**UNITEDSTATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C.  20549**

**FORM 10-K**

| **(Mark One)**                                                                                                                                                                                                                  |                                                   |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------|
| **x**                                                                                                                                                                                                                           | **ANNUAL REPORT PURSUANT TO SECTION 13 OR  15(d)**     |
| ** **                                                                                                                                                                                                                      | **OF THE SECURITIES EXCHANGE ACT OF 1934**             |
| ** **                                                                                                                                                                                                                      | ** **                                             |
| **For the fiscal year  ended December 31, 2006**                                                                                                                                                                                |
|                                                                                                                                                                                                                            |                                                   |
| **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**                                                                                                                                                                                           |

**CLAYTON WILLIAMS 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 theAct:

**Common Stock - $.10 Par Value**

(Title of Class)

Securities registered pursuant to Section 12(g) of theAct:

**None**

Indicate by check mark ifthe registrant is a well-known seasoned issuer, as defined in Rule 405 ofthe Securities Act

|  | o  Yes |   | x  No |   |
|--|--------|--------|-------|--------|

 

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

|  | o  Yes |   | x  No |   |
|--|--------|--------|-------|--------|

 

Indicateby check mark whether the registrant (1) has filed all reports required to befiled by Section 13 or 15(d) of the Securities Exchange Act of 1934 duringthe preceding 12 months (or for such shorter period that the registrant wasrequired to file such reports), and (2) has been subject to such filingrequirements for the past 90 days.

|  | x  Yes |   | o  No |   |
|--|--------|--------|-------|--------|

 

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.            ̈

 

Indicate by check mark whetherthe 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 |   | Accelerated  filer x |   | Non-accelerated  filer o |
|---------------------------|--------|----------------------|--------|--------------------------|

 

Indicate by check mark whether the registrant is ashell company (as defined in Rule 12b-2 of the Act). oYes x No

 

State the aggregate market valueof the voting and non-voting common equity held by non-affiliates, computed byreference to the price at which common equity was last sold, as of the lastbusiness day of the registrant’s most recently completed second fiscal quarter.  $214,601,268.

** **

There were 11,352,051 shares ofCommon Stock, $.10 par value, of the registrant outstanding as ofMarch 14, 2007.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2007 AnnualMeeting of Stockholders, which will be filed with the Commission not later thanApril 30, 2007, are incorporated by reference in Part III 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 Equity, Related  Stockholder Matters and            |       |       |
|        |       | Issuer Repurchases of Equity Securities                                                     |       |       |
|        |       | 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                                                                    |       |       |
|        |       | Proved  Oil and Gas Reserves                                                                |       |       |

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## **TABLE OF CONTENTS (Continued)**

| Item 7.                |   | Management’s  Discussion and Analysis of Financial Condition and Results of Operations  (continued) |   |   |
|------------------------|--------|----------------------------------------------------------------------------------------------------------|--------|--------|
|                   |   | 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 and  Financial Statement Schedules                                                              |   |   |
| ** **             |   | Financial Statements and Schedules                                                                       |   |   |
| ** **             |   | Exhibits                                                                                                 |   |   |
| ** **             |   |                                                                                                     |   |   |
| **Glossary  of Terms** |   |                                                                                                     |
|                   |   |                                                                                                     |   |   |
| **Signatures**         |   |                                                                                                     |
|                        |        |                                                                                                          |        |        |  |  |

 

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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;estimates of 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 an independent oil and gas company engagedin the exploration for and production of oil and natural gas primarily inTexas, Louisiana and New Mexico.  Unlessthe context otherwise requires, references to the “Company”, “CWEI”, “we”, “us”or “our” mean Clayton Williams Energy, Inc. and its consolidatedsubsidiaries.  On December 31, 2006,our estimated proved reserves were 271.5 Bcfe, of which 75% were proved developed.  We have a balanced portfolio of oil andnatural gas reserves, with approximately 44% of our proved reserves at December 31, 2006 consisting ofnatural gas and approximately 56%consisting of oil and natural gas liquids. During 2006, we added proved reserves of 29.4 Bcfe throughextensions and discoveries, had downward revisions of 28.7 Bcfe andacquired 6.4 Bcfe through purchases of minerals-in-place.  We also achieved average net production of 80.6 Mmcfe per day in 2006, whichimplies a reserve life of approximately 9.2 years.  CWEI held interests in 6,626 gross(891.9 net) producing oil and gas wells and owned leasehold interests inapproximately 1.3 million gross (865,000 net) undeveloped acres atDecember 31, 2006.

Clayton W. Williamsbeneficially owns, either individually or through his affiliates, approximately47% of the outstanding shares of our common stock.  Mr. Williams is also our Chairman of theBoard and Chief Executive Officer.  As aresult, Mr. Williams has significant influence in matters voted on by ourshareholders, including the election of our Board members.  Mr. Williams actively participates inall facets of our business and has a significant impact on both our businessstrategy and daily operations.

In 2007, we plan to spendapproximately $170.1 million on exploration and development activities, ofwhich 83% relate to exploratory prospects. More than 60% of these planned expenditures in 2007 have been allocatedto exploration and development activities in Louisiana.

**Company Profile**

***Domestic Operations***

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

***Exploration Program***

Our primary business strategy is togrow our oil and gas reserves through exploration activities, consisting ofgenerating exploratory prospects, leasing the acreage applicable to theprospects, drilling exploratory wells on these

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prospects to determine ifrecoverable oil and gas reserves exist, drilling developmental wells onprospects, and producing and selling any resulting oil and gas production.

To generate a typical exploratoryprospect, we first identify geographical areas that we believe may containundiscovered oil and gas reserves.  Wethen consider many other business factors related to those geographical areas,including proximity to our other areas of operations, our technical knowledgeand experience in the area, the availability of acreage, and the overallpotential for finding reserves.  Most ofour current exploration efforts are concentrated in regions that have beenknown to produce oil and gas.  Theseregions include some of the larger producing regions in Texas and Louisiana.

In most cases, we then obtain andprocess seismic data using sophisticated geophysical technology to attempt tovisualize underground structures and stratigraphic traps that may holdrecoverable reserves.  Although thistechnology increases our expectations of a successful discovery, it does notand cannot assure us of success.  Manyfactors are involved in the interpretation of seismic data, including the fieldrecording parameters of the data, the type of processing, the extent ofattribute analyses, the availability of subsurface geological data, and thedepth and complexity of the subsurface. Significant judgment is required in the evaluation of seismic data, anddifferences of opinion often exist between experienced professionals.  These interpretations may turn out to beinvalid and may result in unsuccessful drilling results.

Obtaining oil and gas reserves throughexploration activities involves a higher degree of risk than through drillingdevelopmental wells or purchasing proved reserves.  We often commit significant resources toidentify a prospect, lease the drilling rights and drill a test well before weknow if a well will be productive.  Tooffset this risk, our typical exploratory prospect is expected to offer asignificantly higher reserve potential than a typical lower-riskdevelopment prospect might offer.  Thereserve potential is determined by estimating the aerial extent of thestructural or stratigraphic trap, the vertical thickness of the reservoir inthe trap, and the recovery factor of the hydrocarbons in the trap.  The recovery factor is affected by a combinationof factors including (i) the reservoir drive mechanism (water drive,depletion drive or a combination of both), (ii) the permeability andporosity of the reservoir, and (iii) the bottom hole pressure (in the caseof gas reserves).

Due to the high risk/high rewardnature of oil and gas exploration, we expect to spend money on prospects thatare ultimately nonproductive.  However,over time, we believe our productive prospects will generate sufficient cashflow to provide us with an acceptable rate of return on our entire investment,both nonproductive and productive.

Weare presently concentrating our exploration efforts in South Louisiana, NorthLouisiana and East Texas.  Approximately83% of our planned expenditures for 2007 relate to exploratory prospects, ascompared to approximately 84% of actual expenditures in 2006 and 73% of actualexpenditures in 2005.  During 2006, wespent $210.2 million on exploratory prospects, including$58.6 million on seismic and leasing activities and $151.6 million ondrilling activities.

***Development Program***

Complimentaryto our higher risk/higher potential exploration program is our developmentprogram.  We have an inventory ofdevelopmental projects available for drilling in the future.  At December 31, 2006, we had proveddeveloped nonproducing reserves and proved undeveloped reserves of99.8 Bcfe.  We currently estimatethat we will be required to spend approximately $160.3 million indevelopment costs to develop these reserves. Since the timing of developing these reserves is discretionary, we havedecided to limit expenditures on our developmental program in 2007 in order topreserve more capital resources for our exploratory activities in areas wherewe have leases that will expire unless commercial production is commencedbefore the end of their current lease terms. We may allocate a more significant portion of our capital expendituresto development activities in years after 2007.

***Acquisition and Divestitures of Proved Properties***

In addition to our exploration anddevelopment activities, we are also engaged in the business of acquiring provedreserves.  Competition for the purchaseof proved reserves is intense.  Sellersoften utilize 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 2007.

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In 2006, an affiliated partnership,West Coast Energy Properties, L.P. (“WCEP”), acquired certain producing oil andgas assets in California and Texas for aggregate cash consideration of $58million.  Approximately 75% of thepurchase price related to properties in three fields in southern California,and the remaining 25% related primarily to properties located in MitchellCounty, Texas.  One of our subsidiariesis the general partner of WCEP, and an affiliate of GE Energy FinancialServices is the limited partner.  Wecontributed $6.2 million to WCEP for an initial general partner interest of5%.  Our general partner interest can increaseto 37.63%, and ultimately to 49%, if the limited partner achieves certaintarget rates of return.

From time to time, we sell certainof our proved properties when we believe it is more advantageous to dispose ofthe selected properties than to continue to hold them.  We consider many factors in deciding to sellproperties, including the need for liquidity, the risks associated withcontinuing to own the properties, our expectations for future development onthe property, the fairness of the price offered, and other factors related tothe condition and location of the property.  We did not sell any proved properties in 2006,but we may elect to sell selected properties in 2007.

***Drilling Rigs***

In April 2006, we formed a jointventure (“Larclay JV”) with Lariat Services, Inc. (“Lariat”) to construct, ownand operate 12 new drilling rigs, consisting of five 1,000 horsepower rigs,five 1,300 horsepower rigs and two 2,000 horsepower rigs.  Our business purpose for Larclay JV was toprovide us with a reliable source of drilling rigs to be used in ourexploration and development drilling programs. At the time, the supply of suitable drilling rigs was tight, causing theavailability of rigs to be uncertain and the contract terms under drillingcontracts to be less favorable.  Tolessen our reliance on other contractors for drilling rigs, and to mitigate ourexposure to high contract rates and terms, we decided to join with anestablished drilling contractor for the construction and ownership of theLarclay JV rigs.

The rigs are being constructed onbehalf of Larclay JV by Lariat, as operations manager.  All five of the 1,300 horsepower rigs and oneof the 1,000 horsepower rigs were fully constructed at December 31,2006.  Subsequently, construction onthree of the remaining four 1,000 horsepower rigs has been completed.  The remaining three rigs are expected to befully constructed June 2007.  Totalconstruction cost of all rigs, excluding capitalized interest, is expected tobe approximately $79 million.

Our principal obligation as apartner in the Larclay JV is to provide the necessary credit support to financethe construction of the rigs.  Wearranged for a lender to provide a $75 million secured term loan to Larclay JVto finance most of the cost of constructing and initially equipping the rigs.The terms of the loan originally required us to issue a $19 million letterof credit to the lender as additional collateral during the constructionperiod.  In February 2007, the lenderreleased the letter of credit in exchange for our limited guaranty in theamount of $19.5 million.  Aftercompletion of the construction period, outstanding advances under the term loanmust not exceed 75% of the appraised value of the rigs.  If proceeds available to Larclay JV under theterm loan are not sufficient to fully finance the cost of acquiring the rigs,we will be required to loan funds to Larclay JV at the same interest rate asthe term loan.

Also in April 2006, we entered intoa three-year drilling contract with Larclay JV assuring the availability ofeach rig for use in the ordinary course of our exploration and developmentdrilling programs throughout the term of the drilling contract.  The provisions of the drilling contractprovide that we contract for each rig on a well-by-well basis at then currentmarket rates.  If we do not need a rig atany time during the term of the contract, Larclay JV may contract with otheroperators for the use of that rig, subject to certain restrictions.  If a rig is idle, we are required to payLarclay JV an idle rig rate ranging from $8,100 per day to $10,300 per day (pluscrew labor expenses, if applicable), depending on the size of the rig.

Our maximum potential obligation topay idle rig rates over the term of this drilling contract, excluding any crewlabor expenses, totals $109 million; however, our obligation under thecontract is mitigated as rigs are contracted to drill for other operators.  Currently, two rigs are drilling for us, fiverigs are drilling for an affiliate of Lariat, and two rigs are drilling forother operators.  We currently plan touse at least one of the 1,300 horsepower rigs in our North Louisiana programand both of the 2,000 horsepower rigs in our East Texas Bossier program during2007.

In addition to the Larclay JV rigs,we have placed orders for two additional 2,000 horsepower rigs for possible usein our North Louisiana Bossier and our East Texas Bossier programs.  At December 31, 2006, we had invested$8.7 million in these rigs and were committed under firm purchasecontracts for an additional $15.8 million. We estimate that the combined construction cost of both rigs will beapproximately $27 million.

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**Exploration and DevelopmentActivities**

In2006, we spent $250.2 million on exploration and drilling activities,approximately 60% of which was financed by cash flow from operations and theremainder by borrowings on our revolving credit facility.  We presently plan to spend approximately$170.1 million on exploration and drilling activities during 2007, most ofwhich will be financed by cash flow from operations, and the balance will befinanced by borrowings on the revolving credit facility and supplemented byproceeds from sales of assets, if needed. We may increase or decrease our planned activities, depending upondrilling results, product prices, the availability of capital resources, and otherfactors affecting the economic viability of such activities.

***South Louisiana***

Since 2000, we have been exploringfor oil and gas reserves in South Louisiana and have developed this area intoone of our key sources of production and cash flow.  Most of the prospects we have generated inSouth Louisiana have been identified based on 3-D seismic data andtechnology and have generally consisted of multi-pay, Miocene-agesands.

Prior to 2006, we had drilled 53gross (42.0 net) exploratory wells in South Louisiana, of which 24 gross(18.0 net) were completed as producers. The following table sets forth certain information about our exploratorywell activities in South Louisiana subsequent to December 31, 2005.
| **Spud Date** | ** ** | **Well Name (Prospect)**                   | ** ** | **Working  Interest** | ** ** | **Current  Status**   |
|---------------|------------|--------------------------------------------|------------|-----------------------|------------|-----------------------|
|          |       |                                       |       |                  |       |                  |
| January 2006  |       | Borah #1 (Cypress Isle)                    |       | 75                    | %          | Dry                   |
| February 2006 |       | SL 195 QQ #2 (Floyd)                       |       | 81                    | %          | Producing             |
| February 2006 |       | SL 195 QQ #3 (Floyd)                       |       | 75                    | %          | Producing             |
| March 2006    |       | SL 195 QQ #4 (Floyd)                       |       | 72                    | %          | Producing             |
| March 2006    |       | A. J. Beshel #1  (Beshel)                  |       | 100                   | %          | Producing             |
| April 2006    |       | Cobena #1 (Boa II)                         |       | 63                    | %          | Completing            |
| May 2006      |       | SL 195 QQ #5 (Floyd)                       |       | 75                    | %          | Producing             |
| June 2006     |       | SL 195 QQ #8 (Floyd)                       |       | 70                    | %          | Producing             |
| August 2006   |       | SL 195 QQ #6 (Floyd)                       |       | 75                    | %          | Producing             |
| August 2006   |       | Apache Louisiana  Minerals #73-1 (Abigail) |       | 100                   | %          | Dry                   |
| October 2006  |       | SL 195 QQ #11 (Floyd)                      |       | 72                    | %          | Producing             |
| November 2006 |       | Kyle Peterman Mgt #30-1  (Pigeon)          |       | 100                   | %          | Dry                   |
| November 2006 |       | Luke Harvey #1 (Beshal  Shallow)           |       | 100                   | %          | Producing             |
| December 2006 |       | Rose Chouest #1 (South  Empire)            |       | 95                    | %          | Dry                   |
| December 2006 |       | SL 18065 #3 (West  Alabama)                |       | 100                   | %          | Producing             |
| January 2007  |       | SL 195 QQ #7 (Floyd)                       |       | 75                    | %          | Completing            |
| February 2007 |       | SL 195 QQ #10 (Floyd)                      |       | 75                    | %          | Waiting on completion |
| February 2007 |       | Orleans Levee District  #2 (American Bay)  |       | 45                    | %          | Drilling              |
| February 2007 |       | Bowie Lumber Co. #1                        |       | 100                   | %          | Drilling              |

We spent $118.5 million in South Louisiana during 2006 on explorationand development activities, of which $110 million was spent on drillingand completion activities and $8.5 million was spent on seismic andleasing activities.  Our drillingactivities in South Louisiana resulted in the addition of approximately26.6 Bcfe of proved reserves in 2006, most of which came from our Floydprospect in Plaquemines Parish.  To date,we have completed seven productive wells on this prospect.  Under the terms of a farmout agreement, webear 100% of the cost of wells on this prospect to casing point and earn up toa 75% working interest in the drilled acreage.

In contrast to the successfuldrilling results on the Floyd prospect, we also recorded $33.7 million ofexploration expense due primarily to four high-cost exploratory dry holes, theBorah #1 (Cypress Isle), the Apache Louisiana Minerals (Abigail), the KylePeterman Mgt #30-1 (Pigeon) and the Rose Chouest #1 (South Empire).  First quarter 2007 exploration costs willinclude an additional $2.5 million of abandonment costs incurredsubsequent to December 31, 2006 related to the Rose Chouest #1.

We are attempting to complete theCobena #1 (Boa II), a 15,250-foot exploratory well in Acadia Parish, in a zoneto which we have attributed approximately 2.3 Bcf of net gas reserves asof December 31, 2006.  To date, wehave incurred approximately $9 million in drilling and completion costs onthis well, net to our interest.

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We currently plan to spendapproximately $39.3 million in South Louisiana in 2007 to generate andlease new exploratory prospects and to drill wells on existing exploratory anddevelopmental prospects.  Our plansinclude drilling two wells and upgrading production facilities on our Floydprospect and drilling three development wells offsetting existing production.

***North Louisiana***

In 2005, we began an explorationprogram in North Louisiana targeting the Cotton Valley/Hosston and Bossierformations.  In this area, the CottonValley/Hosston formations are encountered at depths ranging from 8,000 to12,000 feet, and the Bossier formation is encountered at depths rangingfrom 11,000 to 15,500 feet.  Webelieve that these tight sandstone formations have become more economicallyviable due to higher product prices, coupled with enhanced drilling andcompletion techniques.

The following table sets forthcertain information about our exploratory well activities in North Louisianasubsequent to December 31, 2005. This table does not include 12 gross (1.3 net) non-operatedwells in which our working interests range from 1% to 44%.
| **Spud Date** | ** ** | **Well Name (Prospect)**          | ** ** | **Working  Interest** | ** ** | **Current  Status**   |
|---------------|------------|-----------------------------------|------------|-----------------------|------------|-----------------------|
|          |       |                              |       |                  |       |                  |
| May 2006      |       | Atkins Estate #1  (Frazier Creek) |       | 100                   | %          | Producing             |
| August 2006   |       | Weyerhaeuser #1  (Frazier Creek)  |       | 100                   | %          | Dry                   |
| July 2006     |       | Roberson #1  (Terryville)         |       | 100                   | %          | Dry                   |
| October 2006  |       | P. Benoit #1 (Sarepta)            |       | 91                    | %          | Waiting on completion |
| October 2006  |       | Donald Woodard #1  (Terryville)   |       | 71                    | %          | Producing             |
| January 2007  |       | J.L. Hood #1  (Terryville)        |       | 86                    | %          | Waiting on pipeline   |
| February 2007 |       | J. Huey #1 (Terryville)           |       | 86                    | %          | Waiting on completion |
| March 2007    |       | David Barton #1  (Winnsboro)      |       | 100                   | %          | Drilling              |

We spent $48.9 million in North Louisiana during 2006 on explorationactivities, of which $20.4 million was spent on seismic and leasingactivities and $28.5 million was spent on drilling and completionactivities.  Most of the costs incurredin this area at December 31, 2006 relate to prospects and wells that were inprogress and had not been evaluated at that date.  In 2007, we currently plan to spendapproximately $54 million in North Louisiana in 2007 to generate and leasenew exploratory prospects and to drill wells on existing exploratory prospects.

We drilled two exploratory wells onour Frazier Creek prospect in Claiborne Parish targeting the CottonValley/Hosston formations.  The AtkinsEstate #1 was completed as a marginal producer, and the Weyerhaeuser #1 was notproductive, resulting in a pre-tax charge of $3.2 million in 2006 relatedto the abandonment of the well.  We donot currently plan to drill additional wells in this area in 2007.

On our Terryville prospect in Lincoln Parish, wehave drilled and completed three wells in the Cotton Valley interval.  The Roberson #1 was a dry hole and resultedin a pre-tax charge of $5.7 million in 2006 related to the abandonment ofthe well.  The Donald Woodard #1 wascompleted in the first quarter of 2007 and is currently producing at a rate ofapproximately 2.3 Mmcfe per day, net to our interest.  The J.L. Hood #1 has been completed as a gaswell and is waiting on pipeline connections. We currently plan to drill four additional wells on this prospect in 2007.

In addition, we have drilled the P. Benoit #1, thefirst exploratory well on our Sarepta prospect in Webster Parish.  We attempted to complete the Benoit #1 in theGray sand, but that zone was nonproductive. We are currently waiting on availability of a completion rig to attemptcompletion in the Cotton Valley interval. We currently plan to drill five additional wells on this prospect in2007.

We are currently drilling the David Barton #1, a17,000-foot exploratory well on our Winnsboro prospect in Richland Parishand currently plan to drill at least one additional well in this area in 2007.

***East TexasBossier***

We have acquired a significant acreage position inEast Texas targeting the Bossier formation which is encountered at depthsranging from 14,000 to 22,000 feet in this area.  To date, we have acquired approximately54,000

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net acres and hold up to 50,000 additional acres in the area of ourAustin Chalk (Trend) production primarily in Burleson, Robertson, Brazos andMilam Counties, Texas.  We spent$20.8 million on prospective Bossier acreage in East Texas in 2006.

In 2007, we currently plan to spendapproximately $4.1 million to acquire additional acreage and$44.3 million to drill three exploratory wells.  In April, we plan to spud the Big BillSimpson #1, a 19,000-foot exploratory well in Leon County (70% workinginterest) targeting the Bossier formation. Both of the other Bossier wells are expected to be drilled to similardepths.  These wells are very expensiveto drill and involve a high degree of risk.

***PermianBasin***

We spent $40.6 million in thePermian Basin during 2006 on exploration and development activities, of which$39 million was spent on drilling and completion activities and$1.6 million was spent on seismic and leasing activities.  We drilled 9 gross (7.6 net)operated wells in the Permian Basin and conducted remedial operations onexisting wells in 2006.  Of the operatedwells drilled, two were dry holes and the rest are currently producing.  In addition, we participated in the drillingof 24 gross non-operated wells (3.8 net), with working interests ranging from2% to 50%.  One of these was a dry hole,and the majority of the remaining wells were producers on the Davidson Ranchand Amacker-Tippet prospects.  ThePermian Basin continues to be a significant source of production and cash flowfor us.  We currently plan to spend$17.3 million on drilling activities in the Permian Basin in 2007.

***Montana/Utah***

We spent $7.1 million inMontana and Utah during 2006 on drilling, seismic, and leasing activities.  In Montana, we drilled and abandoned theRuegsegger 24H #1, a 7,600-foot exploratory vertical well with a3,600-foot lateral in the Bakken shale formation, after it was determined to benonproductive.  We recorded a pre-tax charge of approximately$2.3 million in 2006 related to the abandonment of this well.  We do not plan to spend any capitaldrilling in Montana in 2007.

In addition, we are participatingin a joint exploration program with industry partners in the Overthrust play incentral Utah in which we own a 33% interest. We are currently participating in the drilling of the Vonda Christensen35A31, a 13,500-foot non-operated exploratory well in Sanpete County. Wecurrently plan to spend approximately $6.3 million for additional leasingactivities and to participate in the drilling of another exploratory well totest this acreage.

***Colorado***

In 2006, we drilled two wells inRoutt County, Colorado targeting the Niobraro formation at a depth ofapproximately 8,500 feet.  The FocusRanch Federal 12#1 and the Focus Ranch Federal 3-1 have been temporarily abandonedbecause we do not believe the discovered reserves justify the cost ofproduction facilities and pipelines due to the remote location and ruggedterrain in this area.  As a result, werecorded a pre-tax charge of $9.7 million related to the abandonment ofthese wells in 2006.

***Other Exploration and Development Activities***

During 2006, we spent $3.8 millionin the Austin Chalk (Trend) area of Texas primarily for production enhancementactivities, and currently plan to spend approximately $3.1 million for similaractivities in this area in 2007.  Inaddition, we plan to spend approximately $1.8 million in 2007 to participate inan exploration project in the Sacramento and San Joaquin Basins of California.

**MarketingArrangements**

We sell substantially all of our oilproduction under short-term contracts based on prices quoted on the New YorkMercantile Exchange (“NYMEX”) for spot West Texas Intermediate contracts, lessagreed-upon deductions which vary by grade of crude oil.  The majority of our gas production is soldunder short-term contracts based on pricing formulas which are generally marketresponsive.  From time to time, we mayalso sell a portion of our gas production under short-term contracts at fixedprices.  We believe that the loss of anyof our oil and gas purchasers would not have a material adverse effect on ourresults of operations due to the availability of other purchasers.

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**NaturalGas Services**

Weown an interest in and operate natural gas service facilities in the states ofTexas, Louisiana, Mississippi and New Mexico. These natural gas servicefacilities consist of interests in approximately 94 miles of pipeline,three treating plants, one dehydration facility, three compressor stations, andfour wellhead type treating and/or compression facilities.  Most of our operated gas gathering andtreating activities exist to facilitate the transportation and marketing of ouroperated oil and gas production.

**Competitionand Markets**

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

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

Themarket for our oil, gas and natural gas liquids production depends on factorsbeyond our control, including domestic and foreign political conditions, theoverall level of supply of and demand for oil, gas and natural gas liquids, theprice of imports of oil and gas, weather conditions, the price and availabilityof alternative fuels, the proximity and capacity of gas pipelines and othertransportation facilities and overall economic conditions.

**Regulation**

Ouroil and gas exploration, production and related operations are subject toextensive rules and regulations promulgated by federal, state and localagencies. 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.

Allof the states in which we operate generally require permits for drillingoperations, drilling bonds and reports concerning operations and impose otherrequirements relating to the exploration and production of oil and gas. Suchstates also have statutes or regulations addressing conservation matters,including provisions for the unitization or pooling of oil and gas properties,the establishment of maximum rates of production from oil and gas wells and 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.

TheFederal Energy Regulatory Commission (“FERC”) regulates interstate natural gastransportation rates and service conditions, which affect the marketing of gaswe produce, as well as the revenues we receive for sales of suchproduction.  Since the mid-1980s, theFERC has issued various orders that have significantly altered the marketingand transportation of gas.  These ordersresulted in a fundamental restructuring of interstate pipeline sales andtransportation services, including the unbundling by interstate pipelines of thesales, transportation, storage and other components of the city-gate salesservices such pipelines previously performed. These FERC actions were designed to increase competition within allphases of the gas industry.  Theinterstate regulatory framework may enhance our ability to market and transportour 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.

Oursales of oil and natural gas liquids are not presently regulated and are madeat market prices.  The price we receivefrom the sale of those products is affected by the cost of transporting theproducts to market.  The FERC hasimplemented regulations establishing an indexing system for transportationrates for oil pipelines, which,

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generally, wouldindex such rate to inflation, subject to certain conditions andlimitations.  We are not able to predictwith any 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.

**EnvironmentalMatters**

Ouroperations pertaining to oil and gas exploration, production and relatedactivities are subject to numerous and constantly changing federal, state andlocal laws governing the discharge of materials into the environment orotherwise relating to environmental protection. These laws and regulations may require the acquisition of certainpermits prior to or in connection with our operations, restrict or prohibit thetypes, quantities and concentration of substances that we can release into theenvironment, restrict or prohibit activities that could impact wetlands,endangered or threatened species or other protected areas or natural resources,require some degree of remedial action to mitigate pollution from formeroperations, such as pit cleanups and plugging abandoned wells, and impose substantialliabilities for pollution resulting from our operations.  Such laws and regulations may substantiallyincrease the cost of our operations and may prevent or delay the commencementor continuation of a given project and thus generally could have a materialadverse effect upon our capital expenditures, earnings, or competitiveposition.  Violation of these laws andregulations could result in significant fines or penalties.  We have experienced accidental spills, leaksand other discharges of contaminants at some of our properties, as have othersimilarly situated oil and gas companies, and some of the properties that wehave acquired, operated or sold, or in which we may hold an interest but notoperational control, may have past or ongoing contamination for which we may beheld responsible.  Some of our operationsare located in environmentally sensitive environments, such as coastal waters,wetlands and other protected areas.  Someof our properties are located in areas particularly susceptible to hurricanesand other destructive storms, which may damage facilities and cause the releaseof pollutants. 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 would have a material adverse impacton our financial condition and operations.

Webelieve that we are in substantial compliance with current applicableenvironmental laws and regulations, and the cost of compliance with such lawsand regulations has not been material and is not expected to be material during2007.  We do not believe that we will berequired to incur any material capital expenditures to comply with existingenvironmental requirements. Nevertheless, changes in existing environmental laws and regulations orin the interpretations thereof could have a significant impact on ouroperations, as well as the oil and gas industry in general.  For instance, any changes in environmental lawsand regulations that result in more stringent and costly waste handling,storage, transport, disposal or clean-up requirements could have amaterial adverse impact on our operations.

TheComprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”),also known as the “Superfund” law, imposes liability, without regard to faultor the legality of the original conduct, on certain classes of persons that areconsidered to have contributed to the release of a “hazardous substance” intothe environment.  These persons includethe owner or operator of the disposal site or the site where the releaseoccurred and companies that disposed or arranged for the disposal of thehazardous 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 neighboring landowners and otherthird parties to file claims for personal injury and property damage allegedlycaused by the hazardous substances released into the environment.  We are able to control directly the operationof only those wells with respect to which we act as operator.  Notwithstanding our lack of direct controlover wells operated by others, the failure of an operator other than us tocomply with applicable environmental regulations may, in certain circumstances,be attributed to us.  We are not aware ofany liabilities for which we may be held responsible that would materially andadversely affect us.

TheResource Conservation and Recovery Act (“RCRA”), and analogous state laws,impose detailed requirements for the handling, storage, treatment and disposalof hazardous and solid wastes.  RCRAspecifically excludes drilling fluids, produced waters, and other wastesassociated with the exploration, development, or production of crude oil,natural gas or geothermal energy from regulation as hazardous wastes.  However, these wastes may be regulated by theU.S. Environmental Protection Agency (“EPA”) or state agencies as solidwastes.  Moreover, many ordinaryindustrial wastes, such as paint wastes, waste solvents, laboratory wastes andwaste compressor oils, are regulated as hazardous wastes.  Although the costs of managing hazardouswaste may be

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significant, we donot believe that our costs in this regard are materially more burdensome thanthose for similarly situated companies.

Ouroperations are subject to the federal Clean Air Act, and comparable state lawsand regulations.  These laws andregulations regulate emissions of air pollutants from various industrialsources, including compressor stations and natural gas processing facilities,and also impose various monitoring and reporting requirements.  Such laws and regulations may require that weobtain pre-approval for the construction or modification of certain projects orfacilities expected to produce air emissions or result in the increase ofexisting air emissions, obtain and strictly comply with air permits containingvarious emissions and operational limits, or utilize specific emission controltechnologies to limit emissions.  Ourfailure to comply with these requirements could subject us to monetarypenalties, injunctions, conditions or restrictions on operations, andpotentially criminal enforcement actions. Capital expenditures for air pollution equipment may be required inconnection with maintaining or obtaining operating permits and approvalsrelating to air emissions at facilities owned or operated by us. We do notbelieve that our operations will be materially adversely affected by any suchrequirements.

TheFederal Water Pollution Control Act (“Clean Water Act”), and analogous statelaws, impose restrictions and strict controls with respect to the discharge ofpollutants, including spills and leaks of oil and other substances, into watersof the United States.  The discharge ofpollutants into regulated waters is prohibited, except in accordance with theterms of a permit issued by EPA or an analogous state agency.  Federal and state regulatory agencies canimpose administrative, civil and criminal penalties for non-compliance withdischarge permits or other requirements of the Clean Water Act and analogous statelaws and regulations.  In addition, theUnited States Oil Pollution Act of 1990 (“OPA”), and similar legislationenacted in Texas, Louisiana and other coastal states, addresses oil spillprevention and control and significantly expands liability exposure across allsegments of the oil and gas industry. OPA and such similar legislation andrelated regulations impose on us a variety of obligations related to theprevention of oil spills and liability for damages resulting from suchspills.  OPA imposes strict and, withlimited exceptions, joint and several liabilities upon each responsible partyfor oil removal costs and a variety of public and private damages.

