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EX-21 - SUBSIDIARIES OF THE REGISTRANT - CLAYTON WILLIAMS ENERGY INC /DEcwei123110_exhibit21.htm
EX-32.1 - CERTIFICATION OF CEO & CFO - CLAYTON WILLIAMS ENERGY INC /DEcwei123110exhibit32_1.htm
EX-31.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER - CLAYTON WILLIAMS ENERGY INC /DEcwei123110exhibit31_1.htm
EX-24.1 - POWER OF ATTORNEY - CLAYTON WILLIAMS ENERGY INC /DEcwei123110exhibit24_1.htm
EX-23.3 - CONSENT OF INDEPENDENT ENGINEERS - RYDER SCOTT - CLAYTON WILLIAMS ENERGY INC /DEcwei123110exhibit23_3.htm
EX-23.2 - CONSENT OF INDEPENDENT ENGINEERS - WILLIAMSON - CLAYTON WILLIAMS ENERGY INC /DEcwei123110exhibit23_2.htm
EX-23.1 - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - CLAYTON WILLIAMS ENERGY INC /DEcwei123110exhibit23_1.htm
EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER - CLAYTON WILLIAMS ENERGY INC /DEcwei123110exhibit31_2.htm
EX-99.2 - RYDER SCOTT COMPANY, L.P, - CLAYTON WILLIAMS ENERGY INC /DEryder123110exhibit99_2.htm
EX-99.1 - WILLIAMSON PETROLEUM CONSULTANTS, INC. - CLAYTON WILLIAMS ENERGY INC /DEwilliamson123110exhibit99_1.htm

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

FORM 10-K

(Mark One)
   
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
 
 
OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the fiscal year ended December 31, 2010
 

¨
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 as specified in its charter)
 
Delaware
 
75-2396863
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
Six Desta Drive - Suite 6500
   
Midland, Texas
 
79705-5510
(Address of principal executive offices)
 
(Zip code)
Registrant’s telephone number, including area code:
 
(432) 682-6324

Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Stock - $.10 Par Value
 
The NASDAQ Stock Market LLC

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act
 
¨ Yes
 
x No
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
 
¨ Yes
 
x No
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 
x Yes
 
¨ No
 

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
         
 
Large accelerated filer  ¨
 
Accelerated filer  x
 
 
Non-accelerated filer  ¨
 
Smaller reporting company ¨
 

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter.  $248,192,774.
 
There were 12,155,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of February 28, 2011.
 
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the definitive proxy statement relating to the 2011 Annual Meeting of Stockholders, which will be filed with the Commission not later than April 30, 2011, are incorporated by reference in Part III of this Form 10-K.

 
 

 

CLAYTON WILLIAMS ENERGY, INC.
TABLE OF CONTENTS

   
Page
Part I
     
Business                                                                                                  
6
 
 
General                                                                                              
6
 
 
Company Profile                                                                                              
6
 
 
Desta Drilling                                                                                              
8
 
 
Exploration and Development Activities                                                                                              
9
 
 
Marketing Arrangements                                                                                              
11
 
 
Natural Gas Services                                                                                              
11
 
 
Competition and Markets                                                                                              
12
 
 
Regulation                                                                                              
12
 
 
Environmental Matters                                                                                              
14
 
 
Title to Properties                                                                                              
16
 
 
Operational Hazards and Insurance                                                                                              
16
 
 
Operating Segments                                                                                              
17
 
 
Executive Officers                                                                                              
17
 
 
Employees                                                                                              
17
 
 
Website Address                                                                                              
17
 
       
Risk Factors                                                                                              
18
 
       
Unresolved Staff Comments                                                                                              
28
 
       
Properties                                                                                                  
28
 
 
Reserves                                                                                              
28
 
 
Delivery Commitments                                                                                              
33
 
 
Exploration and Development Activities                                                                                              
33
 
 
Productive Well Summary                                                                                              
33
 
 
Volumes, Prices and Production Costs                                                                                              
34
 
 
Development, Exploration and Acquisition Expenditures                                                                                              
34
 
 
Acreage                                                                                              
35
 
 
Desta Drilling                                                                                              
36
 
 
Offices                                                                                              
36
 
       
Legal Proceedings                                                                                                  
36
 
       
(Removed and Reserved)                                                                                                  
36
 
       
Part II
     
   
 
Issuer Purchases of Equity Securities                                                                                              
37
 
 
Price Range of Common Stock                                                                                            
37
 
 
Dividend Policy                                                                                            
37
 
 
37
 
       
Selected Financial Data                                                                                                  
38
 
       
   
 
Results of Operations                                                                                              
39
 
 
Overview                                                                                            
39
 
 
Key Factors to Consider                                                                                            
39
 
 
Proved Oil and Gas Reserves                                                                                            
40
 


 
2

 

TABLE OF CONTENTS (Continued)

   
Page
       
   
     
 
Supplemental Information                                                                                            
41
 
 
Operating Results                                                                                            
43
 
 
Liquidity and Capital Resources                                                                                            
47
 
 
Known Trends and Uncertainties                                                                                            
50
 
 
51
 
 
Adopted Accounting Pronouncements                                                                                            
54
 
       
Quantitative and Qualitative Disclosure About Market Risks                                                                                                  
55
 
 
Oil and Gas Prices                                                                                            
55
 
 
Interest Rates                                                                                            
56
 
       
Financial Statements and Supplementary Data                                                                                                  
56
 
       
   
 
Financial Disclosure                                                                                              
56
 
       
Controls and Procedures                                                                                                  
56
 
 
Disclosure Controls and Procedures                                                                                            
56
 
 
Internal Control Over Financial Reporting                                                                                            
57
 
 
Changes in Internal Control Over Financial Reporting                                                                                            
57
 
 
57
 
 
58
 
       
Other Information                                                                                                  
59
 
       
Part III
     
Information Incorporated by Reference                                                                                                  
59
 
       
Part IV
     
Exhibits and Financial Statement Schedules                                                                                                  
60
 
 
Financial Statements and Schedules                                                                                            
60
 
 
Exhibits                                                                                            
60
 
       
Glossary of Terms                                                                                                                      
65
 
     
Signatures                                                                                                                      
68
 

 
3

 

Forward-Looking Statements

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

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

·  
estimates of our oil and gas reserves;

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

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

·  
our outlook on oil and gas prices;

·  
our outlook on domestic and worldwide economic conditions;

·  
our access to capital and our anticipated liquidity;

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

·  
the impact of political and regulatory developments;

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

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

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


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

·  
the possibility of unsuccessful exploration and development drilling activities;

·  
our ability to replace and sustain production;

·  
commodity price volatility;

·  
domestic and worldwide economic conditions;

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

 
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·  
our level of indebtedness;

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

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

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

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

·  
drilling and other operating risks;

·  
hurricanes and other weather conditions;

·  
lack of availability of goods and services;

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

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

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

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

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

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

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

 
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PART I


Item 1 -                 Business


Clayton Williams Energy, Inc., incorporated in Delaware in 1991, is an independent oil and gas company engaged in the exploration for and production of oil and natural gas primarily in Texas, Louisiana and New Mexico.  Unless the context otherwise requires, references to the “Company”, “CWEI”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries.  On December 31, 2010, our estimated proved reserves were 51,065 MBOE, of which 68% were proved developed.  Our portfolio of oil and natural gas reserves is weighted in favor of oil, with approximately 74% of our proved reserves at December 31, 2010 consisting of oil and natural gas liquids and approximately 26% consisting of natural gas.  During 2010, we added proved reserves of 23,193 MBOE through extensions and discoveries, had upward revisions of 2,282 MBOE, had purchases of minerals-in-place of 349 MBOE and had sales of minerals-in-place of 2,937 MBOE.  We also achieved average net production of 15 MBOE per day in 2010, which implies a reserve life of approximately 9.4 years.  CWEI held interests in 6,789 gross (1,020.7 net) producing oil and gas wells and owned leasehold interests in approximately 1 million gross (535,000 net) undeveloped acres at December 31, 2010.

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


Company Profile

Business Strategy

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

Recent Developments

           Beginning in 2009 and continuing through 2010, we have been engaged in developmental drilling in two primary oil-prone regions, the Permian Basin and the Giddings Area located in Robertson, Burleson, Brazos, Lee, Milam, Leon, Fayette and Washington Counties, Texas.  During the first half of 2009, uncertainties in the oil and gas markets caused by the recession negatively impacted demand for field services and equipment.  We took advantage of this period of reduced demand to enter into two year term agreements with selected vendors in our core operating areas to fix unit costs covering a significant portion of our drilling and completion services that we expected to be provided by third parties.  We also acquired the noncontrolling interest in our contract drilling company, Desta Drilling, giving us full control over the management and operation of substantially all of our drilling services.  Further, we purchased significant volumes of casing and tubing at discounts to then current market prices for use in our drilling programs.
 
 
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These actions, along with continued improvements in oil prices, have provided us with what we believe is an acceptable profit margin on our investments in these core areas.
 
In the Permian Basin, we currently have eight Desta Drilling rigs and one contract rig working in Andrews County, Texas drilling vertical Wolfberry wells, which are wells that commingle production from the Wolfcamp and the Spraberry formations.  We are also working two Desta Drilling rigs in the Giddings Area in East Central Texas drilling horizontal wells in the Austin Chalk formation (see Exploration and Development Activities – Core Areas).

We are also engaged in an emerging play in the southern portion of the Delaware Basin, a portion of the Permian Basin that is currently being drilled to tap the Bone Springs/Wolfcamp formations.  We are actively leasing acreage in this area and could begin drilling operations in 2011 (see Exploration and Development Activities – Emerging Play).

Domestic Operations

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

Development Program

Our current focus is on developmental drilling.  A developmental well is a well drilled within the proved area of an oil and gas reservoir to a horizon known to be productive.  We have an inventory of developmental projects available for drilling in the future, most of which are located in the oil-prone regions of the Permian Basin and the Giddings Area.  In most cases, our leasehold interests in developmental projects are held by the continuous production of other wells, meaning that our rights to drill these projects are not subject to near-term expiration.  This provides us with a high degree of flexibility in the timing of developing these reserves.  Consistent with our business strategy, approximately $362.1 million, or 95% of our planned expenditures for 2011 relate to developmental drilling, most of which are in oil-prone areas.

Exploration Program

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

To generate a typical exploratory prospect, we first identify geographical areas that we believe may contain undiscovered oil and gas reserves.  We then consider many other business factors related to those geographical areas, including proximity to our other areas of operations, our technical knowledge and experience in the area, the availability of acreage, and the overall potential for finding reserves.  Most of our current exploration efforts are concentrated in regions that have been known to produce oil and gas.  These regions include some of the larger producing regions in Texas and Louisiana.

In most cases, we then obtain and process seismic data using sophisticated geophysical technology to attempt to visualize underground structures and stratigraphic traps that may hold recoverable reserves.  Although this technology increases our expectations of a successful discovery, it does not and cannot assure us of success.  Many factors are involved in the interpretation of seismic data, including the field recording parameters of the data, the type of processing, the extent of attribute analyses, the availability of subsurface geological data, and the depth and complexity of the subsurface.  Significant judgment is required in the evaluation of seismic data, and differences of opinion often exist between experienced professionals.  These interpretations may turn out to be invalid and may result in unsuccessful drilling results.

Obtaining oil and gas reserves through exploration activities involves a higher degree of risk than through drilling developmental wells or purchasing proved reserves.  We often commit significant resources to identify a prospect, lease the drilling rights and drill a test well before we know if a well will be productive.  To offset this risk, our typical exploratory prospect is expected to offer a significantly higher reserve potential than a typical lower risk development prospect might offer.  The reserve potential is determined by estimating the aerial extent of the structural or stratigraphic trap, the vertical thickness of the reservoir in the trap, and the recovery factor of the hydrocarbons in the trap.  The recovery factor is affected by a combination of factors including (1) the reservoir drive mechanism (water
 
 
 
7

 
 
drive, depletion drive or a combination of both), (2) the permeability and porosity of the reservoir, and (3) the bottom hole pressure (in the case of gas reserves).

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

Many of our exploration activities, particularly those related to our Bossier prospects in the Giddings Area and our prospects in South Louisiana, target gas reserves.  Since we believe gas prices are likely to be less favorable than oil prices in the near term, we currently plan to spend only $19.7 million on exploration activities in 2011.

Acquisition and Divestitures of Proved Properties

In addition to our exploration and development activities, we seek to acquire proved reserves, but competition for the purchase of proved reserves is intense.  Sellers often utilize a bid process to sell properties.  This process usually intensifies the competition and makes it extremely difficult for us to acquire reserves without assuming significant price and production risks.  During the second quarter of 2010, we acquired from a group of private investors an undivided 14% working interest in 36 Wolfberry operated wells in Andrews County, Texas for $9.6 million, after customary closing adjustments.  This purchase increased our working interest in these 36 wells to 100%.  We are actively searching for opportunities to acquire proved oil and gas properties, but we cannot give any assurance that we will be successful in our efforts to acquire proved properties in 2011.

From time to time, we sell certain of our proved properties when we believe it is more advantageous to dispose of the selected properties than to continue to hold them.  We consider many factors in deciding to sell properties, including the need for liquidity, the risks associated with continuing to own the properties, our expectations for future development on the property, the fairness of the price offered, and other factors related to the condition and location of the property.  In June 2010, we sold our interests in 22 operated and 76 non-operated producing wells in North Louisiana for net proceeds of $73.1 million, and in August 2010, we sold our interest in one non-operated well and related leasehold interests in North Louisiana for net proceeds of $2.9 million.  The assets sold in these transactions represented substantially all of our proved oil and gas properties in North Louisiana.

Desta Drilling

In 2006, we formed a drilling rig joint venture with Lariat Services, Inc. (“Lariat”).  Initially, we referred to this joint venture as Larclay JV, but in June 2009, we changed the legal name of the operating entity in the joint venture to Desta Drilling, LP (“Desta Drilling”).  Lariat was designated as the operator of the rigs and provided all management services on behalf of Desta Drilling.  To permit Desta Drilling to finance the construction of 12 drilling rigs and related equipment, we provided credit support in the form of (1) a limited guaranty to the secured lender in the original amount of $19.5 million, (2) a drilling contract with Desta Drilling that expired in 2009 under which we were obligated to use the drilling rigs or pay idle rig rates, and (3) a subordinated loan to Desta Drilling of $4.6 million to finance excess construction costs.  During the term of the drilling contract, we paid Desta Drilling $24.4 million in idle rig fees.  We and Lariat also made cash advances to Desta Drilling in the form of subordinated loans of $7.5 million each to provide additional financial support.

