect any of these to have a materialadverse effect on the Company’s consolidated financial condition or results ofoperations.

 

**14.****          Impairment of Property and Equipment**

 

TheCompany has recorded provisions for impairment of proved properties underSFAS 144 of $18.3 million in 2005 and $170,000 in 2003.  The 2005 provision relates to productionperformance on prospects in West Texas. The 2003 provision relates to the Sweetlake area in south Louisiana.  No provision was recorded in 2004.

 

TheCompany has also recorded provisions for impairment of unproved propertiesaggregating $5.3 million, $20.4 million and $7.3 million in 2005,2004 and 2003, respectively, and charged these impairments to exploration costsin the accompanying statements of operations. The impairments of unproved properties recorded were based on drillingresults and management’s plans for future drilling activities.

 

**15.****          Sales of Assets**

 

Gainon sale of property and equipment for 2005 was $18.9 million.  In August 2005, the Company sold its interests in two leases inthe Breton Sound area in the Gulf of Mexico (offshore Louisiana) for$21.3 million, subject to post-closing adjustments and realized a gain of$16.8 million on this sale.  Gain on sale ofproperty and equipment for 2004 was $4.1 million, including the sale ofthe Jo-Mill Unit in Borden County, Texas. Loss on sale of property and equipment for 2004 was $14.3 millionincluding the sale of the Romere Pass Unit in Plaquemines Parish, Louisiana.  Under EITF 03-13, “Applying theConditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether toReport Discontinued Operations”, the Company has determined that these sales donot qualify for discontinued operations reporting.  The Company applied the guidance ofEITF 03-13 beginning in the fourth quarter of 2004.

 

F-25

----

 

**16.****          Quarterly Financial Data (Unaudited)**

 

The following table summarizesresults for each of the four quarters in the years ended December 31, 2005and 2004.

 
| ** **                                  | ** ** | **First**                            | ** ** | **Second**  | ** ** | **Third**   | ** ** | **Fourth**  | ** ** | ** ** | ** ** |
|---------------------------------------------|------------|--------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|------------|------------|
| ** **                                  | ** ** | **Quarter**                          | ** ** | **Quarter** | ** ** | **Quarter** | ** ** | **Quarter** | ** ** | **Year**   | ** ** |
| ** **                                  | ** ** | **(In thousands, except per share)** | ** ** |
| **Year ended December 31, 2005:**           | ** ** | ** **                           | ** ** | ** **  | ** ** | ** **  | ** ** | ** **  | ** ** | ** ** | ** ** |
| Total revenues                              |       | $                                    | 65,689     |        | $          | 66,318      |       | $           | 85,143     |       | $          | 66,449 |   | $ | 283,599 |   |
| Operating income                            |       | $                                    | 23,522     |        | $          | 26,283      |       | $           | 29,284     |       | $          | 1,252 |   | $ | 80,341 |   |
| Net income (loss) (a)                       |       | $                                    | (8,992     | )           | $          | 9,950       |       | $           | (2,040     | )          | $          | 1,339 |   | $ | 257 |   |
|                                        |       |                                 |       |        |       |        |       |        |       |       |       |
| Net income (loss) per common share (b):     |       |                                 |       |        |       |        |       |        |       |       |       |
| Basic                                       |       | $                                    | (.83       | )           | $          | .92         |       | $           | (.19       | )          | $          | .12 |   | $ | .02 |   |
| Diluted                                     |       | $                                    | (.83       | )           | $          | .90         |       | $           | (.19       | )          | $          | .12 |   | $ | .02 |   |
|                                        |       |                                 |       |        |       |        |       |        |       |       |       |   |   |   |   |   |
| Weighted average common shares outstanding: |       |                                 |       |        |       |        |       |        |       |       |       |
| Basic                                       |       | 10,792                               |       | 10,800      |       | 10,810      |       | 10,814      |       | 10,804     |       |
| Diluted                                     |       | 10,792                               |       | 11,089      |       | 10,810      |       | 11,254      |       | 11,241     |       |
|                                        |       |                                 |       |        |       |        |       |        |       |       |       |
| **Year ended December 31, 2004:**           | ** ** | ** **                           | ** ** | ** **  | ** ** | ** **  | ** ** | ** **  | ** ** | ** ** | ** ** |
| Total revenues                              |       | $                                    | 38,864     |        | $          | 43,552      |       | $           | 54,679     |       | $          | 69,235 |   | $ | 206,330 |   |
| Operating income                            |       | $                                    | 11,000     |        | $          | 6,005       |       | $           | 13,233     |       | $          | (19,799 | ) | $ | 10,439 |   |
| Net income (loss) (a)                       |       | $                                    | 4,813      |        | $          | 2,869       |       | $           | (9,188     | )          | $          | (12,522 | ) | $ | (14,028 | ) |
|                                        |       |                                 |       |        |       |        |       |        |       |       |       |   |   |   |   |   |
| Net income (loss) per common share (b):     |       |                                 |       |        |       |        |       |        |       |       |       |
| Basic                                       |       | $                                    | .51        |        | $          | .29         |       | $           | (.85       | )          | $          | (1.16 | ) | $ | (1.37 | ) |
| Diluted                                     |       | $                                    | .50        |        | $          | .28         |       | $           | (.85       | )          | $          | (1.16 | ) | $ | (1.37 | ) |
|                                        |       |                                 |       |        |       |        |       |        |       |       |       |   |   |   |   |   |
| Weighted average common shares outstanding: |       |                                 |       |        |       |        |       |        |       |       |       |
| Basic                                       |       | 9,371                                |       | 9,923       |       | 10,769      |       | 10,780      |       | 10,213     |       |
| Diluted                                     |       | 9,720                                |       | 10,230      |       | 10,769      |       | 10,780      |       | 10,213     |       |