Recentstudies have suggested that emissions of certain gases may be contributing towarming of the Earth’s atmosphere.  Inresponse to these studies, many nations have agreed to limit emissions of “greenhousegases”, pursuant to the United Nations Framework Convention of Climate Change,also known as the “Kyoto Protocol”. Methane, a primary component of natural gas, and carbon dioxide, abyproduct of the burning of natural gas and oil, and refined petroleumproducts, are “greenhouse gases” regulated by the Kyoto Protocol.  Although the United States is notparticipating in the Kyoto Protocol, the current session of Congress isconsidering climate change legislation, with multiple bills having beenintroduced in the Senate that propose to restrict greenhouse gasemissions.  Several states have alreadyadopted legislation, regulations and/or regulatory initiatives to reduceemissions of greenhouse gases.  Forinstance, California adopted the “California Global Warming Solutions Act of2006”, which requires the California Air Resources Board to achieve a 25%reduction in emissions of greenhouse gases from sources in California by2020.  Additionally, on November 29,2006, the U.S. Supreme Court heard arguments on and has since begun reviewing adecision made by the U.S. Circuit Court of Appeals for the District of Columbiain Massachusetts, et al v. EPA, a case in which the appellate court held thatEPA had discretion under the Clean Air Act to refuse to regulate carbon dioxideemissions from mobile sources.  Passageof climate change legislation by Congress or a Supreme Court reversal of theappellate decision could result in federal regulation of carbon dioxideemissions and other greenhouse gases.  Atthis time, it is not possible to accurately estimate how potential future lawsor regulations addressing greenhouse gas emissions would impact our operationsor financial condition.

Claims are sometimes made or threatened againstcompanies engaged in oil and gas exploration, production and related activitiesby owners of surface estates, adjoining properties or others alleging damagesresulting from environmental contamination and other incidents of operations.We have been named as a defendant in a number of such lawsuits. While somejurisdictions in which we operate limit damages in such cases to the value ofland that has been impaired, in other jurisdictions in which we operate, courtshave allowed damage claims in excess of land value, including claims for thecost of remediation of contaminated properties. However, we do not believe thatresolution of these claims will have a material adverse impact on our financialcondition and operations.

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**Title toProperties**

Asis 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. These title investigations and title opinions, while consistent withindustry standards, may not reveal existing or potential title defects,encumbrances or adverse claims as we are subject from time to time to claims ordisputes regarding title to properties. Our properties are subject to customary royalty interests, liensincident to operating agreements, liens for current taxes and other burdensthat we believe do not materially interfere with the use of or affect the valueof such properties. Substantially all of our oil and gas properties are currentlymortgaged to secure borrowings under our revolving credit facility and may bemortgaged under any future credit facilities entered into by us.

**OperationalHazards and Insurance**

Ouroperations are subject to the usual hazards incident to the drilling andproduction 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.

Wemaintain insurance of various types to cover our operations with policy limitsand 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.

**ExecutiveOfficers**

Thefollowing is a list, as of March 15, 2007 of the name, age and position withthe Company of each person who is an executive officer of the Company:

CLAYTON W. WILLIAMS, age 75, is Chairman of the Board, President, ChiefExecutive Officer and a director of the Company, having served in suchcapacities since September 1991.  Formore than the past five years, Mr. Williams has also been the chief executiveofficer and director of certain entities which are controlled directly orindirectly by Mr. Williams.

L. PAUL LATHAM, age 55, is Executive Vice President, Chief OperatingOfficer and a director of the Company, having served in such capacities sinceSeptember 1991.  Mr. Latham also servesas an officer and director of certain entities controlled by Mr. Williams.

MEL G. RIGGS, age 52, is Senior Vice President and Chief FinancialOfficer of the Company, having served in such capacities since September1991.  Mr. Riggs has served as a directorof the Company since May 1994.

PATRICK C. REESBY, age 54, is Vice President – New Ventures of theCompany, having served in such capacity since 1993.

ROBERT C. LYON, age 70, is Vice President – Gas Gathering and Marketingof the Company, having served in such capacity since 1993.

MICHAEL L. POLLARD, age 57, is Vice President – Accounting of theCompany, having served in such capacity since 2003.  Prior to that, Mr. Pollard had served asController of the Company since 1993.

T. MARK TISDALE, age 50, is Vice President and General Counsel of theCompany, having served in such capacity since 1993.

GREGORY S. WELBORN, age 33, is Vice President – Land of the Company,having served in such capacity since 2006.

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**Employees**

AtDecember 31, 2006, we had 180 full-time employees, none of whom is subject to acollective bargaining agreement.  In ouropinion, our relations with employees are good.

**WebsiteAddress**

TheCompany maintains an internet website at www.claytonwilliams.com.  The Company makes available, free of charge,on its website, the annual report on Form 10-K, quarterly reports on Form10-Q, current reports on Form 8-K and amendments to those reports,as soon as reasonably practicable after providing such reports to the SEC.  The information contained in or incorporatedin our website is not part of this report.

**Item 1A****-****      ****RiskFactors**

Thereare many factors that affect our business, some of which are beyond ourcontrol.  Our business, financialcondition and results of operations could be materially adversely affected byany of these risks.  The risks describedbelow are not the only ones facing our company. Additional risks not presently known to us or that we currently deemimmaterial individually or in the aggregate may also impair our businessoperations.

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

For2007, approximately 83% of our planned capital expenditures relate toexploratory prospects. Exploration is a higher risk activity than development.Exploration activities involve the drilling of wells in areas where there islittle or no known production. Development activities relate to increasing oilor natural gas production from an area that is known to be productive bydrilling additional wells, working over and recompleting existing wells andother production enhancement techniques. Exploration projects are identifiedthrough subjective analysis of geological and geophysical data, including theuse of 3-D seismic and other available technology. By comparison, theidentification of development prospects is significantly based upon existingproduction surrounding or adjacent to the proposed drilling site.

Becausewe engage in exploration activities, we have a greater risk of drilling dryholes or not finding oil and natural gas that can be produced economically. Theseismic data and other technology we use does not allow us to know withcertainty prior to drilling a well whether oil or natural gas is present or canbe produced economically. We charged to expense $65.2 million in 2006 for abandonment and impairment, most ofwhich was related to unsuccessful exploratory drilling activities in North andSouth Louisiana, Colorado, Montana andthe Permian Basin area of West Texas. We cannot assure you that any of our future exploration efforts will besuccessful. If these activities are unsuccessful, it will have a significantadverse affect on our results of operations, cash flow and capital resources.

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

Ingeneral, the volume of production from an oil and gas property declines asreserves related to that property are depleted. The decline rates depend uponreservoir characteristics. Historically, our oil and gas properties have had steeprates of decline and short estimated productive lives. The implied life of ourproved reserves at December 31, 2006 is approximately 9.2 years, based on 2006 productionlevels.

Ouroil and gas reserves will decline as they are produced unless we are able toconduct successful exploration and development activities or acquire propertieswith proved reserves. Because we are engaged to a large extent in explorationactivities, our ability to replace produced reserves is subject to a higherlevel of risk and is less predictable than it might be if we concentrated ondevelopmental drilling activities.

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***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 we believe that they arelikely to continue to be volatile. Significant changes in oil and gas pricesmay result from relatively minor changes in the supply of and demand for oiland natural gas, market uncertainty and other factors that are beyond ourcontrol. We cannot predict, with any degree of certainty, future oil andnatural gas prices. Changes in oil and natural gas prices significantly affectour revenues, operating results, profitability and the value of our oil and gasreserves. Those prices also affect the amount of cash flow available for capitalexpenditures, our ability to borrow money or raise additional capital and theamount of oil and natural gas that we can produce economically. The amount wecan borrow under our senior revolving credit facility is subject to periodicredeterminations based in part on current prices for oil and natural gas at thetime of the redetermination.

Changesin oil and gas prices impact both our estimated future net revenue and theestimated quantity of proved reserves. Price increases may permit additional quantitiesof reserves to be produced economically, and price decreases may renderuneconomic the production of reserves previously classified as proved. Thus, wemay experience material increases and decreases in reserve quantities solely asa result of price changes and not as a result of drilling or well performance.We attempt to optimize the price we receive for our oil and gas productionwhile maintaining a prudent hedging program to mitigate our exposure todeclining product prices. Our management may elect to enter into and terminatehedges based on expectations of future market conditions. If prices continue torise while our hedges are in place, we will forego revenue we would haveotherwise received. If we terminate a hedge because we anticipate an increasein product prices that we would not realize with the hedge in place, andproduct prices do not increase as anticipated, we may be exposed to downsiderisk that would not have existed otherwise.

***Our liquidity, including the availability of capital resources,is uncertain.***

Ourcash flow forecasts indicate that the amount of funds available to us under ourrevolving credit facility, when combined with our anticipated operating cashflow, will be sufficient to finance our capital expenditures and will provideus with adequate liquidity at least through 2007.  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 than expected,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.

**Our liquidity will suffer if our exploration activitiesare not successful.** For 2007, approximately 83% of our planned capital expenditures relateto exploratory prospects, where we have a greater risk of drilling dry holes ornot finding oil and natural gas that can be produced economically.  Several of our exploratory prospects targetdeep formations, including the Bossier formation in North Louisiana and EastTexas.  Wells on these prospects are veryexpensive to drill and involve a very high degree of risk.  If these exploratory wells are unsuccessful,our cash flow from operations and our liquidity will be adversely affected.

**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 commodity pricescould 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, 2006 reserve estimates, we project that a $1.00drop in oil price and a $.50 drop in gas price would reduce our gross revenuesin 2007 by approximately $2.2 million and $8.5 million, respectively.

**Adverse changes in the borrowing base may cause outstandingdebt 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.

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**Delays in bringing successful wells on production may reduceour liquidity**.  As ageneral rule, we experience a significant lag time between the initial cashoutlay on a prospect and the inclusion of any value for such prospect in theborrowing 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.

**Commitments under long-term drilling contracts mayreduce our cash flow from operating activities.**  We have entered into long-term drillingcontracts to ensure the availability of the drilling rigs we need to conductour drilling program.  If we contract fora rig and do not need the rig due to changes in our drilling program, we will berequired to pay a daily rate specified in the contract while the rig is idleduring the contract term.  Long-termdrilling commitments may also influence us to drill a well in 2007 that we mayotherwise choose to defer until a later period in order to avoid paying for anidle rig.  Our cash flow from operationsmay be less than expected and/or our capital expenditures may be more thanexpected if commitments on long-term drilling contracts result in the paymentof idle rig costs and/or an increase in drilling costs related to wells notcurrently included in our drilling schedule.

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

Fromtime to time, we use commodity derivatives, consisting of “swaps,” “collars”and “floors,” to attempt to optimize the price we receive for the sale of ouroil and natural gas production.  Whenusing swaps to hedge our oil and natural gas production, we receive a fixedprice for the hedged commodity and pay a floating market price as defined ineach contract (generally NYMEX futures prices), resulting in a net amount dueto or from the counterparty at the settlement date.  Collars are a combination of options thatprovide us with a put option (fixed floor price) in exchange for a call option(fixed ceiling price).  If the marketprice for the hedged commodity exceeds the fixed ceiling price or falls belowthe fixed floor price, then we receive the fixed price and pay the marketprice.  If the market price is betweenthe fixed floor and the fixed ceiling prices, then no payments are due fromeither 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.

Thedecision to initiate or terminate commodity hedges is made by management basedon its expectation of future market price movements.  We have no set goals for the percentage ofour production we hedge and we do not use any formulas or triggers in decidingwhen to initiate or terminate a hedge. If we enter into swaps or collars and the floating market price at thesettlement date is higher than the fixed price or the fixed ceiling price, wewill forego revenue we would have otherwise received.  If we terminate a swap, collar or floorbecause we anticipate future increases in market prices, we may be exposed todownside risk that would not have existed otherwise.

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

Theaccuracy of proved reserves estimates and estimated future net revenues fromsuch reserves is a function of the quality of available geological,geophysical, engineering and economic data and is subject to various assumptions,including assumptions required by the SEC relating to oil and gas prices,drilling and operating expenses, and other matters.  Although we believe that our estimated provedreserves represent reserves that we are reasonably certain to recover, actualfuture production, oil and gas prices, revenues, taxes, developmentexpenditures, operating expenses and quantities of recoverable oil and gasreserves will most likely vary from the assumptions and estimates used todetermine proved reserves.  Any significantvariance could materially affect the estimated quantities and value of our oiland gas reserves, which in turn could adversely affect our cash flow, resultsof operations and the availability of capital resources.  In addition, we may adjust estimates ofproved reserves to reflect production history, results of exploration anddevelopment, prevailing oil and gas prices and other factors, many of which arebeyond our control.  Downward adjustmentsto our estimated proved reserves could require us to write down the carryingvalue of our oil and gas properties, which would reduce our earnings and ourstockholders’ equity.

Thepresent value of proved reserves will not necessarily equal the current fairmarket value of our estimated oil and gas reserves.  In accordance with the reserve reportingrequirements of the SEC, the estimated discounted future net cash flows fromproved reserves are generally based on prices and costs as of the date of theestimate.  Actual future prices and costsmay be materially higher or lower than those as of the date of theestimate.  

15

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The timing of boththe production and the expenses with respect to the development and productionof oil and gas properties will affect the timing of future net cash flows fromproved reserves and their present value.

Theestimated proved reserve information is based upon reserve reports prepared byindependent engineers.  From time totime, estimates of our reserves are also made by our banks in establishing theborrowing base under our senior revolving credit facility and by our engineersfor use in developing business plans 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.***

Weplan to continue growing our reserves and drilling inventory throughacquisitions.  Acquired properties can besubject to significant unknown liabilities. Prior to completing an acquisition,it is generally not feasible to conduct a detailed review of each individualproperty to be acquired in an acquisition. Even a detailed review or inspection of each property may not reveal allexisting or potential liabilities associated with owning or operating theproperty. Moreover, some potential liabilities, such as environmentalliabilities related to groundwater contamination, may not be discovered evenwhen a review or inspection is performed.

Ourinitial reserve estimates for acquired properties may be inaccurate. Downwardadjustments to our estimated proved reserves, including reserves added throughacquisitions, could require us to write down the carrying value of our oil andgas properties, which would reduce our earnings and our stockholders’ equity.

Ourfailure to integrate acquired businesses successfully into our existingbusiness could result in our incurring unanticipated expenses and losses.  In addition, we may have to assume cleanup orreclamation obligations or other unanticipated liabilities in connection withthese acquisitions.  The scope and costof these obligations may ultimately be materially greater than estimated at thetime of the acquisition.

Theprocess of integrating acquired operations into our existing operations mayresult in unforeseen operating difficulties and may require significantmanagement attention and financial resources that would otherwise be availablefor 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.***

Drillingoil and natural gas wells, including development wells, involves numerousrisks, including the risk that we may not encounter commercially productive oilor natural gas reservoirs. We may not recover all or any portion of ourinvestment in new wells. The presence of unanticipated pressures orirregularities in formations, miscalculations or accidents may cause ourdrilling activities to be unsuccessful and result in a total loss of ourinvestment. In addition, we often are uncertain as to the future cost or timingof drilling, completing and operating wells. Further, our drilling operationsmay be curtailed, delayed or canceled as a result of a variety of factors,including:

·                  unexpecteddrilling conditions;

·                  titleproblems;

·                  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, tubular materialsand equipment and services.

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

Ouroperations are subject to the usual hazards incident to the drilling andproduction of oil and gas, such as windstorms, blowouts, cratering, explosions,uncontrollable flows of oil, gas or well fluids, fires, severe weather andpollution and other environmental risks. These hazards can cause personalinjury and loss of life, severe damage to and destruction of property and equipment,pollution or environmental damage, clean-up responsibilities, regulatoryinvestigation and penalties, and suspension of operation, operations whichcould result in substantial loss. We maintain insurance against some, but notall, of the risks described above. Such insurance may not be adequate to coverlosses or liabilities. Also, we cannot assure you of the continued availabilityof insurance at premium levels that justify its purchase.

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

Themarketability of our oil and natural gas production depends in large part onthe availability, proximity and capacity of pipeline systems owned by thirdparties. The unavailability of or lack of available capacity on these systemsand facilities could result in the shut-in of producing wells or the delay ordiscontinuance of drilling plans for properties. Although we have somecontractual control over the transportation of our product, material changes inthese business relationships could materially affect our operations. Federaland state regulation of oil and natural gas production and transportation, taxand energy policies, changes in supply and demand, pipeline pressures, damageto or destruction of pipelines and general economic conditions could adverselyaffect our ability to produce, gather and transport oil and natural gas.

***A shortage of available drilling rigs, equipment andpersonnel may delay or restrict our operations.***

Theoil and natural gas industry is cyclical and, from time to time, there is ashortage of drilling rigs, equipment, supplies or personnel. During theseperiods, the costs and delivery times of drilling rigs, equipment and suppliesare 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 development operations,which in turn could impair our financial condition and results of operations.

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

Competitionin all areas of our operations is intense. We experience competition from majorand independent 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. Ourability to increase reserves in the future will depend on our success atselecting and acquiring suitable producing properties and prospects for futuredevelopment and exploration activities.

Inaddition, the oil and gas industry as a whole competes with other industries insupplying the energy and fuel requirements of industrial, commercial andindividual consumers. The price and availability of alternative energy sourcescould adversely affect our revenue.

Themarket for our oil, gas and natural gas liquids production depends on factorsbeyond our control, including domestic and foreign political conditions, theoverall level of supply of and demand for oil, gas and natural gas liquids, theprice of imports of oil and gas, weather conditions, the price and availabilityof alternative fuels, the proximity and capacity of gas pipelines and othertransportation facilities and overall economic conditions.

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

Oursuccess is highly dependent on our senior management personnel, none of whomare currently subject to an employment contract. The loss of one or more ofthese individuals could have a material adverse effect on our business.Furthermore, competition for experienced technical and other professionalpersonnel is intense. If we cannot retain our current personnel or attractadditional experienced personnel, our ability to compete could be adverselyaffected.

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

ClaytonW. Williams beneficially owns, either individually or through his affiliates,approximately 47% of the outstanding shares of our common stock. Mr. Williamsis also the Chairman of the Board and Chief Executive Officer. As a result, Mr.Williams has significant influence in matters voted on by our shareholders,including the election of board members, and in management decisions. Mr.Williams actively participates in all facets of our business and has asignificant impact on both our business strategy and daily operations. Theretirement, incapacity or death of Mr. Williams, or any change in the power tovote his shares, could result in negative market or industry perception andcould have a material adverse effect on our business.

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

Wesell our oil and natural gas production to various customers, serve as operatorin the drilling, completion and operation of oil and gas wells, and enter intoderivatives with various counterparties. As appropriate, we obtain letters ofcredit to secure amounts due from our principal oil and gas purchasers andfollow other procedures to monitor credit risk from joint owners andderivatives counterparties. We cannot assure you that we will not suffer anyeconomic loss related to credit risks in the future.

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

Ouroil and gas exploration, production and related operations are subject toextensive rules and regulations promulgated by federal, state and local agencies.Failure to comply with such rules and regulations can result in substantialpenalties. The regulatory burden on the oil and gas industry increases our costof doing business and affects our profitability. Because such rules andregulations are frequently amended or reinterpreted, we are unable to predictthe future cost or impact of complying with such laws.

Allof the states in which we operate generally require permits for drillingoperations, drilling bonds and reports concerning operations and impose otherrequirements relating to the exploration and production of oil and gas. Suchstates also have statutes or regulations addressing conservation matters,including provisions for the unitization or pooling of oil and gas properties,the establishment of maximum rates of production from oil and gas wells and 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.

TheFederal Energy Regulatory Commission (“FERC”) regulates interstate natural gastransportation rates and service conditions, which affect the marketing of gaswe produce, as well as the revenues we receive for sales of such production.Since the mid-1980s, the FERC has issued various orders that have significantlyaltered the marketing and transportation of gas. These orders resulted in afundamental restructuring of interstate pipeline sales and transportationservices, including the unbundling by interstate pipelines of the sales,transportation, storage and other components of the city-gate sales servicessuch pipelines previously performed. These FERC actions were designed toincrease 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.

Oursales of oil and natural gas liquids are not presently regulated and are madeat market prices.  The price we receivefrom the sale of those products is affected by the cost of transporting theproducts to market. The FERC has implemented regulations establishing an indexingsystem for transportation rates for oil pipelines, which, generally, wouldindex such rate to inflation, subject to certain conditions and limitations. Weare not able to predict with any certainty what effect, if any, theseregulations will have on us, but, other factors being equal, the

18

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regulations may,over time, tend to increase transportation costs which may have the effect ofreducing wellhead prices for oil and natural gas liquids.

***Our oil and gas exploration and production, and related activitiesare subject to extensive environmental regulations, and to laws that can giverise to substantial liabilities from environmental contamination.***

Ouroperations are subject to extensive federal, state and local environmental lawsand regulations, which impose limitations on the discharge of pollutants intothe environment, establish standards for the management, treatment, storage,transportation and disposal of hazardous materials and of solid and hazardouswastes, and impose obligations to investigate and remediate contamination incertain circumstances.  Liabilities toinvestigate or remediate contamination, as well as other liabilities concerninghazardous materials or contamination such as claims for personal injury orproperty damage, may arise at many locations, including properties in which wehave an ownership interest but no operational control, properties we formerlyowned or operated and sites where our wastes have been treated or disposed of,as well as at properties that we currently own or operate.  Such liabilities may arise even where thecontamination 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.

Wehave incurred expenses in connection with environmental compliance, and weanticipate 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 in environmentallysensitive environments, such as coastal waters, wetlands and other protectedareas.  Some of our operations are inareas particularly susceptible to damage by hurricanes or other destructivestorms, which could result in damage to facilities and discharge ofpollutants.  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 for remediation under, these laws andregulations, and liabilities concerning contamination or hazardous materials,may adversely affect our business, financial condition and results ofoperations.

**Item 1B****-       Unresolved StaffComments**

Notapplicable.

**Item 2****-          Properties**

Ourproperties consist primarily of oil and gas wells and our ownership inleasehold acreage, both developed and undeveloped.  At December 31, 2006, we had interests in6,626 gross (891.9 net) oil and gas wells and owned leasehold interests inapproximately 1.3 million gross (865,000 net) undeveloped acres.

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**Reserves**

Thefollowing table sets forth certain information as of December 31, 2006 withrespect to our estimated proved oil and gas reserves pursuant to SECguidelines, standardized measure of discounted future net cash flows andpresent value of proved reserves.
| ** **                                                | ** ** | **Proved Developed**            | ** ** | **Proved**       | ** ** | **Total**       | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------|------------|------------------|------------|-----------------|------------|
| ** **                                                | ** ** | **Producing**                        | ** ** | **Nonproducing** | ** ** | **Undeveloped** | ** ** | **Proved** | ** ** |
| ** **                                                | ** ** | **(Dollars in thousands)** | ** ** |
| Gas (MMcf)                                                |       | 71,284                               |       | 18,932           |       | 28,951          |       | 119,167 |   |
| Oil and natural  gas liquids (MBbls)                      |       | 16,729                               |       | 2,144            |       | 6,508           |       | 25,381 |   |
| Total (MMcfe)                                             |       | 171,656                              |       | 31,794           |       | 68,003          |       | 271,453 |   |
| Standardized measure of discounted future net cash  flows |       |                                 |       |             |       |            |       | $      514,800 |   |
| Present value of proved reserves (a)                      |       |                                 |       |             |       |            |       | $      712,368 |   |

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(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, 2006 were $180.8 millionand $19.5 million, respectively.

Thefollowing table sets forth certain information as of December 31, 2006regarding our proved oil and gas reserves in each of our principal producingareas.
| ** **                  | ** ** | ** **               | ** ** | ** ** | ** ** | ** **         | ** ** | **Percent**         | ** ** |
|-----------------------------|------------|--------------------------|------------|------------|------------|--------------------|------------|---------------------|------------|
| ** **                  | ** ** | **Proved reserves** | ** ** | ** ** | ** ** | **Present**        | ** ** | **of Present** | ** ** |
| ** **                  | ** ** | ** **               | ** ** | ** ** | ** ** | **Total Gas** | ** ** | **Percent of** | ** ** | **Value of** | ** ** | **Value of** | ** ** |
| ** **                  | ** ** | **Oil (a)**         | ** ** | **Gas**    | ** ** | **Equivalent**     | ** ** | **Total Gas**  | ** ** | **Proved** | ** ** | **Proved** | ** ** |
| ** **                  | ** ** | **(MBbls)**              | ** ** | **(MMcf)** | ** ** | **(MMcfe)**        | ** ** | **Equivalent**      | ** ** | **Reserves** | ** ** | **Reserves** | ** ** |
| ** **                  | ** ** | ** **               | ** ** | ** ** | ** ** | ** **         | ** ** | ** **          | ** ** | **(In thousands)** | ** ** | ** ** | ** ** |
|                        |       |                     |       |       |       |               |       |                |       |   |   |   |   |
| Permian Basin  (b)          |       | 15,679                   |       | 64,620     |       | 158,694            |       | 58.4                | %          | $ | 350,047 |   | 49.1 | % |
| Louisiana                   |       | 2,231                    |       | 34,262     |       | 47,648             |       | 17.5                | %          | 182,807 |   | 25.7 | % |
| Austin Chalk  (Trend)       |       | 6,469                    |       | 4,789      |       | 43,603             |       | 16.1                | %          | 131,207 |   | 18.4 | % |
| Cotton Valley  Reef Complex |       | —                   |       | 11,562     |       | 11,562             |       | 4.3                 | %          | 27,077 |   | 3.8 | % |
| Other                       |       | 1,002                    |       | 3,934      |       | 9,946              |       | 3.7                 | %          | 21,230 |   | 3.0 | % |
| Total                       |       | 25,381                   |       | 119,167    |       | 271,453            |       | 100.0               | %          | $ | 712,368 |   | 100.0 | % |

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(a)    Includesnatural gas liquids.

(b)   PrimarilyWest Texas and New Mexico.

Ourestimated recoverable proved reserves have been determined using standardgeological and engineering methods generally accepted by the petroleum industryand in accordance with SEC financial accounting and reporting standards.  The estimated present value of provedreserves does not give effect to indirect expenses such as general andadministrative expenses, debt service and future income tax expense or todepletion, depreciation and amortization, and does not include any economicimpact that may result from our hedging activities.

Substantiallyall of our estimates of proved reserves are derived from reports prepared byWilliamson Petroleum Consultants, Inc., independent petroleum engineers, andRyder Scott Company, L.P., petroleum consultants.

Inaccordance with applicable financial accounting and reporting standards of theSEC, the estimates of our proved reserves and the present value of provedreserves set forth herein are made using oil and gas sales prices estimated tobe in effect as of the date of such reserve estimates and are held constantthroughout the life of the properties. Estimated quantities of proved reservesand their present value are affected by changes in oil and gas prices.  The average prices utilized for the purposesof estimating our proved reserves and the present value of

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proved reserves asof December 31, 2006 were $57.18 per Bbl of oil and natural gas liquids and$5.24 per Mcf of gas, as compared to $57.85 per Bbl of oil and $10.65 per Mcfof gas as of December 31, 2005.  Weestimate that a $1.00 per Bbl change in oil price and a $.50 per Mcf change ingas price from those utilized in calculating the present value of provedreserves would change the present value by approximately $12.7 million and$33.9 million, respectively.

Thereserve information shown is estimated. The accuracy of any reserve estimate is a function of the quality ofavailable geological, geophysical, engineering and economic data, the precisionof the engineering and geological interpretation and judgment.  The estimates of reserves, future cash flowsand present value are based on various assumptions, including those prescribedby the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual futureproduction, cash flows, taxes, development expenditures, operating expenses andquantities of recoverable oil and natural gas reserves may vary substantiallyfrom these estimates.  Also, the use of a10% discount factor for reporting purposes may not necessarily represent themost appropriate discount factor, given actual interest rates and risks towhich our business or the oil and natural gas industry in general are subject.

SinceJanuary 1, 2006, we have not filed an estimate of our net proved oil and gasreserves with any federal authority or agency other than the SEC.

**Exploration and DevelopmentActivities**

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

|                         | ** ** | **Year Ended December 31,**                                                             | ** ** |
|-------------------------|------------|--------------------------------------------------------------------------------------------------------|------------|
| ** **              | ** ** | **2006**                                                                                               | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **              | ** ** | **Gross**                                                                                              | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| ** **              | ** ** | **(Excludes wells in progress at the end of any period)** | ** ** |
| ** **              | ** ** | ** **                                                                                             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Development  Wells:** | ** ** | ** **                                                                                             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil                     |       | 2                                                                                                      |       | 1.0 |   | 49 |   | 26.4 |   | 39 |   | 11.7 |   |
| Gas                     |       | 16                                                                                                     |       | 1.8 |   | 10 |   | 3.2 |   | 2 |   | 1.3 |   |
| Dry                     |       | 1                                                                                                      |       | .8 |   | 1 |   | .2 |   | 2 |   | .9 |   |
| Total                   |       | 19                                                                                                     |       | 3.6 |   | 60 |   | 29.8 |   | 43 |   | 13.9 |   |
| **Exploratory  Wells:** | ** ** | ** **                                                                                             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil                     |       | 6                                                                                                      |       | 5.2 |   | 2 |   | 1.8 |   | 1 |   | .3 |   |
| Gas                     |       | 35                                                                                                     |       | 14.5 |   | 7 |   | 4.5 |   | 7 |   | 4.9 |   |
| Dry                     |       | 10                                                                                                     |       | 8.7 |   | 10 |   | 6.1 |   | 13 |   | 7.1 |   |
| Total                   |       | 51                                                                                                     |       | 28.4 |   | 19 |   | 12.4 |   | 21 |   | 12.3 |   |
| **Total  Wells:**       | ** ** | ** **                                                                                             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil                     |       | 8                                                                                                      |       | 6.2 |   | 51 |   | 28.2 |   | 40 |   | 12.0 |   |
| Gas                     |       | 51                                                                                                     |       | 16.3 |   | 17 |   | 7.7 |   | 9 |   | 6.2 |   |
| Dry                     |       | 11                                                                                                     |       | 9.5 |   | 11 |   | 6.3 |   | 15 |   | 8.0 |   |
| Total                   |       | 70                                                                                                     |       | 32.0 |   | 79 |   | 42.2 |   | 64 |   | 26.2 |   |

The information contained in the foregoing table shouldnot be considered indicative of future drilling performance, nor should it beassumed that there is any necessary correlation between the number ofproductive wells drilled and the amount of oil and gas that may ultimately berecovered by us.

We own a 50% interest in LarclayJV, a joint venture with Lariat Services, Inc. formed to construct, own andoperate 12 drilling rigs, consisting of five 1,000 horsepower rigs, five 1,300horsepower rigs and two 2,000 horsepower rigs. The rigs are being constructed on behalf of Larclay JV by Lariat, asoperations manager.  All five of the1,300 horsepower rigs and one of the 1,000 horsepower rigs were fullyconstructed at December 31, 2006. Subsequently, construction on three of the remaining four 1,000horsepower rigs has been completed.  Theremaining three rigs are expected to be fully constructed by June 2007.  In addition to the Larclay JV rigs, we haveplaced orders for two additional 2,000 horsepower rigs for delivery later in2007.  We used four of the Larclay JVrigs during 2006 to drill certain wells in our exploration and developmentdrilling program.  In 2007, we expect touse at least one of the 1,300 horsepower rigs in our North Louisiana CottonValley/Hosston program and both of the 2,000 horsepower rigs in our East TexasBossier program.  In addition, we may useone or both of the additional 2,000 horsepower rigs in our Bossier drillingprograms in North Louisiana and East Texas.

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We also use other drillingcontractors, as needed, to drill wells. At December 31, 2006, we had two barge rigs and one 2,000 horsepowerland rig under long-term contracts for drilling wells in South Louisiana.

## **ProductiveWell Summary**

The following table sets forthcertain information regarding our ownership, as of December 31, 2006, ofproductive wells in the areas indicated.
| ** **            | ** ** | **Oil**   | ** ** | **Gas** | ** ** | **Total** | ** ** |
|-----------------------|------------|-----------|------------|---------|------------|-----------|------------|
| ** **            | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Permian Basin         |       | 5,482     |       | 508.4   |       | 732       |       | 96.4 | ** ** | 6,214 |   | 604.8 |   |
| Louisiana             |       | 7         |       | 4.2     |       | 44        |       | 26.3 |   | 51 |   | 30.5 |   |
| Austin Chalk  (Trend) |       | 294       |       | 224.4   |       | 17        |       | 9.3 |   | 311 |   | 233.7 |   |
| Cotton Valley         |       | —    |       | —  |       | 14        |       | 11.6 |   | 14 |   | 11.6 |   |
| Other                 |       | 6         |       | 5.2     |       | 30        |       | 6.1 |   | 36 |   | 11.3 |   |
| Total                 |       | 5,789     |       | 742.2   |       | 837       |       | 149.7 |   | 6,626 |   | 891.9 |   |

**Volumes, Prices and Production Costs**

The following table sets forthcertain information regarding the production volumes of, average sales pricesreceived from, and average production costs associated with our sales of oiland gas for the periods indicated.
| ** **                       | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------|------------|-----------------------------|------------|
| ** **                       | ** ** | **2006**                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Oil and Gas Production Data:** |       |                        |       |   |   |   |   |
| Gas (MMcf)                       |       | 15,198                      |       | 16,408 |   | 17,938 |   |
| Oil (MBbls)                      |       | 2,171                       |       | 2,258 |   | 2,094 |   |
| Natural gas liquids  (MBbls)     |       | 199                         |       | 246 |   | 249 |   |
| Total (MMcfe)                    |       | 29,418                      |       | 31,432 |   | 31,996 |   |
|                             |       |                        |       |   |   |   |   |
| **Average Realized Prices (a):** |       |                        |       |   |   |   |   |
| Gas ($Mcf)                       |       | $                           | 6.68       |   | $ | 7.49 |   | $ | 5.60 |   |
| Oil ($Bbl)                       |       | $                           | 62.92      |   | $ | 53.37 |   | $ | 40.65 |   |
| Natural gas liquids  ($/Bbl)     |       | $                           | 38.18      |   | $ | 33.57 |   | $ | 27.90 |   |
|                             |       |                        |       |   |   |   |   |
| **Average Production Costs**     |       |                        |       |   |   |   |   |
| Production ($/Mcfe) (b)          |       | $                           | 2.15       |   | $ | 1.83 |   | $ | 1.29 |   |

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(a)          No derivatives were designated as cash flow hedges in the tableabove.  All gains or losses on settledderivatives were included in gain/loss on derivatives.