We and Lariat each owned a 50% equity interest in Desta Drilling, but effective April 15, 2009, we entered into an agreement with Lariat whereby Lariat assigned to us their 50% equity interest  (the “Assignment”).  The Assignment from Lariat also included all of Lariat’s right, title and interest in the subordinated loans previously made by Lariat to Desta Drilling.  As consideration for the Assignment, CWEI assumed all of the obligations and liabilities of Lariat relating to Desta Drilling from and after the effective date, including Lariat’s obligations as operator of Desta Drilling’s rigs.  Upon consummation of the Assignment, CWEI contributed all of the subordinated loans to Desta Drilling’s capital.  In August 2009, we repaid in full all amounts outstanding under the secured term loan of Desta Drilling with borrowings of approximately $27.2 million under our revolving credit facility.

In April 2009, we adopted a plan of disposition to sell eight of the 12 drilling rigs then owned by Desta Drilling.  As a result, we recorded a $32.1 million impairment of property and equipment during the second quarter of 2009 to write-down the rigs to their estimated fair value of $18.8 million.  In December 2009, we modified the plan of disposition.  Based on significant improvements in oil prices, we escalated our developmental drilling program and put six of the drilling rigs previously held for sale back to work and transferred their estimated fair value of $11.4 million to property and equipment.  In the accompanying consolidated balance sheets at December 31, 2010 and December 31, 2009, assets held for sale were $8.8 million and $7.4 million, respectively.  In February 2011, we sold two 2,000 horsepower drilling rigs and related equipment for $22 million of total consideration, and expect to record a
 
 
 
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gain on the sale of approximately $13.2 million during the first quarter of 2011.  Proceeds from the sale consisted of $11 million cash and an $11 million promissory note due in August 2011.
 
In December 2010, Desta Drilling purchased two additional drilling rigs to increase its fleet to 12 operating rigs.

Exploration and Development Activities

Overview
Since the second quarter of 2009, we have been primarily committed to drilling developmental oil wells in the Permian Basin and the Austin Chalk.  We currently plan to spend approximately $381.8 million on exploration and development activities during fiscal 2011.  Approximately 95% of the estimated expenditures for fiscal 2011 are expected to be spent on developmental drilling.  We may increase or decrease our planned activities, depending upon drilling results, operating margins, the availability of capital resources, and other factors affecting the economic viability of such activities.

Core Areas

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

We spent $176.4 million in the Permian Basin during fiscal 2010 on drilling and completion activities and $13.6 million on seismic and leasing activities.  In addition, we spent $9.6 million to acquire an undivided 14% working interest in 36 Wolfberry operated wells in Andrews County, Texas.  We drilled 116 gross (109 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during fiscal 2010.  We currently plan to spend approximately $295.3 million on drilling, completion and leasing activities during fiscal 2011.  Following is a discussion of our principal assets in the Permian Basin.

Wolfberry
Our primary focus in the Permian Basin is the drilling of Wolfberry wells in the Midland Basin.  Wolfberry is a term applied to the combined production from the Spraberry and Wolfcamp formations, which are generally found at depths from 7,500 to 10,500 feet.  These formations are comprised of a sequence of basinal, interbedded shales and carbonates.  We have over 20,000 net acres in Andrews County, Texas on which we have drilled more than 130 wells to date and have identified more than 200 additional drill sites, 67 of which are classified as proved undeveloped locations as of December 31, 2010.  We spent approximately $145 million on Wolfberry drilling and completion activities during fiscal 2010, and currently plan to use eight Desta Drilling rigs and one or more contract rigs through August 2011 and five rigs through the remainder of 2011 to drill and complete over 150 Wolfberry wells during fiscal 2011 at an estimated cost of $266.5 million, net to our working interest.

Fuhrman-Mascho Field
We also resumed a drilling program in the Fuhrman-Mascho Field in Andrews County, Texas beginning in July 2009.  Wells in the Fuhrman-Mascho Field produce from the San Andres formation, a reservoir comprised of fractured carbonate sediments found at a depth of approximately 4,300 feet.  We drilled and completed six wells in this area during fiscal 2010, and currently plan to drill eight additional wells during fiscal 2011.

New Mexico
We currently plan to drill additional development wells in Eddy County, New Mexico targeting the Yeso, San Andres and Grayburg formations.  The San Andres-Grayburg is a mixed clastic and carbonate reservoir from 2,300 to 3,800 feet in the Loco Hills area of New Mexico.  The Yeso is a dolomite formation found from 3,800 to 4,200 feet. We plan to drill 19 developmental wells in this area during fiscal 2011.

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

Giddings Area
Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Giddings Area.  Most of our wells in the Giddings Area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations.  Hydrocarbons are also encountered in the Giddings Area from other formations, including the Cotton Valley, Bossier and Eagle Ford Shale.  In 2010, we spent approximately $58.5 million on Austin Chalk/Eagle Ford Shale drilling and completion and currently plan to spend approximately $46.9 million on similar drilling activities in this area in 2011.  Following is a discussion of our principal assets in the Giddings Area.

Austin Chalk
We have concentrated our recent drilling activities in the Giddings Area on the Austin Chalk formation, an upper Cretaceous geologic formation in the Gulf Coast region of the United States that stretches across numerous fields in Texas and Louisiana.  The Austin Chalk formation is generally encountered at depths of 5,500 to 7,000 feet.  Horizontal drilling is the primary technique used in the Austin Chalk formation to enhance productivity by intersecting multiple zones.  Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations.  The existing spacing between some of our wells in this area affords us the opportunity to tap additional oil and gas reserves by drilling new wells between existing wells, a technique referred to as in-fill drilling.  These in-fill wells are considered lower risk as compared to exploratory wells.  We are currently working two of our drilling rigs in the Giddings Area to drill dual opposed or dual stacked lateral horizontal wells in the Austin Chalk, and intermittently drilling wells in the Eagle Ford Shale.

Eagle Ford Shale
The Eagle Ford Shale is a formation immediately beneath the Austin Chalk formation.  In February 2010, we completed our first Eagle Ford Shale well, the Broesche Unit #1 in Burleson County.  This well was drilled to a total vertical depth of 7,580 feet with a 4,880 foot lateral and was completed with a nine stage frac.  In June 2010, we completed the Smalley-Robinson Unit #1 in Burleson County which was drilled to total vertical depth of 7,020 feet with a 5,500 foot lateral and was completed with a 13 stage frac.  In October 2010, we completed the Scallions-Lehmann #1 in Lee County, which was drilled to a total vertical depth of 7,665 feet with a 5,210 foot lateral and was completed with a one stage frac.  In December 2010, we drilled the Loebau Unit #1 in Lee County well to a total vertical depth of 7,911 feet with a 4,967 foot lateral and completed with a three stage frac.  To date, our Eagle Ford Shale results have not met our expectations.  None of the completion techniques that we have tried thus far have been effective in unlocking the large volumes of oil that we believe exist in this portion of the Eagle Ford Shale play.  We plan to continue searching for a completion technique that will make a multi-well drilling program economically viable.

Deep Bossier
We have an extensive acreage position in the Giddings Area that is also prospective for Deep Bossier sands which are encountered at depths ranging from 14,000 to 22,000 feet.  Exploration for Deep Bossier gas sands in this area involves a high degree of risk.  The geological structures are complex, very little subsurface control exists, and wells are expensive to drill.  Although seismic data is helpful in identifying possible sand accumulations, the only way to determine whether the Deep Bossier sand will be commercially productive is to drill wells to the targeted structures.  In fiscal year 2011, we currently plan to drill the Hamill #1, an exploratory well which is an offset to our previously drilled Big Bill Simpson #1.  We believe that the reserve potential from this well justifies the exploration risks despite current price levels of natural gas.


 
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Emerging Play
 
Delaware Basin – Bone Springs/Wolfcamp
We are actively acquiring acreage in the emerging Bone Springs/Wolfcamp play (“Wolfbone”) located in the Delaware Basin on the western edge of the Permian Basin.  A Wolfbone well is a well that commingles production from the Bone Springs and Wolfcamp formations which are typically encountered at depths of 8,000 to 13,000 feet.  These Permian aged formations in the Delaware Basin are comprised of limestone and sandstone.  We spent approximately $8.9 million for leasing activities in the Wolfbone play during fiscal 2010 and expect to spend at least an additional $9 million in 2011.  To date, we have accumulated approximately 17,000 net acres.
 
South Louisiana
In the first quarter of 2010, we successfully drilled and completed the State Lease 17378 #4, a developmental well in Plaquemines Parish, Louisiana.  During the second quarter of 2010, we also drilled and are currently completing the State Lease 19964 #1, an exploratory well in Plaquemines Parish.  In December 2010, we drilled the State Lease 19720 #1 as a producer and are currently waiting on pipeline connections.  We plan to spend $3.8 million in fiscal 2011 in connection with drilling and completion activities in South Louisiana.

Known Trends and Uncertainties
During the first quarter of 2010, we drilled a commercial step-out well in Lee County, Texas to determine the viability of expanding our Austin Chalk developmental drilling program to the southwest of our core properties where the number of drilling locations was limited.  This commercial step-out well was drilled approximately ten miles west of the nearest producing Austin Chalk well. Based on our evaluation of this well, we now believe that we will be able to extend our Austin Chalk drilling program into 2011 and subsequent years.  In addition, we are continuing efforts to identify other opportunities for growth in the Austin Chalk area, including the addition of reserves and production through improved technology, acquisitions of proved reserves, and participation agreements with industry partners.

Our Wolfberry developmental drilling program is very sensitive to oil prices and drilling costs.  We believe that the steps we have taken to fix unit costs with selected service providers, improve drilling efficiencies through the use of Desta Drilling’s rigs and crews, and purchase casing and tubing at discounts to current market prices, will enable us to continue drilling in this area through mid-year 2011 as long as oil prices remain favorable.  In order to continue drilling in this area, we must be able to realize an acceptable margin between our expected cash flow from new production and our cost to drill new wells.  If any combination of falling oil prices and rising drilling costs occur in future periods, we may not be able to continue developmental drilling in this area.

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

Marketing Arrangements

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

Natural Gas Services

We own an interest in and operate natural gas service facilities in the states of Texas, Louisiana, Mississippi and New Mexico. These natural gas service facilities consist of interests in approximately 108 miles of pipeline, four treating plants, one dehydration facility, and seven wellhead type treating and/or compression stations.  Most of our operated gas gathering and treating activities exist to facilitate the transportation and marketing of our operated oil and gas production.


 
 
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Competition and Markets

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

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

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


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

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

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

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

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

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

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

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

FERC has issued certain market transparency rules for the natural gas industry pursuant to its EP Act 2005 authority, which may affect some or all of our operations.  FERC issued a final rule in 2007, as amended by subsequent orders on rehearing (“Order 704”), which requires wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including natural gas producers, gatherers, processors, and marketers, to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices, as explained in the order. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704.  In addition, on November 20, 2008, FERC issued a final rule pursuant to its EP Act 2005 authority regarding daily scheduled flows and capacity posting requirements, as amended by a subsequent order on rehearing (“Order 720”).  Under Order 720, certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous three calendar years, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu per day.  Over the previous three calendar years, we have delivered, on average, less than 50 million MMBtu of gas, and therefore we believe that we are currently exempt from Order 720.

Gathering regulations.  Section 1(b) of the federal Natural Gas Act (“NGA”) exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA.  We own certain natural gas pipelines that we believe meet the traditional tests that the FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction.  The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities is, however, the subject of substantial, on-going litigation, so the classification and regulation of our gathering lines may be subject to change based on future determinations by the FERC, the courts or the U.S. Congress.
 
State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation.  Our gathering operations are also subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another.  The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas.  In addition, our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner materially differently than other companies in our areas of operation.

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

We believe that we are in substantial compliance with current applicable environmental laws and regulations, and the cost of compliance with such laws and regulations has not been material and is not expected to be material during 2011.  We do not believe that we will be required to incur material capital expenditures to comply with existing environmental requirements.  Nevertheless, changes in existing environmental laws and regulations or in the interpretations thereof could have a significant impact on our operations, as well as the oil and gas industry in general.  For instance, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or clean-up requirements could have an adverse impact on our operations.

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

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


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

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

Global Warming and Climate Change.  In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.  The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011.  The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules.  The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.
 
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.  Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

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

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

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

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

Title to Properties

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

Operational Hazards and Insurance

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

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


 
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Operating Segments

For financial information about our operating segments, see Note 16 to the accompanying consolidated financial statements.

Executive Officers

The following is a list, as of February 28, 2011 of the name, age and position with the Company of each person who is an executive officer of the Company:

CLAYTON W. WILLIAMS, JR., age 79, is Chairman of the Board, President, Chief Executive Officer and a director of the Company, having served in such capacities since September 1991.  For more than the past five years, Mr. Williams has also been the chief executive officer and a director of certain entities which are controlled directly or indirectly by Mr. Williams.  Mr. Williams beneficially owns, either individually or through his affiliates, approximately 26% of the outstanding shares of our common stock.
 
MEL G. RIGGS, age 56, is Executive Vice President and Chief Operating Officer of the Company, having served in such capacities since January 2011.  Prior to that, Mr. Riggs had served as Senior Vice President - Finance and Chief Financial Officer of the Company since 1991.  Mr. Riggs has served as a director of the Company since May 1994.
 
MICHAEL L. POLLARD, age 60, is Senior Vice President – Finance and Chief Financial Officer of the Company, having served in such capacity since January 2011.  Prior to that, Mr. Pollard had served as Vice President - Accounting of the Company since 2003.
 
PATRICK C. REESBY, age 58, is Vice President – New Ventures of the Company, having served in such capacity since 1993.
 