 

----

(a)           The Company recorded a $18.3 million chargefor impairment of proved properties in the fourth quarter of 2005.  The Company recorded a $10.2 million losson sales of property and equipment and a $38.7 million loss forabandonments and impairments in the fourth quarter of 2004.

 

(b)           The sum of the individual quarterly net income(loss) per share amounts may not agree to the total for the year due to eachperiod’s computation based on the weighted average number of common sharesoutstanding during each period.

 

**17.****          Costs of Oil and Gas Properties**

 

The following table sets forthcertain information with respect to costs incurred in connection with the Company’soil and gas producing activities during the years ended December 31, 2005, 2004and 2003.

 
| ** **             | ** ** | **2005**           | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------|------------|--------------------|------------|----------|------------|----------|------------|
| ** **             | ** ** | **(In thousands)** | ** ** |
| Property acquisitions: |       |               |       |     |       |     |       |
| Proved                 |       | $                  | 5,567      |     | $          | 237,042  |       | $ | — |   |
| Unproved               |       | 50,238             |       | 33,826   |       | 7,982    |       |
| Developmental costs    |       | 42,292             |       | 27,469   |       | 12,465   |       |
| Exploratory costs      |       | 86,304             |       | 73,655   |       | 49,277   |       |
| Total                  |       | $                  | 184,401    |     | $          | 371,992  |       | $ | 69,724 |   |
|                        |            |                    |            |          |            |          |            |  |  |  |  |  |  |

 

F-26

----

 

The following table sets forththe capitalized costs for oil and gas properties as of December 31, 2005and 2004.

 
| ** **                                           | ** ** | **2005**           | ** ** | **2004** | ** ** |
|------------------------------------------------------|------------|--------------------|------------|----------|------------|
| ** **                                           | ** ** | **(In thousands)** | ** ** |
| Proved properties                                    |       | $                  | 957,962    |     | $          | 873,939 |   |
| Unproved properties                                  |       | 79,900             |       | 35,156   |       |
| Total capitalized costs                              |       | 1,037,862          |       | 909,095  |       |
| Accumulated depreciation, depletion and amortization |       | (570,386           | )          | (518,787 | )          |
| Net capitalized costs                                |       | $                  | 467,476    |     | $          | 390,308 |   |

 

**18.****          Oil and Gas Reserve Information (Unaudited)**

 

The estimates of proved oil andgas reserves utilized in the preparation of the consolidated financialstatements were prepared by independent petroleum engineers.  Such estimates are in accordance withguidelines established by the Securities and Exchange Commission and theFinancial Accounting Standards Board, which require that reserve reports beprepared under economic and operating conditions existing at the registrant’syear end with no provision for price and cost escalations except by contractualarrangements.  Future cash inflows werecomputed by applying year-end prices to the year-end quantities of provedreserves.  Future development,abandonment and production costs were computed by estimating the expendituresto be incurred in developing, producing, and abandoning proved oil and gasreserves at the end of the year, based on year-end costs.  Future income taxes were computed by applyingstatutory tax rates to the estimated net pre-tax cash flows after considerationof tax basis and tax credits and carryforwards. All of the Company’s reserves are located in the United States.  For information about the Company’s resultsof operations from oil and gas producing activities, see the accompanyingconsolidated statements of operations.

 

The Company emphasizes thatreserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current informationbecomes available.  In addition, aportion of the Company’s proved reserves are classified as proved developednonproducing and proved undeveloped, which increases the imprecision inherentin estimating reserves which may ultimately be produced.