(b)         Includesdirect lifting costs (labor, repairs and maintenance, materials and supplies),workover costs, administrative costs of production offices, insurance andproperty and severance taxes.

**Development, Exploration andAcquisition Expenditures**

The following table sets forthcertain information regarding the costs we incurred in our development,exploration and acquisition activities during the periods indicated.
| ** **             | ** ** | **Year Ended December 31,** | ** ** |
|------------------------|------------|-----------------------------|------------|
| ** **             | ** ** | **2006**                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **             | ** ** | **(In thousands)**          | ** ** |
| Property Acquisitions: |       |                        |       |   |   |   |   |
| Proved                 |       | $                           | 6,432      |   | $ | 5,567 |   | $ | 237,042 |   |
| Unproved               |       | 54,437                      |       | 50,238 |   | 33,826 |   |
| Developmental Costs    |       | 35,698                      |       | 42,292 |   | 27,469 |   |
| Exploratory Costs      |       | 157,509                     |       | 86,304 |   | 73,655 |   |
| Total                  |       | $                           | 254,076    |   | $ | 184,401 |   | $ | 371,992 |   |

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**Acreage**

The following table sets forthcertain information regarding our developed and undeveloped leasehold acreageas of December 31, 2006 in the areas indicated. This table excludes options to acquire leases and acreage in which ourinterest is limited to royalty, overriding royalty and similar interests.
| ** **           | ** ** | **Developed** | ** ** | **Undeveloped** | ** ** | **Total** | ** ** |
|----------------------|------------|---------------|------------|-----------------|------------|-----------|------------|
| ** **           | ** ** | **Gross**     | ** ** | **Net**         | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Permian Basin        |       | 81,576        |       | 45,427          |       | 341,722   |       | 150,872 |   | 423,298 |   | 196,299 |   |
| Trend/Cotton  Valley |       | 108,984       |       | 106,577         |       | 56,723    |       | 31,936 |   | 165,707 |   | 138,513 |   |
| Louisiana            |       | 12,710        |       | 10,373          |       | 231,915   |       | 215,101 |   | 244,625 |   | 225,474 |   |
| Other (a)            |       | 11,566        |       | 3,996           |       | 715,070   |       | 466,637 |   | 726,636 |   | 470,633 |   |
| Total                |       | 214,836       |       | 166,373         |       | 1,345,430 |       | 864,546 |   | 1,560,266 |   | 1,030,919 |   |

----

(a)          Net undeveloped acres are attributable to the following areas:  Montana – 149,630;Mississippi – 112,057; East Texas – 61,417; Utah – 49,076;Alabama – 38,808; Colorado – 36,423; and other – 19,196.

**Offices**

We lease from a relatedpartnership approximately 61,000 square feet of office space in Midland, Texasfor our corporate headquarters.  We alsolease approximately 10,000 square feet of office space in Houston, Texas froman unaffiliated third party.

**Item 3 -          LegalProceedings**

We are a defendant in severallawsuits that have arisen in the ordinary course of business. While the outcomeof these lawsuits cannot be predicted with certainty, management does notexpect any of these to have a material adverse effect on our consolidatedfinancial condition or results of operations.

**Item 4 -          Submissionof Matters to a Vote of Security Holders**

No matter was submitted to a voteof our security holders during the fourth quarter of our fiscal year endedDecember 31, 2006.

23

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**PART II**

**Item 5 -****                               Marketfor the Registrant’s Common Equity, Related Stockholder Matters and IssuerRepurchases of Equity Securities**

## **Price Range of Common Stock**

Our Common Stock is quoted on theNasdaq Stock Market’s Global Market under the symbol “CWEI”.  As of March 14, 2007, there wereapproximately 1,900 beneficialstockholders 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 Global Market:
| ** **                     | ** ** | **High** | ** ** | **Low** | ** ** |
|--------------------------------|------------|----------|------------|---------|------------|
| Year Ended December 31,  2006: |       |     |       |    |       |
| Fourth Quarter                 |       | $        | 43.87      |    | $          | 27.64 |   |
| Third Quarter                  |       | 37.91    |       | 27.11   |       |
| Second Quarter                 |       | 43.50    |       | 33.97   |       |
| First Quarter                  |       | 55.33    |       | 37.12   |       |
|                           |       |     |       |    |       |
| 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   |       |

The quotations in the table above reflect inter-dealer priceswithout retail markups, markdowns or commissions and may not necessarilyreflect actual transactions.  The closingprice of our common stock at March 14, 2007 was $27.34 per share.

**Dividend Policy**

Wehave never paid any cash dividends on our Common Stock, and our Board ofDirectors does not currently anticipate paying any cash dividends to the commonstockholders in the foreseeable future. In addition, the terms of our secured bank credit facilities prohibitthe payment of cash dividends.

**Securities Authorized for Issuance under Equity CompensationPlans**

Forinformation concerning shares available for issuance under equity compensationplans, see Item 11, which is to be incorporated by reference to our proxystatement.

24

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**Item 6 -          Selected Financial Data**

Thefollowing table sets forth selected consolidated financial data for CWEI as ofthe dates and for the periods indicated. The consolidated financial data for each of the years in the five-yearperiod ended December 31, 2006 was derived from our audited financialstatements.  The data set forth in thistable should be read in conjunction with *“Management’sDiscussion and Analysis of Financial Condition and Results of Operations”*and the accompanying consolidated financial statements, including the notesthereto.
| ** **                                                                                 | ** ** | **Year Ended December 31,**               | ** ** |
|--------------------------------------------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                                                                 | ** ** | **2006**                                                 | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                 | ** ** | **(In thousands, except per share)** | ** ** |
| **Statement  of Operations Data:**                                                         |       |                                                     |       |   |   |   |   |   |   |   |   |
| Revenues:                                                                                  |       |                                                     |       |   |   |   |   |   |   |   |   |
| Oil and gas  sales                                                                         |       | $                                                        | 245,967    |   | $ | 252,599 |   | $ | 193,127 |   | $ | 163,032 |   | $ | 86,302 |   |
| Natural gas  services                                                                      |       | 11,327                                                   |       | 12,080 |   | 9,083 |   | 8,758 |   | 5,568 |   |
| Drilling rig  services                                                                     |       | 6,937                                                    |       | — |   | — |   | — |   | — |   |
| Gain on sales of  property and equipment                                                   |       | 1,767                                                    |       | 18,920 |   | 4,120 |   | 267 |   | 2,241 |   |
| Total revenues                                                                             |       | 265,998                                                  |       | 283,599 |   | 206,330 |   | 172,057 |   | 94,111 |   |
| Costs and  expenses:                                                                       |       |                                                     |       |   |   |   |   |   |   |   |   |
| Production                                                                                 |       | 63,298                                                   |       | 57,404 |   | 41,163 |   | 28,239 |   | 21,857 |   |
| Exploration:                                                                               |       |                                                     |       |   |   |   |   |   |   |   |   |
| Abandonment and  impairments                                                               |       | 65,173                                                   |       | 39,957 |   | 67,956 |   | 35,120 |   | 21,571 |   |
| Seismic and  other                                                                         |       | 11,299                                                   |       | 10,780 |   | 7,124 |   | 8,755 |   | 8,578 |   |
| Natural gas  services                                                                      |       | 10,005                                                   |       | 11,212 |   | 8,538 |   | 8,279 |   | 4,853 |   |
| Drilling rig  services                                                                     |       | 4,538                                                    |       | — |   | — |   | — |   | — |   |
| Depreciation,  depletion and amortization                                                  |       | 66,163                                                   |       | 47,509 |   | 44,040 |   | 40,284 |   | 29,656 |   |
| Impairment of  property and equipment                                                      |       | 21,848                                                   |       | 18,266 |   | — |   | 170 |   | 349 |   |
| Accretion of  abandonment obligations                                                      |       | 1,653                                                    |       | 1,158 |   | 1,044 |   | 651 |   | — |   |
| General and  administrative                                                                |       | 16,676                                                   |       | 15,410 |   | 11,689 |   | 10,934 |   | 8,615 |   |
| Loss on sales of  property and equipment                                                   |       | 99                                                       |       | 209 |   | 14,337 |   | 68 |   | 1,880 |   |
| Other                                                                                      |       | —                                                   |       | 1,353 |   | — |   | — |   | — |   |
| Total costs and  expenses                                                                  |       | 260,752                                                  |       | 203,258 |   | 195,891 |   | 132,500 |   | 97,359 |   |
| Operating income  (loss)                                                                   |       | 5,246                                                    |       | 80,341 |   | 10,439 |   | 39,557 |   | (3,248 | ) |
| Other income  (expense):                                                                   |       |                                                     |       |   |   |   |   |   |   |   |   |
| Interest expense                                                                           |       | (20,895                                                  | )          | (14,498 | ) | (7,877 | ) | (3,138 | ) | (4,006 | ) |
| Gain (loss) on  derivatives                                                                |       | 37,340                                                   |       | (70,059 | ) | (25,329 | ) | (1,593 | ) | (1,581 | ) |
| Other income  (expense)                                                                    |       | (1,339                                                   | )          | 4,022 |   | 1,354 |   | (1,662 | ) | 1,755 |   |
| Total other  income (expense)                                                              |       | 15,106                                                   |       | (80,535 | ) | (31,852 | ) | (6,393 | ) | (3,832 | ) |
| Income (loss)  before income taxes                                                         |       | 20,352                                                   |       | (194 | ) | (21,413 | ) | 33,164 |   | (7,080 | ) |
| Income tax  (expense) benefit                                                              |       | (1,979                                                   | )          | 451 |   | 7,385 |   | (10,515 | ) | 1,742 |   |
| Minority  interest, net of tax                                                             |       | (574                                                     | )          | — |   | — |   | — |   | — |   |
| Income (loss)  from continuing operations                                                  |       | 17,799                                                   |       | 257 |   | (14,028 | ) | 22,649 |   | (5,338 | ) |
| Cumulative  effect of accounting change, net of tax                                        |       | —                                                   |       | — |   | — |   | 207 |   | — |   |
| Income from  discontinued operations, including gain on sale of $1,196 in 2002, net of tax |       | —                                                   |       | — |   | — |   | — |   | 1,335 |   |
| NET INCOME (LOSS)                                                                          |       | $                                                        | 17,799     |   | $ | 257 |   | $ | (14,028 | ) | $ | 22,856 |   | $ | (4,003 | ) |
|                                                                                       |       |                                                     |       |   |   |   |   |   |   |   |   |
| Net income  (loss) per common share:                                                       |       |                                                     |       |   |   |   |   |   |   |   |   |
| Basic:                                                                                     |       |                                                     |       |   |   |   |   |   |   |   |   |
| Income (loss)  from continuing operations                                                  |       | $                                                        | 1.64       |   | $ | .02 |   | $ | (1.37 | ) | $ | 2.43 |   | $ | (.58 | ) |
| Net income  (loss)                                                                         |       | $                                                        | 1.64       |   | $ | .02 |   | $ | (1.37 | ) | $ | 2.45 |   | $ | (.43 | ) |
| Diluted:                                                                                   |       |                                                     |       |   |   |   |   |   |   |   |   |
| Income (loss)  from continuing operations                                                  |       | $                                                        | 1.58       |   | $ | .02 |   | $ | (1.37 | ) | $ | 2.38 |   | $ | (.58 | ) |
| Net income  (loss)                                                                         |       | $                                                        | 1.58       |   | $ | .02 |   | $ | (1.37 | ) | $ | 2.40 |   | $ | (.43 | ) |
| Weighted average  common shares outstanding:                                               |       |                                                     |       |   |   |   |   |   |   |   |   |
| Basic                                                                                      |       | 10,885                                                   |       | 10,804 |   | 10,213 |   | 9,329 |   | 9,241 |   |
| Diluted                                                                                    |       | 11,244                                                   |       | 11,241 |   | 10,213 |   | 9,509 |   | 9,241 |   |
| **Other  Data:**                                                                           | ** ** | ** **                                               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net cash  provided by operating activities                                                 |       | $                                                        | 145,990    |   | $ | 163,475 |   | $ | 126,980 |   | $ | 119,750 |   | $ | 34,514 |   |

 
| ** **                 | ** ** | **December 31,**   | ** ** |
|----------------------------|------------|-------------------------|------------|
| ** **                 | ** ** | **2006**                | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                 | ** ** | **(In thousands)** | ** ** |
| **Balance  Sheet Data:**   | ** ** | ** **              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Working capital  (deficit) |       | $                       | (23,068    | ) | $ | (35,812 | ) | $ | (27,566 | ) | $ | (13,119 | ) | $ | (18,843 | ) |
| Total assets               |       | 795,433                 |       | 587,335 |   | 462,235 |   | 224,433 |   | 218,992 |   |
| Long-term debt             |       | 413,876                 |       | 235,700 |   | 177,519 |   | 53,295 |   | 94,949 |   |
| Stockholders’  equity |       | 144,980                 |       | 120,291 |   | 117,596 |   | 100,781 |   | 68,781 |   |
|                            |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

25

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**Item 7-  Management’s Discussion and Analysisof Financial Condition and Results of Operations**

The following discussion isintended to provide information relevant to an understanding of our financialcondition, changes in our financial condition and our results of operations andcash flows and should be read in conjunction with our consolidated financialstatements and notes thereto included elsewhere in this Form 10-K.

**Overview**

We are an oil and natural gasexploration, development, acquisition, and production company.  Our basic business model is to find anddevelop oil and gas reserves through exploration and development activities,and sell the production from those reserves at a profit.  To be successful, we must, over time, be ableto find oil and gas reserves and then sell the resulting production at a pricethat is sufficient to cover our finding costs, operating expenses, administrativecosts and interest expense, plus offer us a return on our capitalinvestment.  From time to time, we mayalso acquire producing properties if we believe the acquired assets offer usthe potential for reserve growth through additional developmental or exploratorydrilling activities.

We believe that the economicclimate in the domestic oil and gas industry continues to be suitable for ourbusiness model.  Although oil prices haveretreated from their peaks in mid-2006, and gas prices have been volatile, webelieve that supply and demand fundamentals in the energy marketplace continueto provide us with the economic incentives necessary for us to assume the riskswe face in our search for oil and gas reserves. However, we are experiencing a shrinking profit margin related to risingdrilling and production costs.  Whileprofit margins still remain favorable, operating metrics per Mcfe, such asfinding costs, production costs and DD&A expense, are rising.

Finding quality domestic oil andgas reserves through exploration is a significant challenge and involves a highdegree of risk.  We replacedapproximately 100% of our 2006 production through extensions and discoveries in2006, most of which were derived from drilling activities on our Floyd prospectin South Louisiana.  However,depreciation, depletion and amortization (“DD&A”) per Mcfe of oil and gasproduction, an operating metric that measures a company’s cumulative cost tofind or purchase a unit of production, increased 49% from 2005 to 2006.  Our planned exploration activities in 2007offer us the opportunity to improve our DD&A rate through the drilling ofseveral potentially high-impact wells, particularly in our East Texas Bossierarea.  However, these wells are veryexpensive to drill and involve a high degree of risk.

**KeyFactors to Consider**

The following summarizes the keyfactors considered by management in the review of our financial condition andoperating performance for 2006 and the outlook for 2007.

·                  We spent $250.2 million on exploration and development activitiesduring 2006, of which approximately 84% was on exploratory prospects.  We currently plan to spend approximately$170.1 million for the calendar year 2007, of which approximately 83% isestimated to be spent on exploratory prospects. The 2006 expenditures exceeded our cash flow from operating activitiesby more than $100 million.  Our 2007expenditures are also expected to exceed our cash flow from operatingactivities in 2007, although not by as large a margin.  We cannot predict our drillingsuccess on exploratory prospects, and our future results of operations andfinancial condition could be adversely affected by unsuccessful exploratorydrilling results.

·                  During2006, we increased borrowings under our revolving credit facility by$129.3 million from $10.7 million at December 31, 2005 to$140 million at December 31, 2006 to partially finance ourexploration and development activities. As of February 28, 2007, our outstanding balance on the revolvingcredit facility had increased to $160 million due to additional borrowingsto finance our exploration program and to pay interest on our Senior Notes.

·                  Despiteour high level of capital spending in 2006, our oil and gas production for 2006was 6% lower on an Mcfe basis than in 2005. A significant portion of our 2006 expenditures have not resulted incurrent production because they relate to (a) unproved exploratory prospects,(b) drilling or completion activities that are in progress, or (c)non-productive leasing and drilling activities.

26

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·                  At December 31, 2006, our capitalized unproved oil and gas propertiestotaled $129.4 million, of which approximately $102.4 million wasattributable to unproved acreage. Unproved properties are subject to a valuation impairment to the extentthe carrying cost of a prospect exceeds its estimated fair value.  Therefore, our results of operations infuture periods may be adversely affected by unproved property impairments.

·                  Exploration costs related toabandonments and impairments were $65.2 million in 2006, of whichapproximately $51.3 million related to unsuccessful well costs and$13.9 million related to impairment of unproved acreage.  Over 50% of these costs were related toexploratory prospects in South Louisiana, and approximately 25% related toprospects in Colorado and Montana.

·                  We recorded a $37.3million net gain on derivatives in 2006 as compared to a $70.1 million loss in2005.  For 2006, cash settlements tocounterparties accounted for a $20.2 million loss and changes in mark-to-marketvaluations accounted for a $57.5 million gain.  Since we do not presently designate ourderivatives as cash flow hedges under applicable accounting standards, werecognize the full effect of changing prices on mark-to-market valuations as acurrent charge or credit to our results of operations.

·                  We recorded a $21.8 million impairment of proved properties in 2006 dueto the combined effects of lower commodity prices and lower reserveestimates.  The impairment applied toseveral areas in the Permian Basin and one prospect in South Louisiana.

·                  Our proved oil and gas reserves atDecember 31, 2006 were 271.5 Bcfe compared to 293.8 Bcfe at December31, 2005.  We added 29.4 Bcfethrough extensions and discoveries, and lost 28.7 Bcfe through netdownward revisions.

**ProvedOil and Gas Reserves**

Thefollowing table summarizes changes in our proved reserves during 2006 on a Bcfebasis.

|                                           | ** ** | **Bcfe** | ** ** |
|-------------------------------------------|------------|----------|------------|
| Total proved  reserves, December 31, 2005 |       | 293.8    |       |
| Purchases of  minerals-in-place           |       | 6.4      |       |
| Extensions and  discoveries               |       | 29.4     |       |
| Revisions                                 |       | (28.7    | )          |
| Production                                |       | (29.4    | )          |
| Total proved  reserves, December 31, 2006 |       | 271.5    |       |

During 2006, we replaced 24% of the 29.4 Bcfe that we produced in2006, computed by dividing the sum of all net reserve additions (purchases ofminerals-in-place, extensions and discoveries, and revisions), by2006 production.  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 net reserveadditions during 2006.

*Purchases of minerals-in-place.*  We purchased 6.4 Bcfe of reserves in2006 relating to properties in California and West Texas.  Although we are continually looking foracquisitions, we cannot predict the likelihood of adding any reserves in 2007through purchases of minerals-in-place.

*Extensions and discoveries.*  Our extensions and discoveries during 2006consist of proved reserves attributable directly to the drilling of discoverywells primarily in South Louisiana and the Permian Basin.  Of the 29.4 Bcfe of additions,substantially all are proved developed reserves.  Due to the nature of exploratory drilling, wecannot predict the extent to which we will add any reserves in 2007 throughextensions and discoveries.

*Revisions.*  Our proved reserves were 28.7 Bcfe lowerdue to revisions of previous estimates. Downward revisions of 22 Bcfe wereattributable to the effects of lower product prices on the estimated quantitiesof proved reserves, and downward revisions of approximately 6.7 Bcfe wereattributable to lower well performance, primarily in the Permian Basin.  Gas prices at December 31, 2006 wereapproximately half of the prices at

27

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December 31,2005, contributing to the downward price revision.  In addition, higher projected operating costswere responsible for a portion of the decrease.

**SupplementalInformation**

The following unaudited informationis intended to supplement the consolidated financial statements included inthis Form 10-K with data that is not readily available from those statements.
| ** **                                                | ** **                | **As of or for the Year Ended December 31,** | ** ** |
|-----------------------------------------------------------|---------------------------|--------------------------------------------------------------------------------------|------------|
| ** **                                                | ** **                | **2006**                                                                             | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Oil and  Gas Production Data:**                         | ** **                | ** **                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (MMcf)                                                |                      | 15,198                                                                               |       | 16,408 |   | 17,938 |   |
| Oil (MBbls)                                               |                      | 2,171                                                                                |       | 2,258 |   | 2,094 |   |
| Natural gas  liquids (MBbls)                              |                      | 199                                                                                  |       | 246 |   | 249 |   |
| Total (MMcfe)                                             |                      | 29,418                                                                               |       | 31,432 |   | 31,996 |   |
|                                                      |                      |                                                                                 |       |   |   |   |   |
| **Average  Realized Prices (a):**                         | ** **                | ** **                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas ($/Mcf)                                               |                      | $                                                                                    | 6.68       |   | $ | 7.49 |   | $ | 5.60 |   |
| Oil ($/Bbl)                                               |                      | $                                                                                    | 62.92      |   | $ | 53.37 |   | $ | 40.65 |   |
| Natural gas  liquids ($/Bbl):                             |                      | $                                                                                    | 38.18      |   | $ | 33.57 |   | $ | 27.90 |   |
|                                                      |                      |                                                                                 |       |   |   |   |   |
| **Gain  (Losses) on Settled Derivative Contracts (a):**   | ** **                | ** **                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas:                                                      | Net realized  gain (loss) |                                                                                 | $          | 679 |   | $ | (7,301 | ) | $ | (5,011 | ) |
|                                                      | Per unit  produced ($Mcf) |                                                                                 | $          | .04 |   | $ | (.44 | ) | $ | (.30 | ) |
| Oil:                                                      | Net realized  gain (loss) |                                                                                 | $          | (19,886 | ) | $ | (21,976 | ) | $ | (13,135 | ) |
|                                                      | Per unit  produced ($Bbl) |                                                                                 | $          | (9.16 | ) | $ | (9.73 | ) | $ | (4.31 | ) |
|                                                      |                      |                                                                                 |       |   |   |   |   |
| **Average  Daily Production:**                            | ** **                | ** **                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (Mcf):                                                |                      |                                                                                 |       |   |   |   |   |
| Permian Basin                                             |                      | 14,260                                                                               |       | 15,893 |   | 9,458 |   |
| Louisiana                                                 |                      | 14,626                                                                               |       | 10,865 |   | 12,089 |   |
| Austin Chalk  (Trend)                                     |                      | 2,504                                                                                |       | 2,435 |   | 3,155 |   |
| Cotton Valley  Reef Complex                               |                      | 9,735                                                                                |       | 15,155 |   | 23,131 |   |
| Other                                                     |                      | 513                                                                                  |       | 605 |   | 1,312 |   |
| Total                                                     |                      | 41,638                                                                               |       | 44,953 |   | 49,145 |   |
| Oil (Bbls):                                               |                      |                                                                                 |       |   |   |   |   |
| Permian Basin                                             |                      | 3,172                                                                                |       | 3,245 |   | 2,410 |   |
| Louisiana                                                 |                      | 955                                                                                  |       | 994 |   | 1,055 |   |
| Austin Chalk  (Trend)                                     |                      | 1,770                                                                                |       | 1,892 |   | 2,215 |   |
| Other                                                     |                      | 51                                                                                   |       | 55 |   | 57 |   |
| Total                                                     |                      | 5,948                                                                                |       | 6,186 |   | 5,737 |   |
| Natural Gas  Liquids (Bbls):                              |                      |                                                                                 |       |   |   |   |   |
| Permian Basin                                             |                      | 226                                                                                  |       | 255 |   | 213 |   |
| Austin Chalk  (Trend)                                     |                      | 269                                                                                  |       | 322 |   | 284 |   |
| Other                                                     |                      | 50                                                                                   |       | 97 |   | 185 |   |
| Total                                                     |                      | 545                                                                                  |       | 674 |   | 682 |   |
|                                                      |                      |                                                                                 |       |   |   |   |   |
| **Total  Proved Reserves:**                               | ** **                | ** **                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (MMcf)                                                |                      | 119,167                                                                              |       | 126,758 |   | 138,278 |   |
| Oil and natural  gas liquids (MBbls)                      |                      | 25,381                                                                               |       | 27,835 |   | 26,793 |   |
| Total gas  equivalent (MMcfe)                             |                      | 271,453                                                                              |       | 293,768 |   | 299,036 |   |
| Standardized  measure of discounted future net cash flows |                      | $                                                                                    | 514,800    |   | $ | 753,712 |   | $ | 500,198 |   |

 

28

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| ** **                                | ** ** | **As of or for the Year Ended December 31,** | ** ** |
|-------------------------------------------|------------|--------------------------------------------------------------------------------------|------------|
| ** **                                | ** ** | **2006**                                                                             | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Total  Proved Reserves by Area:**       | ** ** | ** **                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (MMcf):                               |       |                                                                                 |       |   |   |   |   |
| Permian Basin                             |       | 64,620                                                                               |       | 79,466 |   | 85,243 |   |
| Louisiana                                 |       | 34,262                                                                               |       | 20,883 |   | 26,844 |   |
| Austin Chalk  (Trend)                     |       | 4,789                                                                                |       | 6,234 |   | 6,225 |   |
| Cotton Valley  Reef Complex               |       | 11,562                                                                               |       | 15,396 |   | 19,116 |   |
| Other                                     |       | 3,934                                                                                |       | 4,779 |   | 850 |   |
| Total                                     |       | 119,167                                                                              |       | 126,758 |   | 138,278 |   |
| Oil and Natural  Gas Liquids (MBbls):     |       |                                                                                 |       |   |   |   |   |
| Permian Basin                             |       | 15,679                                                                               |       | 18,504 |   | 17,113 |   |
| Louisiana                                 |       | 2,231                                                                                |       | 1,667 |   | 1,942 |   |
| Austin Chalk  (Trend)                     |       | 6,469                                                                                |       | 7,467 |   | 7,586 |   |
| Other                                     |       | 1,002                                                                                |       | 197 |   | 152 |   |
| Total                                     |       | 25,381                                                                               |       | 27,835 |   | 26,793 |   |
| Total Gas  Equivalent (MMcfe):            |       |                                                                                 |       |   |   |   |   |
| Permian Basin                             |       | 158,694                                                                              |       | 190,490 |   | 187,921 |   |
| Louisiana                                 |       | 47,648                                                                               |       | 30,885 |   | 38,496 |   |
| Austin Chalk  (Trend)                     |       | 43,603                                                                               |       | 51,036 |   | 51,741 |   |
| Cotton Valley  Reef Complex               |       | 11,562                                                                               |       | 15,396 |   | 19,116 |   |
| Other                                     |       | 9,946                                                                                |       | 5,961 |   | 1,762 |   |
| Total                                     |       | 271,453                                                                              |       | 293,768 |   | 299,036 |   |
|                                      |       |                                                                                 |       |   |   |   |   |
| **Exploration  Costs (in thousands):**    | ** ** | ** **                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Abandonment and  impairment costs:        |       |                                                                                 |       |   |   |   |   |
| South Louisiana                           |       | $                                                                                    | 33,695     |   | $ | 12,405 |   | $ | 32,760 |   |
| North Louisiana                           |       | 9,235                                                                                |       | — |   | — |   |
| Colorado                                  |       | 9,675                                                                                |       | — |   | — |   |
| Montana                                   |       | 6,462                                                                                |       | — |   | — |   |
| Permian Basin                             |       | 5,638                                                                                |       | 7,411 |   | 2,378 |   |
| Cotton Valley  Reef Complex               |       | —                                                                               |       | 7,405 |   | 205 |   |
| Nevada, Arizona,  California and Utah     |       | —                                                                               |       | — |   | 2,513 |   |
| Mississippi (b)                           |       | 328                                                                                  |       | 4,306 |   | 29,547 |   |
| Other (c)                                 |       | 140                                                                                  |       | 8,430 |   | 553 |   |
| Total                                     |       | 65,173                                                                               |       | 39,957 |   | 67,956 |   |
|                                      |       |                                                                                 |       |   |   |   |   |
| Seismic and  other                        |       | 11,299                                                                               |       | 10,780 |   | 7,124 |   |
| Total  exploration costs                  |       | $                                                                                    | 76,472     |   | $ | 50,737 |   | $ | 75,080 |   |
|                                      |       |                                                                                 |       |   |   |   |   |
| **Oil and  Gas Costs ($/Mcfe Produced):** |       |                                                                                 |       |   |   |   |   |
| Production                                |       | $                                                                                    | 2.15       |   | $ | 1.83 |   | $ | 1.29 |   |
| DD&A                                  |       | $                                                                                    | 2.12       |   | $ | 1.42 |   | $ | 1.28 |   |
| **Net  Wells Drilled (d):**               | ** ** | ** **                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                | ** ** | ** **                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Exploratory  wells                        |       | 28.4                                                                                 |       | 12.4 |   | 12.3 |   |
| Developmental  wells                      |       | 3.6                                                                                  |       | 29.8 |   | 13.9 |   |

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(a)                      Noderivatives were designated as cash flow hedges in the table above.  All gains or losses on settled derivativeswere included in gain/loss on derivatives.

(b)                     Includes a$13.7 million impairment of unproved acreage in the Black Warrior Basin in2004.

(c)                      Includesan $8 million charge in South Texas for the Deer-Hamilton #1 in 2005.

(d)                     Excludeswells being drilled or completed at the end of each period.

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**Operating Results**

***2006 Compared to 2005***

The following discussion comparesour results for the year ended December 31, 2006 to the year ended December 31,2005.  Unless otherwise indicated,references to 2006 and 2005 within this section refer to the respective annualperiods.

***Oil and gas operating results***

Oil and gas sales in 2006 decreased$6.6 million, or 3%, from 2005, of which production variances accountedfor a $16 million decrease and price variances accounted for a$9.4 million increase.  Productionin 2006 (on an Mcfe basis) was 6% lower than 2005.  Oil production decreased 4% and gasproduction decreased 7% in 2006 as compared to 2005 due primarily to naturalproduction declines, offset in part by new production from our exploration anddevelopment activities.  In 2006, ourrealized oil price was 18% higher than 2005, while our realized gas price was11% lower.  Historically, the markets foroil and gas have been volatile, and they are likely to continue to be volatile.

Production costs, consisting oflease operating expenses, production taxes and other miscellaneous marketingcosts, increased 10% in 2006 as compared to 2005 due primarily to higheroilfield service costs.  After givingeffect to a 6% decline in oil and gas production on an Mcfe basis, productioncosts per Mcfe increased 17% from $1.83 per Mcfe in 2005 to $2.15 per Mcfe in2006.  It is likely that these factorswill continue to contribute to higher production costs in future periods.

DD&A expense increased 39% from$47.5 million in 2005 to $66.2 million in 2006.  DD&A expense attributable to oil and gasproperties increased $17.8 million, of which rate variances accounted fora $20.6 million increase and production variances accounted for a$2.8 million decrease.  On an Mcfebasis, DD&A expense increased 49% from $1.42 per Mcfe in 2005 to $2.12 perMcfe in 2006.  DD&A per Mcfe of oiland gas production is an operating metric that is indicative of our weightedaverage cost to find or acquire a unit of equivalent production.  Unless our exploration activities result inan improvement in our finding costs in 2007, we may continue to realize higherDD&A rates in future periods.

We recorded a provision forimpairment of proved properties under SFAS 144 of $21.8 million during 2006 dueto the combination of production performance and lower commodity prices.  This provision was attributable to two areasin the Permian Basin and one area in South Louisiana.  We recorded a provision for impairment ofproved properties of $18.3 million in 2005.

***Gain on property sales***

Gain on sales of property and equipmentin 2006 was $1.8 million as compared to $18.9 million in 2005. The gain in 2006was derived from the sale of other property and equipment.  Most of the gain in 2005 related to the saleof our interests in two leases in the Breton Sound area of the Gulf of Mexico.

***Exploration costs***

Since we follow the successfulefforts method of accounting, our results of operations are adversely affectedduring any accounting period in which significant seismic costs, exploratorydry hole costs, and unproved acreage impairments are expensed.  In 2006,we charged to expense $76.5 million of exploration costs, as compared to$50.7 million in 2005.  Most of the 2006 costs were incurred inLouisiana, the Permian Basin, Montana and Colorado.

At December 31, 2006, our capitalizedunproved oil and gas properties totaled $129.4 million, of whichapproximately $102.4 million was attributable to unproved acreage.  Unproved properties are subject to avaluation impairment to the extent the carrying cost of a prospect exceeds itsestimated fair value.  Therefore, ourresults of operations in future periods may be adversely affected by unprovedproperty impairments.