ROBERT C. LYON, age 74, is Vice President – Gas Gathering and Marketing of the Company, having served in such capacity since 1993.
 
T. MARK TISDALE, age 54, is Vice President and General Counsel of the Company, having served in such capacity since 1993.
 
GREGORY S. WELBORN, age 37, is Vice President – Land of the Company, having served in such capacity since 2006.  Prior to that, Mr. Welborn was self-employed.  Mr. Welborn is the son-in-law of Clayton W. Williams, Jr.
 
ROBERT L. THOMAS, age 54, is Vice President – Accounting of the Company, having served in such capacity since January 2011.  Prior to that, Mr. Thomas had served as General Accounting Manager of the Company since 2003.
 


At December 31, 2010, we had 437 full-time employees, of which 219 were employed by Desta Drilling.  None of our employees are subject to a collective bargaining agreement.  In our opinion, relations with employees are good.

Website Address

We maintain an internet website at www.claytonwilliams.com.  We make available, free of charge, on our website, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the Securities and Exchange Commission (“SEC”).  The information contained in or incorporated in our website is not part of this report.


 
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Item 1A -                      Risk Factors

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

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

    Our revenues, operating results, liquidity, cash flows, profitability and value of proved reserves depend substantially upon the market prices of oil and natural gas.  Product prices affect our cash flow available for capital expenditures and our ability to access funds under our revolving credit facility and through the capital markets.  The amount available for borrowing under our revolving credit facility is subject to a borrowing base, which is determined at least semi-annually by our lenders taking into account the estimated value of our proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. The decline in oil and natural gas prices in 2009 impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base.  If commodity prices decline in the future, the decline could have adverse effects on our reserves and borrowing base.

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

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

·  
market uncertainty;

·  
the level of consumer product demands;

·  
hurricanes and other weather conditions;

·  
domestic governmental regulations and taxes;

·  
the price and availability of alternative fuels;

·  
political and economic conditions in oil producing countries;

·  
the foreign supply of oil and natural gas;

·  
the price of oil and gas imports; and

·  
overall domestic and foreign economic conditions.

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

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

    In general, the volume of production from an oil and gas property declines as reserves related to that property are depleted. The decline rates depend upon reservoir characteristics. Historically, our oil and gas properties have had steep rates of decline and short estimated productive lives. The implied life of our proved reserves at December 31, 2010 is approximately 9.4 years, based on 2010 production levels.

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

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

    Our business is capital intensive and requires us to spend substantial amounts of capital for exploration and development activities.  If low oil and natural gas prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to internally fund our exploration and development activities, and if our borrowing base under the revolving facility is redetermined to a lower amount, this could adversely affect our ability to supplement cash flow from operations as a source of funding for these activities.  After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot give assurance that additional debt or equity financing will be available or cash flows provided by operations will be sufficient to meet these requirements.

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

    As of December 31, 2010, the principal amount of our outstanding consolidated debt was approximately $385 million, which included approximately $160 million outstanding under our revolving credit facility and $225 million in outstanding principal amount of our 7¾% Senior Notes due 2013.  Our revolving credit facility and the Indenture governing our 7¾% Senior Notes due 2013 impose significant restrictions on our ability to take certain actions, including our ability to incur additional indebtedness, sell certain assets or merge, make investments or loans, issue redeemable or preferred stock, pay distributions or dividends, create liens, guarantee other indebtedness and enter into new lines of business.

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

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

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

·  
limit our access to the capital markets;

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

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

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

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

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

 
 
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A financial crisis may impact our business and financial condition and it may adversely impact our ability to obtain funding under our revolving credit facility or in the capital markets.

    The credit crisis and related turmoil in the global financial systems during the past three years have had an impact on our business and our financial condition. An economic recession could reduce the demand for oil and natural gas and put downward pressure on the prices for oil and natural gas.  Historically, we have used our cash flow from operations and borrowings under our revolving credit facility to fund our capital expenditures.  In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (1) a decrease in our borrowing base due to the outcome of a borrowing base redetermination, or (2) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations.  In addition, we may face limitations on our ability to access the debt and equity capital markets and complete asset sales, and an increased counterparty credit risk on our derivatives contracts.

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

    To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we have entered into and may in the future enter into hedging transactions for a significant portion of our expected oil and gas production.  These transactions could result in both realized and unrealized hedging losses.
   
    The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities.  For example, the derivative instruments we utilize are primarily based on NYMEX futures prices, which may differ significantly from the actual crude oil and gas prices we realize in our operations.  Furthermore, we have adopted a policy that requires, and our credit facility also mandates, that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we will continue to have direct commodity price exposure on the portion of our production volumes not covered by these derivative transactions.

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

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

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

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

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

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


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

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

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

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

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

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

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

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

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


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

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

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

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

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

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

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

·  
unexpected drilling conditions;

·  
title problems;

·  
pressure or irregularities in formations;

·  
equipment failures or accidents;

·  
adverse weather conditions;

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

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

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

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

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

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

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

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

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

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

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

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

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

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


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

    We have never paid any cash dividends on our common stock and our Board of Directors does not currently anticipate paying any cash dividends to our stockholders in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Covenants contained in our revolving credit facility and the Indenture governing our 7¾% Senior Notes due 2013 restrict the payment of dividends. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.

Our industry is highly competitive.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future.  Failure to comply with extensive applicable environmental laws and regulations could result in significant civil or criminal penalties and remediation costs.  Some of our properties, including properties in which we have an ownership interest but no operating control, may be affected by environmental contamination that may require investigation or remediation.  Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas.  Some of our operations are in areas particularly susceptible to damage by hurricanes or other destructive storms, which could result in damage to facilities and discharge of pollutants.  In addition, claims are sometimes made or threatened against companies engaged in oil and gas exploration and production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation, and such claims have been asserted against us as well as companies we have acquired.  Compliance with, and liabilities for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our business, financial condition and results of operations.
 
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of proposed legislation.

    Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies.  These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures.  It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective.  The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact the value of an investment in our common stock.
 
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

    In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.  The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011.  The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules.  The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

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


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

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

    The U.S. Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.  The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment.  In its rulemaking under the Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents.  Certain bona fide hedging transactions or positions would be exempt from these position limits.  It is not possible at this time to predict when the CFTC will finalize these regulations.  The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time.  The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.  The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties.  If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.  Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas.  Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.  Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

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

    Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations.  We routinely utilize hydraulic fracturing techniques in many of our natural gas well drilling and completion programs.  The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.  The process is typically regulated by state oil and gas commissions.  However, the U.S. Environmental Protection Agency, or the EPA, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program.  While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision.  At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices.  Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.  In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations.  For example, Pennsylvania, Colorado, and Wyoming have each adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure.  If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations.  In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional
 
 
 
27

 
 
permitting requirements, and also to attendant permitting delays and potential increases in costs.  Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Item 1B -                 Unresolved Staff Comments

    Not applicable.


Item 2 -                 Properties

    Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped.  At December 31, 2010, we had interests in 6,789 gross (1,020.7 net) oil and gas wells and owned leasehold interests in approximately 1 million gross (535,000 net) undeveloped acres.


    See “Glossary of Terms” for current definitions of terms related to oil and gas reserves.

    The following table sets forth our estimated quantities of proved reserves as of December 31, 2010, all of which are located within the United States.

   
   
Proved Reserves(a)
 
         
Natural
   
Total Oil
 
   
Oil(b)
   
Gas
   
Equivalents(c)
 
Reserve Category
 
(MBbls)
   
(MMcf)
   
(MBOE)
 
                   
Developed                                                     
    24,570       59,409       34,472  
Undeveloped                                                     
    13,245       20,088       16,593  
Total Proved                                                     
    37,815       79,497       51,065  
                                      
(a)      None of our oil and gas reserves are derived from non-traditional sources.
(b)     Oil reserves include crude oil, condensate and natural gas liquids.
(c)     Natural gas reserves have been converted to oil equivalents at the rate of six Mcf of gas to one barrel of oil.

    The present value of future net cash flows from proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10% (“PV-10 Value”), totaled $992 million at December 31, 2010.  The commodity prices used to estimate proved reserves and their related PV-10 Value at December 31, 2010 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from January 2010 through December 2010.  The benchmark averages for 2010 were $79.43 per barrel of oil and NGL and $4.38 per MMBtu of natural gas.  These benchmark average prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $72.36 per barrel of oil and NGL and $5.44 per Mcf of natural gas over the remaining life of our proved reserves.  Operating costs were not escalated.

    PV-10 Value is not a generally accepted accounting principle (“GAAP”) financial measure, but we believe it is useful as a supplemental disclosure to the standardized measure of discounted future net cash flows presented in our consolidated financial statements.  To compute our standardized measure of discounted future net cash flows at December 31, 2010, we began with the PV-10 Value of our proved reserves and deducted the present value of estimated future income taxes of $276.9 million and net abandonment costs of $30.4 million, discounted at 10%.  At December 31, 2010, our standardized measure of discounted future net cash flows totaled $684.4 million.  While the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each company, the present value of proved reserves is based on prices and discount factors that are consistent for all companies and can be used within the industry and by securities analysts to evaluate proved reserves on a more comparable basis.


 
 
28

 
 
    The following table summarizes certain information as of December 31, 2010 regarding our estimated proved reserves in each of our principal producing areas.

                                 
Percent
 
   
Proved Reserves
         
PV-10
   
of PV-10
 
         
Natural
   
Total Oil
   
Percent of
   
Value of
   
Value of
 
   
Oil (a)
   
Gas
   
Equivalents(b)
   
Total Oil
   
Proved
   
Proved
 
   
(MBbls)
   
(MMcf)
   
(MBOE)
   
Equivalent
   
Reserves
   
Reserves
 
                         
(In thousands)
     
                                     
Permian Basin
    27,628       59,549       37,553       73.5 %   $ 664,170       67.0 %
Giddings Area:
                                               
Austin Chalk/
                                               
Eagle Ford Shale
    9,552       5,620       10,489       20.6 %     274,115       27.6 %
Cotton Valley
                                               
Reef Complex
    -       5,235       873       1.7 %     8,124       0.8 %
South Louisiana
    423       5,358       1,316       2.6 %     33,587       3.4 %
Other
    212       3,735       834       1.6 %     11,752       1.2 %
Total
    37,815       79,497       51,065       100.0 %   $ 991,748       100.0 %
                                                              
(a)  Oil reserves include crude oil, condensate and natural gas liquids.
(b)  Natural gas reserves have been converted to oil equivalents at the rate of six Mcf to one barrel of oil.

    The following table summarizes changes in our estimated proved reserves during 2010.

   
Proved
 
   
Reserves
 
   
(MBOE)
 
As of December 31, 2009                                                                                                
    33,637  
Extensions and discoveries                                                                                            
    23,193  
Revisions                                                                                            
    2,282  
Purchases of minerals-in-place                                                                                            
    349  
Sales of minerals-in-place                                                                                            
    (2,937 )
Production                                                                                            
    (5,459 )
As of December 31, 2010                                                                                                
    51,065  

 Extensions and discoveries.  Extensions and discoveries in 2010 added 23,193 MBOE of proved reserves, replacing 425% of our 2010 production.  These additions resulted primarily from our Andrews County drilling program in the Permian Basin and our Austin Chalk drilling program in the Giddings Area.  Of the total reserve additions, proved developed reserves accounted for 8,759 MBOE, while the remaining 14,434 MBOE were proved undeveloped reserves.

    Revisions.  Net upward revisions of 2,282 MBOE consisted of upward revisions of 6,005 MBOE related to pricing and downward revisions of 3,723 MBOE related to performance.  Upward revisions of 6,005 MBOE were attributable to the effects of higher product prices on the estimated quantities of proved reserves.  Most of the downward performance revisions resulted from the reclassification of 2,009 MBOE of Permian Basin reserves from proved undeveloped to probable (see discussion below concerning changes in proved undeveloped reserves).

    Purchases and sales of minerals-in-place.  In June 2010, we acquired from a group of private investors an undivided 14% working interest in 36 Wolfberry operated wells in Andrews County, Texas resulting in an increase of 349 MBOE.  Also in June 2010, we sold our interests in 22 operated and 76 non-operated producing wells in North Louisiana resulting in a decrease of 2,937 MBOE.
 
    The following table summarizes changes in our estimated proved undeveloped reserves during 2010.

   
Proved
 
   
Undeveloped
 
   
Reserves
 
   
(MBOE)
 
As of December 31, 2009                                                                                                
    5,051  
Extensions and discoveries                                                                                            
    14,434  
Revisions                                                                                            
    (2,027 )
Reclassified to proved developed                                                                                            
    (865 )
As of December 31, 2010                                                                                                
    16,593  

 
 
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    We added 14,434 MBOE of proved undeveloped reserves from extensions and discoveries related to Permian Basin and Giddings Area drilling locations, including 4,592 MBOE of upgrades from probable to proved undeveloped.  Downward revisions of 2,027 MBOE resulted primarily from the reclassification of 2,009 MBOE of Permian Basin reserves from undeveloped to probable in accordance with SEC standards that require proved undeveloped reserves to be developed within five years from their date or origin.  We also converted 865 MBOE of proved undeveloped reserves at December 31, 2009 to proved developed reserves during 2010 at a cost of approximately $17.2 million.  We expect to develop approximately 77% of our proved undeveloped reserves in 2011 at a cost of approximately $223.2 million.
 
Alternative Pricing Cases

    In addition to the estimated proved reserves disclosed above in accordance with the commodities pricing required by the new reserves rule (referred to as the “SEC Case”), the following table compares certain information regarding our SEC proved reserves to a Futures Pricing Case.
 
   
Proved Reserves
 
         
Natural
   
Total Oil
       
   
Oil(a)
   
Gas
   
Equivalents(b)
       
Pricing Cases
 
(MBbls)
   
(MMcf)
   
(MBOE)
   
PV-10 Value
 
                     
(In thousands)
 
SEC Case                                        
    37,815       79,497       51,065     $ 991,748  
Futures Pricing Case                                        
    38,888       82,151       52,580     $ 1,289,753  
                                                  
(a)  Oil reserves include crude oil, condensate and natural gas liquids.
(b)  Natural gas has been converted to oil equivalents at the rate of six Mcf to one barrel of oil.