 

The following table sets forth proved oil and gasreserves together with the changes therein (oil in MBbls, gas in MMcf, oilconverted to MMcfe at six MMcf per MBbl) for the years ended December 31,2005, 2004 and 2003.

** **
| ** **                     | ** ** | **2005** | ** ** | **2004** | ** ** | **2003**  | ** ** |
|--------------------------------|------------|----------|------------|----------|------------|-----------|------------|
| ** **                     | ** ** | **Oil**  | ** ** | **Gas**  | ** ** | **MMcfe** | ** ** | **Oil** | ** ** | **Gas** | ** ** | **MMcfe** | ** ** | **Oil** | ** ** | **Gas** | ** ** | **MMcfe** | ** ** |
| Proved reserves:               |       |     |       |     |       |      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Beginning of period            |       | 26,793   |       | 138,278  |       | 299,036   |       | 10,335 |   | 62,916 |   | 124,926 |   | 11,884 |   | 86,912 |   | 158,216 |   |
| Revisions                      |       | 2,193    |       | (5,333   | )          | 7,825     |       | 1,603 |   | 6,962 |   | 16,580 |   | (84 | ) | (7,323 | ) | (7,827 | ) |
| Extensions and discoveries     |       | 868      |       | 12,476   |       | 17,684    |       | 3,966 |   | 23,034 |   | 46,828 |   | 274 |   | 8,024 |   | 9,668 |   |
| Sales of minerals-in-place     |       | (101     | )          | (2,922   | )          | (3,528    | )          | (3,359 | ) | (7,967 | ) | (28,121 | ) | — |   | — |   | — |   |
| Purchases of minerals-in-place |       | 586      |       | 667      |       | 4,183     |       | 16,591 |   | 71,271 |   | 170,819 |   | — |   | — |   | — |   |
| Production                     |       | (2,504   | )          | (16,408  | )          | (31,432   | )          | (2,343 | ) | (17,938 | ) | (31,996 | ) | (1,739 | ) | (24,697 | ) | (35,131 | ) |
| End of period                  |       | 27,835   |       | 126,758  |       | 293,768   |       | 26,793 |   | 138,278 |   | 299,036 |   | 10,335 |   | 62,916 |   | 124,926 |   |
|                           |       |     |       |     |       |      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved developed reserves:     |       |     |       |     |       |      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Beginning of period            |       | 19,799   |       | 95,224   |       | 214,018   |       | 9,349 |   | 62,514 |   | 118,806 |   | 9,349 |   | 76,224 |   | 132,318 |   |
| End of period                  |       | 21,503   |       | 91,366   |       | 220,384   |       | 19,799 |   | 95,224 |   | 214,018 |   | 9,349 |   | 62,514 |   | 118,606 |   |

 

Net revisions of 7.8 Bcfe in 2005 consisted of approximately17.5 Bcfe of upward revisions attributable to the effects of higherproduct prices on the estimated quantities of proved reserves, net of downwardrevisions of approximately 9.7 Bcfe attributable to well performanceprimarily from properties in West Texas.

 

F-27

----

 

The standardized measure of discounted future netcash flows relating to proved reserves as of December 31, 2005, 2004 and 2003was as follows:

 
| ** **                                        | ** ** | **2005**           | ** ** | **2004** | ** ** | **2003**  | ** ** |
|---------------------------------------------------|------------|--------------------|------------|----------|------------|-----------|------------|
| ** **                                        | ** ** | **(In thousands)** | ** ** |
| Future cash inflows                               |       | $                  | 2,910,325  |     | $          | 1,867,242 |       | $ | 661,862 |   |
| Future costs:                                     |       |               |       |     |       |      |       |
| Production                                        |       | (811,529           | )          | (569,999 | )          | (179,500  | )          |
| Development                                       |       | (161,921           | )          | (119,807 | )          | (17,446   | )          |
| Income taxes                                      |       | (612,771           | )          | (336,030 | )          | (118,869  | )          |
| Future net cash flows                             |       | 1,324,104          |       | 841,406  |       | 346,047   |       |
| 10% discount factor                               |       | (570,392           | )          | (341,208 | )          | (93,067   | )          |
| Standardized measure of discounted net cash flows |       | $                  | 753,712    |     | $          | 500,198   |       | $ | 252,980 |   |

 