We plan to spend approximately$170.1 million on exploration and development activities in fiscal 2007,of which approximately 83% is expected to be allocated to explorationactivities.  Since exploratory drilling involves a high degree of risk, itis likely that a significant portion of the costs we incur in fiscal 2007 willbe charged to exploration costs. However, we cannot predict our success ratesand, accordingly, cannot predict our exploration costs related to abandonmentand impairment costs.

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***General and administrative expenses***

General and administrative (“G&A”)expenses increased 8% from $15.4 million in 2005 to $16.7 million in2006.  Excluding non-cash employeecompensation, G&A expenses increased from $12.8 million in 2005 to$14 million in 2006 due primarily to higher personnel costs and professionalfees attributable to the increase in overall drilling and explorationactivities.  In 2006, we recorded a$2.5 million non-cash compensation charge related to our after payoutincentive plan and $128,000 for stock-based employee compensation.  In 2005, we recorded a $1.9 million non-cashcharge for stock-based employee compensation and a $680,000 non-cash chargerelated to our after payout incentive plan.

***Interest expense***

Interest expense increased 44% from$14.5 million in 2005 to $20.9 million in 2006 due to severalfactors.  In July 2005, we issued $225million of Senior Notes which bear interest at a fixed rate of 7.75%, and usedthe proceeds to repay our then-outstanding bank indebtedness.  As a result, the 2005 period included anon-cash charge of $1.8 million of debt issue costs related to the early repaymentof our senior term credit facility and the reduction in our borrowing baseunder the revolving credit facility.  In2006, we used our revolving loan facility to partially finance our explorationand development activities.  The averagedaily principal balance outstanding under our revolving credit facility for2006 was $89 million compared to $101 million for 2005; however, theSenior Notes were outstanding for the entire 2006 period.  Capitalized interest for 2006 was $5.8million compared to $2.2 million in 2005.

***Gain/loss on derivatives***

We recorded a gain on derivativesof $37.3 million in 2006 compared to a loss of $70.1 million for2005.  We did not designate anyderivative contracts in 2006 or 2005 as cash flow hedges; therefore all cashsettlements and changes resulting from mark-to-market valuations have beenrecorded as gain/loss on derivatives. Cash settlements were $20.2 million in 2006, as compared to$29.7 million in 2005.  We recordeda gain on derivatives of $57.5 million in 2006 compared to a loss of $40.4million in 2005 resulting from mark-to-market valuations.

***Income tax expense (benefit)***

Our effective income tax rate in2006 of 9.7% differed from the statutory federal rate of 35% due primarily to areduction in our state tax provision of $4.4 million related to the adoption ofTexas House Bill 3 in May 2006.  Ourincome tax benefit in 2005 of $451,000 differed from the statutory federalbenefit due primarily to the utilization of tax depletion in excess of basis.

***2005Compared to 2004***

The following discussion comparesour results for the year ended December 31, 2005 to the comparative period in2004.

***Oil and gas operating results***

Oil and gas sales in 2005 increased$59.5 million, or 31%, from 2004, of which price variances accounted for a$61.3 million increase and production variances accounted for a$1.8 million decrease.  Productionin 2005 (on an Mcfe basis) was 2% lower than 2004.  Oil production increased 8% in 2005 from 2004due primarily to additional well production from our Southwest Royalties, Inc.(“SWR”) acquisition in May 2004, offset in part by lost production as a resultof Hurricane Katrina.  Gas productiondecreased 9% due primarily to lost production from the hurricane and declinesin the Cotton Valley Reef Complex area due to formation performance.  In 2005, our realized oil price was 31%higher than 2004, while our realized gas price was 34% higher.  Historically, the markets for oil and gas havebeen volatile, and they are likely to continue to be volatile.

Production costs, consisting oflease operating expenses, production taxes and other miscellaneous marketingcosts, increased 39% in 2005 as compared to 2004 due primarily to higheroilfield service costs and increased workover activities.  Also contributing to the added expense wasthe addition of higher cost oil properties acquired in connection with the SWRacquisition, as well as increased production tax costs related to higherproduct prices. After giving effect to a 2% decline in oil and gas productionon an Mcfe basis, production costs per Mcfe increased 42% from $1.29 per Mcfein 2004 to $1.83 per Mcfe in 2005.

DD&A expense increased from$44 million in 2004 to $47.5 million in 2005.  DD&A expense attributable to oil and gasproperties increased $3.5 million, of which rate variances accounted for a$4.2 million increase and production variances accounted for a $700,000decrease.  On an Mcfe basis, DD&Aexpense increased 11% from

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$1.28 per Mcfe in 2004 to $1.42 per Mcfe in 2005.  Depletion rates for each depletable group area function of net capitalized costs and estimated reserve quantities.

We recorded a provision forimpairment of proved properties under SFAS 144 of $18.3 million during 2005 dueto the combination of production performance and lower commodity prices.  This provision was attributable to theWolfcamp exploration program in the Permian Basin.

***Gain/loss on property sales***

Gain on sales of property andequipment in 2005 was $18.9 million as compared to $4.1 million in 2004. Thegain in 2005 was from the sale of our interests in two leases in the BretonSound area in the Gulf of Mexico.  Thegain in 2004 related to the sale of the Jo-Mill Unit in Borden County,Texas.  In 2004, we also recorded a losson sale of property and equipment of $14.3 million, consisting primarilyof the sale of the Romere Pass Unit in Plaquemines Parish, Louisiana.

***Exploration costs***

Since we follow the successfulefforts method of accounting, our results of operations are adversely affectedduring any accounting period in which significant seismic costs, exploratorydry hole costs, and unproved acreage impairments are expensed.  In 2005,we charged to expense $50.7 million of exploration costs, as compared to$75.1 million in 2004.  Most of the 2005 and 2004 costs were incurredin South Louisiana and Mississippi.

***General and administrative expenses***

G&A expenses increased 32% from$11.7 million in 2004 to $15.4 million in 2005.  Excluding non-cash employee compensation,G&A expenses increased 8% from $11.9 million in 2004 to $12.8 millionin 2005 due to higher personnel costs and professional fees attributable to theincrease in overall drilling and exploration activities.  In 2005, we recorded a $680,000 non-cashcompensation charge related to our after payout incentive plan and $1.9 millionfor stock-based employee compensation. In 2004, we recorded a $245,000 non-cash credit for stock-based employeecompensation.

***Interest expense***

Interest expense increased from$7.9 million in 2004 to $14.5 million in 2005 due to several factors.  In July 2005, we issued $225 million ofSenior Notes which bear interest at a fixed rate of 7.75%, and used theproceeds to repay our then-outstanding bank indebtedness.  As a result, the 2005 period included anon-cash charge of $1.8 million of debt issue costs related to the earlyrepayment of our senior term credit facility and the reduction in our borrowingbase under the revolving credit facility. The average daily principal balance outstanding under our bank creditfacility for 2005 was $101 million compared to $148.8 million for2004; however, the Senior Notes were outstanding for almost half of the 2005period.  Higher effective interest rateson our bank credit facilities also contributed to the increase in interestexpense.  Capitalized interest for 2005was $2.2 million compared to $877,000 in 2004.

***Gain/loss on derivatives***

We recorded a loss on derivativesof $70.1 million in 2005 compared to a loss of $25.3 million for2004.  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.  We recorded a loss on derivativesof $40.4 million in 2005 compared to a loss of $7.1 million in 2004resulting from mark-to-market valuations.

***Income tax expense (benefit)***

Our income tax benefit in 2005 of$451,000 differed from the statutory federal benefit due primarily to theutilization of tax depletion in excess of basis.  Our income benefit in 2004 was substantiallyequal to the statutory federal rate of 35% since the benefit derived from theutilization of tax depletion in excess of basis was offset by a provision forstate taxes.

**Liquidity and Capital Resources**

***Overview***

Ourprimary financial resource is our base of oil and gas reserves.  We pledge our producing oil and gas properties to a groupof banks to secure our revolving credit facility.  The banks establish a borrowing base by

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making an estimateof the collateral value of our oil and gas properties.  We borrow funds on the revolving creditfacility as needed to supplement our operating cash flow as a financing sourcefor our capital expenditure program.  Ourability to fund our capital expenditure program is dependent upon the level ofproduct prices and the success of our exploration program in replacing ourexisting oil and gas reserves.  Ifproduct prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduceour borrowing base, thus reducing funds available to fund our capital expenditure program.  The effects of product prices on cash flowcan be mitigated through the use of commodity derivatives. If we are unable to replace our oil and gasreserves through our exploration program, we may also suffer a reduction in ouroperating cash flow and access to funds under the revolving creditfacility.  Under extreme circumstances, productprice reductions or exploration drilling failures could allow the banks to seekto foreclose on our oil and gas properties, thereby threatening our financialviability.

In 2005, we issued $225 million of aggregateprincipal amount of Senior Notes and used the net proceeds to repay all amountsoutstanding on the revolving credit facility at that time.  However, we relied heavily on advances underthe revolving credit facility to finance a significant portion of ourexploration and development activities in 2006. At December 31, 2006, we had $140 million outstanding on therevolving credit facility.

Our 2006 expenditures exceeded cash flow fromoperating activities by more than $100 million. Our 2007 expenditures are also expected to exceed our cash flow fromoperating activities in 2007, although not by as large a margin.  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 this section, we willdescribe our current plans for capital spending, identify the capital resourcesavailable to finance our capital spending, and discuss the principal factorsthat can affect our liquidity and capital resources.

***Capital expenditures***

The following table summarizes, by area, ourplanned expenditures for exploration and development activities during 2007, ascompared to our actual expenditures in 2006.

|                       | ** ** | **Actual**                      | ** ** | **Planned**                     | ** ** | ** **        | ** ** |
|-----------------------|------------|---------------------------------|------------|---------------------------------|------------|-------------------|------------|
| ** **            | ** ** | **Expenditures**                | ** ** | **Expenditures**                | ** ** | **2007**          | ** ** |
| ** **            | ** ** | **Year Ended**             | ** ** | **Year Ended**             | ** ** | **Percentage**    | ** ** |
| ** **            | ** ** | **December 31, 2006** | ** ** | **December 31, 2007** | ** ** | **of Total** | ** ** |
| ** **            | ** ** | **(In thousands)**         | ** ** | ** **                      | ** ** |
| South Louisiana       |       | $                               | 118,500    |                            | $          | 39,300            |       | 23 | % |
| North Louisiana       |       | 48,900                          |       | 54,000                          |       | 32                | %          |
| Permian Basin         |       | 40,600                          |       | 17,200                          |       | 10                | %          |
| East Texas  Bossier   |       | 20,800                          |       | 48,400                          |       | 28                | %          |
| Utah/Montana          |       | 7,100                           |       | 6,300                           |       | 4                 | %          |
| Austin Chalk  (Trend) |       | 3,800                           |       | 3,100                           |       | 2                 | %          |
| Colorado              |       | 7,900                           |       | —                          |       | —            | %          |
| Other                 |       | 2,600                           |       | 1,800                           |       | 1                 | %          |
|                  |       | $                               | 250,200    |                            | $          | 170,100           |       | 100 | % |

Ouractual expenditures during fiscal 2007 may be substantially higher or lowerthan these estimates since our plans for exploration and development activitiesmay 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 2007.

Approximately 83% of the planned expendituresrelate to exploratory prospects. Exploratory prospects involve a higher degree of risk than developmentalprospects.  To offset the higher risk, wegenerally strive to achieve a higher reserve potential and rate of return oninvestments in exploratory prospects.  Wedo not attempt to forecast our success rate on exploratory drilling.  Accordingly, these current estimates do notinclude costs we may incur to complete any future successful exploratory wellsand construct the required production facilities for these wells.  Also, we are actively searching for otheropportunities to increase our oil and gas reserves, including the evaluation ofnew prospects for exploratory and developmental drilling activities andpotential acquisitions of proved oil and gas properties.  We cannot predict our drilling success onexploratory prospects, and our future results of operations and financialcondition could be adversely affected by unsuccessful exploratory drillingresults.

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Wespent $250.2 million on exploration and development activities during2006, of which approximately 84% was on exploratory prospects.  We currently plan to spend approximately$170.1 million for the calendar year 2007, of which approximately 83% isestimated to be spent on exploratory prospects. The 2006 expenditures exceeded our cash flow from operating activitiesby more than $100 million.  Our 2007expenditures are also expected to exceed our cash flow from operatingactivities in 2007, although not by as large a margin.  We intend to finance this shortfall byborrowings on the revolving credit facility. Our internal cash flow forecasts indicate that the amount of funds availableto us 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 2007.  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.

Wehave placed orders for two 2,000 horsepower rigs for possible use in ourBossier drilling program in North Louisiana and East Texas.  At December 31, 2006, we had invested$8.7 million in these rigs and were committed under firm purchasecontracts for an additional $15.8 million. We estimate that the combined construction cost of both rigs will beapproximately $27 million, and currently plan to seek financing for mostof the remaining cost of these rigs.

***Cash flowprovided by operating activities***

Substantiallyall of our cash flow from operating activities is derived from the productionof our oil and gas reserves.  We use thiscash flow to fund our on-going exploration and development activities in searchof new oil and gas reserves.  Variationsin cash flow from operating activities may impact our level of exploration anddevelopment expenditures.

Cash flowprovided by operating activities for the year ended December 31, 2006 decreased$17.5 million, or 11%, as compared to the corresponding period in 2005 dueto the combined effects of several factors. Oil and gas sales, net of production costs, general and administrativecosts and interest expense, were $20.2 million lower in 2006 as comparedto the same period in 2005.  Our primarysource of cash from operating activities is our oil and gas sales, net of productioncosts.  Our cash flow provided by operatingactivities is subject to material variation from changes in oil and gasproduction levels and product prices. Settlements on derivative contracts, excluding those contracts thatcontain a financing element as in the case of the contracts assumed in ouracquisition of Southwest Royalties, Inc. in May 2004, were substantially thesame in both periods.  Interest expenseincreased in 2006 due primarily to higher levels of indebtedness resulting fromthe issuance of the Senior Notes.

***Credit facility***

A groupof banks have provided us with a revolving credit facility on which we havehistorically relied for both our short-term liquidity (working capital) and ourlong-term financing needs.  The fundsavailable to us at any time under this revolving credit facility are limited tothe amount of the borrowing base established by the banks.  As long as we have sufficient availabilityunder this credit facility to meet our obligations as they come due, we willhave sufficient liquidity and will be able to fund any short-term workingcapital deficit.

At thebeginning of 2006, we had an outstanding balance under the revolving creditfacility of $10.7 million, and the borrowing base was $150 million,providing us with available funds of $138.5 million after accounting foroutstanding letters of credit.  In June2006, the borrowing base was increased to $200 million.  During 2006, we generated cash flow fromoperating activities of $146 million and received cash proceeds of$8.4 million from sales of assets and issuances of common stock.  We also spent $254.8 million on capitalexpenditures (excluding Larclay JV) and paid $29.4 million to settlederivatives with financing elements.  Tofinance the excess of expenditures over cash flow, we borrowed$129.3 million on the revolving credit facility.

Usingthe revolving credit facility for both our short-term liquidity and long-termfinancing needs can cause unusual fluctuations in our reported working capital,depending on the timing of cash receipts and expenditures.  On a daily basis, we use most of ouravailable cash to pay down our outstanding balance on the revolving creditfacility, which is classified as a non-current liability since we currentlyhave no required principal reductions. As we use cash to pay a non-current liability, our reportedworking capital decreases.  Conversely,as we draw on the revolving credit facility for funds to pay currentliabilities (such as payables for drilling and operating costs), our reportedworking capital increases.  Also,volatility in oil and gas prices can cause significant fluctuations in reportedworking capital as we record changes in the fair value of derivatives fromperiod to period.  For these reasons, theworking capital covenant related to the revolving credit facility requires usto (i) include the amount of funds available under this

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facility as a current asset,(ii) exclude current assets and liabilities related to the fair value ofderivatives, and (iii) exclude current maturities of vendor financeobligations, if any, when computing the working capital ratio at any balancesheet date.

Workingcapital computed for loan compliance purposes differs from our working capitalin accordance with generally accepted accounting principles (GAAP).  Since compliance with financial covenants isa 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 reportedworking capital deficit decreased from $35.8 million at December 31,2005 to $23.1 million at December 31, 2006 due primarily to a combinationof factors, including increases in fair value of derivatives and increases inreceivables, offset in part by increases in payables and current maturities oflong-term debt.  After giving effect tothe adjustments, our working capital computed for loan compliance purposes wasa positive $36.9 million at December 31, 2006, as compared to a positive$136.2 million at December 31, 2005. The following table reconciles our GAAP working capital to the workingcapital computed for loan compliance purposes at December 31, 2006 andDecember 31, 2005.
| ** **                                                                             | ** ** | **December 31,**   | ** ** |
|----------------------------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                                             | ** ** | **2006**                | ** ** | **2005** | ** ** |
| ** **                                                                             | ** ** | **(In thousands)** | ** ** |
| Working capital  (deficit) per GAAP                                                    |       | $                       | (23,068    | ) | $ | (35,812 | ) |
| Add funds  available under the revolving credit facility                               |       | 40,196                  |       | 138,496 |   |
| Exclude fair  value of derivatives classified as current assets or current liabilities |       | 5,993                   |       | 33,479 |   |
| Exclude current  assets and current liabilities of Larclay JV                          |       | 13,759                  |       | — |   |
|                                                                                   |       |                    |       |   |   |
| Working capital per  loan covenant                                                     |       | $                       | 36,880     |   | $ | 136,163 |   |

Since we use this revolvingcredit facility for both short-term liquidity and long-term financing needs, itis important that we comply in all material respects with the loan agreement,including financial covenants that are computed quarterly.  The working capital covenant requires us tomaintain positive working capital using the computations 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 incompliance with all financial and non-financial covenants at December 31, 2006,our increased leverage and reduced liquidity may result in our failing tocomply with one or more of these covenants in the future.  If we fail tomeet any of these loan covenants, we would ask the banks to allow us sufficienttime to obtain additional capital resources through alternative means.  If a suitable arrangement could not bereached with the banks, the banks could accelerate the indebtedness and seek toforeclose on the pledged assets.

Thebanks redetermine the borrowing base under the revolving credit facility atleast twice a year, in May and November. The November 2006 borrowing base review resulted in maintaining theborrowing base at $200 million.  Ifat any time, the borrowing base is less than the amount of outstandingindebtedness, we will be required to (i) pledge additional collateral,(ii) prepay the excess in not more than five equal monthly installments,or (iii) elect to convert the entire amount of outstanding indebtedness toa term obligation based on amortization formulas set forth in the loanagreement.  We relied heavily on advancesunder the revolving credit facility to finance a significant portion of ourexploration and development activities in 2006. At December 31, 2006, we had $140 million outstanding on therevolving credit facility, as compared to $160 million onFebruary 28, 2007.  The increasedborrowings since December 31, 2006 were required to finance ourexploration program and to pay interest on our Senior Notes.

***73⁄4% Senior Notes due 2013***

In July 2005, we issued, in a private placement,$225 million of aggregate principal amount of Senior Notes.  The Senior Notes were issued at face valueand will 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 repayamounts outstanding on our secured credit facilities and for general corporatepurposes, including the funding of planned exploration and developmentactivities.

At any time prior to August 1, 2008, we may redeem upto 35% of the aggregate principal amount of the Senior Notes with the proceedsof certain equity offerings at a redemption price of 107.75% of the principalamount, plus accrued and unpaid interest. In addition, prior to August 1, 2009, we may redeem some or all of theSenior Notes at a redemption price equal to 100% of the principal amount of theSenior Notes to be redeemed, plus a make-whole

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premium,plus any accrued and unpaid interest.  Onand after August 1, 2009, we may redeem some or all of the Senior Notes atredemption prices (expressed as percentages of principal amount) equal to103.875% for the twelve-month period beginning on August 1, 2009, 101.938%for the twelve-month period beginning on August 1, 2010, and 100.00% beginningon August 1, 2011, for any period thereafter, in each case plus accrued andunpaid interest.

The Indenture governing the Senior Notes restricts ourability and the ability of our restricted subsidiaries to:  (i) borrow money; (ii) issueredeemable and preferred stock; (iii) pay distributions or dividends;(iv) make investments; (v) create liens without securing the Notes;(vi) enter into agreements that restrict dividends from subsidiaries;(vii) sell certain assets or merge with or into other companies;(viii) enter into transactions with affiliates; (ix) guaranteeindebtedness; and (x) enter into new lines of business.  These covenants are subject to a number ofimportant exceptions and qualifications. We were in compliance with these covenants at December 31, 2006.

***Alternativecapital resources***

Althoughour base of oil and gas reserves, as collateral for both of our creditfacilities, has historically been our primary capital resource, we have in thepast, and we believe we could in the future, use alternative capital resources,such as asset sales, vendor financing arrangements, and/or public or privateissuances of common stock.  We could alsoissue senior or subordinated debt or preferred stock in a public or a privateplacement if we choose to raise capital through either of these markets.  While we believe we would be able to obtainfunds through one or more of these alternatives, if needed, there can be noassurance that these capital resources would be available on terms acceptableto us.

***ContractualObligations and Contingent Commitments***

Thefollowing table summarizes our contractual obligations as of December 31, 2006by payment due date.
| ** **                       | ** ** | **Payments Due by Period** | ** ** |
|----------------------------------|------------|-------------------------------------------|------------|
| ** **                       | ** ** | **Total**                                 | ** ** | **2007** | ** ** | **2008  to  2009** | ** ** | **2010  to  2011** | ** ** | **2012 and  Thereafter** | ** ** |
| ** **                       | ** ** | **(In thousands)**                   | ** ** |
| Contractual  obligations:        |       |                                      |       |   |   |   |   |   |   |   |   |
| 73⁄4% Senior Notes (a)        |       | $                                         | 225,000    |   | $ | — |   | $ | — |   | $ | — |   | $ | 225,000 |   |
| Secured bank credit facility (a) |       | 140,000                                   |       | — |   | 140,000 |   | — |   | — |   |
| Drilling contracts               |       | 128,425                                   |       | 57,660 |   | 70,765 |   | — |   | — |   |
| Larclay JV note                  |       | 66,273                                    |       | 17,397 |   | 34,793 |   | 14,083 |   | — |   |
| Purchase commitments             |       | 18,599                                    |       | 18,599 |   | — |   | — |   | — |   |
| Lease obligations                |       | 4,779                                     |       | 1,412 |   | 1,903 |   | 1,353 |   | 111 |   |
| Total  contractual obligations   |       | $                                         | 583,076    |   | $ | 95,068 |   | $ | 247,461 |   | $ | 15,436 |   | $ | 225,111 |   |

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(a)                      Inaddition to the principal payments presented, we expect to make annual interestpayments of $17.4 million on the Senior Notes and approximately$10.4 million on the secured bank credit facility (based on the balancesand interest rates at December 31, 2006).

Excludedfrom the table above is our mark-to-market liability related to commodity andinterest rate derivatives.  Ourderivative obligations, based on mark-to-market valuations at December 31,2006, would mature as follows: 2007 - $6 million, and 2008 - $19.5 million.

**Known Trends and Uncertainties**

***Oil and GasProduction***

Aswith all companies engaged in oil and gas exploration and production, we facethe challenge 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.  In 2006, we replaced more than 100% of our2006 oil and gas production through our exploratory drilling program.  Production from these discoveries shouldcontribute favorably to production in 2007, and may help offset the naturalproduction declines from our base of oil and gas reserves.  Even

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with this new production, wewill need to discover new sources of production from our exploration anddevelopment activities in 2007.  While wecannot predict the results of our exploration and development activities, webelieve that oil and gas production levels in 2007 will be comparable to thosein 2006.

***ProfitMargins***

We analyze, on an Mcfe produced basis, thoserevenues and expenses that have a significant impact on our oil and gas profitmargin.  Our weighted average oil and gassales per Mcfe have been on an upward trend, from $6.04 per Mcfe in 2004, $8.04per Mcfe in 2005 and $8.36 per Mcfe in 2006. Higher product prices have provided us with a significant incentive toassume the risks associated with many of the exploratory prospects that we haveinitiated in the past three years. However, our expenses per Mcfe are also on an upward trend and isresulting in a narrowing profit margin. Our oil and gas DD&A per Mcfe has increased from $1.28 per Mcfe in2004, to $1.42 per Mcfe in 2005, to $2.12 in 2006.  An upward trend in DD&A per Mcfeindicates that our cost to find and/or acquire reserves is increasing at afaster rate than the reserves we are adding. Although we replaced approximately 100% of our 2006 production in 2006,our cost to find those reserves was higher than our historical combinedrate.  Also affecting our profit marginis the cost of producing our reserves. Our production costs per Mcfe have risen from $1.29 per Mcfe in 2004, to$1.83 per Mcfe in 2005, to $2.15 per Mcfe in 2006.  Our rise in production costs per Mcfe is aresult of a combination of factors.  Mostof the increase in 2004 was attributable to the acquisition of mature PermianBasin properties that had a higher production cost profile than ourthen-existing properties.  Since thebeginning of 2005, we have experienced significant increases in the cost offield services to maintain and produce our production.

**Application of Critical AccountingPolicies and Estimates**

***Summary***

In this section, we will identify the critical accountingpolicies we follow in preparing our financial statements and disclosures.  Many of these policies require us to makedifficult, subjective and complex judgments in the course of making estimatesof matters that are inherently imprecise. We explain the nature of these estimates, assumptions and judgments, andthe likelihood that materially different amounts would be reported in ourfinancial statements under different conditions or using different assumptions.

The following table lists our critical accountingpolicies, the estimates and assumptions that can have a significant impact onthe application of these accounting policies, and the financial statementaccounts affected by these estimates and assumptions.
| Accounting Policies              | ** ** | **Estimates or Assumptions**                                             | ** ** | **Accounts Affected**                                                    |
|----------------------------------|------------|--------------------------------------------------------------------------|------------|--------------------------------------------------------------------------|
| Successful efforts  accounting   |       | ·  Reserve estimates                                           |       | ·  Oil and gas properties                                      |
| for oil and gas properties       |       | ·  Valuation of unproved properties                            |       | ·  Accumulated DD&A*                                       |
|                                  |       | ·  Judgment regarding status of in progress  exploratory wells |       | ·  Provision for DD&A

·  Impairment of unproved |
|                                  |       |                                                                     |       | properties                                                               |
|                                  |       |                                                                     |       | ·  Abandonment costs (dry hole costs)                          |
|                             |       |                                                                     |       |                                                                     |
| Impairment of proved  properties |       | ·  Reserve estimates and related present value  of             |       | ·  Oil and gas properties                                      |
|                                  |       | future net  Revenues                                                     |       | ·  Accumulated DD&A                                        |
|                                  |       |                                                                     |       | ·  Impairment of proved properties                             |
|                             |       |                                                                     |       |                                                                     |
| 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                               |

----

*              DD&A means depreciation,depletion and amortization.

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***Significant Estimates and Assumptions***

*Oil and gas reserves*

Reserve engineering is a subjective process ofestimating underground accumulations of oil and gas that cannot be measured inan exact manner.  The accuracy of areserve estimate depends on the quality of available geological and engineeringdata, the precision of the interpretation of that data, and judgment based onexperience and training.  Annually, weengage independent 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 usuallydepend on the nature and extent of available data, and the accuracy of theestimates vary accordingly.  As a generalrule, the degree 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 to futurecommodity prices and operating and capital costs also play a significant rolein estimating oil and gas reserves and the estimated present value of the cashflows 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.

|                     | ** ** | ** **               | ** ** | ** **             | ** ** | ** **             | ** ** | ** **  | ** ** | **Standardized**             | ** ** |
|---------------------|------------|--------------------------|------------|------------------------|------------|------------------------|------------|-------------|------------|------------------------------|------------|
| ** **          | ** ** | ** **               | ** ** | ** **             | ** ** | ** **             | ** ** | ** **  | ** ** | **Measure**                  | ** ** |
| ** **          | ** ** | **Proved Reserves** | ** ** | **Average Price** | ** ** | **of Discounted** | ** ** |
| ** **          | ** ** | **Oil (a)**         | ** ** | **Gas**                | ** ** | **Oil (a)**       | ** ** | **Gas**     | ** ** | **Future**                   | ** ** |
| ** **          | ** ** | **(MMBbls)**             | ** ** | **(Bcf)**              | ** ** | **($/Bbl)**            | ** ** | **($/Mcf)** | ** ** | **Net Cash Flows** | ** ** |
| ** **          | ** ** | ** **               | ** ** | ** **             | ** ** | ** **             | ** ** | ** **  | ** ** | **(In millions)**       | ** ** |
| As of December  31: |       |                     |       |                   |       |                   |       |        |       |                         |       |
| 2006                |       | 25.4                     |       | 119.2                  |       | $                      | 57.18      |        | $          | 5.24                         |       | $ | 514.8 |   |
| 2005                |       | 27.8                     |       | 126.8                  |       | $                      | 57.85      |        | $          | 10.65                        |       | $ | 753.7 |   |
| 2004                |       | 26.8                     |       | 138.3                  |       | $                      | 41.48      |        | $          | 5.59                         |       | $ | 500.2 |   |

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(a)     Includes natural gas liquids

***Valuation of unprovedproperties***

Placing a fair market value onunproved properties (also known as prospects) is very subjective since there isno quoted market for undeveloped exploratory prospects.  The negotiated price of any prospect betweena willing seller and willing buyer depends on the specific facts regarding theprospect, including:

·                  The location of the prospect in relation to knownfields and reservoirs, available markets and transportation systems for oil andgas production in the vicinity, and other critical services;

·                  The nature and extent of geological and geophysicaldata on the prospect;

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·                  The terms of the leases holding the acreage in theprospect, such as ownership interests, expiration terms, delay rentalobligations, depth limitations, drilling and marketing restrictions, andsimilar terms;

·                  The prospect’s risk-adjusted potential for return oninvestment, 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 close proximity tothe prospect that could either enhance or condemn the prospect’s chances ofsuccess.

***Asset RetirementObligations***

Weare required by SFAS 143 “Accounting for Asset Retirement Obligations” toestimate the present value of the amount we will incur to plug, abandon andremediate our producing properties at the end of their productive lives, inaccordance with applicable state laws. We compute our liability for asset retirement obligations by calculatingthe present value of estimated future cash flows related to each property.  This requires us to use significantassumptions, including current estimates of plugging and abandonment costs,annual inflation of these costs, the productive lives of wells and ourrisk-adjusted interest rate. Changes in any of these assumptions can result insignificant revisions to the estimated asset retirement obligations.

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

Generallyaccepted accounting principles do not require, or even permit, the restatementof previously issued financial statements due to changes in estimates unlesssuch estimates were unreasonable or did not comply with applicable SECaccounting rules.  We are required to useour best judgment in making estimates and assumptions, taking into considerationthe best and most current data available to us at the time of theestimate.  At each accounting period, wemake a new estimate 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.

***Provision for DD&A***

Wecompute our provision for DD&A on a unit-of-production method.  Each quarter, we use the following formulasto compute the provision for DD&A for each of our producing properties (orappropriate groups of properties based on geographical and geologicalsimilarities):

·                  DD&A Rate = Unamortized Cost  ̧ Beginningof Period Reserves

·                  Provision for DD&A = DD&A Rate  ́Current Period Production

Reserveestimates 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 therevision.  Alternatively, if reserveestimates are revised upward, the DD&A rate will decrease.

***Impairment of UnprovedProperties***

Eachquarter, we review our unproved oil and gas properties to determine if therehas been, in our judgment, an impairment in value of each prospect that weconsider individually significant.  Tothe extent that the carrying cost of a prospect exceeds its estimated value, wemake a provision for impairment of unproved properties, and record theprovision 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.

***Impairment of ProvedProperties***

Eachquarter, 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

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buyer mightuse.  These parameters may includeescalations of prices instead of constant pricing, and they may also includethe risk-adjusted value of reserves that do not qualify as provedreserves.  To the extent that thecarrying cost for the affected property exceeds its estimated value, we make aprovision for impairment of proved properties. If the value is revised upward in a future period, we do not reverse theprior provision, and we continue to carry the property at a net cost that islower than its estimated value.  If thevalue is revised downward in a future period, an additional provision forimpairment is made in that period. Accordingly, the carrying costs of producing properties on our balancesheet will vary from (and often will be less than) the present value of provedreserves for these properties.

***Judgment RegardingStatus of In-Progress Wells***

On aquarterly basis, we review the status of each in-progress well to determine theproper accounting treatment under the successful efforts method ofaccounting.  Cumulative costs onin-progress wells remain capitalized until their productive status becomesknown.  If an in-progress exploratorywell is found to be unsuccessful (often referred to as a dry hole) prior to theissuance of our financial statements, we write-off all costs incurred throughthe balance sheet date to abandonments and impairments expense, a component ofexploration costs.  Costs incurred onthat dry hole after the balance sheet date are charged to exploration costs inthe period incurred.

Occasionally,we are unable to make a final determination about the productive status of awell prior to issuance of our financial statements.  In these cases, we leave the well classifiedas in-progress until we have had sufficient time to conduct additionalcompletion or testing operations and to evaluate the pertinent geological andgeophysical and engineering data obtained. At the time when we are able to make a final determination of a well’sproductive status, the well is removed from the in-progress status and theproper accounting treatment is recorded.