Futures Pricing Case.  The Futures Pricing Case discloses our estimated proved reserves using future market-based commodities prices instead of the average historical prices used in the SEC Case.  Under the Futures Pricing Case, we used futures prices, as quoted on the New York Mercantile Exchange (“NYMEX”) on December 31, 2010, as benchmark prices for 2011 through 2015, and continued to use the 2015 futures price for all subsequent years.  These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $84.57 per barrel of oil and NGL and $6.75 per Mcf of natural gas over the remaining life of the proved reserves.

Reserve Estimation Procedures

    Overview
    We have established a system of internal controls over our reserve estimation process, which we believe provides us reasonable assurance that reserve estimates have been prepared in accordance with SEC and FASB standards.  These controls include oversight by trained technical personnel employed by us and by the use of qualified independent petroleum engineers to evaluate our proved reserves on an annual basis.  Substantially all of our estimated proved reserves as of December 31, 2010 were derived from engineering evaluation reports prepared by Williamson Petroleum Consultants, Inc. (“Williamson”) and Ryder Scott Company, L.P. (“Ryder Scott”).  Of our total SEC Case estimated proved reserves, Williamson evaluated 62.7% and Ryder Scott evaluated 36.9% on a BOE basis.

    Qualifications of Technical Manager and Consultants
    Ron D. Gasser, our Engineering Manager, is the person within our organization that is primarily responsible for overseeing the preparation of the reserve estimates.  Mr. Gasser joined our Company in 2002 as a Senior Engineer working on acquisitions/divestitures and special projects and was promoted to his current position as Engineering Manager in 2006.  Mr. Gasser has 28 years experience as a petroleum engineer, including 25 years directly involved in the estimation and evaluation of oil and gas reserves.  Mr. Gasser holds a Bachelor of Science degree in Petroleum Engineering from Texas Tech University.  He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers.


 
 
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    Williamson is an independent petroleum engineering consulting firm registered in the State of Texas, and John D. Savage, Executive Vice President – Engineering Manager of Williamson, is the technical person primarily responsible for evaluating the proved reserves covered by their report.  Mr. Savage has 29 years experience in evaluating oil and gas reserves, including 27 years experience as a consulting reservoir engineer.  Mr. Savage holds a Bachelor of Science degree in Petroleum Engineering from Texas A&M University.  He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers and the Society of Independent Professional Earth Scientists.
 
    Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years.  John E. Hamlin, Managing Senior Vice President of Ryder Scott, is the technical person primarily responsible for evaluating the proved reserves covered by their report.  Mr. Hamlin has more than 34 years of experience in the estimation and evaluation of petroleum reserves.  Mr. Hamlin holds a Bachelor of Science degree in Petroleum Engineering from the University of Texas.  He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers.

    Technology Used to Establish Proved Reserves
    Under current SEC standards, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.  The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate.  Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.  Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
   
    In order to establish reasonable certainty with respect to our estimated proved reserves, we employ technologies that have been demonstrated to yield results with consistency and repeatability.  The technological data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data.  Generally, oil and gas reserves are estimated using, as appropriate, one or more of these available methods: production decline curve analysis, analogy to similar reservoirs or volumetric calculations.  Reserves attributable to producing wells with sufficient production history are estimated using appropriate decline curves or other performance relationships.  Reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technological data to assess the reservoir continuity.  In some instances, particularly in connection with exploratory discoveries, analogous performance data is not available, requiring us to rely primarily on volumetric calculations to determine reserve quantities.  Volumetric calculations are primarily based on data derived from geologic-based seismic interpretation, open-hole logs and completion flow data.  When using production decline curve analysis or analogy to estimate proved reserves, we limit our estimates to the quantities of oil and gas derived through volumetric calculations.

    More than 98% of our additions to proved reserves in 2010 were derived from wells drilled in the Permian Basin and the Giddings Area.  A significant amount of technological data is available in these areas, which allows us to estimate with reasonable certainty the proved reserves and production decline rates attributable to most of our reserve additions through analogy to historical performance from wells in the same reservoirs.  None of our additions to proved reserves for 2010 were estimated solely on volumetric calculations.

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


 
 
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   Using the most appropriate method available, Mr. Gasser applies his professional judgment, based on his training and experience, to project a production profile for each evaluated property.  Mr. Gasser consults with other engineers and geoscientists within our company as needed to validate the accuracy and completeness of his estimates and to determine if any of the technological data upon which his estimates were based are incorrect or outdated.
 
    The engineering staff consults with our accounting department to validate the accuracy and completeness of certain operational data maintained in the reserves database, including ownership interests, average commodity prices, price differentials, and operating costs.
 
    Although we believe that the estimates of reserves prepared by our engineering staff have been prepared in accordance with professional engineering standards consistent with SEC and FASB guidelines, we engage independent petroleum engineering consultants to prepare annual evaluations of our estimated reserves.  After Mr. Gasser and our engineering staff have made an internal evaluation of our estimated reserves, we provide copies of the AriesTM reserves database to Ryder Scott as it relates to properties owned by Southwest Royalties, Inc., one of our wholly-owned subsidiaries, and to Williamson as it relates to properties owned by CWEI and Warrior Gas Company, another of our wholly-owned subsidiaries.  In addition, we provide to the consultants for their analysis all pertinent data needed to properly evaluate our reserves.  The services provided by Williamson and Ryder Scott are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties.  For more information about the evaluations performed by Williamson and Ryder Scott, see copies of their respective reports filed as exhibits to this Form 10-K.

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

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

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

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

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


 
 
32

 


Delivery Commitments

    As of December 31, 2010, we had no commitments to provide fixed and determinable quantities of oil or natural gas in the near future under contracts or agreements, other than through customary marketing arrangements which require us to nominate estimated volumes of natural gas production for sale during periods of one month or less.

Exploration and Development Activities

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

   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
   
(Excludes wells in progress at the end of any period)
 
Development Wells:
                                   
Oil                                   
    136       110.7       58       49.5       70       51.5  
Gas                                   
    1       .5       11       5.4       41       14.7  
Dry                                   
    3       1.3       1       1.0       1       1.0  
Total                                
    140       112.5       70       55.9       112       67.2  
Exploratory Wells:
                                               
Oil                                   
    2       2.0       1       .2       1       .5  
Gas                                   
    -       -       1       .1       3       1.7  
Dry                                   
    2       .5       6       4.4       4       3.0  
Total                                
    4       2.5       8       4.7       8       5.2  
Total Wells:
                                               
Oil                                   
    138       112.7       59       49.7       71       52.0  
Gas                                   
    1       .5       12       5.5       44       16.4  
Dry                                   
    5       1.8       7       5.4       5       4.0  
Total                                
    144       115.0       78       60.6       120       72.4  

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

Productive Well Summary

    The following table sets forth certain information regarding our ownership, as of December 31, 2010, of productive wells in the areas indicated.

   
Oil
   
Gas
   
Total
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Permian Basin                                        
    5,617       606.6       731       95.0       6,348       701.6  
Giddings Area:
                                               
Austin Chalk                                      
    330       263.5       19       11.7       349       275.2  
Deep Bossier                                      
    -       -       2       1.8       2       1.8  
Cotton Valley Reef Complex
    -       -       14       11.6       14       11.6  
South Louisiana                                        
    5       2.5       15       9.3       20       11.8  
Other                                        
    12       5.9       44       12.8       56       18.7  
Total
    5,964       878.5       825       142.2       6,789       1,020.7  


 
 
33

 


Volumes, Prices and Production Costs

    All of our oil and gas properties are located in one geographical area, specifically the United States.  The following table sets forth certain information regarding the production volumes of, average sales prices received from, and average production costs associated with all of our sales of oil and gas production for the periods indicated.
   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
Oil and Gas Production Data:
                 
Oil (MBbls)                                                              
    3,375       2,865       2,952  
Gas (MMcf)                                                              
    10,750       15,949       18,553  
Natural gas liquids (MBbls)                                                              
    292       240       182  
Total (MBOE)                                                            
    5,459       5,763       6,226  
Average Realized Prices(a):
                       
Oil ($/Bbl)                                                              
  $ 76.44     $ 57.37     $ 97.35  
Gas ($/Mcf)                                                              
  $ 5.17     $ 4.35     $ 9.02  
Natural gas liquids ($/Bbl)                                                              
  $ 42.47     $ 30.83     $ 54.45  
Average Production Costs:
                       
Production ($/MBOE)(b)                                                              
  $ 10.71     $ 9.82     $ 9.83  
                                      
(a)   No derivatives were designated as cash flow hedges in the table above.  All gains or losses on settled derivatives were included in other income (expense) - gain (loss) on derivatives.
(b)   Excludes property taxes and severance taxes.

    Only two fields, the Giddings field (Austin Chalk) in the Giddings Area and the Spraberry Trend field in the Permian Basin, accounted for 15% or more of our total proved reserves (on a BOE basis) as of December 31, 2010.  The following table discloses our oil, gas and natural gas liquids production from these fields for the periods indicated.

   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
Oil and Gas Production Data:
                 
                   
Giddings Field
                 
Oil (MBbls)                                                              
    1,012       963       1,189  
Gas (MMcf)                                                              
    694       773       709  
Natural gas liquids (MBbls)                                                              
    78       94       83  
Total (MBOE)                                                            
    1,206       1,186       1,390  

Spraberry Trend Field
                 
Oil (MBbls)                                                              
    671       148       60  
Gas (MMcf)                                                              
    304       72       22  
Natural gas liquids (MBbls)                                                              
    94       13       2  
Total (MBOE)                                                            
    816       173       66  

Development, Exploration and Acquisition Expenditures

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

   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
   
(In thousands)
 
Property Acquisitions:
                 
Proved                                                              
  $ 9,556     $ -     $ -  
Unproved                                                              
    29,680       12,558       36,397  
Developmental Costs                                                                 
    238,197       86,672       260,073  
Exploratory Costs                                                                 
    7,528       32,758       51,237  
Total                                                              
  $ 284,961     $ 131,988     $ 347,707  



 
 
34

 



    The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2010 in the areas indicated.  This table excludes options to acquire leases and acreage in which our interest is limited to royalty, overriding royalty and similar interests.
 
   
Developed
   
Undeveloped
   
Total
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Permian Basin                            
    89,678       41,871       342,887       156,094       432,565       197,965  
Giddings Area                            
    145,993       131,688       229,714       121,933       375,707       253,621  
North Louisiana                            
    5,049       4,203       93,546       87,965       98,595       92,168  
South Louisiana                            
    7,788       5,236       20,401       16,485       28,189       21,721  
Other(a)                            
    10,951       3,506       321,766       152,924       332,717       156,430  
Total                          
    259,459       186,504       1,008,314       535,401       1,267,773       721,905  
                                                           
(a)   Net undeveloped acres are attributable to the following areas:  Utah – 52,404; Mississippi – 41,608; Colorado – 28,798; and Other – 30,114.

    The following table sets forth expiration dates of the leases of our gross and net undeveloped acres as of December 31, 2010.

   
Acres Expiring(a)
 
   
2011
   
2012
   
2013
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Permian Basin                            
    33,254       18,930       11,962       9,662       24,941       17,938  
Giddings Area                            
    30,194       20,502       74,928       35,048       53,462       22,957  
South Louisiana                            
    3,302       2,983       198       191       1,303       1,292  
Other                            
    148,108       111,563       39,469       23,204       12,450       8,907  
      214,858       153,978       126,557       68,105       92,156       51,094  
                                                           
(a)   Acres expiring are based on contractual lease maturities.  We may extend the leases prior to their expiration based upon planned activities or for other business activities.


 
 
35

 


Desta Drilling

    Through a wholly-owned subsidiary, Desta Drilling, we currently own and operate 12 drilling rigs, consisting of six 1,000 horsepower rigs and six 1,300 horsepower rigs.  As of February 18, 2011, we were using ten of our rigs to drill wells in our developmental drilling program.  The Desta Drilling rigs are currently reserved for our use, but we may conduct contract drilling operations for third parties in the future.  In February 2011, we sold two 2,000 horsepower drilling rigs and related equipment for aggregate consideration of $22 million, and we expect to record a gain on the sale of approximately $13.2 million during the first quarter of 2011.  Proceeds from the sale consisted of $11 million cash and an $11 million promissory note due in August 2011.


    We lease from a related partnership approximately 71,000 square feet of office space in Midland, Texas for our corporate headquarters.  We also lease approximately 10,500 square feet of office space in Houston, Texas from unaffiliated third parties.


Item 3 -                 Legal Proceedings

    We are a defendant in several lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations.


Item 4 -                 (Removed and Reserved)

 
 
36

 


PART II


Item 5 -           Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Price Range of Common Stock

    Our Common Stock is quoted on the Nasdaq Stock Market’s Global Market under the symbol “CWEI”.  As of February 17, 2011, there were approximately 2,848 beneficial stockholders as reflected in security position listings.  The following table sets forth, for the periods indicated, the high and low sales prices for our Common Stock, as reported on the Nasdaq Global Market:

   
High
   
Low
 
Year Ended December 31, 2010:
           
Fourth Quarter                                                                                    
  $ 84.77     $ 48.62  
Third Quarter                                                                                    
    52.09       37.83  
Second Quarter                                                                                    
    54.50       35.07  
First Quarter                                                                                    
    41.75       32.34  
                 
Year Ended December 31, 2009:
               
Fourth Quarter                                                                                    
  $ 37.51     $ 24.67  
Third Quarter                                                                                    
    31.84       15.66  
Second Quarter                                                                                    
    35.27       17.80  
First Quarter                                                                                    
    52.69       19.37  

    The closing price of our common stock at February 25, 2011 was $101.47 per share.


Dividend Policy

    We have never paid any cash dividends on our Common Stock, and our Board of Directors does not currently anticipate paying any cash dividends to our stockholders in the foreseeable future.  In addition, the terms of our revolving credit facility and the Indenture governing our 7¾% Senior Notes restrict the payment of cash dividends.

Securities Authorized for Issuance under Equity Compensation Plans

    For information concerning shares available for issuance under equity compensation plans, see Item 12, which is to be incorporated by reference to our proxy statement.