Changes in the standardizedmeasure of discounted future net cash flows relating to proved reserves for theyears ended December 31, 2005, 2004 and 2003 were as follows:

 
| ** **                                           | ** ** | **2005**           | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------------------------|------------|--------------------|------------|----------|------------|----------|------------|
| ** **                                           | ** ** | **(In thousands)** | ** ** |
| Standardized measure, beginning of period            |       | $                  | 500,198    |     | $          | 252,980  |       | $ | 293,698 |   |
| Net changes in sales prices, net of production costs |       | 458,744            |       | 43,178   |       | 28,745   |       |
| Revisions of quantity estimates                      |       | 35,741             |       | 37,629   |       | (21,212  | )          |
| Accretion of discount                                |       | 58,095             |       | 51,870   |       | 38,252   |       |
| Changes in future development costs, including       |       |               |       |     |       |     |       |
| development costs incurred that reduced  future      |       |               |       |     |       |     |       |
| development costs                                    |       | (21,368            | )          | (2,489   | )          | 10,106   |       |
| Changes in timing and other                          |       | (20,024            | )          | (16,297  | )          | (5,938   | )          |
| Net change in income taxes                           |       | (154,401           | )          | (119,605 | )          | 10,282   |       |
| Future abandonment cost, net of salvage              |       | (4,657             | )          | (3,395   | )          | (3,579   | )          |
| Extensions and discoveries                           |       | 100,302            |       | 149,680  |       | 37,419   |       |
| Sales, net of production costs                       |       | (195,195           | )          | (151,963 | )          | (134,793 | )          |
| Sales of minerals-in-place                           |       | (13,781            | )          | (56,142  | )          | —   |       |
| Purchases of minerals-in-place                       |       | 10,058             |       | 314,752  |       | —   |       |
| Standardized measure, end of period.                 |       | $                  | 753,712    |     | $          | 500,198  |       | $ | 252,980 |   |

 

The estimated present value offuture cash flows relating to proved reserves is extremely sensitive to pricesused at any measurement period.  The averageprices used for each commodity for the years ended December 31, 2005, 2004 and 2003 were as follows:

** **
| ** **         | ** ** | **Average Price** | ** ** |
|--------------------|------------|-------------------|------------|
| ** **         | ** ** | **Oil (a)**       | ** ** | **Gas** | ** ** |
| As of December 31: |       |              |       |   |   |
| 2005               |       | $                 | 57.85      |   | $ | 10.65 |   |
| 2004               |       | $                 | 41.48      |   | $ | 5.59 |   |
| 2003               |       | $                 | 30.45      |   | $ | 5.61 |   |

 

----

(a)   Includes natural gas liquids

 

F-28

----

 

**CLAYTON WILLIAMS ENERGY INC**

** **
| **Schedule  II – Valuation and Qualifying Accounts** |
|-----------------------------------------------------------|

 
| ** **                                                  | ** ** | **Balance at**     | ** ** | ** **       | ** ** | ** **        | ** ** | **Balance at** | ** ** |
|-------------------------------------------------------------|------------|--------------------|------------|------------------|------------|-------------------|------------|----------------|------------|
| ** **                                                  | ** ** | **Beginning of**   | ** ** | ** **       | ** ** | ** **        | ** ** | **End of**     | ** ** |
| **Description**                                             | ** ** | **Period**         | ** ** | **Additions(a)** | ** ** | **Deductions(b)** | ** ** | **Period**     | ** ** |
| ** **                                                  | ** ** | **(In thousands)** | ** ** |
| **Year Ended December 31, 2005:**                           |       |               |       |             |       |              |       |           |       |
| Allowance for doubtful accounts - Joint  interest and other |       | $                  | 1,013      |             | $          | 89                |       | $              | (15        | ) | $ | 1,087 |   |
|                                                        |       | $                  | 1,013      |             | $          | 89                |       | $              | (15        | ) | $ | 1,087 |   |
| **Year Ended December 31, 2004:**                           |       |               |       |             |       |              |       |           |       |
| Allowance for doubtful accounts - Joint  interest and other |       | $                  | 1,338      |             | $          | 50                |       | $              | (375       | ) | $ | 1,013 |   |
|                                                        |       | $                  | 1,338      |             | $          | 50                |       | $              | (375       | ) | $ | 1,013 |   |
| **Year Ended December 31, 2003:**                           |       |               |       |             |       |              |       |           |       |
| Allowance for doubtful accounts - Joint  interest and other |       | $                  | 400        |             | $          | 1,002             |       | $              | (64        | ) | $ | 1,338 |   |
| Allowance for doubtful accounts - Oil and  gas sales        |       | 286                |       | —           |       | (286              | )          | —         |       |
|                                                        |       | $                  | 686        |             | $          | 1,002             |       | $              | (350       | ) | $ | 1,338 |   |

 

----

(a)   Additionsrelate to provisions for doubtful accounts

(b)   Deductionsrelate to the write-off of accounts receivable deemed uncollectible

 

S-1

----