***Asset RetirementObligations***

Ourasset retirement obligation is recorded as a liability at its estimated presentvalue as of the asset’s inception, with an offsetting increase to oil and gasproperties. Periodic accretion of discount of the estimated liability isrecorded as an expense in the statement of operations.  During 2006, we revised our estimated assetretirement obligations by $6.5 million, or approximately 33% of the assetretirement obligations at December 31, 2005, based on a review of current pluggingand abandonment costs. Revisions to the asset retirement obligation arerecorded with an offsetting change to producing properties, resulting inprospective changes to depreciation, depletion and amortization expense andaccretion expense. Because of the subjectivity of assumptions and the relativelylong lives of most of our wells, the costs to ultimately retire our wells mayvary significantly from prior estimates.

**RecentAccounting Pronouncements**

InSeptember 2006, the Securities and Exchange Commission issued Staff AccountingBulletin No. 108 (“SAB 108”), which becomes effective beginning onJanuary 1, 2007. SAB 108 provides guidance on the consideration of theeffects of prior period misstatements in quantifying current year misstatementsfor the purpose of a materiality assessment. SAB 108 requires an entity toevaluate the impact of correcting all misstatements, including both thecarryover and reversing effects of prior year misstatements, on current yearfinancial statements. If a misstatement is material to the current yearfinancial statements, the prior year financial statements should also becorrected, even though such revision was, and continues to be, immaterial tothe prior year financial statements. Correcting prior year financial statementsfor immaterial errors would not require previously filed reports to be amended.Such correction should be made in the current period filings.  The adoption of SAB 108 had no effect onour consolidated financial statements.

InSeptember 2006, the FASB issued SFAS No. 157 “Fair Value Measurements”(“SFAS 157”), which defines fair value, establishes a framework for measuringfair value in generally accepted accounting principles and expands disclosuresabout fair value measurements. This Statement applies under other accountingpronouncements that require or permit fair value measurements, the FASB havingpreviously concluded in those accounting pronouncements that fair value is therelevant measurement attribute. Accordingly, this Statement does not requireany new fair value measurements. SFAS 157 is effective for fiscal yearsbeginning after December 15, 2007. We plan to adopt SFAS 157 beginning inthe first quarter of fiscal 2008. We are currently evaluating the impact, ifany, the adoption of SFAS 157 will have on our consolidated financial position,results of operations or cash flows.

EmergingIssues Task Force Issue 04-5 (“EITF 04-5”), which became effective January 1,2006, requires companies to fully consolidate any limited partnerships that thecompany controls as general partner. EITF 04-5 presumes that a sole general partner in a limited partnershipcontrols the limited partnership; however, the presumption of control can beovercome if the limited partners have (i) the substantive ability to remove thesole general partner or

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otherwise dissolvethe limited partnership or (ii) substantive participating rights.  For this purpose, the EITF has concluded thata general partner lacks control if the limited partners can remove the generalpartner with a simple majority vote.  Wehave entered into contracts with 17 oil and gas limited partnerships of whichwe are the sole general partner. Generally, these contracts require us to abstain from voting any of ourlimited partnership units in matters related to our removal as generalpartner.  As a result, the limitedpartners in all of the oil and gas partnerships in which we serve as generalpartner can remove us as general partner with a simple majority vote.  Accordingly, we have continued consolidatingour proportionate share of all of these limited partnerships.  The adoption of EITF 04-5 had no effecton our consolidated financial statements.

InJune 2006, the Financial Accounting Standards Board (“FASB”) issued FASBInterpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN 48”)to clarify the manner in which enterprises account for uncertainties in theirprovisions for income taxes.  Generally,the standard presented by FIN 48 is a “more likely than not” standard andis intended to enhance the relevancy and comparability of financial reportingby companies.  FIN 48 is effectivefor fiscal years beginning after December 31, 2006.  The adoption of FIN 48 is not expectedto have a significant impact on our consolidated financial statements.

## **Item 7A -       Quantitative and Qualitative DisclosureAbout Market Risks**

Ourbusiness is impacted by fluctuations in commodity prices and interestrates.  The following discussion isintended to identify the nature of these market risks, describe our strategyfor managing such risks, and to quantify the potential affect of marketvolatility on our financial condition and results of operations.

**Oil and Gas Prices**

Ourfinancial condition, results of operations, and capital resources are highlydependent upon the prevailing market prices of, and demand for, oil and naturalgas.  These commodity prices are subjectto wide fluctuations and market uncertainties due to a variety of factors thatare beyond our control.  These factorsinclude the level of global demand for petroleum products, foreign supply ofoil and gas, 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 and domestic.  We cannot predict future oil and gas priceswith any degree of certainty.  Sustainedweakness in oil and gas prices may adversely affect our financial condition andresults of operations, and may also reduce the amount of net oil and gasreserves that we can produce economically. Any reduction in reserves, including reductions due to pricefluctuations, can reduce the borrowing base under our revolving credit facilityand adversely affect our liquidity and our ability to obtain capital for ourexploration and development activities. Similarly, any improvements in oil and gas prices can have a favorableimpact on our financial condition, results of operations and capitalresources.  Based on December 31,2006 reserve estimates, we project that a $1.00 drop in the price per Bbl ofoil and a $.50 drop in the price per Mcf of gas from year end 2006 would reduceour gross revenues for the year ending December 31, 2007 by$10.7 million.

Fromtime to time, we utilize commodity derivatives, consisting primarily of swaps,floors and collars to attempt to optimize the price received for our oil andnatural gas production.  When using swapsto hedge our oil and natural gas production, we receive a fixed price for therespective commodity and pay a floating market price as defined in eachcontract (generally NYMEX futures prices), resulting in a net amount due to orfrom the counterparty.  When purchasingfloors, we receive 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 theput strike price, then we receive the fixed price and pay the marketprice.  If the market price is betweenthe call and the 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.

Thedecision to initiate or terminate commodity hedges is made by management basedon its expectation of future market price movements.  We have no set goals for the percentage ofour production we hedge and we do not use any formulas or triggers in decidingwhen to initiate or terminate a hedge. If we enter into swaps or collars and the floating market price at thesettlement date is higher than the fixed price or the fixed ceiling price, wewill forego

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revenue we wouldhave otherwise received.  If we terminatea swap, collar or floor because we anticipate future increases in marketprices, we may be exposed to downside risk that would not have existedotherwise.

Thefollowing summarizes information concerning the Company’s net positions in opencommodity derivatives applicable to periods subsequent to December 31,2006.  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 2007 |       | 454,000            |       | $         | 4.00       |   | $ | 5.18 |   | 139,000 |   | $ | 23.00 |   | $ | 25.20 |   |
| 2nd Quarter 2007 |       | 459,000            |       | $         | 4.00       |   | $ | 5.18 |   | 141,000 |   | $ | 23.00 |   | $ | 25.20 |   |
| 3rd Quarter 2007 |       | 459,000            |       | $         | 4.00       |   | $ | 5.18 |   | 141,000 |   | $ | 23.00 |   | $ | 25.20 |   |
| 4th Quarter 2007 |       | 459,000            |       | $         | 4.00       |   | $ | 5.18 |   | 141,000 |   | $ | 23.00 |   | $ | 25.20 |   |
| 2008                  |       | 1,279,000          |       | $         | 4.00       |   | $ | 5.15 |   | 392,000 |   | $ | 23.00 |   | $ | 25.07 |   |
|                  |       |               |       |      |       |   |   |   |   |   |   |   |   |
|                  |       | 3,110,000          |       |      |       |   |   | 954,000 |   |   |   |   |   |

***Swaps:***
| ** **            | ** ** | **Gas**            | ** ** | **Oil**   | ** ** |
|-----------------------|------------|--------------------|------------|-----------|------------|
| ** **            | ** ** | **MMBtu **(a) | ** ** | **Price** | ** ** | **Bbls** | ** ** | **Price** | ** ** |
| Production  Period:   |       |               |       |      |       |   |   |   |   |
| 1st Quarter 2007 |       | 3,000,000          |       | $         | 8.26       |   | 150,000 |   | $ | 72.75 |   |
| 2nd Quarter 2007 |       | 2,600,000          |       | $         | 8.16       |   | — |   | $ | — |   |
| 3rd Quarter 2007 |       | 2,400,000          |       | $         | 8.34       |   | 75,000 |   | $ | 72.75 |   |
| 4th Quarter 2007 |       | 2,400,000          |       | $         | 8.34       |   | 225,000 |   | $ | 72.75 |   |
| 2008                  |       | 6,300,000          |       | $         | 8.19       |   | 720,000 |   | $ | 65.60 |   |
|                  |       |               |       |      |       |   |   |   |   |
|                  |       | 16,700,000         |       |      |       | 1,170,000 |   |   |   |

----

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

In January 2007, the Company terminated certain fixed-priceoil swaps covering 450,000 barrels at a price of $55.35 per barrel, from March2007 through August 2007, resulting in an aggregate realized gain ofapproximately $7.8 million, which will be collected from the counterpartymonthly during 2007.

In July 2006, the Company also terminated certainfixed-price oil swaps covering 300,000 barrels at a price of $80.45 perbarrel, from January 2007 through December 2007, resulting in an aggregaterealized loss of approximately $2.4 million, which will be paid to thecounterparty monthly during 2007.

We use a sensitivity analysis technique to evaluatethe hypothetical effect that changes in the market value of oil and gas mayhave on the fair value of our commodity derivatives.  A $1 per barrel change in the price ofoil and a $.50 per MMBtu change in the price of gas would change the fair valueof our outstanding commodity derivatives at December 31, 2006 byapproximately $8.3 million.

**Interest Rates**

We are exposed to interest rate risk on our long-termdebt with a variable interest rate.  AtDecember 31, 2006, our variable rate debt had a carrying value of $206.3million, which approximated its fair value. At December 31, 2006, our fixed rate debt had a carrying value of $225million and an approximate fair value of $207.6 million, based on currentmarket quotes.  We estimate that thehypothetical change in the fair value of our long-term debt resulting from a100-basis point change in interest rates would be approximately$9.4 million.

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, 2006.

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

**Item 8 -          FinancialStatements and Supplementary Data**

For the financial statementsand supplementary data required by this Item 8, see the Index toConsolidated Financial Statements included elsewhere in this Form 10-K.

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

None.

**Item 9A -       Controlsand Procedures**

**Disclosure Controls andProcedures**

In September 2002, our Board ofDirectors adopted a policy designed to establish disclosure controls andprocedures that are adequate to provide reasonable assurance that ourmanagement will be able to collect, process and disclose both financial andnon-financial information, on a timely basis, in our reports to the SEC andother communications with our stockholders. Disclosure controls and procedures include all processes necessary toensure that material information is recorded, processed, summarized andreported within the time periods specified in the SEC’s rules and forms, and isaccumulated and communicated to our management, including our chief executiveand chief financial officers, to allow timely decisions regarding requireddisclosures.

With respect to our disclosurecontrols and procedures:

·                  management has evaluated the effectiveness of ourdisclosure controls and procedures as of the end of the period covered by thisreport;

·                  this evaluation was conducted under the supervisionand with the participation of our management, including our chief executive andchief financial officers; and

·                  it is the conclusion of our chief executive and chieffinancial officers that these disclosure controls and procedures are effectivein ensuring that information that is required to be disclosed by the Company inreports filed or submitted with the SEC is recorded, processed, summarized andreported within the time periods specified in the rules and forms establishedby the SEC.

**Internal Control Over Financial Reporting**

Management designed our internalcontrol over financial reporting to provide reasonable assurance regarding thereliability of our financial reporting and the preparation of our financialstatements for external purposes in accordance with generally acceptedaccounting principles.  Our internalcontrol over financial reporting includes those policies and procedures that:

·                  pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions anddispositions of our assets;

·                  provide reasonable assurance thattransactions are recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accounting principles, andthat our receipts and expenditures are being made only in accordance withauthorizations of management and our Board of Directors; and

43

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·                  provide reasonable assurance regarding prevention ortimely detection of any unauthorized acquisition, use or disposition of ourassets that could have a material 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 riskthat controls may become inadequate because of changes in conditions, or thatthe degree of compliance with the policies or procedures may deteriorate.

**Changes in Internal Control OverFinancial Reporting**

No changes in internal control overfinancial reporting were made during the quarter ended December 31, 2006that have materially affected, or are reasonably likely to materially affect,our internal control over financial reporting.

**Management’s Report on InternalControl Over Financial Reporting**

Our management is responsible forestablishing and maintaining adequate internal control over financial reportingas defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Actof 1934.  Management assessed theeffectiveness of our internal control over financial reporting as of December31, 2006.  In making this assessment,management used the criteria set forth by the Committee of SponsoringOrganizations of the Treadway Commission (COSO) in *InternalControl-Integrated Framework*. Based on this assessment, management has concluded that, as of December31, 2006, our internal control over financial reporting is effective based onthose criteria.

KPMG LLP has issued an attestationreport on management’s assessment of internal control over financial reporting,the contents of which are shown below.

44

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**Report of Independent RegisteredPublic Accounting Firm**

The Board of Directors and Stockholders

Clayton Williams Energy,Inc.:

We have audited management’s assessment, included in theaccompanying Management’s Report on Internal Control Over Financial Reporting,that Clayton Williams Energy, Inc. (Company) maintained effective internalcontrol over financial reporting as of December 31, 2006, based on criteriaestablished in Internal Control—Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission (COSO). The Company’smanagement is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internalcontrol over financial reporting. Our responsibility is to express an opinionon management’s assessment and an opinion on the effectiveness of the Company’sinternal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards ofthe Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether effective internal control over financial reporting was maintained inall material respects. Our audit included obtaining an understanding ofinternal control over financial reporting, evaluating management’s assessment,testing and evaluating the design and operating effectiveness of internalcontrol, and performing such other procedures as we considered necessary in thecircumstances. We believe that our audit provides a reasonable basis for ouropinion.

A company’s internal control over financial reporting is aprocess designed to provide reasonable assurance regarding the reliability offinancial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles.  A company’s internal control over financialreporting includes those policies and procedures that (1) pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2)provide reasonable assurance that transactions are recorded as necessary topermit preparation of financial statements in accordance with generallyaccepted accounting principles, and that receipts and expenditures of thecompany are being made only in accordance with authorizations of management anddirectors of the company; and (3) provide reasonable assurance regardingprevention or timely detection of unauthorized acquisition, use, or dispositionof the company’s assets that could have a material effect on the financialstatements.

Because of its inherent limitations, internal control overfinancial reporting may not prevent or detect misstatements.  Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls maybecome inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Companymaintained effective internal control over financial reporting as of December31, 2006, is fairly stated, in all material respects, based on criteriaestablished in *Internal Control—Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commission(COSO). Also, in our opinion, the Company maintained, in all material respects,effective internal control over financial reporting as of December 31, 2006, basedon criteria established in *InternalControl—Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards ofthe Public Company Accounting Oversight Board (United States), the consolidatedbalance sheets of Clayton Williams Energy, Inc. and subsidiaries as of December31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for eachof the years in the three-year period ended December 31, 2006, and our reportdated March 15, 2007, expressed an unqualified opinion on those consolidatedfinancial statements.

KPMG LLP

Dallas, Texas

March 15, 2007

45

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**Item 9B -       Other Information**

None.

**PART III**

**Item 10 -        Directors, Executive Officers and Corporate Governance**

Information required by this Item is incorporated byreference to our definitive proxy statement, which will be filed with the SECno later than April 30, 2007.

**Item 11 -        Executive Compensation**

Information required by this Item is incorporated byreference to our definitive proxy statement, which will be filed with the SECno later than April 30, 2007.

**Item 12 -****                        SecurityOwnership of Certain Beneficial Owners and Management and Related StockholderMatters**

Information required by this Item is incorporated byreference to our definitive proxy statement, which will be filed with the SECno later than April 30, 2007.

**Item 13 -        Certain Relationships and Related Transactions, andDirector Independence**

Information required by this Item is incorporated byreference to our definitive proxy statement, which will be filed with the SECno later than April 30, 2007.

**Item 14 -        Principal Accounting Fees and Services**

Information required by this Item is incorporated byreference to our definitive proxy statement, which will be filed with the SECno later than April 30, 2007.

**PART IV**

**Item 15 -        Exhibits and Financial Statement Schedules**

**FinancialStatements and Schedules**

For a list of the consolidated financial statementsand financial statement schedules filed as part of this Form 10-K,see the Index to Consolidated Financial Statements on page F-1.

**Exhibits**

The following exhibits arefiled as a part of this Report, with each exhibit that consists of or includesa management contract or compensatory plan or arrangement being identified witha “†”:
| 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                                                                         |

46

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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 March 8, 2007††                                                                                          |
|         |       |                                                                                                                                                                                                                                                                                        |
| **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, filed as Exhibit 10.3 to the  Company’s Form 10-K for the period ended December 31, 2005††                                                                                     |
|         |       |                                                                                                                                                                                                                                                                                        |
| **10.4       |       | Third Amendment to Amended and Restated Credit  Agreement dated June 30, 2006, filed as Exhibit 10.1 to the Company’s  Current Report on Form 8-K filed with the Commission on July 14, 2006††                                                                          |
|         |       |                                                                                                                                                                                                                                                                                        |
| **10.5       |       | 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††                               |
|         |       |                                                                                                                                                                                                                                                                                        |
| **10.6† |       | 1993 Stock Compensation Plan, filed as Exhibit 10.1  to the Company’s Form S-8 Registration Statement, Commission File No.  033-68318                                                                                                                                                  |
|         |       |                                                                                                                                                                                                                                                                                        |
| **10.7† |       | 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††                                                                                                                                |
|         |       |                                                                                                                                                                                                                                                                                        |
| **10.8† |       | 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                                                                                                                           |
|         |       |                                                                                                                                                                                                                                                                                        |
| **10.9† |       | 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                                                                                                                               |

47

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| Exhibit       | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                    |
|---------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number**    | ** ** | **Description of Exhibit**                                                                                                                                                                                                                                                                                                                                                    |
| ** **    | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                    |
| **10.10† |       | 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                                                                                                                                                                                                                |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.11† |       | Fifth Amendment to 1993 Stock Compensation Plan,  filed as Exhibit 10.13 to the Company’s Form 10-K for the period ended  December 31, 2005††                                                                                                                                                                                                             |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.12† |       | Outside Directors Stock Option Plan, filed as  Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission  File No. 33-68316                                                                                                                                                                                                                              |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.13† |       | 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††                                                                                                                                                                                                           |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.14† |       | Second 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, 2005††                                                                                                                                                                                                     |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.15† |       | Bonus Incentive Plan, filed as Exhibit 10.1 to the  Company’s Form S-8 Registration Statement, Commission File No. 33-68320                                                                                                                                                                                                                                              |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.16† |       | 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††                                                                                                                                                                                                                           |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.17† |       | 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, 2004††                                                                                                                          |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.18† |       | Executive Incentive Stock Compensation Plan, filed  as Exhibit 10.1 to the Company’s Form S-8 Registration Statement,  Commission File No. 33-92834                                                                                                                                                                                                                      |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.19† |       | 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††                                                                                                                                                                                         |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.20       |       | 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                                                                                                                                 |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.21       |       | 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††                                                                                             |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.22       |       | 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                                                                                                                                                                                     |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.23       |       | 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†† |
|          |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **10.24† |       | 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††                                                                                                                                                                  |

48

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| Exhibit       | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                     |
|---------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number**    | ** ** | **Description of Exhibit**                                                                                                                                                                                                                                                                                                                                     |
| ** **    | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                     |
| **10.25† |       | 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††                                                                                                                                            |
|          |       |                                                                                                                                                                                                                                                                                                                                                           |
| **10.26† |       | 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††                                                                                                                                                       |
|          |       |                                                                                                                                                                                                                                                                                                                                                           |
| **10.27† |       | 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††                                                                                                                                          |
|          |       |                                                                                                                                                                                                                                                                                                                                                           |
| **10.28† |       | 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††                                                                                                                            |
|          |       |                                                                                                                                                                                                                                                                                                                                                           |
| **10.29† |       | 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††                                                                                                                                |
|          |       |                                                                                                                                                                                                                                                                                                                                                           |
| **10.30† |       | 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††                                                                                                                                         |
|          |       |                                                                                                                                                                                                                                                                                                                                                           |
| **10.31† |       | 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††                                                                                                                                                      |
|          |       |                                                                                                                                                                                                                                                                                                                                                           |
| **10.32† |       | 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††                                                                                                                                               |
|          |       |                                                                                                                                                                                                                                                                                                                                                           |
| **10.33† |       | 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††                                                                                                                                                                              |
|          |       |                                                                                                                                                                                                                                                                                                                                                           |
| **10.34† |       | 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††                                                                                                                                                                       |
|          |       |                                                                                                                                                                                                                                                                                                                                                           |
| **10.35       |       | 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††                                                                                                              |
|          |       |                                                                                                                                                                                                                                                                                                                                                           |
| **10.36       |       | Limited Liability Company Agreement, dated April 21,  2006, by and between Clayton Williams Energy, Inc. and Lariat Services, Inc.,  with respect to the formation of Larclay GP, LLC, a Texas limited liability  company, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K  filed with the Commission on April 26, 2006††     |
|          |       |                                                                                                                                                                                                                                                                                                                                                           |
| **10.37       |       | Agreement of Limited Partnership, dated April 21,  2006, by and among Larclay GP, LLC, Clayton Williams Energy, Inc. and Lariat  Services, Inc., with respect to the formation of Larclay, L.P., a Texas  limited partnership, filed as Exhibit 10.2 to the Company’s Current Report on  Form 8-K filed with the Commission on April 26, 2006†† |

49

----

 
| Exhibit       | ** ** | ** **                                                                                                                                                                                                                                                                              |
|---------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number**    | ** ** | **Description of Exhibit**                                                                                                                                                                                                                                                              |
| ** **    | ** ** | ** **                                                                                                                                                                                                                                                                              |
| **10.38       |       | Drilling Contract for Multiple Rigs, dated April 21,  2006, by and between Clayton Williams Energy, Inc. and Larclay, L.P., filed  as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the  Commission on April 26, 2006††                            |
|          |       |                                                                                                                                                                                                                                                                                    |
| **10.39       |       | Subordination Agreement, dated April 21, 2006, by  and among Clayton Williams Energy, Inc., Lariat Services, Inc. and Merrill  Lynch Capital, as agent, filed as Exhibit 10.4 to the Company’s Current  Report on Form 8-K filed with the Commission on April 26, 2006†† |
|          |       |                                                                                                                                                                                                                                                                                    |
| **10.40       |       | Consent and Agreement, dated April 21, 2006, by and  among Clayton Williams Energy, Inc., Lariat Services, Inc. and Merrill Lynch  Capital, as agent, filed as Exhibit 10.5 to the Company’s Current Report on  Form 8-K filed with the Commission on April 26, 2006††   |
|          |       |                                                                                                                                                                                                                                                                                    |
| **10.41       |       | Letter of Credit, dated April 21, 2006, issued in  favor of Merrill Lynch Capital, as agent, filed as Exhibit 10.6 to the  Company’s Current Report on Form 8-K filed with the Commission on April 26,  2006††                                                           |
|          |       |                                                                                                                                                                                                                                                                                    |
| **10.42       |       | Form of Unconditional Limited Guaranty, to be issued  by Clayton Williams Energy, Inc. in favor of Merrill Lynch Capital, as agent,  filed as Exhibit 10.7 to the Company’s Current Report on Form 8-K filed with  the Commission on April 26, 2006††                    |
|          |       |                                                                                                                                                                                                                                                                                    |
| **10.43† |       | Agreement of Limited Partnership of Floyd Prospect  II, L.P. dated May 15, 2006., filed as Exhibit 10.1 to the Company’s Current  Report on Form 8-K filed with the Commission on May 17, 2006††                                                                         |
|          |       |                                                                                                                                                                                                                                                                                    |
| **10.44† |       | Participation Agreement relating to South Louisiana  IV dated August 2, 2006, filed as Exhibit 10.1 to the Company’s Current  Report on Form 8-K filed with the Commission on August 7, 2006††                                                                           |
|          |       |                                                                                                                                                                                                                                                                                    |
| **10.45† |       | Participation Agreement relating to North Louisiana  — Hosston/Cotton Valley dated August 2, 2006, filed as Exhibit 10.2 to the  Company’s Current Report on Form 8-K filed with the Commission on August 7,  2006††                                                |
|          |       |                                                                                                                                                                                                                                                                                    |
| **10.46† |       | Participation Agreement relating to North Louisiana  — Bossier dated August 2, 2006, filed as Exhibit 10.3 to the Company’s  Current Report on Form 8-K filed with the Commission on August 7, 2006††                                                               |
|          |       |                                                                                                                                                                                                                                                                                    |
| **10.47† |       | Participation Agreement relating to Floyd Prospect  III dated November 15, 2006, filed as Exhibit 10.1 to the Company’s Current  Report on Form 8-K filed with the Commission on November 17, 2006††                                                                     |
|          |       |                                                                                                                                                                                                                                                                                    |
| **10.48† |       | Participation Agreement relating to North Louisiana  - Bossier II dated November 15, 2006, filed as Exhibit 10.2 to the Company’s  Current Report on Form 8-K filed with the Commission on November 17, 2006††                                                           |
|          |       |                                                                                                                                                                                                                                                                                    |
| **10.49† |       | Participation Agreement relating to North Louisiana  - Hosston/Cotton Valley II dated November 15, 2006, filed as Exhibit 10.3 to  the Company’s Current Report on Form 8-K filed with the Commission on  November 17, 2006††                                            |
|          |       |                                                                                                                                                                                                                                                                                    |
| **10.50† |       | Participation Agreement relating to South Louisiana  V dated November 15, 2006, filed as Exhibit 10.4 to the Company’s Current  Report on Form 8-K filed with the Commission on November 17, 2006††                                                                      |

50

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| Exhibit       | ** ** | ** **                                                                                                                                                                                                                                |
|---------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number**    | ** ** | **Description of Exhibit**                                                                                                                                                                                                                |
| ** **    | ** ** | ** **                                                                                                                                                                                                                                |
| **10.51† |       | Southwest Royalties Reward Plan dated  January 15, 2007, filed as Exhibit 10.1 to the Company’s Current Report  on Form 8-K filed with Commission on January 18, 2007††                                     |
|          |       |                                                                                                                                                                                                                                      |
| **10.52† |       | Participation Agreement relating to West Coast  Energy Properties, L.P. dated December 11, 2006, filed as Exhibit 10.1  to the Company’s Current Report on Form 8-K filed with the Commission  on December 14, 2006†† |
|          |       |                                                                                                                                                                                                                                      |
|  *21     |       | Subsidiaries of the Registrant                                                                                                                                                                                                            |
|          |       |                                                                                                                                                                                                                                      |
| *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                                                                                          |
|          |       |                                                                                                                                                                                                                                      |
| *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.                                                  |

51

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# **GLOSSARY OF TERMS**

Thefollowing are abbreviations and definitions of terms commonly used in the oiland gas industry and this Form 10-K.

*3-D seismic*.  An advanced technology method of detectingaccumulations of hydrocarbons identified by the collection and measurement ofthe intensity and timing of sound waves transmitted into the earth as theyreflect back to the surface.

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

*Bcf*. One billion cubic feet.

*Bcfe*. One billion cubic feet of natural gas equivalents.

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

*Credit Facility.*  A line of credit provided by a group ofbanks, secured by oil and gas properties.

*DD&A.* Refers to depreciation, depletion and amortization of the Company’sproperty and equipment.

*Development well*.  A well drilled within the proved area of anoil or gas reservoir to the depth of a stratigraphic horizon known to beproductive.

*Dry hole*. A well found to be incapable of producing hydrocarbons in sufficientquantities to justify completion as an oil or gas well.

*Exploratory well*.  A well drilled to find and produce oil ornatural gas reserves not classified as proved, to find a new productivereservoir in a field previously found to be productive of oil or natural gas inanother reservoir or to extend a known reservoir.

*Extensions and discoveries*.  As to any period, the increases to provedreserves from all sources other than the acquisition of proved properties orrevisions of previous estimates.

*Gross acres or wells*.  Refers to the total acres or wells in whichthe Company has a working interest.

*Horizontal drilling*.  A drilling technique that permits theoperator to contact and intersect a larger portion of the producing horizonthan conventional vertical drilling techniques and may, depending on thehorizon, result in increased production rates and greater ultimate recoveriesof hydrocarbons.

*MBbls*. One thousand barrels.

*Mcf*. One thousand cubic feet.

*Mcfe*. One thousand cubic feet of natural gas equivalents, based on a ratio of6 Mcf for each barrel of oil, which reflects the relative energy content.

*MMbtu.* One million British thermal units. One British thermal unit is the heat required to raise the temperatureof a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

*MMcf*.  One million cubic feet.

*MMcfe.* One million cubic feet of natural gas equivalents.

*Natural gas liquids*.  Liquid hydrocarbons that have been extractedfrom 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.

52

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*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 the exploration, developmentand production of an oil or gas well or lease.

*Present value of proved reserves*.  The present value of estimated futurerevenues, discounted at 10% annually, to be generated from the production of provedreserves determined in accordance with Securities and Exchange Commissionguidelines, net of estimated production and future development costs, usingprices and costs as of the date of estimation without future escalation,without giving effect to (i) estimated future abandonment costs, net ofthe estimated salvage value of related equipment, (ii) nonproperty relatedexpenses such as general and administrative expenses, debt service and futureincome 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.

*Proved reserves*.  The estimated quantities of crude oil,natural gas, and natural gas liquids which geological and engineering datademonstrate with reasonable certainty to be recoverable in future years fromknown reservoirs under existing economic and operating conditions, i.e., pricesand costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided onlyby contractual arrangements, but not on escalations based upon futureconditions.

*Proved undeveloped reserves (PUD)*.  Proved reserves that are expected to berecovered from new wells on undrilled acreage, or from existing wells where arelatively major expenditure is required for recompletion.

*Royalty*. An interest in an oil and gas lease that gives the owner of the interestthe right to receive a portion of the production from the leased acreage (or ofthe proceeds of the sale thereof), but generally does not require the owner topay any portion of the costs of drilling 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.

*SEC*. The United States Securities and Exchange Commission.

*Standardized measure of discounted future net cash flows*.  Present value of proved reserves, as adjustedto give effect to (i) estimated future abandonment costs, net of the estimatedsalvage value of related equipment, and (ii) estimated future incometaxes.

*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.

53

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*Working interest*.  An interest in an oil and gas lease thatgives the owner of the interest the right to drill for and produce oil and gason the leased acreage and requires the owner to pay a share of the costs ofdrilling and production operations.  Theshare of production to which a working interest is entitled will be smallerthan the share of costs that the working interest owner is required to bear tothe extent of any royalty burden.

*Workover*. Operations on a producing well to restore or increase production.

54

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SIGNATURES

In accordance with the requirementsof Section 13 or 15(d) of the Securities Exchange Act of 1934, the registranthas duly caused this report to be signed on its behalf by the undersigned,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 with the requirements of the Securities Exchange Act of1934, this report has been signed below by the following persons on behalf ofthe registrant and in the capacities and on the dates indicated.
| Signature                 | ** ** | **Title**                            | ** ** | **Date**       |
|---------------------------|------------|--------------------------------------|------------|----------------|
|                      |       |                                 |       |           |
| /s/ CLAYTON W. WILLIAMS * |       | Chairman of the Board,               |       | March 15, 2007 |
| Clayton W. Williams       |       | President and Chief Executive        |       |           |
|                      |       | Officer and Director                 |       |           |
|                      |       |                                 |       |           |
| /s/ L. PAUL LATHAM        |       | Executive Vice President,            |       | March 15, 2007 |
| L. Paul Latham            |       | Chief Operating Officer and          |       |           |
|                      |       | Director                             |       |           |
|                      |       |                                 |       |           |
| /s/ MEL G. RIGGS          |       | Senior Vice President -              |       | March 15, 2007 |
| Mel G. Riggs              |       | Finance, Secretary, Treasurer,       |       |           |
|                      |       | Chief Financial Officer and Director |       |           |
|                      |       |                                 |       |           |
| /s/ MICHAEL L. POLLARD    |       | Vice President – Accounting and |       | March 15, 2007 |
| Michael L. Pollard        |       | Principal Accounting Officer         |       |           |
|                      |       |                                 |       |           |
| /s/ STANLEY S. BEARD *    |       | Director                             |       | March 15, 2007 |
| Stanley S. Beard          |       |                                 |       |           |
|                      |       |                                 |       |           |
| /s/ DAVIS L. FORD *       |       | Director                             |       | March 15, 2007 |
| Davis L. Ford             |       |                                 |       |           |
|                      |       |                                 |       |           |
| /s/ ROBERT L. PARKER *    |       | Director                             |       | March 15, 2007 |
| Robert L. Parker          |       |                                 |       |           |
|                      |       |                                 |       |           |
| /s/ JORDAN R. SMITH *     |       | Director                             |       | March 15, 2007 |
| Jordan R. Smith           |       |                                 |       |           |

 

----

| *      | By:                |   | /s/ L. PAUL LATHAM |   |
|--------|--------------------|--------|--------------------|--------|
|   | L. Paul Latham     |   |
|   | *Attorney-in-Fact* |   |

 

55

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**CLAYTON WILLIAMS ENERGY, INC.**

**INDEX TO CONSOLIDATED FINANCIALSTATEMENTS**

**ANDFINANCIAL 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 andStockholders

ClaytonWilliams Energy, Inc.:

Wehave audited the accompanying consolidatedbalance sheets of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2006 and 2005, and therelated consolidated statementsof operations, stockholders’ equity, and cash flows for each of the years inthe three-year period ended December 31, 2006. 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.

Weconducted our audits in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtainreasonable assurance about whether the financial statements are free ofmaterial misstatement.  An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements. An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well asevaluating the overall financial statement presentation.  We believe that our audits provide areasonable basis for our opinion.