 
 
37

 

Item 6 -                 Selected Financial Data

    The following table sets forth selected consolidated financial data for CWEI as of the dates and for the periods indicated.  The consolidated financial data for each of the years in the five-year period ended December 31, 2010 was derived from our audited financial statements.  The data set forth in this table should be read in conjunction with “Management's Discussion and Analysis of Financial Condition and Results of Operations” and the accompanying consolidated financial statements, including the notes thereto.

   
Year Ended December 31,
 
   
2010
   
2009
   
2008
   
2007
   
2006
 
   
(In thousands, except per share)
 
Statement of Operations Data:
                             
Revenues:
                             
Oil and gas sales                                                   
  $ 326,320     $ 242,338     $ 463,964     $ 316,992     $ 245,967  
Natural gas services                                                   
    1,631       6,146       10,926       10,230       11,327  
Drilling rig services                                                   
    -       6,681       46,124       52,649       6,937  
Gain on sales of assets                                                   
    3,680       796       44,503       14,024       1,767  
Total revenues                                                
    331,631       255,961       565,517       393,895       265,998  
Costs and expenses:
                                       
Production                                                   
    83,146       76,288       89,054       75,319       63,298  
Exploration:
                                       
Abandonment and impairments
    9,074       78,798       80,112       68,870       65,173  
Seismic and other                                                
    6,046       8,189       22,685       4,765       11,299  
Natural gas services                                                   
    1,209       5,348       10,060       9,745       10,005  
Drilling rig services                                                   
    1,198       10,848       37,789       32,964       4,538  
Depreciation, depletion and amortization
    101,145       129,658       120,542       84,476       66,163  
Impairment of property and equipment
    11,908       59,140       12,882       12,137       21,848  
Accretion of abandonment obligations
    2,623       3,120       2,355       2,508       1,653  
General and administrative                                                   
    35,588       20,715       25,635       19,266       16,676  
Loss on sales of assets and impairment of inventory
    1,750       5,282       2,122       9,815       99  
Total costs and expenses                                                
    253,687       397,386       403,236       319,865       260,752  
Operating income (loss)                                                
    77,944       (141,425 )     162,281       74,030       5,246  
Other income (expense):
                                       
Interest expense                                                   
    (24,402 )     (23,758 )     (24,994 )     (32,118 )     (20,895 )
Gain (loss) on derivatives                                                   
    722       (17,416 )     74,743       (31,968 )     37,340  
Other income (expense)                                                   
    3,308       2,543       6,539       5,355       (1,339 )
Total other income (expense)                                                
    (20,372 )     (38,631 )     56,288       (58,731 )     15,106  
Income (loss) before income taxes
    57,572       (180,056 )     218,569       15,299       20,352  
Income tax (expense) benefit                                                     
    (20,634 )     64,096       (77,327 )     (5,497 )     (1,979 )
NET INCOME (LOSS)                                                     
    36,938       (115,960 )     141,242       9,802       18,373  
Less income attributable to noncontrolling
                                       
interest, net of tax                                                
    -       (1,455 )     (708 )     (3,812 )     (574 )
NET INCOME (LOSS) attributable to
                                       
Clayton Williams Energy, Inc.                                                   
  $ 36,938     $ (117,415 )   $ 140,534     $ 5,990     $ 17,799  
Net income (loss) per common share attributable
                                       
to Clayton Williams Energy, Inc. stockholders:
                                       
Basic                                                   
  $ 3.04     $ (9.67 )   $ 11.78     $ .53     $ 1.64  
Diluted                                                   
  $ 3.04     $ (9.67 )   $ 11.67     $ .52     $ 1.58  
Weighted average common shares outstanding:
                                       
Basic                                                   
    12,148       12,138       11,932       11,337       10,885  
Diluted                                                   
    12,148       12,138       12,039       11,494       11,244  
Other Data:
                                       
Net cash provided by operating activities
  $ 208,251     $ 104,711     $ 381,980     $ 234,866     $ 145,990  
                                         
   
December 31,
 
      2010       2009       2008       2007       2006  
   
(In thousands)
 
Balance Sheet Data:
                                       
Working capital (deficit)                                                     
  $ (19,899 )   $ 19,324     $ 2,607     $ (76,388 )   $ (23,068 )
Total assets                                                     
    890,917       784,604       943,409       861,096       795,433  
Long-term debt                                                     
    385,000       395,000       347,225       430,175       413,876  
Stockholders’ equity                                                     
    249,452       212,275       320,276       160,806       144,980  


 
 
38

 

Item 7 -                 Management's Discussion and Analysis of Financial Condition and Results of Operations

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



Beginning in 2009 and continuing through 2010, we have been engaged in developmental drilling in two primary oil-prone regions, the Permian Basin and Giddings Area, where we have a significant inventory of developmental drilling opportunities.  We currently have eight of our drilling rigs and on contract rig working in Andrews County, Texas drilling Wolfberry wells.  We spent approximately $145 million drilling and completing Wolfberry wells in Andrews County in 2010 and currently plan to spend approximately $269 million in this area in 2011.  Most of our drilling to date has been based on 80-acre spacing across our acreage position so that as much acreage as possible may be held by production.  In some areas of the field, we have begun drilling infill wells on 40-acre spacing and believe we have the potential to add more reserves through increasing densities to 20-acre spacing in the future.

We are continuing to exploit our extensive acreage position in the Giddings Area of East Central Texas.  While most of our drilling activities have been directed toward infill drilling of horizontal wells in the Austin Chalk formation, this area is also known for its reserve potential from other formations such as the Eagle Ford Shale, Buda, Georgetown, Cotton Valley, Deep Bossier and Taylor.  We are currently working two of our drilling rigs in this area to drill dual opposed or dual stacked lateral horizontal wells in the Austin Chalk, and intermittently drilling single lateral horizontal wells in the Eagle Ford Shale.  In 2010, we spent approximately $58.5 million on Austin Chalk/Eagle Ford Shale drilling and completion and currently plan to spend approximately $46.9 million on similar drilling activities in this area in 2011. We believe that our Austin Chalk drilling program has been very successful in developing oil and casinghead gas reserves to our reserve base.  Our Eagle Ford Shale results, on the other hand, have not met our expectations.  We have tried different completion techniques on the four Eagle Ford Shale wells that we have drilled to date, but have not yet discovered effective techniques to unlock the large volumes of oil that we believe exist in this portion of the Eagle Ford Shale play.  We plan to continue searching for a completion technique that will make a multi-well drilling program economically viable.

Key Factors to Consider

    The following summarizes the key factors considered by management in the review of our financial condition and operating performance for 2010 and the outlook for 2011.

·  
    Our oil and gas sales increased $84 million, or 35%, from 2009.  Price variances accounted for an increase of $76.7 million while, production variances accounted for the remaining $7.3 million increase.

·  
    Our combined oil and gas production for 2010 was 5% lower on a barrel of oil equivalent (“BOE”) basis than in the comparable period in 2009.  Our oil production increased 18% compared to 2009 while gas production declined 33%.  On a comparable basis, after giving effect to the sale of properties in North Louisiana in June 2010, total oil and gas production in 2010 (on a BOE basis) was 5% higher than 2009.

·  
    We recorded a $722,000 net gain on derivatives in fiscal 2010, consisting of a $9.9 million realized gain on settled contracts and a $9.2 million non-cash loss for changes in mark-to-market valuations.  For fiscal 2009, we reported a $17.4 million net loss on derivatives consisting of a $15.9 million realized loss on settled contracts and a $1.5 million non-cash loss for changes in market-to-market valuations.  Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.

·  
    At December 31, 2010, our capitalized unproved oil and gas properties totaled $52 million, of which approximately $17.7 million was attributable to unproved acreage.  Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value.  Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.


 
 
39

 


·  
    We recorded a non-cash charge of $11.9 million for impairment of property and equipment primarily related to certain non-core oil and gas properties in the Permian Basin to reduce the carrying value to their estimated fair market value.

·  
    Our estimated proved oil and gas reserves at December 31, 2010 were 51,065 MBOE compared to 33,637 MBOE at December 31, 2009.  In 2010, we added 23,193 MBOE through extensions and discoveries, had upward net revisions of 2,282 MBOE, had purchases of minerals-in-place of 349 MBOE and had sales of minerals-in-place of 2,937 MBOE (see Item 2 – Properties – Reserves).
 
Proved Oil and Gas Reserves

    The following table summarizes changes in our estimated proved reserves during 2010.

   
Proved
 
   
Reserves
 
   
(MBOE)
 
As of December 31, 2009                                                                                                
    33,637  
Extensions and discoveries                                                                                            
    23,193  
Revisions                                                                                            
    2,282  
Purchases of minerals-in-place                                                                                            
    349  
Sales of minerals-in-place                                                                                            
    (2,937 )
Production                                                                                            
    (5,459 )
As of December 31, 2010                                                                                                
    51,065  

Extensions and discoveries.  Extensions and discoveries in 2010 added 23,193 MBOE of proved reserves, replacing 425% of our 2010 production.  These additions resulted primarily from our drilling activities in the Permian Basin and the Austin Chalk.  Of the total reserve additions, proved developed reserves accounted for 8,759 MBOE, while the remaining 14,434 MBOE were proved undeveloped reserves.

    Revisions.  Net upward revisions of 2,282 MBOE consisted of upward revisions of 6,005 MBOE related to pricing and downward revisions of 3,723 MBOE related to performance.  Upward revisions of 6,005 MBOE were attributable to the effects of higher product prices on the estimated quantities of proved reserves.  Most of the downward performance revisions resulted from the reclassification of 2,009 MBOE of Permian Basin reserves from proved undeveloped to probable (see discussion below concerning changes in proved undeveloped reserves).

    Purchases and sales of minerals-in-place.  In June 2010, we acquired from a group of private investors an undivided 14% working interest in 36 Wolfberry operated wells in Andrews County, Texas resulting in an increase of 349 MBOE.  Also in June 2010, we sold our interests in 22 operated and 76 non-operated producing wells in North Louisiana resulting in a decrease of 2,937 MBOE.
 
    The following table summarizes changes in our estimated proved undeveloped reserves during 2010.

   
Proved
 
   
Undeveloped
 
   
Reserves
 
   
(MBOE)
 
As of December 31, 2009                                                                                                
    5,051  
Extensions and discoveries                                                                                            
    14,434  
Revisions                                                                                            
    (2,027 )
Reclassified to proved developed                                                                                            
    (865 )
As of December 31, 2010                                                                                                
    16,593  

    We added 14,434 MBOE of proved undeveloped reserves from extensions and discoveries related to Permian Basin and Giddings Area drilling locations, including 4,592 MBOE of upgrades from probable to proved undeveloped.  Downward revisions of 2,027 MBOE resulted primarily from the reclassification of 2,009 MBOE of Permian Basin reserves from undeveloped to probable in accordance with SEC standards that require proved undeveloped reserves to be developed within five years from their date or origin.  We also converted 865 MBOE of proved undeveloped reserves at December 31, 2009 to proved developed reserves during 2010 at a cost of approximately $17.2 million.  We expect to develop approximately 77% of our proved undeveloped reserves in 2011 at a cost of approximately $223.2 million.


 
 
40

 


Supplemental Information

    The following unaudited information is intended to supplement the consolidated financial statements included in this Form 10-K with data that is not readily available from those statements.

   
As of or for the Year Ended December 31,
 
   
2010
   
2009
   
2008
 
Oil and Gas Production Data:
                 
Oil (MBbls)                                                   
    3,375       2,865       2,952  
Gas (MMcf)                                                   
    10,750       15,949       18,553  
Natural gas liquids (MBbls)                                                   
    292       240       182  
Total (MBOE)                                                   
    5,459       5,763       6,226  
Average Realized Prices(a):
                       
Oil ($/Bbl)                                                   
  $ 76.44     $ 57.37     $ 97.35  
Gas ($/Mcf)                                                   
  $ 5.17     $ 4.35     $ 9.02  
Natural gas liquids ($/Bbl)                                                   
  $ 42.47     $ 30.83     $ 54.45  
Gain (Loss) on Settled Derivative Contracts(a):
                       
($ in thousands, except per unit)
                       
Oil:      Net realized gain (loss)                                           
  $ (7,685 )   $ (25,713 )   $ 15,560  
Per unit produced ($/Bbl)                                           
  $ (2.28 )   $ (8.97 )   $ 5.27  
Gas:    Net realized gain                                           
  $ 17,560     $ 9,777     $ 11,764  
Per unit produced ($/Mcf)                                           
  $ 1.63     $ .61     $ .63  
                         
Average Daily Production:
                       
Oil (Bbls):
                       
Permian Basin                                              
    5,601       4,142       3,821  
Austin Chalk/Eagle Ford Shale
    2,944       2,734       3,384  
North Louisiana                                              
    71       238       415  
South Louisiana                                              
    559       649       378  
Other                                              
    72       86       90  
Total                                         
    9,247       7,849       8,088  
Gas (Mcf):
                       
Permian Basin                                              
    13,668       14,739       14,326  
Giddings Area:
                       
Austin Chalk/Eagle Ford Shale
    2,179       2,485       2,367  
Cotton Valley Reef Complex
    3,599       3,960       5,745  
North Louisiana                                              
    3,581       11,325       17,500  
South Louisiana                                              
    5,265       9,851       10,402  
Other                                              
    1,160       1,336       490  
Total                                         
    29,452       43,696       50,830  
Natural Gas Liquids (Bbls):
                       
Permian Basin                                              
    440       241       183  
Austin Chalk/Eagle Ford Shale
    237       288       250  
North Louisiana                                              
    8       22       7  
South Louisiana                                              
    89       98       49  
Other                                              
    26       9       10  
Total                                         
    800       658       499  
Total Proved Reserves:
                       
Oil and natural gas liquids (MBbls)
    37,815       20,953       20,776  
Gas (MMcf)                                                   
    79,497       76,103       103,929  
Total (MBOE)                                                   
    51,065       33,637       38,098  
Standardized measure of discounted
                       
future net cash flows                                                
  $ 684,438     $ 364,273     $ 405,166  




 
(Continued)

 
 
41

 


 

   
As of or for the Year Ended December 31,
 
   
2010
   
2009
   
2008
 
Total Proved Reserves by Area:
                 