In ouropinion, the consolidatedfinancial statements referred to above present fairly, in all materialrespects, the financial position of Clayton Williams Energy, Inc. and subsidiaries as of December 31,2006 and 2005, and the results of theiroperations and their cash flowsfor each of the years in the three-year period ended December 31, 2006, 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, presents fairly, in all materialrespects, the information set forth therein.

Asdiscussed in Note 2 of the consolidated financial statements, effective January1, 2006, the Company adopted the provisions of Statement of FinancialAccounting Standards No. 123 (revised 2004) “Share Based Payment”.

Wealso have audited, in accordance with the standards of the Public CompanyAccounting Oversight Board (United States), the effectiveness of ClaytonWilliams Energy, Inc.’s internal control over financial reporting as ofDecember 31, 2006, based on criteria established in Internal Control—IntegratedFramework issued by the Committee of Sponsoring Organizations of the TreadwayCommission, and our report dated March 15, 2007, expressed an unqualifiedopinion on management’s assessment of, and the effective operations of,internal control over financial reporting.

 

KPMG LLP

Dallas, Texas

March15, 2007

F-2

----

**CLAYTON WILLIAMS ENERGY, INC.**

**CONSOLIDATED BALANCE SHEETS**

**(Dollars in thousands)**
| ** **                                                 | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                 | ** ** | **2006**              | ** ** | **2005** | ** ** |
| **ASSETS**                                                 |       |                  |       |   |   |
| CURRENT ASSETS                                             |       |                  |       |   |   |
| Cash and cash equivalents                                  |       | $                     | 13,840     |   | $ | 5,935 |   |
| Accounts receivable:                                       |       |                  |       |   |   |
| Oil and gas sales                                          |       | 23,398                |       | 28,317 |   |
| Joint interest and other, net                              |       | 17,810                |       | 6,972 |   |
| Affiliates                                                 |       | 2,436                 |       | 254 |   |
| Inventory                                                  |       | 40,392                |       | 43,753 |   |
| Deferred income taxes                                      |       | 505                   |       | 439 |   |
| Fair value of derivatives                                  |       | 23,729                |       | 191 |   |
| Prepaids and other                                         |       | 3,888                 |       | 2,581 |   |
|                                                       |       | 125,998               |       | 88,442 |   |
| PROPERTY AND  EQUIPMENT                                    |       |                  |       |   |   |
| Oil and gas properties, successful efforts method          |       | 1,226,761             |       | 1,037,862 |   |
| Natural gas gathering and processing systems               |       | 18,068                |       | 18,034 |   |
| Contract drilling equipment                                |       | 66,418                |       | — |   |
| Other                                                      |       | 15,848                |       | 12,396 |   |
|                                                       |       | 1,327,095             |       | 1,068,292 |   |
| Less accumulated depreciation, depletion and  amortization |       | (682,286              | )          | (594,225 | ) |
| Property and equipment, net                                |       | 644,809               |       | 474,067 |   |
|                                                       |       |                  |       |   |   |
| OTHER ASSETS                                               |       |                  |       |   |   |
| Debt issue costs, net                                      |       | 8,104                 |       | 8,557 |   |
| Advances to drilling rig joint venture                     |       | —                |       | 10,329 |   |
| Fair value of derivatives                                  |       | 1,785                 |       | 127 |   |
| Other                                                      |       | 14,737                |       | 5,813 |   |
|                                                       |       | 24,626                |       | 24,826 |   |
|                                                       |       | $                     | 795,433    |   | $ | 587,335 |   |

 

The accompanyingnotes are an integral part of these consolidated financial statements.

F-3

----

**CLAYTON WILLIAMS ENERGY, INC.**

**CONSOLIDATEDBALANCE SHEETS**

**(Dollars in thousands)**

|                                                                                                                                                                      | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                                                           | ** ** | **2006**              | ** ** | **2005** | ** ** |
| **LIABILITIES AND STOCKHOLDERS’ EQUITY**                                                                                                                        |       |                  |       |   |   |
| CURRENT  LIABILITIES                                                                                                                                                 |       |                  |       |   |   |
| Accounts payable:                                                                                                                                                    |       |                  |       |   |   |
| Trade                                                                                                                                                                |       | $                     | 75,815     |   | $ | 59,861 |   |
| Oil and gas sales                                                                                                                                                    |       | 14,222                |       | 18,236 |   |
| Affiliates                                                                                                                                                           |       | 1,407                 |       | 2,857 |   |
| Current maturities of long-term debt                                                                                                                                 |       | 17,397                |       | 19 |   |
| Fair value of derivatives                                                                                                                                            |       | 29,722                |       | 33,670 |   |
| Accrued liabilities and other                                                                                                                                        |       | 10,503                |       | 9,611 |   |
|                                                                                                                                                                 |       | 149,066               |       | 124,254 |   |
| NON-CURRENT  LIABILITIES                                                                                                                                             |       |                  |       |   |   |
| Long-term debt                                                                                                                                                       |       | 413,876               |       | 235,700 |   |
| Deferred income taxes                                                                                                                                                |       | 36,409                |       | 37,042 |   |
| Fair value of derivatives                                                                                                                                            |       | 21,281                |       | 49,705 |   |
| Other                                                                                                                                                                |       | 29,821                |       | 20,343 |   |
|                                                                                                                                                                 |       | 501,387               |       | 342,790 |   |
| 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 – 11,152,051 shares in 2006 and  10,815,575 shares in 2005 |       | 1,115                 |       | 1,082 |   |
| Additional paid-in capital                                                                                                                                           |       | 113,965               |       | 107,108 |   |
| Retained earnings                                                                                                                                                    |       | 29,900                |       | 12,101 |   |
|                                                                                                                                                                 |       | 144,980               |       | 120,291 |   |
|                                                                                                                                                                 |       | $                     | 795,433    |   | $ | 587,335 |   |

 

The accompanying notes are an integral part of theseconsolidated financial statements.

F-4

----

**CLAYTONWILLIAMS ENERGY, INC.**

**CONSOLIDATED STATEMENTS OF OPERATIONS**

**(In thousands, except per share)**
| ** **                                   | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                   | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| REVENUES                                     |       |                                       |       |   |   |   |   |
| Oil and gas sales                            |       | $                                          | 245,967    |   | $ | 252,599 |   | $ | 193,127 |   |
| Natural gas services                         |       | 11,327                                     |       | 12,080 |   | 9,083 |   |
| Drilling rig services                        |       | 6,937                                      |       | — |   | — |   |
| Gain on sales of property and equipment      |       | 1,767                                      |       | 18,920 |   | 4,120 |   |
| Total revenues                               |       | 265,998                                    |       | 283,599 |   | 206,330 |   |
|                                         |       |                                       |       |   |   |   |   |
| COSTS AND  EXPENSES                          |       |                                       |       |   |   |   |   |
| Production                                   |       | 63,298                                     |       | 57,404 |   | 41,163 |   |
| Exploration:                                 |       |                                       |       |   |   |   |   |
| Abandonments and impairments                 |       | 65,173                                     |       | 39,957 |   | 67,956 |   |
| Seismic and other                            |       | 11,299                                     |       | 10,780 |   | 7,124 |   |
| Natural gas services                         |       | 10,005                                     |       | 11,212 |   | 8,538 |   |
| Drilling rig services                        |       | 4,538                                      |       | — |   | — |   |
| Depreciation, depletion and amortization     |       | 66,163                                     |       | 47,509 |   | 44,040 |   |
| Impairment of property and equipment         |       | 21,848                                     |       | 18,266 |   | — |   |
| Accretion of abandonment obligations         |       | 1,653                                      |       | 1,158 |   | 1,044 |   |
| General and administrative                   |       | 16,676                                     |       | 15,410 |   | 11,689 |   |
| Loss on sales of property and equipment      |       | 99                                         |       | 209 |   | 14,337 |   |
| Other                                        |       | —                                     |       | 1,353 |   | — |   |
| Total costs and expenses                     |       | 260,752                                    |       | 203,258 |   | 195,891 |   |
| Operating income                             |       | 5,246                                      |       | 80,341 |   | 10,439 |   |
| OTHER INCOME  (EXPENSE)                      |       |                                       |       |   |   |   |   |
| Interest expense                             |       | (20,895                                    | )          | (14,498 | ) | (7,877 | ) |
| Gain (loss) on derivatives                   |       | 37,340                                     |       | (70,059 | ) | (25,329 | ) |
| Other                                        |       | (1,339                                     | )          | 4,022 |   | 1,354 |   |
| Total other income (expense)                 |       | 15,106                                     |       | (80,535 | ) | (31,852 | ) |
| Income (loss)  before income taxes           |       | 20,352                                     |       | (194 | ) | (21,413 | ) |
| Income tax  (expense) benefit                |       | (1,979                                     | )          | 451 |   | 7,385 |   |
| Minority interest,  net of tax               |       | (574                                       | )          | — |   | — |   |
| NET INCOME  (LOSS)                           |       | $                                          | 17,799     |   | $ | 257 |   | $ | (14,028 | ) |
| Net income  (loss) per common share:         |       |                                       |       |   |   |   |   |
| Basic                                        |       | $                                          | 1.64       |   | $ | .02 |   | $ | (1.37 | ) |
| Diluted                                      |       | $                                          | 1.58       |   | $ | .02 |   | $ | (1.37 | ) |
|                                         |       |                                       |       |   |   |   |   |
| Weighted average  common shares outstanding: |       |                                       |       |   |   |   |   |
| Basic                                        |       | 10,885                                     |       | 10,804 |   | 10,213 |   |
| Diluted                                      |       | 11,244                                     |       | 11,241 |   | 10,213 |   |

 

The accompanying notes are an integral part of theseconsolidated financial statements.

F-5

----

**CLAYTONWILLIAMS ENERGY, INC.**

# **CONSOLIDATEDSTATEMENTS OF STOCKHOLDERS’ EQUITY**

**(In thousands)**
| ** **                                                                   | ** ** | ** **            | ** ** | ** **     | ** ** | ** **  | ** ** | ** **        | ** ** | ** ** | ** ** |
|------------------------------------------------------------------------------|------------|-----------------------|------------|----------------|------------|-------------|------------|-------------------|------------|------------|------------|
| ** **                                                                   | ** ** | ** **            | ** ** | ** **     | ** ** | ** **  | ** ** | ** **        | ** ** | **Total**  | ** ** |
| ** **                                                                   | ** ** | **Common Stock** | ** ** | **Additional** | ** ** | ** **  | ** ** | **Comprehensive** | ** ** |
| ** **                                                                   | ** ** | **No. of**       | ** ** | **Par**        | ** ** | **Paid-In** | ** ** | **Retained**      | ** ** | **Income** | ** ** |
| ** **                                                                   | ** ** | **Shares**            | ** ** | **Value**      | ** ** | **Capital** | ** ** | **Earnings**      | ** ** | **(Loss)** | ** ** |
| BALANCE,                                                                     |       |                  |       |           |       |        |       |              |       |       |       |
| December 31, 2003                                                            |       | 9,368                 |       | $              | 937        |        | $          | 73,972            |       | $          | 25,872     |   |   |   |
| Net loss and total comprehensive loss                                        |       | —                |       | —         |       | —      |       | (14,028           | )          | $          | (14,028    | ) |
| Issuance of stock through compensation plans,  including income tax benefits |       | 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        |   |
| Issuance of stock through compensation plans,  including income tax benefits |       | 19                    |       | 3              |       | 2,164       |       | —            |       |       |       |
| Restricted stock issued as compensation                                      |       | 9                     |       | 1              |       | 270         |       | —            |       |       |       |
| BALANCE,                                                                     |       |                  |       |           |       |        |       |              |       |       |       |
| December 31, 2005                                                            |       | 10,815                |       | 1,082          |       | 107,108     |       | 12,101            |       |       |       |
| Net income and total comprehensive income                                    |       | —                |       | —         |       | —      |       | 17,799            |       | $          | 17,799     |   |
| Issuance of stock through compensation plans,  including income tax benefits |       | 337                   |       | 33             |       | 6,857       |       | —            |       |       |       |
| BALANCE,                                                                     |       |                  |       |           |       |        |       |              |       |       |       |
| December 31,  2006                                                           |       | 11,152                |       | $              | 1,115      |        | $          | 113,965           |       | $          | 29,900     |   |   |   |

 

The accompanying notesare an integral part of these consolidated financial statements.

F-6

----

**CLAYTONWILLIAMS ENERGY, INC.**

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

**(Inthousands)**
| ** **                                                                            | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                            | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| CASH FLOWS FROM  OPERATING ACTIVITIES                                                 | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net income (loss)                                                                     |       | $                                          | 17,799     |   | $ | 257 |   | $ | (14,028 | ) |
| Adjustments to reconcile net income (loss) to cash provided  by operating activities: | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Depreciation, depletion and amortization                                              |       | 66,163                                     |       | 47,509 |   | 44,040 |   |
| Impairment of property and equipment                                                  |       | 21,848                                     |       | 18,266 |   | — |   |
| Exploration costs                                                                     |       | 65,173                                     |       | 39,957 |   | 67,956 |   |
| (Gain) loss on sales of property and equipment, net                                   |       | (1,668                                     | )          | (18,711 | ) | 10,217 |   |
| Deferred income taxes                                                                 |       | 1,979                                      |       | (526 | ) | (7,645 | ) |
| Non-cash employee compensation                                                        |       | 2,279                                      |       | 2,998 |   | 536 |   |
| Unrealized (gain) loss on derivatives                                                 |       | (57,568                                    | )          | 40,406 |   | 7,104 |   |
| Settlements on derivatives with financing elements                                    |       | 29,407                                     |       | 27,731 |   | 9,890 |   |
| Amortization of debt issue costs                                                      |       | 1,308                                      |       | 2,631 |   | — |   |
| Accretion of abandonment obligations                                                  |       | 1,653                                      |       | 1,158 |   | 1,044 |   |
| Excess tax benefit on exercise of stock options                                       |       | (1,807                                     | )          | — |   | — |   |
| Minority interest, net of tax                                                         |       | 574                                        |       | — |   | — |   |
| Changes in operating working capital:                                                 |       |                                       |       |   |   |   |   |
| Accounts receivable                                                                   |       | (8,101                                     | )          | (4,764 | ) | 581 |   |
| Accounts payable                                                                      |       | 3,543                                      |       | 1,707 |   | 8,881 |   |
| Other                                                                                 |       | 3,408                                      |       | 4,856 |   | (1,596 | ) |
| Net cash provided by operating activities                                             |       | 145,990                                    |       | 163,475 |   | 126,980 |   |
| CASH FLOWS FROM  INVESTING ACTIVITIES                                                 |       |                                       |       |   |   |   |   |
| Additions to property and equipment                                                   |       | (254,840                                   | )          | (172,987 | ) | (123,991 | ) |
| Additions to equipment of Larclay JV.                                                 |       | (60,655                                    | )          | — |   | — |   |
| Investment in Southwest Royalties, Inc.                                               |       | —                                     |       | — |   | (168,204 | ) |
| Proceeds from sales of property and equipment                                         |       | 4,451                                      |       | 23,252 |   | 35,020 |   |
| Change in equipment inventory                                                         |       | (662                                       | )          | (36,519 | ) | — |   |
| Other                                                                                 |       | 1,753                                      |       | (10,411 | ) | 269 |   |
| Net cash used in investing activities                                                 |       | (309,953                                   | )          | (196,665 | ) | (256,906 | ) |
| CASH FLOWS FROM  FINANCING ACTIVITIES                                                 |       |                                       |       |   |   |   |   |
| Proceeds from long-term debt                                                          |       | 129,300                                    |       | 235,700 |   | 172,500 |   |
| Proceeds from long-term debt of Larclay JV                                            |       | 66,254                                     |       | — |   | — |   |
| Repayments of long-term debt                                                          |       | —                                     |       | (177,531 | ) | (60,530 | ) |
| Proceeds from sale of common stock                                                    |       | 3,914                                      |       | 292 |   | 30,018 |   |
| Settlements on derivatives with financing elements                                    |       | (29,407                                    | )          | (27,731 | ) | (9,890 | ) |
| Payment of debt issue costs                                                           |       | —                                     |       | (7,964 | ) | (4,156 | ) |
| Excess tax benefit on exercise of stock options                                       |       | 1,807                                      |       | — |   | — |   |
| Other                                                                                 |       | —                                     |       | — |   | 2,889 |   |
| Net cash provided by financing activities                                             |       | 171,868                                    |       | 22,766 |   | 130,831 |   |
| NET INCREASE  (DECREASE) IN CASH AND CASH EQUIVALENTS                                 |       | 7,905                                      |       | (10,424 | ) | 905 |   |
| CASH AND CASH  EQUIVALENTS                                                            |       |                                       |       |   |   |   |   |
| Beginning of period                                                                   |       | 5,935                                      |       | 16,359 |   | 15,454 |   |
| End of period                                                                         |       | $                                          | 13,840     |   | $ | 5,935 |   | $ | 16,359 |   |
| SUPPLEMENTAL  DISCLOSURES                                                             |       |                                       |       |   |   |   |   |
| Cash paid for interest, net of amounts capitalized                                    |       | $                                          | 19,653     |   | $ | 4,343 |   | $ | 7,246 |   |
| Cash paid for  income taxes                                                           |       | $                                          | 196        |   | $ | 365 |   | $ | 90 |   |

 

The accompanying notes are an integral part of theseconsolidated financial statements.

F-7

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**1.         Natureof Operations**

ClaytonWilliams Energy, Inc. (a Delaware corporation) and its subsidiaries(collectively, the “Company”) is an independent oil and gas company engaged inthe exploration for and development and production of oil and natural gasprimarily in Texas, Louisiana and New Mexico. Approximately 47% of the Company’s outstanding common stock isbeneficially owned by its Chairman of the Board and Chief Executive Officer,Clayton W. Williams (“Mr. Williams”).

Substantiallyall of the Company’s oil and gas production is sold under short-term contractswhich are market-sensitive.  Accordingly,the Company’s financial condition, results of operations and capital resourcesare highly 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.         Summaryof Significant Accounting Policies**

*Estimates and Assumptions*

Thepreparation of financial statements in conformity with accounting principlesgenerally accepted in the United States requires management of the Company tomake estimates and assumptions that affect the reported amounts of assets andliabilities and disclosure of contingent assets and liabilities at the date ofthe financial statements and the reported amounts of revenues and expensesduring the reporting period.  Actualresults could differ materially from those estimates.  The accounting policies most affected bymanagement’s estimates and assumptions are as follows:

·                               Thereliance on estimates of proved reserves to compute the provision fordepreciation, depletion and amortization, and to determine the amount of anyimpairment of proved properties;

·                              Thevaluation of unproved acreage and proved oil and gas properties to determinethe amount of any impairments of oil and gas properties;

·                              Judgmentregarding the productive status of in-progress exploratory wells to determinethe amount of any provision for abandonment; and

·                              Estimatesregarding abandonment obligations.

*Principles of Consolidation*

Theconsolidated financial statements include the accounts of Clayton WilliamsEnergy, Inc., its subsidiaries and the accounts of the Larclay JV (see Note11).  The Company accounts for itsundivided interest in oil and gas limited partnerships using the proportionateconsolidation method, whereby its share of assets, liabilities, revenues andexpenses are consolidated with other operations.  All significant intercompany transactions andbalances associated with the consolidated operations have been eliminated.

*Oil and Gas Properties*

TheCompany follows the successful efforts method of accounting for its oil and gasproperties, whereby costs of productive wells, developmental dry holes andproductive leases are capitalized into appropriate groups of properties basedon geographical and geological similarities. These capitalized costs are amortized using the unit-of-productionmethod based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and again or loss is recognized when a significant portion of an amortization baseis sold or abandoned.

Explorationcosts, including geological and geophysical expenses and delay rentals, arecharged to expense as incurred.  Exploratory drilling costs, including the costof stratigraphic test wells, are initially capitalized but charged toexploration expense if and when the well is determined to be nonproductive.  The determination of an exploratory well’sability to produce must be made within one year from the completion of drillingactivities.  The acquisition costs ofunproved acreage are initially capitalized and are carried at cost, net ofaccumulated impairment provisions, until such leases are transferred to provedproperties or charged to exploration expense as impairments of unprovedproperties.

F-8

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

*Natural Gas and Other Property and Equipment*

Naturalgas gathering and processing systems consist primarily of gas gatheringpipelines, compressors and gas processing plants.  Other property and equipment consistsprimarily of field equipment and facilities, office equipment, leaseholdimprovements and vehicles.  Majorrenewals and betterments are capitalized while the costs of repairs andmaintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicableaccumulated depreciation are removed from the accounts, and any gain or loss isincluded in other income in the accompanying consolidated statements ofoperations.

Depreciationof natural gas gathering and processing systems and other property andequipment is computed on the straight-line method over the estimated usefullives of the assets, which generally range from 3 to 12 years.

*Contract Drilling*

TheCompany consolidates the accounts of Larclay JV (see Note 11), a joint ventureengaged in contract drilling of oil and gas wells.  Larclay recognizes revenues and expenses fromdaywork drilling contracts as the work is performed, but defers revenues andexpenses from footage or turnkey contracts until the well is substantiallycompleted or until a loss, if any, on a contract is determinable.

Propertyand equipment, including major replacements, improvements and capitalizedinterest on construction-in-progress, are capitalized and are depreciated usingthe straight-line method over estimated useful lives of three to sevenyears.  Upon disposition, the costs andrelated accumulated depreciation of assets are eliminated from the accounts andthe resulting gain or loss is recognized.

*Valuation of Property and Equipment*

TheCompany follows the provisions of Statement of Financial Accounting StandardsNo. 144 “Accounting for 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 theestimated undiscounted future net cash flows of the asset are less than itscarrying value.  Any such impairment is recognizedbased on the differences in the carrying value and estimated fair value of theimpaired asset.

SFAS144 provides for future revenue from the Company’s oil and gas production to beestimated based upon prices at which management reasonably estimates suchproducts will be sold.  These estimatesof future product prices may differ from current market prices of oil andgas.  Any downward revisions tomanagement’s estimates of future production or product prices could result inan impairment of the Company’s oil and gas properties in subsequent periods.

Unprovedoil and gas properties with individually significant acquisition costs areperiodically assessed, and any impairment in value is charged to explorationcosts.  The amount of impairmentrecognized on unproved properties which are not individually significant isdetermined by amortizing the costs of such properties within appropriate groupsbased on the Company’s historical experience, acquisition dates and averagelease terms.  At December 31, 2006, theCompany’s unproved oil and gas properties had an aggregate net book value of$129.4 million, including $27 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.

*Abandonment Obligations*

TheCompany follows the provisions of Statement of Financial Accounting StandardsNo. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”), asamended.  SFAS 143 requires the Companyto recognize a liability for the present value of all legal obligationsassociated with the retirement of tangible, long-lived assets and capitalize anequal amount as a cost of the asset.  Thecost associated with the abandonment obligation, along with any estimatedsalvage value, is included in the computation of depreciation, depletion andamortization.

*Income Taxes*

TheCompany follows the asset and liability method prescribed by Statement ofFinancial Accounting Standards No. 109 “Accounting for Income Taxes” (“SFAS 109”).  Under this method of accounting for income 

F-9

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

taxes, deferredtax assets and liabilities are recognized for the future tax consequencesattributable to differences between the financial statement carrying amounts ofexisting assets and liabilities and their respective tax bases.  Deferred tax assets and liabilities aremeasured using enacted tax rates expected to apply to taxable income in theyears in which those temporary differences are expected to be recovered orsettled.  Under SFAS 109, the effect ondeferred tax assets and liabilities of a change in enacted tax rates isrecognized in income in the period that includes the enactment date.

*Hedging Activities*

Fromtime to time, the Company utilizes derivative instruments, consisting of swaps,floors and collars, to attempt to reduce its exposure to changes in commodityprices and interest rates.  The Companyaccounts for its derivatives in accordance with Statement of FinancialAccounting Standards No. 133 “Accounting for Derivative Instruments and HedgingActivities” (“SFAS 133”), as amended. SFAS 133 requires that all derivative instruments be recognized asassets or liabilities in the balance sheet, measured at fair value.  The accounting for changes in the fair valueof a derivative depends on both the intended purpose and the formal designationof the derivative.  Designation isestablished at the inception of a derivative, but subsequent changes to thedesignation are permitted.  Forderivatives designated as cash flow hedges and meeting the effectivenessguidelines of SFAS 133, changes in fair value are recognized in othercomprehensive income until the hedged item is recognized in earnings.  Hedge effectiveness is measured quarterlybased on relative changes in fair value between the derivative contract and thehedged item over time.  Any change infair value resulting from ineffectiveness is recognized immediately inearnings.  Changes in fair value ofderivative instruments which are not designated as cash flow hedges or do notmeet the effectiveness guidelines of SFAS 133 are recorded in earnings as thechanges occur.  If designated as cashflow hedges, actual gains or losses on settled commodity derivatives are recordedas oil and gas revenues in the period the hedged production is sold, whileactual gains or losses on interest rate derivatives are recorded in interestexpense for the applicable period. Actual gains or losses from derivatives not designated as cash flowhedges are recorded in other income (expense) as gain (loss) on derivatives.

*Inventory*

Inventoryconsists primarily of tubular goods and other well equipment which the Companyplans to utilize in its ongoing exploration and development activities and iscarried at the lower of cost or estimated market value.

*Capitalization of Interest*

Interestcosts associated with the Company’s inventory of unproved oil and gas propertylease acquisition costs are capitalized during the periods for whichexploration activities are in progress. During the years ended December 31, 2006, 2005 and 2004, the Companycapitalized interest totaling approximately $5.8 million, $2.2 million and$877,000, respectively.  In addition, theCompany capitalized interest relating to the construction of drilling rigs inthe Larclay JV of $1.8 million in 2006.

*Cash and Cash Equivalents*

TheCompany considers all cash and highly liquid investments with originalmaturities of three months or less to be cash equivalents.

*Net Income (Loss) Per Common Share*

Basicnet income (loss) per share is computed by dividing net income (loss) by theweighted average number of common shares outstanding for the period.  Diluted net income per share reflects thepotential dilution that could occur if dilutive stock options were exercised,calculated using the treasury stock method. The diluted net income per share calculations for 2006 and 2005 includean increase in potential shares attributable to dilutive stock options.  Stock options were not considered in thediluted net loss per share calculations for 2004 as the effect would beanti-dilutive.

*Stock-Based Compensation*

EffectiveJanuary 1, 2006, the Company adopted Statement of Financial AccountingStandards No. 123 (revised 2004) “Share-Based Payment,” (“SFAS 123R”)which requires the measurement and recognition of compensation expense for allshare-based payment awards, including employee stock options, based onestimated fair values. The value of the portion of the award that is ultimatelyexpected to vest is recognized as expense on a straight-line basis over therequisite service periods.  SFAS 123Rsupersedes the Company’s previous accounting under Accounting Principles BoardOpinion No. 25 “Accounting for Stock Issued to Employees” (“APB 25”) forperiods beginning in 2006.  The Companyadopted SFAS 123R using the modified prospective transition method, 

F-10

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

which requires theapplication of the accounting standard prospectively as of January 1, 2006and does not require restatement of previously issued financial statements.

SFAS123R requires the Company to estimate the fair value of stock option awards onthe date of grant using an option-pricing model.  The Company uses the Black-Scholesoption-pricing model (“Black-Scholes Model”) as its method of valuation forshare-based awards granted on or after January 1, 2006, which is the same modelused for the Company’s pro forma information required under SFAS 123. TheCompany’s determination of fair value of share-based payment awards on the dateof grant using an option-pricing model is affected by the Company’s stockprice, as well as assumptions regarding a number of subjective variables. Thesevariables include, but are not limited to, the Company’s expected stock pricevolatility over the term of the awards, as well as actual and projectedexercise activity.

*Revenue Recognition and Gas Balancing*

TheCompany utilizes the sales method of accounting for oil, natural gas andnatural gas liquids revenues whereby revenues, net of royalties, are recognizedas the production is sold to purchasers. The amount of gas sold may differ from the amount to which the Companyis entitled based on its revenue interests in the properties.  The Company did not have any significant gasimbalance positions at December 31, 2006 or 2005.  Revenues from natural gas services arerecognized as services are provided.

*Comprehensive Income*

Statementof Financial Accounting 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 in2006, 2005 and 2004.

*Concentration Risks*

TheCompany sells its oil and natural gas production to various customers, servesas operator in the drilling, completion and operation of oil and gas wells, andenters into derivatives with various counterparties.  When management deems appropriate, the Companyobtains letters of credit to secure amounts due from its principal oil and gaspurchasers and follows other procedures to monitor credit risk from jointowners and derivatives counterparties. Allowances for doubtful accounts at December 31, 2006 and 2005relate to amounts due from joint interest owners.

*Reclassifications*

Certainreclassifications of prior year financial statement amounts have been made toconform to current year presentations.

*Recent Accounting Pronouncements*

InSeptember 2006, the Securities and Exchange Commission issued Staff AccountingBulletin No. 108 (“SAB 108”), which becomes effective beginning onJanuary 1, 2007. SAB 108 provides guidance on the consideration of theeffects of prior period misstatements in quantifying current year misstatementsfor the purpose of a materiality assessment. SAB 108 requires an entity toevaluate the impact of correcting all misstatements, including both thecarryover and reversing effects of prior year misstatements, on current yearfinancial statements. If a misstatement is material to the current yearfinancial statements, the prior year financial statements should also becorrected, even though such revision was, and continues to be, immaterial to theprior year financial statements. Correcting prior year financial statements forimmaterial errors would not require previously filed reports to be amended.Such correction should be made in the current period filings. The adoption ofSAB 108 had no effect on the Company’s consolidated financial statements.

InSeptember 2006, the FASB issued SFAS No. 157 “Fair Value Measurements”(“SFAS 157”), which defines fair value, establishes a framework for measuringfair value in generally accepted accounting principles and expands disclosuresabout fair value measurements. This Statement applies under other accountingpronouncements that require or permit fair value measurements, the FASB havingpreviously concluded in those accounting pronouncements that fair value is therelevant measurement attribute. Accordingly, this Statement does not requireany new fair value measurements. SFAS 157 is effective for fiscal yearsbeginning after December 15, 2007. The Company plans to adopt SFAS 157beginning in the first quarter of fiscal 2008. The Company is currentlyevaluating the impact, if any, the adoption of SFAS 157 will have on itsconsolidated financial position, results of operations or cash flows.

F-11

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

EmergingIssues Task Force Issue 04-5 (“EITF 04-5”), which became effective January 1,2006, requires companies to fully consolidate any limited partnerships that thecompany controls as general partner. EITF 04-5 presumes that a sole general partner in a limited partnershipcontrols the limited partnership; however, the presumption of control can beovercome if the limited partners have (i) the substantive ability to remove thesole general partner or otherwise dissolve the limited partnership or (ii)substantive participating rights.  Forthis purpose, the EITF has concluded that a general partner lacks control ifthe limited partners can remove the general partner with a simple majorityvote.  The Company has entered intocontracts with 17 oil and gas limited partnerships of which the Company is thesole general partner.  Generally, thesecontracts require the Company to abstain from voting any of its limitedpartnership units in matters related to the removal of the Company as generalpartner.  As a result, the limitedpartners in all of the oil and gas partnerships in which the Company serves asgeneral partner can remove the Company as general partner with a simple majorityvote.  Accordingly, the Company hascontinued consolidating its proportionate share of all of these limitedpartnerships.  The adoption ofEITF 04-5 had no effect on the Company’s consolidated financialstatements.

InJune 2006, the Financial Accounting Standards Board (“FASB”) issued FASBInterpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN 48”)to clarify the manner in which enterprises account for uncertainties in theirprovisions for income taxes.  Generally,the standard presented by FIN 48 is a “more likely than not” standard andis intended to enhance the relevancy and comparability of financial reportingby companies.  FIN 48 is effectivefor fiscal years beginning after December 31, 2006.  The adoption of FIN 48 is not expectedto have a significant impact on the Company’s consolidated financialstatements.

**3.         Long-TermDebt**

Long-termdebt consists of the following:
|                                             | ** ** | **December 31,**   | ** ** | **December 31,** | ** ** |
|---------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                  | ** ** | **2006**                | ** ** | **2005**              | ** ** |
| ** **                                  | ** ** | **(In thousands)** | ** ** |
|                                        |       |                    |       |                  |       |
| 73⁄4% Senior Notes due  2013             |       | $                       | 225,000    |                  | $          | 225,000 |   |
| Secured bank credit  facility, due May 2009 |       | 140,000                 |       | 10,700                |       |
| Secured term loan of  Larclay JV            |       | 66,273                  |       | —                |       |
| Other                                       |       | —                  |       | 19                    |       |
|                                        |       | 431,273                 |       | 235,719               |       |
| Less current  maturities(a)                 |       | (17,397                 | )          | (19                   | )          |
|                                        |       | $                       | 413,876    |                  | $          | 235,700 |   |

 

----

(a)   Includes current portion of term loan of Larclay JV of $17,397 atDecember 31, 2006.

Aggregatematurities of long-term debt at December 31, 2006 are as follows:  2007 - $17.4 million; 2008 - $18.2 million;2009 - $156.6 million; 2010 - $11.6 million; 2011 -$2.5 million; and 2013 - $225 million.

*73⁄4% Senior Notes due 2013*

InJuly 2005, the Company issued, in a private placement, $225 million ofaggregate principal 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.