Oil and Natural Gas Liquids (MBbls):
                 
Permian Basin                                                   
    27,628       13,325       13,491  
Austin Chalk/Eagle Ford Shale                                                   
    9,552       6,887       6,280  
North Louisiana                                                   
    -       291       285  
South Louisiana                                                   
    423       243       524  
Other                                                   
    212       207       196  
Total                                               
    37,815       20,953       20,776  
                         
Gas (MMcf):
                       
Permian Basin                                                   
    59,549       39,874       54,914  
Giddings Area:
                       
Austin Chalk/Eagle Ford Shale
    5,620       5,131       4,471  
Cotton Valley Reef Complex                                                
    5,235       5,981       9,281  
Deep Bossier                                                
    -       98       519  
South Louisiana                                                   
    5,358       5,968       13,966  
Other                                                   
    3,370       1,846       1,028  
Total                                               
    79,497       76,103       103,929  
Total Oil Equivalent (MBOE):
                       
Permian Basin                                                   
    37,553       19,971       22,643  
Giddings Area:
                       
Austin Chalk/Eagle Ford Shale
    10,489       7,742       7,025  
Cotton Valley Reef Complex                                                
    873       997       1,547  
Deep Bossier                                                
    -       16       87  
North Louisiana                                                   
    61       3,159       3,577  
South Louisiana                                                   
    1,316       1,238       2,852  
Other                                                   
    773       514       367  
Total                                               
    51,065       33,637       38,098  
Exploration Costs (in thousands):
                       
Abandonment and impairment costs:
                       
North Louisiana                                                   
  $ 2,612     $ 9,716     $ 25,414  
South Louisiana                                                   
    1,261       22,502       3,187  
Permian Basin                                                   
    18       3,484       717  
Deep Bossier                                                   
    2,522       30,200       40,544  
Utah                                                   
    1,929       11,111       6,331  
Other                                                   
    732       1,785       3,919  
Total                                               
    9,074       78,798       80,112  
Seismic and other                                                   
    6,046       8,189       22,685  
Total exploration costs                                               
  $ 15,120     $ 86,987     $ 102,797  
                         
Oil and Gas Costs ($/BOE Produced):
                       
Production costs                                                      
  $ 15.23     $ 13.24     $ 14.30  
Production costs (excluding production taxes)
  $ 12.03     $ 10.79     $ 10.70  
Oil and gas depletion                                                      
  $ 18.09     $ 21.94     $ 17.83  
Net Wells Drilled(b):
                       
Developmental wells                                                      
    112.5       55.9       67.2  
Exploratory wells                                                      
    2.5       4.7       5.2  
                                      
(a)    No derivatives were designated as cash flow hedges in the table above. All gains or losses on settled derivatives were included in other income (expense) - gain (loss) on derivatives.
 
(b)    Excludes wells being drilled or completed at the end of each period.
 


 
 
42

 

Operating Results

2010 Compared to 2009

    The following discussion compares our results for the year ended December 31, 2010 to the year ended December 31, 2009.  Unless otherwise indicated, references to 2010 and 2009 within this section refer to the respective annual periods.

Oil and gas operating results

Oil and gas sales in 2010 increased $84 million, or 35%, from 2009.  Price variances accounted for an increase of $76.7 million while production variances accounted for the remaining $7.3 million increase.  Production in 2010 (on a BOE basis) was 5% lower than 2009.  Oil production increased 18% in 2010 from 2009 while gas production decreased 33% in 2010 from 2009.  Most of the decrease in gas production from 2009 levels was attributed to a combination of normal production declines from existing wells and the loss of production related to the sale of certain properties in North Louisiana in June 2010.  During fiscal 2009, the sold wells produced 239 barrels of oil per day and 11,343 Mcf of gas per day.  On a comparable basis, after giving effect to the sale of these properties, oil production in 2010 was 21% higher than 2009 and total production was 5% higher (on a BOE basis).  In 2010, our realized oil price was 33% higher than 2009, and our realized gas price was 19% higher.  Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 9% in 2010 as compared to 2009 due primarily to an increase in production taxes caused by increases in commodity prices and overall increases in costs of oilfield services.  Production costs (excluding production taxes) increased 6% in 2010 as compared to 2009.  After giving effect to a 5% decrease in total oil and gas production on a BOE basis, production costs per BOE increased 15% from $13.24 per BOE in 2009 to $15.23 per BOE in 2010.

    Oil and gas depletion expense decreased $27.7 million from 2009 to 2010, of which rate variances accounted for a $21 million decrease, and production variances accounted for the remaining $6.7 million decrease.  On a BOE basis, depletion expense decreased 18% from $21.94 per BOE in 2009 to $18.09 per BOE in 2010.  The 2010 depletion rate per BOE dropped from 2009 due primarily to higher estimated reserve quantities in 2010.  Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production.  We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

    We recorded a provision for impairment of property and equipment of $11.9 million during 2010 for certain non-core oil and gas properties in the Permian Basin and for certain non-operated wells in Wyoming to reduce the carrying value of those properties to their estimated fair value.  During 2009, we recorded a $59.1 million impairment of property and equipment, of which $32.1 million related to impairment of certain drilling rigs and related equipment of Desta Drilling to reduce the carrying value of the equipment to its estimated fair value, and the remaining $27 million related to a provision for impairment of proved properties relating primarily to South Louisiana.

Exploration costs

    Since we follow the successful efforts method of accounting, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed.  In 2010, we charged to expense $15.1 million of exploration costs, as compared to $87 million in 2009.

    At December 31, 2010, our capitalized unproved oil and gas properties totaled $52 million, of which approximately $17.7 million was attributable to unproved acreage and the remaining costs were related to drilling costs for wells being drilled or completed.  Therefore, our results of operations in future periods may be adversely affected by abandonments and impairments related to unproved oil and gas properties.

Contract Drilling Services

    Until April 15, 2009, CWEI owned a 50% equity interest in a joint venture that we have historically referred to as Larclay JV and which we now refer to as Desta Drilling.  Effective April 15, 2009, CWEI acquired the remaining 50% equity interest in Desta Drilling.  As primary beneficiary of Desta Drilling’s expected cash flows, prior to April 15, 2009, we fully consolidated the accounts of Desta Drilling in our financial statements and accounted for the equity interest owned by Lariat as a noncontrolling interest.

 
 
43

 


    We utilize drilling rigs owned by Desta Drilling to drill wells in our exploration and development activities.  Since April 2009, Desta Drilling has worked exclusively for CWEI.  As a result, all drilling services revenues received by Desta Drilling subsequent to April 2009, along with the related drilling services costs, have been eliminated in our consolidated statements of operations.

General and Administrative

    General and administrative (“G&A”) expenses increased $14.9 million from $20.7 million in 2009 to $35.6 million in 2010.  Employee compensation expense related to non-equity incentive plans was $13.9 million in 2010 compared to $2.8 million in 2009.  Excluding employee compensation related to non-equity incentive plans, G&A expenses increased from $17.9 million in 2009 to $21.7 million in 2010 due to a combination of factors including a $1 million donation to the National Rifle Association’s Freedom Action Foundation, a one-time charge for cash bonuses totaling $678,000 paid to certain employees in August 2010 in connection with the sale of properties in North Louisiana and overall increases in personnel costs.

Interest expense

    Interest expense increased 3% from $23.8 million in 2009 to $24.4 million in 2010 primarily due to a combination of factors.  Interest expense associated with Desta Drilling’s secured term loan was $1.5 million in 2009 which was repaid in August 2009.  The average daily principal balance outstanding under our revolving credit facility for 2010 was $171.3 million compared to $135.2 million for 2009.  Increased borrowings on our revolving credit facility accounted for a $788,000 increase in interest expense, and higher interest rates and fees resulted in an increase of $612,000.  In addition, capitalized interest was $493,000 in 2010 compared to $698,000 in 2009.

Gain/loss on derivatives

    We did not designate any derivative contracts in 2010 or 2009 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives.  In 2010, we reported a $722,000 net gain on derivatives, consisting of $9.9 million realized gain on settled contracts and a $9.2 million non-cash loss to mark our derivative positions to their fair value at December 31, 2010.  In 2009, we reported a $17.4 million net loss on derivatives, consisting of a $15.9 million realized loss on settled contracts and a $1.5 million non-cash loss to mark our derivative positions to their fair value at December 31, 2009.  Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of assets and impairment of inventory

    We recorded a net gain of $1.9 million on sales of assets and impairment of inventory compared to a net loss of $4.5 million in 2009.  The 2010 gain related primarily to the sale of our interest in a non-operated well and related leasehold interests in North Louisiana, offset in part by the loss recorded on the sale of our interests in 22 operated and 76 non-operated producing wells in North Louisiana in June 2010.  The 2009 loss related primarily to the impairment of inventory to its estimated market value at December 31, 2009.

Income tax expense

    Our estimated effective income tax rate in 2010 of 35.8% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.





 
 
44

 

2009 Compared to 2008

    The following discussion compares our results for the year ended December 31, 2009 to the year ended December 31, 2008.  Unless otherwise indicated, references to 2009 and 2008 within this section refer to the respective annual periods.

Oil and gas operating results

Oil and gas sales in 2009 decreased $221.6 million, or 48%, from 2008.  Price variances accounted for a $195.4 million decrease, and production variances accounted for a $26.2 million decrease.  In 2009, our realized oil price was 41% lower than 2008 while our realized gas price was 52% lower than 2008.  Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.  Production in 2009 (on a BOE basis) was 7% lower than 2008.  Oil production decreased 3% and gas production decreased 14% in 2009 from 2008.

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, decreased 14% in 2009 as compared to 2008.  Some of the key components for the reduction in costs include lower production taxes caused by decreases in commodity prices, lower oilfield service costs and decreases in our overall activity level.  After giving effect to a 7% decrease in oil and gas production on a BOE basis, production costs per BOE decreased 7% from $14.30 per BOE in 2008 to $13.24 per BOE in 2009.

    Oil and gas depletion expense increased $15.5 million from 2008 to 2009, of which rate variances accounted for a $23.7 million increase and production variances accounted for an $8.2 million decrease.  On a BOE basis, depletion expense increased 23% from $17.83 per BOE in 2008 to $21.94 per BOE in 2009 due to a combination of higher depletable cost basis and higher depletion rates caused by lower estimated reserves.  Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production.  We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

    We recorded a provision for impairment of property and equipment of $59.1 million during 2009, of which $32.1 million related to impairment of certain drilling rigs and related equipment of Desta Drilling to reduce the carrying value of the equipment to its estimated fair value, and the remaining $27 million related to a provision for impairment of proved properties relating primarily to South Louisiana.

Exploration costs

    Since we follow the successful efforts method of accounting, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed.  In 2009, we charged to expense $87 million of exploration costs, as compared to $102.8 million in 2008.

    At December 31, 2009, our capitalized unproved oil and gas properties totaled $47.2 million, of which approximately $19.7 million was attributable to unproved acreage.  Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value.  Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.

Contract Drilling Services

    In 2006, CWEI formed a joint venture with Lariat Services, Inc. (“Lariat”) to construct, own, and operate 12 new drilling rigs.  Until April 15, 2009, CWEI owned a 50% equity interest in this joint venture that we have historically referred to as Larclay JV and which we now refer to as Desta Drilling.  Effective April 15, 2009, CWEI acquired the remaining 50% equity interest in Desta Drilling.  As primary beneficiary of Desta Drilling’s expected cash flows, prior to April 15, 2009, we fully consolidated the accounts of Desta Drilling in our financial statements and accounted for the equity interest owned by Lariat as a noncontrolling interest.

 
 
45

 


    We utilize drilling rigs owned by Desta Drilling to drill wells in our exploration and development activities.  All intercompany transactions are eliminated in consolidation to the extent of our equity ownership in Desta Drilling.  Accordingly, consolidated drilling services revenues and drilling services costs may vary significantly based on our equity ownership and the percentage of revenues derived from CWEI.  Since April 2009, Desta Drilling has worked exclusively for CWEI.  As a result, all drilling services revenues received by Desta Drilling subsequent to April 2009, along with the related drilling services costs, have been eliminated in our consolidated statements of operations.

    In April 2009, we adopted a plan of disposition to sell eight of the 12 drilling rigs then owned by Desta Drilling.  As a result, we recorded a $32.1 million impairment of property and equipment during the second quarter of 2009 to write-down the rigs to their estimated fair value of $18.8 million.  In December 2009, we modified the plan of disposition to move six of the previous eight rigs back into operations.  The decision to keep these six drilling rigs was based on an increased requirement for drilling rigs in our developmental drilling program.  As a result, we have recorded $7.4 million for the remaining two designated rigs as “Assets Held for Sale” in the accompanying consolidated balance sheet.

General and Administrative

    G&A expenses decreased 19% from $25.6 million in 2008 to $20.7 million in 2009.  Excluding employee compensation related to non-equity incentive plans, G&A expenses decreased from $19.8 million in 2008 to $17.9 million in 2009 due primarily to a one-time charge in 2008 for cash bonuses paid to employees relating to the sale of certain properties in South Louisiana.  Employee compensation expense related to non-equity incentive plans was $2.8 million in 2009 compared to $5.8 million in 2008.

Interest expense

    Interest expense decreased 5% from $25 million in 2008 to $23.8 million in 2009 due to a combination of reduced consolidated debt levels and lower interest rates.  Lower interest rates during 2009 were a major component of the decrease in interest expense from 2008.  The average interest rate for 2009 was 2.6% compared to 4.5% in 2008.  The average daily principal balance outstanding under our revolving credit facility for 2009 was $135.2 million compared to $128.5 million for 2008.  In addition, capitalized interest for 2009 was $698,000 compared to $3.8 million in 2008, and interest expense associated with Desta Drilling’s term loan during 2009 was $1.5 million compared to $3.4 million in 2008.