Atany time prior to August 1, 2008, the Company may redeem up to 35% of theaggregate principal amount of the Senior Notes with the proceeds of certainequity offerings at a redemption price of 107.75% of the principal amount, plusaccrued and unpaid interest.  Inaddition, prior to August 1, 2009, the Company may redeem some or all of theSenior Notes at a redemption price equal to 100% of the principal amount of theSenior Notes to be redeemed, plus a make-whole premium, plus any accrued andunpaid interest.  On and after August 1,2009, the Company may redeem some or all of the Senior Notes at redemptionprices (expressed as percentages of principal amount) equal to 103.875% for thetwelve-month period beginning on August 1, 2009, 101.938% for the 

F-12

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

twelve-monthperiod beginning on August 1, 2010, and 100.00% beginning on August 1, 2011,for any period thereafter, in each case plus accrued and unpaid interest.

TheIndenture governing the Senior Notes restricts the ability of the Company andits 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 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. The Company was in compliance with these covenants at December 31, 2006.

*Secured Bank Credit Facility*

TheCompany’s secured bank credit facility provides for a revolving loan facilityin an amount not to exceed the lesser of the borrowing base, as established bythe banks, or that portion of the borrowing base determined by the Company tobe the elected borrowing limit.  The borrowing base, which is based on thediscounted present value of future net revenues from oil and gas production, issubject to redetermination at any time, but at least semi-annually in May andNovember, and is made at the discretion of the banks.  If, at any time,the redetermined borrowing base is less than the amount of outstandingindebtedness, the Company will be required to (i) pledge additional collateral,(ii) prepay the excess in not more than five equal monthly installments, or(iii) elect to convert the entire amount of outstanding indebtedness to a termobligation based on amortization formulas set forth in the loanagreement.  Substantially all of the Company’s oil and gas properties arepledged to secure advances under the credit facility.  At December 31, 2006, the borrowing baseestablished by the banks was $200 million, with no monthly commitmentreductions.  After allowing for outstanding letters of credit totaling$19.8 million, the Company had $40.2 million available under thecredit facility at December 31, 2006. Subsequent to December 31, 2006, a letter of credit for$19 million was cancelled.

Therevolving credit facility provides for interest at rates based on the agentbank’s prime rate plus margins ranging from .25% to 1%, or if elected by theCompany based on 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.  Interest and fees are payable at leastquarterly.  The effective annual interestrate on borrowings under the combined credit facility, excluding bank fees andamortization of debt issue costs, for the year ended December 31, 2006 was7.4%.

Theloan agreement applicable to the revolving credit facility contains financialcovenants that are computed quarterly. The working capital covenant requires the Company to maintain a ratio ofcurrent assets to current liabilities of at least 1 to 1.  Another financial covenant under the creditfacility requires the Company to maintain a ratio of indebtedness to cash flowof no more than 3 to 1.  Thecomputations of current assets, current liabilities, cash flow and indebtednessare defined in the loan agreement.  TheCompany was in compliance with all financial and non-financial covenants atDecember 31, 2006.

*Secured Term Loan of Larclay JV*

Inconnection with the Company’s investment in Larclay JV (see Note 11), LarclayJV obtained a $75 million secured term loan facility from a lender tofinance the construction and equipping of 12 new drilling rigs.  The Larclay JV term loan is secured bysubstantially all of the assets of Larclay JV. Initially, the Company pledged additional collateral in the form of a$19 million letter of credit.  InFebruary 2007, the letter of credit was cancelled and replaced by a$19.5 million guaranty from the Company. Although the Company is not a maker on the Larclay JV term loan, ithas provided additional credit support for the Larclay JV term loan and isrequired to fully consolidate the accounts of Larclay JV under FASBInterpretation No. 46R, “Consolidation of Variable Interest Entities – orInterpretation of ARB No. 51 (as amended)” (“FIN 46R”).  At December 31, 2006, the effectiveinterest rate on the Larclay JV term loan was 8.6%.

F-13

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**4.         OtherNon-Current Liabilities**

Other non-currentliabilities at December 31, 2006 and 2005 consist of the following:
|                                | ** ** | **2006**                | ** ** | **2005** | ** ** |
|--------------------------------|------------|-------------------------|------------|----------|------------|
| ** **                     | ** ** | **(In thousands)** | ** ** |
|                           |       |                    |       |     |       |
| Abandonment  obligations       |       | $                       | 27,846     |     | $          | 19,447 |   |
| Minority  interest, net of tax |       | 1,074                   |       | —   |       |
| Other                          |       | 901                     |       | 896      |       |
|                           |       | $                       | 29,821     |     | $          | 20,343 |   |

 

*Abandonment Obligations*

Changes in abandonmentobligations for 2006 and 2005 are as follows:
|                                                    | ** ** | **2006**                | ** ** | **2005** | ** ** |
|----------------------------------------------------|------------|-------------------------|------------|----------|------------|
| ** **                                         | ** ** | **(In thousands)** | ** ** |
|                                               |       |                    |       |     |       |
| Beginning of  year                                 |       | $                       | 19,447     |     | $          | 16,147 |   |
| Additional  abandonment obligations from new wells |       | 1,074                   |       | 796      |       |
| Sales of  properties                               |       | (912                    | )          | (617     | )          |
| Accretion  expense                                 |       | 1,653                   |       | 1,158    |       |
| Abandonment  obligations related to acquisitions   |       | 98                      |       | —   |       |
| Revisions of  previous estimates                   |       | 6,486                   |       | 1,963    |       |
| End of year                                        |       | $                       | 27,846     |     | $          | 19,447 |   |

 

**5.         IncomeTaxes**

Deferred tax assets andliabilities are the result of temporary differences between the financialstatement carrying values and the tax bases of assets and liabilities.  Significant components of net deferred taxassets (liabilities) at December 31, 2006 and 2005 are as follows:
|                                                       | ** ** | **2006**                | ** ** | **2005** | ** ** |
|-------------------------------------------------------|------------|-------------------------|------------|----------|------------|
| ** **                                            | ** ** | **(In thousands)** | ** ** |
|                                                  |       |                    |       |     |       |
| Deferred tax  assets:                                 |       |                    |       |     |       |
| Net operating loss carryforwards                      |       | $                       | —     |     | $          | 2,497 |   |
| Fair value of derivatives                             |       | 8,757                   |       | 28,906   |       |
| Credits related to alternative minimum tax            |       | 418                     |       | 395      |       |
| Statutory depletion carryforwards                     |       | 4,682                   |       | 3,861    |       |
| Other                                                 |       | 7,080                   |       | 5,748    |       |
|                                                  |       | 20,937                  |       | 41,407   |       |
| Deferred tax  liabilities:                            |       |                    |       |     |       |
| Property and equipment                                |       | (56,841                 | )          | (78,010  | )          |
| Net deferred tax  liabilities                         |       | $                       | (35,904    | )        | $          | (36,603 | ) |
|                                                  |       |                    |       |     |       |
| Components of  net deferred tax assets (liabilities): |       |                    |       |     |       |
| Current assets                                        |       | $                       | 505        |     | $          | 439 |   |
| Non-current liabilities                               |       | (36,409                 | )          | (37,042  | )          |
|                                                  |       | $                       | (35,904    | )        | $          | (36,603 | ) |

 

F-14

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

For the years ended December31, 2006, 2005 and 2004, the Company’s effective income tax rates weredifferent than the statutory federal income tax rates for the followingreasons:

|                                                        | ** ** | **2006**                | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------------------------|------------|-------------------------|------------|----------|------------|----------|------------|
| ** **                                             | ** ** | **(In thousands)** | ** ** |
|                                                   |       |                    |       |     |       |     |       |
| Income tax  expense (benefit) at statutory rate of 35% |       | $                       | 7,123      |     | $          | (68      | )          | $ | (7,495 | ) |
| Tax depletion in  excess of basis                      |       | (700                    | )          | (613     | )          | (447     | )          |
| Revision of  previous tax estimates                    |       | (152                    | )          | 102      |       | (51      | )          |
| State income  taxes, net of federal tax effect         |       | (4,429                  | )          | (40      | )          | 608      |       |
| Other                                                  |       | 137                     |       | 168      |       | —   |       |
| Income tax expense (benefit)                           |       | $                       | 1,979      |     | $          | (451     | )          | $ | (7,385 | ) |
|                                                   |       |                    |       |     |       |     |       |
| Current                                                |       | $                       | 1,764      |     | $          | 75       |       | $ | 260 |   |
| Deferred                                               |       | 215                     |       | (526     | )          | (7,645   | )          |
| Income tax  expense (benefit)                          |       | $                       | 1,979      |     | $          | (451     | )          | $ | (7,385 | ) |

 

In May 2006, the State ofTexas adopted House Bill 3, which modified the state’s franchise tax structure,replacing the previous tax based on capital or earned surplus with a margin tax(the “Texas Margin Tax”) effective with franchise tax reports filed on or afterJanuary 1, 2008.  The Texas Margin Tax iscomputed by applying the applicable tax rate (1% for the Company’s businesssector) to the profit margin, which is generally determined by total revenueless either cost of goods sold or compensation, as applicable.  Although House Bill 3 states that the TexasMargin Tax is not an income tax, the Company believes that Statement ofFinancial Accounting Standards No. 109 “Accounting for Income Taxes” (“SFAS 109”)applies to the Texas Margin Tax. Accordingly, the Company has computed its consolidated deferred taxliability based on its current interpretation of the Texas Margin Tax,resulting in a reduction of deferred tax expense during 2006 of$4.4 million.

The Company derives a taxdeduction when employees and directors exercise options granted under theCompany’s stock option plans.  To theextent these tax deductions are used to reduce currently payable taxes in anyperiod, the Company records a tax benefit for the excess of the tax deductionover cumulative book compensation expense as additional paid-in capital and asa financing cash flow in the accompanying consolidated financial statements.

At December 31, 2006, theCompany’s cumulative tax loss carryforwards were approximately$2.5 million and consisted of unrecognized excess tax benefits derivedfrom stock options exercised in 2006.

**6.         Derivatives**

*Commodity Derivatives*

From time to time, theCompany 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 floortransactions, the Company receives a fixed price (put strike price) if themarket price falls below the put strike price for the respectivecommodity.  If the market price isgreater than the put strike 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 theput strike price, 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.

F-15

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

The following summarizesinformation concerning the Company’s net positions in open commodity derivativesapplicable to periods subsequent to December 31, 2006.  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 2007 |       | 454,000            |       | $         | 4.00       |   | $ | 5.18 |   | 139,000 |   | $ | 23.00 |   | $ | 25.20 |   |
| 2nd Quarter 2007 |       | 459,000            |       | $         | 4.00       |   | $ | 5.18 |   | 141,000 |   | $ | 23.00 |   | $ | 25.20 |   |
| 3rd Quarter 2007 |       | 459,000            |       | $         | 4.00       |   | $ | 5.18 |   | 141,000 |   | $ | 23.00 |   | $ | 25.20 |   |
| 4th Quarter 2007 |       | 459,000            |       | $         | 4.00       |   | $ | 5.18 |   | 141,000 |   | $ | 23.00 |   | $ | 25.20 |   |
| 2008                  |       | 1,279,000          |       | $         | 4.00       |   | $ | 5.15 |   | 392,000 |   | $ | 23.00 |   | $ | 25.07 |   |
|                  |       | 3,110,000          |       |      |       |   |   | 954,000 |   |   |   |   |   |

 

**Swaps:**
| ** **            | ** ** | **Gas**            | ** ** | **Oil**   | ** ** |
|-----------------------|------------|--------------------|------------|-----------|------------|
| ** **            | ** ** | **MMBtu (a)** | ** ** | **Price** | ** ** | **Bbls** | ** ** | **Price** | ** ** |
| Production Period:    |       |               |       |      |       |   |   |   |   |
| 1st Quarter 2007 |       | 3,000,000          |       | $         | 8.26       |   | 150,000 |   | $ | 72.75 |   |
| 2nd Quarter 2007 |       | 2,600,000          |       | $         | 8.16       |   | — |   | $ | — |   |
| 3rd Quarter 2007 |       | 2,400,000          |       | $         | 8.34       |   | 75,000 |   | $ | 72.75 |   |
| 4th Quarter 2007 |       | 2,400,000          |       | $         | 8.34       |   | 225,000 |   | $ | 72.75 |   |
| 2008                  |       | 6,300,000          |       | $         | 8.19       |   | 720,000 |   | $ | 65.60 |   |
|                  |       | 16,700,000         |       |      |       | 1,170,000 |   |   |   |

 

----

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

In January 2007, theCompany terminated certain fixed-price oil swaps covering 450,000 barrelsat a price of $55.35 per barrel, from March 2007 through August 2007, resultingin an aggregate realized gain of approximately $7.8 million, which will becollected from the counterparty monthly during 2007.

In July 2006, the Companyalso terminated certain fixed-price oil swaps covering 300,000 barrels ata price of $80.45 per barrel, from January 2007 through December 2007, resultingin an aggregate realized loss of approximately $2.4 million, which will bepaid to the counterparty monthly during 2007.

# *InterestRate Derivatives*

The Company is a party tointerest rate swaps that were acquired in connection with the acquisition of SouthwestRoyalties, Inc. in May 2004.  Under thesederivatives, the Company pays a fixed rate for the notional principal balancesand receives a floating market rate based on LIBOR.  The interest rate swaps are settledquarterly.  The following summarizes informationconcerning the Company’s net positions in open interest rate swaps applicableto periods subsequent to December 31, 2006.

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

 

F-16

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

*Accounting For Derivatives*

TheCompany accounts for its derivatives in accordance with Statement of FinancialAccounting Standards No. 133 “Accounting for Derivative Instruments andHedging Activities” (“SFAS 133”), as amended.  The Company did not designate any of itscurrently open commodity or interest rate derivatives 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 the year ended December 31, 2006,the Company reported a $37.3 million net gain on derivatives, consistingof a $57.5 million gain related to changes in mark-to-market valuationsand a $20.2 million cash charge for settled contracts.  For the year ended December 31, 2005,the net loss on derivatives was $70.1 million, consisting of a$40.4 million non-cash charge related to changes in mark-to-marketvaluations and a $29.7 million cash charge for settled contracts.

**7.        ****Financial Instruments**

Cash and cash equivalents, receivables, accountspayable and accrued liabilities were each estimated to have a fair valueapproximating the carrying amount due to the short maturity of thoseinstruments.  Indebtedness under thesecured bank credit facility was estimated to have a fair value approximatingthe carrying amount since the interest rate is generally market sensitive.  The estimated fair value of the Company’sSenior Notes at December 31, 2006 and 2005 was approximately$207.6 million and $216.8 million, respectively.

The fair values of derivatives as ofDecember 31, 2006 and 2005 are set forth below.
|                           | ** ** | **2006**                | ** ** | **2005**   | ** ** |
|---------------------------|------------|-------------------------|------------|------------|------------|
| ** **                | ** ** | **(In thousands)** | ** ** |
| Assets  (liabilities):    | ** ** | ** **              | ** ** | ** ** | ** ** |
| Commodity derivatives     |       | $                       | (25,289    | )          | $          | (82,635 | ) |
| Interest rate derivatives |       | (200                    | )          | (422       | )          |
| Net liabilities           |       | $                       | (25,489    | )          | $          | (83,057 | ) |

 

**8.         CommonStock**

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.

**9.         CompensationPlans**

*Stock-Based Compensation*

The Company has reserved1,798,200 shares of common stock for issuance under the 1993 Stock CompensationPlan (“1993 Plan”).  The 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, 2006 expire 10 years from the date of grant and become exercisablebased on varying vesting schedules.  TheCompany issues new shares, not repurchased shares, to option holders thatexercise stock options under the plans.

The Company has reserved86,300 shares of common stock for issuance under the Outside Directors StockOption Plan (“Directors Plan”).  Sincethe inception of the Directors Plan, the Company has issued options covering44,000 shares of common stock at option prices ranging from $3.25 to $41.74 pershare.  All outstanding options expire 10years from the grant date and are fully exercisable upon issuance.

F-17

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

The following table setsforth certain information regarding the Company’s stock option plans as of andfor the year ended December 31, 2006:

|                                   | ** ** | ** ** | ** ** | ** **   | ** ** | **Weighted**    | ** ** | ** **         | ** ** |
|-----------------------------------|------------|------------|------------|--------------|------------|-----------------|------------|--------------------|------------|
| ** **                        | ** ** | ** ** | ** ** | **Weighted** | ** ** | **Average**     | ** ** | ** **         | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **Average**  | ** ** | **Remaining**   | ** ** | **Aggregate**      | ** ** |
| ** **                        | ** ** | ** ** | ** ** | **Exercise** | ** ** | **Contractual** | ** ** | **Intrinsic**      | ** ** |
| ** **                        | ** ** | **Shares** | ** ** | **Price**    | ** ** | **Term**        | ** ** | **Value (a)** | ** ** |
| Outstanding at January  1, 2006   |       | 1,338,551  |       | $            | 19.53      |            |       |               |       |   |
| Granted                           |       | 4,000      |       | $            | 41.74      |            |       |               |       |   |
| Exercised (b)                     |       | (333,066   | )          | $            | 11.75      |            |       |               |       |   |
| Outstanding at December  31, 2006 |       | 1,009,485  |       | $            | 22.27      |            | 6.5        |               | $          | 14,174,163 |   |
| Vested at December 31,  2006      |       | 1,009,485  |       | $            | 22.27      |            | 6.5        |               | $          | 14,174,163 |   |
| Exercisable at December  31, 2006 |       | 1,009,485  |       | $            | 22.27      |            | 6.5        |               | $          | 14,174,163 |   |

 

----

(a)   Basedon closing price at December 31, 2006 of $36.31 per share.

(b)   Cashreceived for options exercised totaled $3.9 million and tax benefitrealized totaled $1.8 million.

The following table summarizes information withrespect to options outstanding at December 31, 2006, 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                      |       | 33,485                                                 |       | $ | 5.50 |   | 2.3 |   |
| $10.00 - $19.74            |       | 462,000                                                |       | $ | 17.49 |   | 5.3 |   |
| $22.90 - $41.74            |       | 514,000                                                |       | $ | 27.65 |   | 7.8 |   |
|                       |       | 1,009,485                                              |       | $ | 22.27 |   | 6.5 |   |

 

Prior to the adoption ofSFAS 123R, the Company accounted for options which were repriced in 1999as variable stock options under APB 25 whereby compensation expense wasrecognized through December 31, 2005 for unexercised options based onchanges in the market value of the Company’s common stock.  In accordance with SFAS 123R, theCompany ceased accounting for these options as variable stock options upon theadoption date.  The Company adoptedSFAS 123R using the modified prospective application method.  Since all of the Company’s outstandingoptions were fully vested at January 1, 2006, no future compensation expensewill be recognized for these options under SFAS 123R unless the optionsare modified, and the Company did not recognize any cumulative effect of achange in accounting principles upon adoption of SFAS 123R.

The following table presents certain informationregarding stock-based compensation amounts for the years endedDecember 31, 2006, 2005 and 2004.
| ** **                                                           | ** ** | **2006**                                                 | ** ** | **2005** | ** ** | **2004** | ** ** |
|----------------------------------------------------------------------|------------|----------------------------------------------------------|------------|----------|------------|----------|------------|
| ** **                                                           | ** ** | **(In thousands, except per share)** | ** ** |
| Weighted average grant  date fair value of options granted per share |       | $                                                        | 31.91      |     | $          | 22.81    |       | $ | 19.74 |   |
| Intrinsic value of  options exercised                                |       | $                                                        | 9,725      |     | $          | 133      |       | $ | 107 |   |
| Stock-based employee  compensation expense                           |       | $                                                        | 128        |     | $          | 1,897    |       | $ | (245 | ) |
| Tax benefit                                                          |       | $                                                        | (45        | )        | $          | (664     | )          | $ | 86 |   |
| Net stock-based employee compensation expense                        |       | $                                                        | 83         |     | $          | 1,233    |       | $ | (159 | ) |

 

F-18

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

Pro forma information, as required by Statement ofFinancial Accounting Standards No. 123 “Accounting for Stock-BasedCompensation” (“SFAS 123”), as amended by Statement of Financial AccountingStandards No. 148 (“SFAS 148”), presents net income and earnings pershare information as if the stock options issued since December 31, 1994were accounted for using the fair value method under SFAS 123.  The fair value of stock options issued foreach year was estimated at the date of grant using the Black-Scholes optionpricing model.  The following weightedaverage assumptions were used in this model.
| ** **              | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|-------------------------|------------|----------|------------|----------|------------|----------|------------|
|                    |       |     |       |     |       |     |       |
| Risk-free interest rate |       | 4.4      | %          | 3.9      | %          | 2.5      | %          |
| Stock price volatility  |       | 66       | %          | 67       | %          | 69       | %          |
| Expected life in years  |       | 10       |       | 10       |       | 10       |       |
| Dividend yield          |       | —   |       | —   |       | —   |       |

 

The SFAS 123 pro forma information for the yearended December 31, 2005 and 2004 is as follows:
|                                                                                                                      | ** ** | **2005**                                                 | ** ** | **2004** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------|------------|----------|------------|
| ** **                                                                                                           | ** ** | **(In thousands, except per share)** | ** ** |
| Net income (loss), as  reported                                                                                      |       | $                                                        | 257        |     | $          | (14,028 | ) |
| Add: Stock-based  employee compensation expense (credit) included in net income (loss), net of  tax                  |       | 1,233                                                    |       | (159     | )          |
| Deduct:  Stock-based employee compensation expense determined under fair value based method  (SFAS 123R), net of tax |       | (2,920                                                   | )          | (3,840   | )          |
| Net income (loss), pro  forma                                                                                        |       | $                                                        | (1,430     | )        | $          | (18,027 | ) |
| Basic:                                                                                                               |       |                                                     |       |     |       |
| Net income  (loss) per common share, as reported                                                                     |       | $                                                        | .02        |     | $          | (1.37 | ) |
| Net income  (loss) per common share, pro forma                                                                       |       | $                                                        | (.13       | )        | $          | (1.77 | ) |
| Diluted:                                                                                                             |       |                                                     |       |     |       |
| Net income  (loss) per common share, as reported                                                                     |       | $                                                        | .02        |     | $          | (1.37 | ) |
| Net income (loss) per  common share, pro forma                                                                       |       | $                                                        | (.13       | )        | $          | (1.77 | ) |

 

*After-PayoutIncentive Plan*

The Compensation Committee of the Board of Directorshas adopted an incentive plan for officers, key employees and consultants,excluding Mr. Williams, who promote the Company’s drilling and acquisitionprograms.  Management’s objective inadopting this plan is to further align the interests of the participants withthose of the Company by granting the participants an after-payout interest inthe production developed, directly or indirectly, by the participants.  The plan generally provides for the creationof a series of partnerships or participation arrangements (“APO Arrangements”)between the Company and the participants to which the Company contributes aportion of its economic interest in wells drilled or acquired within certainareas.  Generally, the Company pays allcosts and receives all revenues until payout of its costs, plus interest.  At payout, the participants receive 99% to100% of all subsequent revenues and pay 99% to 100% of all subsequent expensesattributable to the APO Arrangements.

Between 3% and 7.5% of the Company’s economicinterests in specified wells drilled or acquired by the Company subsequent toOctober 2002 are subject to APO Arrangements (excluding properties acquired ina merger with Southwest Royalties, Inc. in May 2004).  The Company records its allocable share ofthe assets, liabilities, revenues, expenses and oil and gas reserves of theseAPO Arrangements in its consolidated financial statements.  To date, two of these APO Arrangements haveachieved payout.  Aggregate cashdistributions of approximately $735,000 were paid to the participants duringthe year ended December 31, 2006.  TheCompany recognized $2.5 million of non-cash compensation expenseduring the year ended December 31, 2006 for the estimated fair value of the APOArrangements granted in 2006 and $680,000 in 2005.

F-19

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**10.      Transactionswith Affiliates**

The Company and other entities (the “Williams Entities”)controlled by Mr. Williams are parties to an agreement (the “ServiceAgreement”) pursuant to which the Company furnishes services to, and receivesservices from, such entities.  Under theService Agreement, the Company provides legal, payroll, benefitsadministration, and financial and accounting services to the Williams Entities,as well as technical services with respect to certain oil and gas propertiesowned by the Williams Entities.  TheWilliams Entities provide tax preparation services, tax planning services, andbusiness entertainment to or for the benefit of the Company.  The following table summarizes the charges toand from the Williams Entities for the years ended December 31, 2006, 2005 and2004.
|                                               | ** ** | **2006**                | ** ** | **2005** | ** ** | **2004** | ** ** |
|-----------------------------------------------|------------|-------------------------|------------|----------|------------|----------|------------|
| ** **                                    | ** ** | **(In thousands)** | ** ** |
| Amounts received  from the Williams Entities: |       |                    |       |     |       |     |       |
| Service Agreement:                            |       |                    |       |     |       |     |       |
| Services                                      |       | $                       | 337        |     | $          | 224      |       | $ | 314 |   |
| Insurance premiums and benefits               |       | 580                     |       | 667      |       | 691      |       |
| Reimbursed expenses                           |       | 407                     |       | 356      |       | 388      |       |
|                                          |       | $                       | 1,324      |     | $          | 1,247    |       | $ | 1,393 |   |
| Amounts paid to  the Williams Entities:       |       |                    |       |     |       |     |       |
| Rent (a)                                      |       | $                       | 619        |     | $          | 582      |       | $ | 493 |   |
| Service Agreement:                            |       |                    |       |     |       |     |       |
| Business entertainment (b)                    |       | 113                     |       | 113      |       | 113      |       |
| Other services                                |       | 150                     |       | 150      |       | 85       |       |
| Reimbursed expenses                           |       | 118                     |       | 122      |       | 105      |       |
|                                          |       | $                       | 1,000      |     | $          | 967      |       | $ | 796 |   |

 

----

(a)          Rent amounts were paid to a Partnership within theWilliams Entities.  The Company owns31.9% of the Partnership and affiliates of the Company own 23.3%.

(b)         Consists of hunting and fishing rights pertaining to land owned byaffiliates of Mr. Williams.

Accounts receivable from affiliates and accountspayable to affiliates include, among other things, amounts for customarycharges by the Company as operator of certain wells in which affiliates own aninterest.

**11.      Investments**

*West Coast Energy Properties, L.P.*

In August 2006, an affiliated partnership, WestCoast Energy Properties, L.P. (“WCEP”), acquired certain producing oil and gasassets in California and Texas for aggregate cash consideration ofapproximately $58 million. Approximately 75% of the purchase price relates to properties in threefields in southern California, and the remaining 25% relates primarily toproperties located in Mitchell County, Texas.

WCEP is a Texas limited partnership formed tofacilitate this acquisition, the general partner of which is a limitedliability company owned by the Company and the limited partner of which is anaffiliate of GE Energy Financial Services. Under the partnership agreement, the general partner contributedapproximately $6.2 million to the partnership for an initial partnershipinterest of 5%, which interest can increase to 37.63%, and ultimately to 49%,upon the achievement of certain target rates of return.

The Company financed itsequity contribution to the general partner through borrowings on its revolvingcredit facility.

*Larclay JV*

In April 2006, the Company formed a joint venture (“LarclayJV”) with Lariat Services, Inc. (“Lariat”) to construct, own and operate 12 newdrilling rigs.  The Company and Lariateach own a 50% interest in Larclay JV. The rigs are being constructed on behalf of Larclay JV by Lariat, asoperations manager.  Six of the rigs werefully constructed at December 31, 2006. Subsequently, construction on three additional rigs has beencompleted.  The remaining three rigs areexpected to be fully constructed by June 2007. The total construction cost of all rigs, excluding capitalized interest,is expected to be approximately $79 million.  A lender has provided a $75 million 

F-20

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

securedterm loan to Larclay JV to finance most of the cost of constructing andinitially equipping the rigs.  Pursuantto the term loan, the Company originally issued a $19 million letter ofcredit to the lender as additional collateral during the constructionperiod.  In February 2007, the lenderreleased the letter of credit in exchange for a $19.5 million guaranty from theCompany.  After completion of theconstruction period, outstanding advances under the term loan must not exceed75% of the appraised value of the rigs. If proceeds available to Larclay JV under the term loan are notsufficient to fully finance the cost of acquiring the rigs, the Company will berequired to loan funds to Larclay JV at the same interest rate as the termloan.  The Larclay JV term loan, asamended, bears interest at a floating rate based on a LIBOR average, plus3.25%, and provides for monthly interest payments through March 2007 andmonthly principal and interest payments thereafter sufficient to retire theprincipal balance by 35% in the first year, 25% in each of the next two years,and 15% in the fourth year.  Two voluntaryprepayments of $10 million each may be made in 2008 and 2009 without aprepayment penalty.  The Larclay JV termloan prohibits Larclay JV from making any cash distributions to the Company orLariat until the balance on the term loan is fully repaid, and repayments byLarclay JV of any loans by the Company or Lariat are subordinated to the loansoutstanding under the term loan and are subject to other restrictions.

Also in April 2006, the Company entered into athree-year drilling contract with Larclay JV assuring the availability of eachrig for use in the ordinary course of the Company’s exploration and developmentdrilling program throughout the term of the drilling contract.  The provisions of the drilling contractprovide that the Company contract for each rig on a well-by-well basis at thencurrent market rates.  If a rig is notneeded by the Company at any time during the term of the contract, Larclay JVmay contract with other operators for the use of such rig, subject to certainrestrictions.  If a rig is idle, theCompany will pay Larclay JV an idle rig rate ranging from $8,100 per day to$10,300 per day (plus crew labor expenses, if applicable), depending on thesize of the rig.  The Company’s maximumpotential obligation to pay idle rig rates over the term of this drillingcontract, excluding any crew labor expenses, totals $109 million.

Although the Company and Lariat own equal interests inLarclay JV, the Company meets the definition of the primary beneficiary ofLarclay JV’s expected cash flows under FIN 46R. As the primary beneficiary under FIN 46R, the Company is required toinclude the accounts of Larclay JV in the Company’s consolidated financialstatements.  As of December 31,2006, Lariat’s equity ownership in the net assets of Larclay JV was $1.1million, which is recorded as minority interest and included in other non-currentliabilities in the accompanying consolidated financial statements.  The Company’s intercompany accounts withLarclay JV have been eliminated in consolidation.

**12.      Commitmentsand Contingencies**

*Leases*

The Company leases officespace from affiliates and nonaffiliates under noncancelable operatingleases.  Rental expense pursuant to theoffice leases amounted to $791,000, $779,000 and $678,000 for the years ended December31, 2006, 2005 and 2004, respectively.

Future minimum paymentsunder noncancelable leases at December 31, 2006, are as follows:
|                               | ** ** | **Leases**              | ** ** | ** **    | ** ** |
|-------------------------------|------------|-------------------------|------------|---------------|------------|
| ** **                    | ** ** | **Capital (a)**    | ** ** | **Operating** | ** ** | **Total** | ** ** |
| ** **                    | ** ** | **(In thousands)** | ** ** |
| 2007                          |       | $                       | 531        |          | $          | 881 |   | $ | 1,412 |   |
| 2008                          |       | 351                     |       | 720           |       | 1,071 |   |
| 2009                          |       | 132                     |       | 700           |       | 832 |   |
| Thereafter                    |       | —                  |       | 1,464         |       | 1,464 |   |
| Total minimum  lease payments |       | $                       | 1,014      |          | $          | 3,765 |   | $ | 4,779 |   |

 

----

(a)   Relatesto vehicle leases.

*Purchase Commitments*

The Company is presentlyobligated under firm orders for two drilling rigs and related equipment in anaggregate amount of $24.5 million, for which cash deposits totaling$8.1 million have been paid to the equipment suppliers as ofDecember 31, 2006.  The total cost ofthe rigs, when completed and fully equipped, is estimated to be 

F-21

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

approximately $27 million.  The rigs are scheduled for delivery inmid-2007 and are expected to be utilized to drill the Company’s deep Bossierprospects in East Texas and North Louisiana.

In addition to the LarclayJV drilling contract discussed in Note 11, the Company has also enteredinto three drilling contracts with third party drilling contractors and isobligated to make payments under these contracts totaling $19.7 million in2007.

*Legal Proceedings*

The Company is a defendantin several lawsuits that have arisen in the ordinary course of business. Whilethe outcome of these lawsuits cannot be predicted with certainty, managementdoes not expect any of these to have a material adverse effect on the Company’sconsolidated financial condition or results of operations.

**13.      Impairmentof Property and Equipment**

The Company has recordedprovisions for impairment of proved properties under SFAS 144 of$21.8 million in 2006 and $18.3 million in 2005.  The 2006 and 2005 provisions related toproduction performance for properties in West Texas.  No impairment was deemed necessary in 2004.

The Company has alsorecorded provisions for impairment of unproved properties aggregating$12.9 million, $5.3 million and $20.4 million in 2006, 2005 and2004, respectively, and charged these impairments to exploration costs in theaccompanying statements of operations. The impairments of unproved properties recorded were based on drillingresults and management’s plans for future drilling activities.

**14.      Salesof Assets**

Gain on sale of propertyand equipment for 2006 was $1.8 million due primarily to the sale of otherproperty and equipment.  Gain on sale ofproperty and equipment for 2005 was $18.9 million.  In August 2005, the Company soldits interests in two leases in the Breton Sound area in the Gulf of Mexico(offshore Louisiana) for $21.3 million, subject to post-closingadjustments and realized a gain of $16.8 million on this sale.  Gainon sale of property and equipment for 2004 was $4.1 million, including thesale of the Jo-Mill Unit in Borden County, Texas.  Loss on sale of property and equipment for2004 was $14.3 million including the sale of the Romere Pass Unit in PlaqueminesParish, Louisiana.  UnderEITF 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No.144 in Determining Whether to Report Discontinued Operations”, the Company hasdetermined that these sales do not qualify for discontinued operationsreporting.  The Company applied theguidance of EITF 03-13 beginning in the fourth quarter of 2004.

F-22

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

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

The following table summarizesresults for each of the four quarters in the years ended December 31, 2006and 2005.
| ** **                                   | ** ** | **First**                                                | ** ** | **Second**  | ** ** | **Third**   | ** ** | **Fourth**  | ** ** | ** ** | ** ** |
|----------------------------------------------|------------|----------------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|------------|------------|
| ** **                                   | ** ** | **Quarter**                                              | ** ** | **Quarter** | ** ** | **Quarter** | ** ** | **Quarter** | ** ** | **Year**   | ** ** |
| ** **                                   | ** ** | **(In thousands, except per share)** | ** ** |
| **Year ended December 31, 2006:**            | ** ** | ** **                                               | ** ** | ** **  | ** ** | ** **  | ** ** | ** **  | ** ** | ** ** | ** ** |
| Total revenues                               |       | $                                                        | 63,394     |        | $          | 70,341      |       | $           | 66,389     |       | $          | 65,874 |   | $ | 265,998 |   |
| Operating income  (loss)                     |       | $                                                        | 10,487     |        | $          | 25,366      |       | $           | (11,476    | )          | $          | (19,131 | ) | $ | 5,246 |   |
| Net income  (loss) (a)                       |       | $                                                        | 3,376      |        | $          | 17,966      |       | $           | 5,349      |       | $          | (8,892 | ) | $ | 17,799 |   |
|                                         |       |                                                     |       |        |       |        |       |        |       |       |       |
| Net income  (loss) per common share (b):     |       |                                                     |       |        |       |        |       |        |       |       |       |
| Basic                                        |       | $                                                        | .31        |        | $          | 1.66        |       | $           | .49        |       | $          | (.81 | ) | $ | 1.64 |   |
| Diluted                                      |       | $                                                        | .30        |        | $          | 1.59        |       | $           | .48        |       | $          | (.81 | ) | $ | 1.58 |   |
|                                         |       |                                                     |       |        |       |        |       |        |       |       |       |
| Weighted average  common shares outstanding: |       |                                                     |       |        |       |        |       |        |       |       |       |
| Basic                                        |       | 10,841                                                   |       | 10,850      |       | 10,810      |       | 11,000      |       | 10,885     |       |
| Diluted                                      |       | 11,351                                                   |       | 11,286      |       | 10,810      |       | 11,000      |       | 11,244     |       |
|                                         |       |                                                     |       |        |       |        |       |        |       |       |       |
| **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     |       |

 

----

(a)                      The Company recorded a $12.9 million chargefor impairment of proved properties in the third quarter of 2006 and a $8.9million charge in the fourth quarter of 2006. The Company also recorded a $18.3 million charge for impairment ofproved properties in the fourth quarter of 2005.

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

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

The following table sets forthcertain information with respect to costs incurred in connection with theCompany’s oil and gas producing activities during the years ended December 31,2006, 2005 and 2004.
|                         | ** ** | **2006**                | ** ** | **2005** | ** ** | **2004** | ** ** |
|-------------------------|------------|-------------------------|------------|----------|------------|----------|------------|
| ** **              | ** ** | **(In thousands)** | ** ** |
| Property  acquisitions: |       |                    |       |     |       |     |       |
| Proved                  |       | $                       | 6,432      |     | $          | 5,567    |       | $ | 237,042 |   |
| Unproved                |       | 54,437                  |       | 50,238   |       | 33,826   |       |
| Developmental  costs    |       | 35,698                  |       | 42,292   |       | 27,469   |       |
| Exploratory  costs      |       | 157,509                 |       | 86,304   |       | 73,655   |       |
| Total                   |       | $                       | 254,076    |     | $          | 184,401  |       | $ | 371,992 |   |

 

F-23

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

The following table sets forththe capitalized costs for oil and gas properties as of December 31, 2006and 2005.
|                                                       | ** ** | **2006**                | ** ** | **2005**  | ** ** |
|-------------------------------------------------------|------------|-------------------------|------------|-----------|------------|
| ** **                                            | ** ** | **(In thousands)** | ** ** |
| Proved  properties                                    |       | $                       | 1,097,341  |      | $          | 957,962 |   |
| Unproved  properties                                  |       | 129,420                 |       | 79,900    |       |
| Total  capitalized costs                              |       | 1,226,761               |       | 1,037,862 |       |
| Accumulated  depreciation, depletion and amortization |       | (654,316                | )          | (570,386  | )          |
| Net capitalized  costs                                |       | $                       | 572,445    |      | $          | 467,476 |   |

 

In April 2005, the FinancialAccounting Standards Board issued Staff Position No. 19-1 (“FSP 19-1”).  FSP 19-1 amends the presentguidance in Statement of Financial Accounting Standards No. 19, paragraphs31 and 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 method of accounting. 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.  At December 31,2006 and December 31, 2005, the Company had capitalized $27 millionand $10.3 million, respectively, of exploratory drilling costs applicableto wells that were pending determination of proved reserves.  Of the $10.3 million costs atDecember 31, 2005, $1.2 million was expensed as a dry hole during theyear ended December 31, 2006 and the remaining $9.1 million wassubsequently deemed productive.

During the year ended December31, 2006, the Company recorded a provision for impairment of proved propertiesof $21.8 million compared to $18.3 million in 2005 under Statement ofFinancial Accounting Standards No. 144 “Accounting for Impairment orDisposal of Long-Lived Assets” (“SFAS 44”) due to a combination ofproduction performance and lower commodity prices.  The provision for both periods wasattributable to two areas in West Texas and one area in South Louisiana.  No provision was recorded in 2004.

**17.      Segment Information**

In accordance with Statement ofFinancial Accounting Standards No. 131, “Disclosures about Segments of anEnterprise and Related Information” (“SFAS 131”), the Company has onereportable operating segment, which is oil and gas exploration andproduction.  Beginning in 2006, theCompany formed the Larclay JV, a contract drilling joint venture that theCompany consolidates in its financial statements (see Note 11).  The contract drilling segment does not meetthe quantitative thresholds under SFAS 131 to be considered a reportableoperating segment and, accordingly, is included in “Other”.  Prior to 2006, the Company had no operatingsegments other than oil and gas exploration and production.

F-24

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

The following table presentsselected financial information regarding the Company’s operating segments for2006.
|                                                                        | ** ** | ** **                | ** ** | ** ** | ** ** | **Intercompany** | ** ** | **Consolidated** | ** ** |
|------------------------------------------------------------------------|------------|---------------------------|------------|------------|------------|------------------|------------|------------------|------------|
| **For the Year Ended December 31, 2006** | ** ** | **Oil and Gas** | ** ** | **Other**  | ** ** | **Eliminations** | ** ** | **Total**        | ** ** |
| ** **                                                             | ** ** | **(In thousands)**   | ** ** |
| Revenues                                                               |       | $                         | 259,061    |       | $          | 11,180           |       | $                | (4,243     | ) | $ | 265,998 |   |
| Depreciation,  depletion and amortization (a)                          |       | 86,887                    |       | 1,646      |       | (522             | )          | 88,011           |       |
| Other operating  expenses (b)                                          |       | 168,359                   |       | 7,100      |       | (2,718           | )          | 172,741          |       |
| Interest expense                                                       |       | 20,227                    |       | 668        |       | —           |       | 20,895           |       |
| Other (income)  expense                                                |       | (36,001                   | )          | —     |       | —           |       | (36,001          | )          |
| Income before  income taxes                                            |       | 19,589                    |       | 1,766      |       | (1,003           | )          | 20,352           |       |
| Income tax  expense                                                    |       | (1,361                    | )          | (618       | )          | —           |       | (1,979           | )          |
| Minority interest,  net of tax                                         |       | —                    |       | (574       | )          | —           |       | (574             | )          |
| Net income                                                             |       | $                         | 18,228     |       | $          | 574              |       | $                | (1,003     | ) | $ | 17,799 |   |
| Total assets                                                           |       | $                         | 720,660    |       | $          | 76,946           |       | $                | (2,173     | ) | $ | 795,433 |   |
| Additions to property  and equipment                                   |       | $                         | 261,508    |       | $          | 66,418           |       | $                | (1,003     | ) | $ | 326,923 |   |

 

----

(a)          Includes impairment ofproperty and equipment.

(b)         Includes the followingexpenses:  production, exploration,natural gas services, accretion of abandonment obligations, general andadministrative and loss on sales of property and equipment.

**18.      Guarantor Financial Information**

In July 2005, Clayton WilliamsEnergy, Inc. (“Issuer”) issued $225 million of Senior Notes (seeNote 3).  Other than West CoastEnergy Properties GP, LLC (“WCEP LLC”), the general partner of WCEP (see Note11), all of the Issuer’s wholly-owned and active subsidiaries (“GuarantorSubsidiaries”) have jointly and severally, irrevocably and unconditionallyguaranteed the performance and payment when due of all obligations under theSenior Notes.  Larclay JV, a 50%-owneddrilling rig joint venture formed in April 2006, and WCEP, LLC have notguaranteed the Senior Notes and are referred to in this Note 18 asNon-Guarantor Entities.

The financial information on thefollowing pages sets forth the Company’s condensed consolidating financialstatements as of and for the periods indicated.

F-25

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Condensed Consolidating Balance Sheet**

**December 31, 2006**

**(Dollars in thousands)**
| ** **                                       | ** ** | ** ** | ** ** | ** **       | ** ** | **Non-**      | ** ** | ** **       | ** ** | ** **       | ** ** |
|--------------------------------------------------|------------|------------|------------|------------------|------------|---------------|------------|------------------|------------|------------------|------------|
| ** **                                       | ** ** | ** ** | ** ** | **Guarantor**    | ** ** | **Guarantor** | ** ** | **Adjustments/** | ** ** | ** **       | ** ** |
| ** **                                       | ** ** | **Issuer** | ** ** | **Subsidiaries** | ** ** | **Entities**  | ** ** | **Eliminations** | ** ** | **Consolidated** | ** ** |
| ** **                                       | ** ** | ** ** | ** ** | ** **       | ** ** | ** **    | ** ** | ** **       | ** ** | ** **       | ** ** |
| Current assets                                   |       | $          | 160,772    |             | $          | 96,386        |       | $                | 11,781     |             | $          | (142,941 | ) | $ | 125,998 |   |
| Property and  equipment, net                     |       | 293,775    |       | 279,913          |       | 71,121        |       | —           |       | 644,809          |       |
| Investments in  subsidiaries                     |       | 72,171     |       | —           |       | —        |       | (72,171          | )          | —           |       |
| Other assets                                     |       | 23,638     |       | 358              |       | 630           |       | —           |       | 24,626           |       |
| Total assets                                     |       | $          | 550,356    |             | $          | 376,657       |       | $                | 83,532     |             | $          | (215,112 | ) | $ | 795,433 |   |
|                                             |       |       |       |             |       |          |       |             |       |             |       |
| Current  liabilities                             |       | $          | 89,704     |             | $          | 176,876       |       | $                | 25,427     |             | $          | (142,941 | ) | $ | 149,066 |   |
| Non-current  liabilities:                        |       |       |       |             |       |          |       |             |       |             |       |
| Long-term debt                                   |       | 365,000    |       | —           |       | 48,876        |       | —           |       | 413,876          |       |
| Fair value of derivatives                        |       | 313        |       | 20,968           |       | —        |       | —           |       | 21,281           |       |
| Other                                            |       | 10,257     |       | 55,870           |       | 103           |       | —           |       | 66,230           |       |
|                                             |       | 375,570    |       | 76,838           |       | 48,979        |       | —           |       | 501,387          |       |
|                                             |       |       |       |             |       |          |       |             |       |             |       |
| Stockholders’  equity                       |       | 85,082     |       | 122,943          |       | 9,126         |       | (72,171          | )          | 144,980          |       |
| Total  liabilities and stockholders’ equity |       | $          | 550,356    |             | $          | 376,657       |       | $                | 83,532     |             | $          | (215,112 | ) | $ | 795,433 |   |

 

**Condensed Consolidating Balance Sheet**

**December 31, 2005**

**(Dollars in thousands)**
| ** **                                       | ** ** | ** ** | ** ** | ** **       | ** ** | **Non-**      | ** ** | ** **       | ** ** | ** **       | ** ** |
|--------------------------------------------------|------------|------------|------------|------------------|------------|---------------|------------|------------------|------------|------------------|------------|
| ** **                                       | ** ** | ** ** | ** ** | **Guarantor**    | ** ** | **Guarantor** | ** ** | **Adjustments/** | ** ** | ** **       | ** ** |
| ** **                                       | ** ** | **Issuer** | ** ** | **Subsidiaries** | ** ** | **Entities**  | ** ** | **Eliminations** | ** ** | **Consolidated** | ** ** |
| ** **                                       | ** ** | ** ** | ** ** | ** **       | ** ** | ** **    | ** ** | ** **       | ** ** | ** **       | ** ** |
| Current assets                                   |       | $          | 188,007    |             | $          | 96,327        |       | $                | —     |             | $          | (195,892 | ) | $ | 88,442 |   |
| Property and  equipment, net                     |       | 195,987    |       | 278,080          |       | —        |       | —           |       | 474,067          |       |
| Investments in  subsidiaries                     |       | 65,005     |       | —           |       | —        |       | (65,005          | )          | —           |       |
| Other assets                                     |       | 24,491     |       | 335              |       | —        |       | —           |       | 24,826           |       |
| Total assets                                     |       | $          | 473,490    |             | $          | 374,742       |       | $                | —     |             | $          | (260,897 | ) | $ | 587,335 |   |
|                                             |       |       |       |             |       |          |       |             |       |             |       |
| Current  liabilities                             |       | $          | 126,299    |             | $          | 193,864       |       | $                | —     |             | $          | (195,909 | ) | $ | 124,254 |   |
| Non-current  liabilities:                        |       |       |       |             |       |          |       |             |       |             |       |
| Long-term debt                                   |       | 235,700    |       | —           |       | —        |       | —           |       | 235,700          |       |
| Fair value of derivatives                        |       | 610        |       | 49,095           |       | —        |       | —           |       | 49,705           |       |
| Other                                            |       | 8,280      |       | 49,105           |       | —        |       | —           |       | 57,385           |       |
|                                             |       | 244,590    |       | 98,200           |       | —        |       | —           |       | 342,790          |       |
|                                             |       |       |       |             |       |          |       |             |       |             |       |
| Stockholders’  equity                       |       | 102,601    |       | 82,678           |       | —        |       | (64,988          | )          | 120,291          |       |
| Total  liabilities and stockholders’ equity |       | $          | 473,490    |             | $          | 374,742       |       | $                | —     |             | $          | (260,897 | ) | $ | 587,335 |   |

 

F-26

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Condensed Consolidating Statement of Operations**

**Year Ended December 31, 2006**

**(Dollars in thousands)**
| ** **                     | ** ** | ** ** | ** ** | ** **       | ** ** | **Non-**      | ** ** | ** **       | ** ** | ** **       | ** ** |
|--------------------------------|------------|------------|------------|------------------|------------|---------------|------------|------------------|------------|------------------|------------|
| ** **                     | ** ** | ** ** | ** ** | **Guarantor**    | ** ** | **Guarantor** | ** ** | **Adjustments/** | ** ** | ** **       | ** ** |
| ** **                     | ** ** | **Issuer** | ** ** | **Subsidiaries** | ** ** | **Entities**  | ** ** | **Eliminations** | ** ** | **Consolidated** | ** ** |
| ** **                     | ** ** | ** ** | ** ** | ** **       | ** ** | ** **    | ** ** | ** **       | ** ** | ** **       | ** ** |
| Total revenue                  |       | $          | 154,159    |             | $          | 106,550       |       | $                | 11,397     |             | $          | (6,108 | ) | $ | 265,998 |   |
| Costs and  expenses            |       | 176,951    |       | 79,456           |       | 9,450         |       | (5,105           | )          | 260,752          |       |
| Operating income  (loss)       |       | (22,792    | )          | 27,094           |       | 1,947         |       | (1,003           | )          | 5,246            |       |
| Other income  (expense)        |       | 4,453      |       | 11,281           |       | (628          | )          | —           |       | 15,106           |       |
| Income tax  expense            |       | (1,979     | )          | —           |       | —        |       | —           |       | (1,979           | )          |
| Minority  interest, net of tax |       | (574       | )          | —           |       | —        |       | —           |       | (574             | )          |
| Net income  (loss)             |       | $          | (20,892    | )                | $          | 38,375        |       | $                | 1,319      |             | $          | (1,003 | ) | $ | 17,799 |   |

 

**Condensed Consolidating Statement of Operations**

**Year Ended December 31, 2005**

**(Dollars in thousands)**
| ** **               | ** ** | ** ** | ** ** | ** **       | ** ** | **Non-**      | ** ** | ** **       | ** ** | ** **       | ** ** |
|--------------------------|------------|------------|------------|------------------|------------|---------------|------------|------------------|------------|------------------|------------|
| ** **               | ** ** | ** ** | ** ** | **Guarantor**    | ** ** | **Guarantor** | ** ** | **Adjustments/** | ** ** | ** **       | ** ** |
| ** **               | ** ** | **Issuer** | ** ** | **Subsidiaries** | ** ** | **Entities**  | ** ** | **Eliminations** | ** ** | **Consolidated** | ** ** |
| ** **               | ** ** | ** ** | ** ** | ** **       | ** ** | ** **    | ** ** | ** **       | ** ** | ** **       | ** ** |
| Total revenue            |       | $          | 160,523    |             | $          | 105,927       |       | $                | —     |             | $          | (1,771 | ) | $ | 264,679 |   |
| Costs and  expenses      |       | 136,275    |       | 67,192           |       | —        |       | (1,771           | )          | 201,696          |       |
| Operating income  (loss) |       | 24,248     |       | 38,735           |       | —        |       | —           |       | 62,983           |       |
| Other income  (expense)  |       | (719       | )          | (62,458          | )          | —        |       | —           |       | (63,177          | )          |
| Income tax  expense      |       | 451        |       | —           |       | —        |       | —           |       | 451              |       |
| Net income  (loss)       |       | $          | 23,980     |             | $          | (23,723       | )          | $                | —     |             | $          | — |   | $ | 257 |   |

 

**Condensed Consolidating Statement of Operations**

**Year Ended December 31, 2004**

**(Dollars in thousands)**
| ** **               | ** ** | ** ** | ** ** | ** **       | ** ** | **Non-**      | ** ** | ** **       | ** ** | ** **       | ** ** |
|--------------------------|------------|------------|------------|------------------|------------|---------------|------------|------------------|------------|------------------|------------|
| ** **               | ** ** | ** ** | ** ** | **Guarantor**    | ** ** | **Guarantor** | ** ** | **Adjustments/** | ** ** | ** **       | ** ** |
| ** **               | ** ** | **Issuer** | ** ** | **Subsidiaries** | ** ** | **Entities**  | ** ** | **Eliminations** | ** ** | **Consolidated** | ** ** |
| ** **               | ** ** | ** ** | ** ** | ** **       | ** ** | ** **    | ** ** | ** **       | ** ** | ** **       | ** ** |
| Total revenue            |       | $          | 146,472    |             | $          | 62,651        |       | $                | —     |             | $          | (2,793 | ) | $ | 206,330 |   |
| Costs and  expenses      |       | 155,220    |       | 43,452           |       | —        |       | (2,781           | )          | 195,891          |       |
| Operating income  (loss) |       | (8,748     | )          | 19,199           |       | —        |       | (12              | )          | 10,439           |       |
| Other income  (expense)  |       | (5,769     | )          | (26,083          | )          | —        |       | —           |       | (31,852          | )          |
| Income tax  expense      |       | 7,385      |       | —           |       | —        |       | —           |       | 7,385            |       |
| Net income  (loss)       |       | $          | (7,132     | )                | $          | (6,884        | )          | $                | —     |             | $          | (12 | ) | $ | (14,028 | ) |

 

F-27

----

**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Condensed Consolidating Statement of Cash Flows**

**Year Ended December 31, 2006**

**(Dollars in thousands)**
| ** **                                            | ** ** | ** ** | ** ** | ** **       | ** ** | **Non-**      | ** ** | ** **       | ** ** | ** **       | ** ** |
|-------------------------------------------------------|------------|------------|------------|------------------|------------|---------------|------------|------------------|------------|------------------|------------|
| ** **                                            | ** ** | ** ** | ** ** | **Guarantor**    | ** ** | **Guarantor** | ** ** | **Adjustments/** | ** ** | ** **       | ** ** |
| ** **                                            | ** ** | **Issuer** | ** ** | **Subsidiaries** | ** ** | **Entities**  | ** ** | **Eliminations** | ** ** | **Consolidated** | ** ** |
| ** **                                            | ** ** | ** ** | ** ** | ** **       | ** ** | ** **    | ** ** | ** **       | ** ** | ** **       | ** ** |
| Operating  activities                                 |       | $          | 50,130     |             | $          | 65,343        |       | $                | 30,229     |             | $          | 288 |   | $ | 145,990 |   |
| Investing  activities                                 |       | (215,405   | )          | (22,007          | )          | (72,753       | )          | 212              |       | (309,953         | )          |
| Financing  activities                                 |       | 167,089    |       | (43,671          | )          | 48,950        |       | (500             | )          | 171,868          |       |
| Net increase  (decrease) in cash and cash equivalents |       | 1,814      |       | (335             | )          | 6,426         |       | —           |       | 7,905            |       |
| Cash at the  beginning of the period                  |       | 4,302      |       | 1,633            |       | —        |       | —           |       | 5,935            |       |
| Cash at end of the  period                            |       | $          | 6,116      |             | $          | 1,298         |       | $                | 6,426      |             | $          | — |   | $ | 13,840 |   |

 

**Condensed Consolidating Statement of Cash Flows**

**Year Ended December 31, 2005**

**(Dollars in thousands)**
| ** **                                            | ** ** | ** ** | ** ** | ** **       | ** ** | **Non-**      | ** ** | ** **       | ** ** | ** **       | ** ** |
|-------------------------------------------------------|------------|------------|------------|------------------|------------|---------------|------------|------------------|------------|------------------|------------|
| ** **                                            | ** ** | ** ** | ** ** | **Guarantor**    | ** ** | **Guarantor** | ** ** | **Adjustments/** | ** ** | ** **       | ** ** |
| ** **                                            | ** ** | **Issuer** | ** ** | **Subsidiaries** | ** ** | **Entities**  | ** ** | **Eliminations** | ** ** | **Consolidated** | ** ** |
| ** **                                            | ** ** | ** ** | ** ** | ** **       | ** ** | ** **    | ** ** | ** **       | ** ** | ** **       | ** ** |
| Operating  activities                                 |       | $          | 141,878    |             | $          | 21,597        |       | $                | —     |             | $          | — |   | $ | 163,475 |   |
| Investing  activities                                 |       | (154,102   | )          | (42,563          | )          | —        |       | —           |       | (196,665         | )          |
| Financing  activities                                 |       | 13,794     |       | 8,972            |       | —        |       | —           |       | 22,766           |       |
| Net increase  (decrease) in cash and cash equivalents |       | 1,570      |       | (11,994          | )          | —        |       | —           |       | (10,424          | )          |
| Cash at the  beginning of the period                  |       | 2,732      |       | 13,627           |       | —        |       | —           |       | 16,359           |       |
| Cash at end of the  period                            |       | $          | 4,302      |             | $          | 1,633         |       | $                | —     |             | $          | — |   | $ | 5,935 |   |

 

**Condensed Consolidating Statement of Cash Flows**

**Year Ended December 31, 2004**

**(Dollars in thousands)**
| ** **                                            | ** ** | ** ** | ** ** | ** **       | ** ** | **Non-**      | ** ** | ** **       | ** ** | ** **       | ** ** |
|-------------------------------------------------------|------------|------------|------------|------------------|------------|---------------|------------|------------------|------------|------------------|------------|
| ** **                                            | ** ** | ** ** | ** ** | **Guarantor**    | ** ** | **Guarantor** | ** ** | **Adjustments/** | ** ** | ** **       | ** ** |
| ** **                                            | ** ** | **Issuer** | ** ** | **Subsidiaries** | ** ** | **Entities**  | ** ** | **Eliminations** | ** ** | **Consolidated** | ** ** |
| ** **                                            | ** ** | ** ** | ** ** | ** **       | ** ** | ** **    | ** ** | ** **       | ** ** | ** **       | ** ** |
| Operating  activities                                 |       | $          | 4,317      |             | $          | 122,663       |       | $                | —     |             | $          | — |   | $ | 126,980 |   |
| Investing  activities                                 |       | (29,700    | )          | (227,206         | )          | —        |       | —           |       | (256,906         | )          |
| Financing  activities                                 |       | 13,418     |       | 117,413          |       | —        |       | —           |       | 130,831          |       |
| Net increase  (decrease) in cash and cash equivalents |       | (11,965    | )          | 12,870           |       | —        |       | —           |       | 905              |       |
| Cash at the  beginning of the period                  |       | 14,697     |       | 757              |       | —        |       | —           |       | 15,454           |       |
| Cash at end of the  period                            |       | $          | 2,732      |             | $          | 13,627        |       | $                | —     |             | $          | — |   | $ | 16,359 |   |

 

F-28

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**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**19.      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 activities for 2006, see Note 17, and for 2005and 2004, see the accompanying consolidated statements of operations.

The Company emphasizes thatreserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more currentinformation becomes available.  In addition,a portion 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 forthproved oil and gas reserves together with the changes therein (oil in MBbls,gas in MMcf, oil converted to MMcfe at six MMcf per MBbl) for the years endedDecember 31, 2006, 2005 and 2004.
| ** **                     | ** ** | **2006** | ** ** | **2005** | ** ** | **2004**  | ** ** |
|--------------------------------|------------|----------|------------|----------|------------|-----------|------------|
| ** **                     | ** ** | **Oil**  | ** ** | **Gas**  | ** ** | **MMcfe** | ** ** | **Oil** | ** ** | **Gas** | ** ** | **MMcfe** | ** ** | **Oil** | ** ** | **Gas** | ** ** | **MMcfe** | ** ** |
| Proved reserves:               |       |     |       |     |       |      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Beginning of period            |       | 27,835   |       | 126,758  |       | 293,768   |       | 26,793 |   | 138,278 |   | 299,036 |   | 10,335 |   | 62,916 |   | 124,926 |   |
| Revisions                      |       | (2,383   | )          | (14,402  | )          | (28,700   | )          | 2,193 |   | (5,333 | ) | 7,825 |   | 1,603 |   | 6,962 |   | 16,580 |   |
| Extensions and discoveries     |       | 1,367    |       | 21,204   |       | 29,406    |       | 868 |   | 12,476 |   | 17,684 |   | 3,966 |   | 23,034 |   | 46,828 |   |
| Sales of minerals-in-place     |       | —   |       | —   |       | —    |       | (101 | ) | (2,922 | ) | (3,528 | ) | (3,359 | ) | (7,967 | ) | (28,121 | ) |
| Purchases of minerals-in-place |       | 932      |       | 805      |       | 6,397     |       | 586 |   | 667 |   | 4,183 |   | 16,591 |   | 71,271 |   | 170,819 |   |
| Production                     |       | (2,370   | )          | (15,198  | )          | (29,418   | )          | (2,504 | ) | (16,408 | ) | (31,432 | ) | (2,343 | ) | (17,938 | ) | (31,996 | ) |
| End of period                  |       | 25,381   |       | 119,167  |       | 271,453   |       | 27,835 |   | 126,758 |   | 293,768 |   | 26,793 |   | 138,278 |   | 299,036 |   |
| Proved developed  reserves:    |       |     |       |     |       |      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Beginning of period            |       | 21,503   |       | 91,366   |       | 220,384   |       | 19,799 |   | 95,224 |   | 214,018 |   | 9,349 |   | 62,514 |   | 118,806 |   |
| End of period                  |       | 18,872   |       | 90,217   |       | 203,450   |       | 21,503 |   | 91,366 |   | 220,384 |   | 19,799 |   | 95,224 |   | 214,018 |   |

 

Net downward revisions of28.7 Bcfe in 2006 consisted of approximately 22 Bcfe of downwardrevisions attributable to the effects of lower natural gas prices on theestimated quantities of proved reserves and approximately 6.7 Bcfeattributable to lower well performance, primarily from properties in thePermian Basin.

The standardized measure ofdiscounted future net cash flows relating to proved reserves as ofDecember 31, 2006, 2005 and 2004 was as follows:
|                                                    | ** ** | **2006**                | ** ** | **2005**  | ** ** | **2004**  | ** ** |
|----------------------------------------------------|------------|-------------------------|------------|-----------|------------|-----------|------------|
| ** **                                         | ** ** | **(In thousands)** | ** ** |
| Future cash  inflows                               |       | $                       | 1,991,628  |      | $          | 2,910,325 |       | $ | 1,867,242 |   |
| Future costs:                                      |       |                    |       |      |       |      |       |
| Production                                         |       | (685,021                | )          | (811,529  | )          | (569,999  | )          |
| Development                                        |       | (160,264                | )          | (161,921  | )          | (119,807  | )          |
| Income taxes                                       |       | (293,870                | )          | (612,771  | )          | (336,030  | )          |
| Future net cash  flows                             |       | 852,473                 |       | 1,324,104 |       | 841,406   |       |
| 10% discount  factor                               |       | (337,673                | )          | (570,392  | )          | (341,208  | )          |
| Standardized measure of  discounted net cash flows |       | $                       | 514,800    |      | $          | 753,712   |       | $ | 500,198 |   |

 

F-29

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**CLAYTON WILLIAMS ENERGY, INC.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (Continued)**

Changes in the standardized measure of discountedfuture net cash flows relating to proved reserves for the years ended December31, 2006, 2005 and 2004 were as follows:
| ** **                                                                                                        | ** ** | **2006**                | ** ** | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|----------|------------|----------|------------|
| ** **                                                                                                        | ** ** | **(In thousands)** | ** ** |
| Standardized  measure, beginning of period                                                                        |       | $                       | 753,712    |     | $          | 500,198  |       | $ | 252,980 |   |
| Net changes in  sales prices, net of production costs                                                             |       | (356,919                | )          | 458,744  |       | 43,178   |       |
| Revisions of  quantity estimates                                                                                  |       | (76,332                 | )          | 35,741   |       | 37,629   |       |
| Accretion of  discount                                                                                            |       | 111,789                 |       | 58,095   |       | 51,870   |       |
| Changes in  future development costs, including development costs incurred that reduced  future development costs |       | 11,665                  |       | (21,368  | )          | (2,489   | )          |
| Changes in  timing and other                                                                                      |       | (37,086                 | )          | (20,024  | )          | (16,297  | )          |
| Net change in  income taxes                                                                                       |       | 174,488                 |       | (154,401 | )          | (119,605 | )          |
| Future  abandonment cost, net of salvage                                                                          |       | (7,880                  | )          | (4,657   | )          | (3,395   | )          |
| Extensions and  discoveries                                                                                       |       | 113,110                 |       | 100,302  |       | 149,680  |       |
| Sales, net of  production costs                                                                                   |       | (181,280                | )          | (195,195 | )          | (151,963 | )          |
| Sales of  minerals-in-place                                                                                       |       | —                  |       | (13,781  | )          | (56,142  | )          |
| Purchases of  minerals-in-place                                                                                   |       | 9,533                   |       | 10,058   |       | 314,752  |       |
| Standardized measure,  end of period.                                                                             |       | $                       | 514,800    |     | $          | 753,712  |       | $ | 500,198 |   |

 

The estimated present value of future cash flowsrelating to proved reserves is extremely sensitive to prices used at anymeasurement period.  The average pricesused for each commodity for the years ended December 31, 2006, 2005 and2004 were as follows:
|                     | ** ** | **Average Price** | ** ** |
|---------------------|------------|------------------------|------------|
| ** **          | ** ** | **Oil (a)**       | ** ** | **Gas** | ** ** |
| As of December  31: |       |                   |       |   |   |
| 2006                |       | $                      | 57.18      |   | $ | 5.24 |   |
| 2005                |       | $                      | 57.85      |   | $ | 10.65 |   |
| 2004                |       | $                      | 41.48      |   | $ | 5.59 |   |

 

----

(a)   Includesnatural gas liquids

F-30

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**CLAYTON WILLIAMS ENERGY, INC.**

**ScheduleII – Valuation and Qualifying Accounts**
| **Description**                                             | ** ** | **Balance at  Beginning of  Period** | ** ** | **Additions(a)** | ** ** | **Deductions(b)** | ** ** | **Balance at  End of  Period** | ** ** |
|-------------------------------------------------------------|------------|------------------------------------------------|------------|------------------|------------|-------------------|------------|------------------------------------------|------------|
| ** **                                                  | ** ** | **(In thousands)**                        | ** ** |
| **Year Ended December 31, 2006:**                           |       |                                           |       |             |       |              |       |                                     |       |
| Allowance for  doubtful accounts - Joint interest and other |       | $                                              | 1,087      |             | $          | —            |       | $                                        | (43        | ) | $ | 1,044 |   |
|                                                        |       |                                           |       |             |       |              |       |                                     |       |
| **Year Ended December 31, 2005:**                           |       |                                           |       |             |       |              |       |                                     |       |
| Allowance for  doubtful accounts - Joint interest and other |       | $                                              | 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 |   |

----

(a)            Additions relate to provisions for doubtfulaccounts.

(b)           Deductions relate to the write-off or recovery of the provisions fordoubtful accounts.

S-1

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