Gain/loss on derivatives

    We did not designate any derivative contracts in 2009 or 2008 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives.  For the year ended December 31, 2009, we reported a $17.4 million net loss on derivatives, consisting of a $15.9 million realized loss on settled contracts and a $1.5 million non-cash loss to mark our derivative positions to their fair value at December 31, 2009.  For the year ended December 31, 2008, we reported a $74.7 million net gain on derivatives, consisting of a $25 million realized gain on settled contracts and a $49.7 million non-cash gain to mark our derivative positions to their fair value at December 31, 2008.  Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of assets and impairment of inventory

We recorded a net loss of $4.5 million on sales of assets and impairment of inventory for 2009 related primarily to the impairment of inventory to its estimated market value at December 31, 2009.  In 2008, we recorded a net gain on sales of assets and impairment of inventory of $42.4 million, which included a $33.1 million gain on sales of properties in South Louisiana, a $3 million gain on the sale of a North Louisiana prospect, and a $5.7 million gain on the sales of two drilling rigs and a surplus well servicing unit.

Income tax expense (benefit)

Our effective income tax rate in 2009 of 35.6% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and tax benefits derived from statutory depletion deductions, offset by the effects of certain non-deductible expenses.


 
 
46

 

Liquidity and Capital Resources

    Our primary financial resource is our base of oil and gas reserves.  We pledge our producing oil and gas properties to a group of banks to secure our revolving credit facility.  The banks establish a borrowing base by making an estimate of the collateral value of our oil and gas properties.  We borrow funds on the revolving credit facility as needed to supplement our operating cash flow as a financing source for our capital expenditure program.  Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration and development programs in replacing our existing oil and gas reserves.  If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program.  However, the effects of product prices on cash flow can be mitigated through the use of commodity derivatives.

The Indenture governing our 7¾% Senior Notes due 2013 contains covenants that restrict our ability to incur indebtedness.  We currently have, and expect to have in 2011, the ability under the Indenture to incur indebtedness as needed in 2011 to fund our exploration and development activities.

Capital expenditures

The following table summarizes, by area, our planned expenditures for exploration and development activities during 2011, as compared to our actual expenditures in 2010.

   
Actual
   
Planned
       
   
Expenditures
   
Expenditures
   
2011
 
   
Year Ended
   
Year Ended
   
Percentage
 
   
December 31, 2010
   
December 31, 2011
   
of Total
 
   
(In thousands)
       
Permian Basin                                             
  $ 199,600     $ 295,300       77 %
Giddings Area:
                       
Austin Chalk/Eagle Ford Shale
    73,600       66,100       17 %
Deep Bossier                                           
    1,600       13,900       4 %
South Louisiana                                             
    8,700       3,900       1 %
Other                                             
    8,600       2,600       1 %
    $ 292,100     $ 381,800       100 %

    Our actual expenditures during fiscal 2011 may vary significantly from these estimates if our plans for exploration and development activities change during the year.  Factors, such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during fiscal 2011.

We spent $292.1 million on exploration and development activities during 2010, of which approximately 93% was on developmental drilling.  We currently plan to spend approximately $381.8 million for fiscal 2011, of which approximately 95% is estimated to be spent on developmental drilling.  We financed these expenditures in 2010 with cash flow from operating activities and advances under the revolving credit facility.  Based on preliminary estimates, our internal cash flow forecasts indicate that our anticipated operating cash flow will be sufficient to finance our exploration and development activities through 2011.  Although we believe the assumptions and estimates made in our forecasts are reasonable, these forecasts are inherently uncertain and the borrowing base may be less than expected, cash flow may be less than expected, or capital expenditures may be more than expected.  In the event we lack adequate liquidity to finance our expenditures through 2011, we will consider options for obtaining alternative capital resources, including selling assets or accessing capital markets.

Cash flow provided by operating activities

Substantially all of our cash flow from operating activities is derived from the production of our oil and gas reserves.  We use this cash flow to fund our on-going exploration and development activities in search of new oil and gas reserves.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.


 
 
47

 


Cash flow provided by operating activities for the year ended December 31, 2010 increased $103.5 million, or 98.9%, as compared to the corresponding period in 2009 due primarily to a 35% increase in oil and gas sales caused by higher commodity prices.

Credit facility

In November 2010, we amended and restated our secured bank credit facility with a syndicate of banks to provide for a revolving line of credit of up to $500 million, limited to the amount of a borrowing base as determined by the banks.  We have historically relied on the revolving credit facility for both our short-term liquidity (working capital) and our long-term financial needs.  As long as we have sufficient availability under the revolving credit facility to meet our obligations as they become due, we believe that we will have sufficient liquidity and will be able to fund any short-term working capital deficit.

The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November.  We or the banks may also request an unscheduled borrowing base redetermination at other times during the year.  If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency (or by a combination of such additional security and such prepayment eliminate such deficiency), or (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest.  The borrowing base was $350 million at December 31, 2010.

The revolving credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in the revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base.  The obligations under the revolving credit facility are guaranteed by each of CWEI’s material domestic subsidiaries.

At our election, annual interest rates under the revolving credit facility are determined by reference to (1) LIBOR plus an applicable margin between 2% and 3% per year or (2) if an alternate base rate loan, the greatest of (A) the prime rate, (B) the federal funds rate plus 0.5%, or (C) one-month LIBOR plus 1% plus, if any of (A), (B) or (C), an applicable margin between 1% and 2%.  We also pay a commitment fee on the unused portion of the revolving credit facility at a flat rate of .5%.  Interest and fees are payable no less often than quarterly.  The effective annual interest rate on borrowings under the revolving credit facility, excluding bank fees and amortization of debt issue costs, for the twelve months ended December 31, 2010 was 3%.

The revolving credit facility contains various covenants and restrictive provisions which may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens.  One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities (the “Consolidated Current Ratio”) of at least 1 to 1.  In computing the Consolidated Current Ratio at any balance sheet date, we must (1) include the amount of funds available under this facility as a current asset, (2) exclude current assets and liabilities related to the fair value of derivatives (non-cash assets or liabilities), and (3) exclude current assets and liabilities attributable to vendor financing transactions, if any.

Working capital computed for loan compliance purposes differs from our working capital in accordance with GAAP.  Since compliance with financial covenants is a material requirement under the credit facilities, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under the revolving credit facility and is not affected by the volatility in working capital caused by changes in fair value of derivatives.  Our GAAP reported working capital decreased from $19.3 million at December 31, 2009 to a deficit of $19.9 million at December 31, 2010.  After giving effect to the adjustments, our working capital computed for loan compliance purposes was $175.3 million at December 31, 2010, as compared to $104.4 million at December 31, 2009.  The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at December 31, 2010 and December 31, 2009.

   
December 31,
 
   
2010
   
2009
 
   
(In thousands)
 
Working capital (deficit) per GAAP
  $ (19,899 )   $ 19,324  
Add funds available under the revolving credit facility
    187,975       79,196  
Exclude fair value of derivatives classified as current assets or current liabilities
    7,224       5,907  
Working capital per loan covenant
  $ 175,300     $ 104,427  


 
 
48

 


The revolving credit facility provides that the ratio of our consolidated funded indebtedness to consolidated EBITDAX (the “Leverage Ratio”) (determined as of the last end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1.

We were in compliance with all financial and non-financial covenants at December 31, 2010.  However, if we increase leverage and our liquidity is reduced, we may fail to comply with one or more of these covenants in the future.  If we fail to meet any of these loan covenants, we would ask the banks to waive compliance, amend the revolving credit facility to allow us to become compliant or grant us sufficient time to obtain additional capital resources through alternative means.  If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.

The lending group under the revolving credit facility includes the following institutions:  JPMorgan Chase Bank, N.A., Bank of Scotland, Union Bank, N.A., BNP Paribas, Natixis, Compass Bank, The Frost National Bank, Bank of Texas, N.A., Keybank, N.A., UBS Loan Finance, LLC, The Royal Bank of Scotland plc, and Societe Generale.

From time to time, we engage in other transactions with lenders under the revolving credit facility.  Such lenders or their affiliates may serve as counterparties to our commodity and interest rate derivative agreements. As of December 31, 2010, JPMorgan Chase Bank, N.A. was the only counterparty to our commodity derivative agreements.  Our obligations under existing derivative agreements with our lenders are secured by the security documents executed by the parties under the revolving credit facility.

During 2010, we decreased indebtedness outstanding under the revolving credit facility by $10 million.  At December 31, 2010, we had $160 million of borrowings outstanding under the revolving credit facility, leaving $188 million available on the facility after allowing for outstanding letters of credit totaling $2 million.  The revolving credit facility matures in May 2012.

7¾% 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 value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006.

We may redeem some or all of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 101.938% for the twelve-month period beginning on August 1, 2010, and 100% beginning on August 1, 2011, for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing the Senior Notes contains covenants that restrict the ability of us and our subsidiaries to:  (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business.  One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) exceeds 2.5 to 1 for the four most recently completed fiscal quarters.  However, this restriction does not prevent us from borrowing funds under the revolving credit facility provided that our outstanding balance on the facility does not exceed the greater of $150 million and 30% of Adjusted Consolidated Net Tangible Assets (as defined in the Indenture).  We currently have, and expect to have in 2011, sufficient EBITDAX coverage under the Indenture to permit us to borrow funds as needed in 2011 to fund our exploration and development activities.  These covenants are subject to a number of important exceptions and qualifications as described in the Indenture.  We were in compliance with these covenants at December 31, 2010.


 
 
49

 


Alternative capital resources

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

Contractual Obligations and Contingent Commitments

The following table summarizes our contractual obligations as of December 31, 2010 by payment due date.

   
Payments Due by Period
 
   
 
Total
   
 
2011
   
2012
to
2013
   
2014
to
2015
 
               
(In thousands)
       
Contractual obligations:
                       
7¾% Senior Notes(a)                                                               
  $ 225,000     $ -     $ 225,000     $ -  
Secured bank credit facility(a)                                                               
    160,000       -       -       160,000  
Lease obligations                                                               
    3,542       2,008       1,521       13  
Other(b)                                                               
    14,084       14,084       -       -  
Total contractual obligations                                                              
  $ 402,626     $ 16,092     $ 226,521     $ 160,013  
                                              
 
(a)
     In addition to the principal payments presented, we expect to make annual interest payments of $17.4 million on the Senior Notes and approximately $4.8 million on the secured bank credit facility (based on the balances and interest rates at December 31, 2010).
(b)
    Amount relates to non-cancellable orders placed for tubular goods at December 31, 2010.

Known Trends and Uncertainties

Operating Margins

We analyze, on a BOE produced basis, those revenues and expenses that have a significant impact on our oil and gas operating margins.  Our weighted average oil and gas sales per BOE have fluctuated from $74.52 per BOE in 2008, to $42.05 per BOE in 2009 and to $59.78 per BOE in 2010.  Our expenses per BOE were on an upward trend through 2009 but operating margins were more favorable in 2010.  Our oil and gas DD&A per BOE was $17.83 per BOE in 2008, $21.94 per BOE in 2009 and $18.09 per BOE in 2010.  The lower DD&A rate was due in part from the replacement of 425% of our production in 2010 and higher commodity prices.  Also affecting our operating margins is the cost of producing our reserves.  Our production costs per BOE have fluctuated from $14.30 per BOE in 2008, to $13.24 per BOE in 2009, to $15.23 per BOE in 2010.  The increase in operating costs per BOE in 2010 was due primarily to higher production taxes resulting from increases in commodity prices and higher costs of field services.

During the last half of 2009, operating margins, particularly on oil-prone properties, began to improve due to higher oil prices and lower costs of field services.  In recent months, our costs to drill and equip wells in the Permian Basin and Austin Chalk areas have been significantly lower than the costs we incurred to drill similar wells in 2008 as a result of lower service and equipment costs and improved drilling efficiencies obtained through Desta Drilling.  Lower drilling and completion costs should continue to provide favorable operating margins through mid- 2011, but we expect to see a rise in costs during the second half of 2011.  However, any ultimate improvement in our operating margins will be dependent on the quantities of proved reserves and production added through our 2011 drilling program.


 
 
50

 


Oil and Gas Production

As with all companies engaged in oil and gas exploration and production, we face the challenge of natural production decline because oil and gas reserves are a depletable resource.  With each unit of oil and gas we produce, we are depleting our proved reserve base, so we must be able to conduct successful exploration and development activities or acquire properties with proved reserves in order to grow our reserve base.  Prior to 2008 our production had been on a gradual decline since 2003 due to the effects of natural production decline, offset in part by reserve additions through exploration and development and acquisitions.  Although our production decreased by 7% in 2009 over 2008 levels, our production in 2010 decreased 5% to 5.5 MMBOE from 5.8 MMBOE in 2009, and we replaced 425% of our 2010 oil and gas production through extensions and discoveries.  While these 2010 reserve additions will contribute favorably to our production in 2011, we do not expect this production to be sufficient to fully offset the natural production declines from our existing base of oil and gas reserves. To grow our production in 2011, we will need to add production from wells drilled in 2011 through our developmental drilling program.

We currently plan to increase capital spending during fiscal 2011 to $381.8 million compared to $292.1 million in fiscal 2010.  Higher spending levels, if successful, should positively impact our ability to replace 2011 production with new reserves.  Failure to maintain or grow our oil and gas reserves may result in lower production and may adversely affect our financial condition, results of operations, and cash flow.

Application of Critical Accounting Policies and Estimates

Summary

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

The following table lists our critical accounting policies, the estimates and assumptions that can have a significant impact on the application of these accounting policies, and the financial statement accounts 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
 
·Accumulated DD&A
   
properties
 
·Provision for DD&A
   
·Judgment regarding status of
 
·Impairment of unproved
       in progress exploratory wells      properties
       
·Abandonment costs
       
(dry hole costs)
Impairment of proved
 
·Reserve estimates and related
 
·Oil and gas properties
properties and long-
 
present value of future net
 
·Contract drilling equipment
lived assets
 
revenues (proved properties)
 
·Accumulated DD&A
   
·Estimates of future undiscounted
 
·Impairment of proved properties
   
cash flows (long-lived assets)
 
and long-lived assets
         
Asset retirement obligations
 
·Estimates of the present value
 
·Abandonment obligations
   
of future abandonment costs
 
(non-current liability)
       
·Oil and gas properties
       
·Accretion of discount
       
expense
Inventory stated at the lower of
 
·Estimates of market value of
 
·Impairment of inventory
average cost or estimated
 
tubular goods and other well
   
market value
 
equipment
   
         
Derivatives mark-to-market
 
·Estimates of the fair value
 
·Fair value of derivatives
   
of derivatives
 
·Other income (expense):
       
Gain (loss) on derivatives

 
 
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Significant Estimates and Assumptions

    Oil and gas reserves
    Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner.  The accuracy of a reserve estimate depends on the quality of available geological and engineering data, the precision of and the interpretation of that data, and judgment based on experience and training.  Annually, we engage independent petroleum engineering firms to evaluate our oil and gas reserves.  As a part of this process, our internal reservoir engineer and the independent engineers exchange information and attempt to reconcile any material differences in estimates and assumptions.

    The techniques used in estimating reserves usually depend on the nature and extent of available data, and the accuracy of the estimates may vary accordingly.  As a general rule, the degree of accuracy of reserve estimates varies with the reserve classification and the related accumulation of available data, as shown in the following table.

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

    Assumptions as to future commodity prices and operating and capital costs also play a significant role in estimating oil and gas reserves and the estimated present value of the cash flows to be received from the future production of those reserves.  Volumes of recoverable reserves are affected by 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 producing recoverable reserves exceed the projected revenues from the reserves).  But more significantly, the standardized measure of discounted future net cash flows is extremely sensitive to prices and costs, and may vary materially based on different assumptions.  Current SEC financial accounting and reporting standards require that pricing parameters be the arithmetic average of the first-day-of-the-month price for the 12-month period preceding the effective date of the reserve report.  Varying pricing can result in significant changes in reserves and standardized measure of discounted future net cash flows from period to period, 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:
                             
2010
    37.8       79.5     $ 72.36     $ 5.44     $ 684.4  
2009
    21.0       76.1     $ 54.81     $ 3.71     $ 364.3  
2008
    20.8       103.9     $ 42.03     $ 5.90     $ 405.2  
                                                      
(a)         Includes crude oil, condensate and  natural gas liquids.

    Valuation of unproved properties
    Estimating fair market value of unproved properties (also known as prospects) is very subjective since there is no quoted market for undeveloped exploratory prospects.  The negotiated price of any prospect between a willing seller and willing buyer depends on the specific facts regarding the prospect, including:

·  
    the location of the prospect in relation to known fields and reservoirs, available markets and transportation systems for oil and gas production in the vicinity, and other critical services;
 
·  
    the nature and extent of geological and geophysical data on the prospect;
 
·  
    the terms of the leases holding the acreage in the prospect, such as ownership interests, expiration terms, delay rental obligations, depth limitations, drilling and marketing restrictions, and similar terms;
 
·  
    the prospect’s risk-adjusted potential for return on investment, giving effect to such factors as potential reserves to be discovered, drilling and completion costs, prevailing commodity prices, and other economic factors; and
 
·  
    the results of drilling activity in close proximity to the prospect that could either enhance or condemn the prospect’s chances of success.
 

 
 
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    Asset Retirement Obligations
    We estimate the present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws.  We compute our liability for asset retirement obligations by calculating the present value of estimated future cash flows related to each property.  This requires us to use significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations.

Effects of Estimates and Assumptions on Financial Statements

    Generally accepted accounting principles do not require, or even permit, the restatement of previously issued financial statements due to changes in estimates unless such estimates were unreasonable or did not comply with applicable SEC accounting rules.  We are required to use our best judgment in making estimates and assumptions, taking into consideration the best and most current data available to us at the time of the estimate.  At each accounting period, we make a new estimate using new data, and continue the cycle.  You should be aware that estimates prepared at various times may be substantially different due to new or additional information.  While an estimate made at one point in time may differ from an estimate made at a later date, both may be proper due to the differences in available information or assumptions.  In this section, we will discuss the effects of different estimates on our financial statements.

    Provision for DD&A
    We compute our provision for DD&A on a unit-of-production method.  Each quarter, we use the following formulas to compute the provision for DD&A for each of our producing properties (or appropriate groups of properties based on geographical and geological similarities):

·  
    DD&A Rate = Unamortized Cost  ¸  Beginning of Period Reserves
 
·  
    Provision for DD&A = DD&A Rate  ´  Current Period Production
 

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

    Impairment of Unproved Properties
    Each quarter, we review our unproved oil and gas properties to determine if there has been, in our judgment, an impairment in value of each prospect that we consider individually significant.  To the extent that the carrying cost of a prospect exceeds its estimated value, we make a provision for impairment of unproved properties, and record the provision as abandonments and impairments within exploration costs on our statement of operations.  If the value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the prospect at a net cost that is lower than its estimated value.  If the value is revised downward in a future period, an additional provision for impairment is made in that period.

    Impairment of Proved Properties and Long-Lived Assets
    Each quarter, we assess our producing properties for impairment.  If we determine there has been an impairment in any of our producing properties (or appropriate groups of properties based on geographical and geological similarities), we will estimate the value of each affected property.  In accordance with applicable accounting standards, the value for this purpose is a fair value using Level 3 inputs instead of a standardized reserve value as prescribed by the SEC.  We attempt to value each property using reserve classifications and pricing parameters similar to what a willing seller and willing buyer might use.  These parameters may include escalations of prices instead of constant pricing, and they may also include the risk-adjusted value of reserves.  To the extent that the carrying cost for the affected property exceeds its estimated fair value, we make a provision for impairment of proved properties.  If the fair value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the property at a net cost that is lower than its estimated fair value.  If the fair value is revised downward in a future period, an additional provision for impairment is made in that period.  Accordingly, the carrying costs of producing properties on our balance sheet will vary from (and often will be less than) the present value of proved reserves for these properties.


 
 
53

 


    Judgment Regarding Status of In-Progress Wells
    On a quarterly basis, we review the status of each in-progress well to determine the proper accounting treatment under the successful efforts method of accounting.  Cumulative costs on in-progress wells remain capitalized until their productive status becomes known.  If an in-progress exploratory well is found to be unsuccessful (often referred to as a dry hole) prior to the issuance of our financial statements, we write-off all costs incurred through the balance sheet date to abandonments and impairments expense, a component of exploration costs.  Costs incurred on that dry hole after the balance sheet date are charged to exploration costs in the period incurred.

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

    Asset Retirement Obligations
    Our asset retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to oil and gas properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statement of operations.  During 2010, we had a downward revision of our estimated asset retirement obligations by $320,000 based on a review of current plugging and abandonment costs. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion expense. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.

Adopted Accounting Pronouncements
    In June 2009, the FASB issued accounting guidance on the consolidation of variable interest entities (“VIEs”). This new guidance revises previous guidance by replacing the quantitative-based risks and rewards calculation for determining which enterprise, if any, has a controlling financial interest in a VIE with a qualitative approach focused on identifying which enterprise has both the power to direct the activities of the VIE that most significantly impacts the entity’s economic performance and has the obligation to absorb losses or the right to receive benefits that could be significant to the entity. In addition, this guidance requires reconsideration of whether an entity is a VIE when any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of the entity that most significantly impact the entity’s economic performance. It also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE and additional disclosures about an enterprise’s involvement in variable interest entities. This guidance is effective for fiscal years beginning after November 15, 2009. Our adoption of the new guidance during the first quarter of 2010 did not have a material effect on our consolidated financial statements.



 
 
54

 


Item 7A -              Quantitative and Qualitative Disclosure About Market Risks

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

Oil and Gas Prices

    Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors, many of which are beyond our control.  These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.  We cannot predict future oil and gas prices with any degree of certainty.  Sustained weakness in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically.  Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities.  Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources.  Based on December 31, 2010 reserve estimates, we project that a $1 decline in the price per Bbl of oil and a $.50 decline in the price per Mcf of gas from year end 2010 would reduce our gross revenues for the year ending December 31, 2011 by $9.9 million.

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

    The decision to initiate or terminate commodity hedges is made by management based on its expectation of future market price movements.  We have no set goals for the percentage of our production we hedge and we do not use any formulas or triggers in deciding when to initiate or terminate a hedge.  If we enter into swaps or collars and the floating market price at the settlement date is higher than the fixed price or the fixed ceiling price, we will forego revenue we would have otherwise received.  If we terminate a swap, collar or floor because we anticipate future increases in market prices, we may be exposed to downside risk that would not have existed otherwise.

    The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 2010.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:
   
Oil
   
Gas
 
   
Bbls
   
Price
   
MMBtu (a)
   
Price
 
Production Period:
                       
1st Quarter 2011                              
    657,000     $ 83.74       1,710,000     $ 7.07  
2nd Quarter 2011                              
    632,000     $ 83.71       1,650,000     $ 7.07  
3rd Quarter 2011                              
    547,000     $ 83.78       1,560,000     $ 7.07  
4th Quarter 2011                              
    540,000     $ 83.78       1,500,000     $ 7.07  
2012                              
    1,170,000     $ 90.65       -     $ -  
      3,546,000               6,420,000          
                                           
(a)    One MMBtu equals one Mcf at a Btu factor of 1,000.
 


 
 
55

 


We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives.  A $1 per barrel change in the price of oil and a $.50 per MMBtu change in the price of gas would change the fair value of our outstanding commodity derivatives at December 31, 2010 by approximately $5.8 million.
 

We are exposed to interest rate risk on our long-term debt with a variable interest rate.  At December 31, 2010, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $226 million, based on current market quotes.  We estimate that the hypothetical change in the fair value of our long-term debt resulting from a 100-basis point change in interest rates would be approximately $5.1 million.  Based on our outstanding variable rate indebtedness at December 31, 2010 of $160 million, a change in interest rates of 100 basis points would affect annual interest payments by $1.6 million.


Item 8 -                 Financial Statements and Supplementary Data

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


Item 9 -                 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.


Item 9A -                      Controls and Procedures

Disclosure Controls and Procedures

    In September 2002, our Board of Directors adopted a policy designed to establish disclosure controls and procedures that are adequate to provide reasonable assurance that our management will be able to collect, process and disclose both financial and non-financial information, on a timely basis, in our reports to the SEC and other communications with our stockholders.  Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.

    With respect to our disclosure controls and procedures:

·  
    management has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report;
 
·  
    this evaluation was conducted under the supervision and with the participation of our management, including our chief executive and chief financial officers; and
 
·  
    it is the conclusion of our chief executive and chief financial officers that these disclosure controls and procedures are effective in ensuring that information that is required to be disclosed by the Company in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.
 

 
 
56

 

 
Internal Control Over Financial Reporting

    Management designed our internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles.  Our internal control over financial reporting includes those policies and procedures that:

·  
    pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
 
·  
    provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and our Board of Directors; and
 
·  
    provide reasonable assurance regarding prevention or timely detection of any unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
 

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

Changes in Internal Control Over Financial Reporting

    No changes in internal control over financial reporting were made during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

    Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934.  Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2010.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.  Based on this assessment, management has concluded that, as of December 31, 2010, our internal control over financial reporting is effective based on those criteria.

    KPMG LLP has issued an audit report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010, the contents of which are shown below.



 
 
57

 


Report of Independent Registered Public Accounting Firm


The Board of Directors and Stockholders
Clayton Williams Energy, Inc.:

We have audited Clayton Williams Energy, Inc.’s (Company) internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

In our opinion, Clayton Williams Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the years in the three-year period ended December 31, 2010, and our report dated February 28, 2011 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Dallas, Texas
February 28, 2011

 
 
58

 


Item 9B-               Other Information

None.


PART III

Item 10 -               Directors, Executive Officers and Corporate Governance

    Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2011.


Item 11 -               Executive Compensation

    Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2011.


Item 12 -         Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

    Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2011.


Item 13 -               Certain Relationships and Related Transactions, and Director Independence

    Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2011.


Item 14 -               Principal Accounting Fees and Services

    Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2011.



 
 
59

 

PART IV

Item 15 -                 Exhibits and Financial Statement Schedules

Financial Statements and Schedules

    For a list of the consolidated financial statements and 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 are filed as a part of this Form 10-K, with each exhibit that consists of or includes a management contract or compensatory plan or arrangement being identified with a “†”:

Exhibit
Number
 
Description of Exhibit
     
**2.1
 
Agreement and Plan of Merger among Clayton Williams Energy, Inc. and Southwest Royalties, Inc. dated May 3, 2004, filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 3, 2004††
     
**3.1
 
Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to the Company’s Form S-2 Registration Statement, Commission File No. 333-13441
     
**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 13, 2008††
     
**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††
     
**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
 
Fourth Amendment to Amended and Restated Credit Agreement dated July 28, 2006
     
**10.6
 
Fifth Amendment to Amended and Restated Credit Agreement dated June 13, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 18, 2008††
     
**10.7
 
Sixth Amendment to Amended and Restated Credit Agreement dated April 14, 2009, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 17, 2009††
     
**10.8
 
Seventh Amendment to Amended and Restated Credit Agreement dated May 26, 2009, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 26, 2009††

 
 
60

 


Exhibit
Number
 
Description of Exhibit
**10.9
 
Eighth Amendment to Amended and Restated Credit Agreement dated April 29, 2010, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 5, 2010††
     
**10.10
 
Second Amended and Restated Credit Agreement dated as of November 29, 2010, among Clayton Williams Energy, Inc., as Borrower, certain Subsidiaries of Clayton Williams Energy, Inc., as Guarantors, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 2, 2010††
     
**10.11†
 
Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68316
     
**10.12†
 
First Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.13 to the Company’s Form 10-K for the period ended December 31, 1995††
     
**10.13†
 
Second Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.13 to the Company’s Form 10-K for the period ended December 31, 2005††
     
**10.14†
 
Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68316
     
**10.15†
 
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
 
Amendment to Second Amended and Restated Service Agreement effective January 1, 2008 among Clayton Williams Energy, Inc. and its subsidiaries, Clayton Williams, Jr., Clayton Williams Ranch Holdings, Inc., ClayDesta L.P., The Williams Children’s Partnership, Ltd. and CWPLCO, Inc.††
     
**10.25†
 
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††

 
 
61

 


Exhibit
Number
 
Description of Exhibit
**10.26†
 
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††
     
**10.27†
 
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††
     
**10.28†
 
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††
     
**10.29†
 
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††
     
**10.30†
 
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††
     
**10.31†
 
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††
     
**10.32†
 
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††
**10.33†
 
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††
     
**10.34†
 
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†
 
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††
     
**10.36†
 
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††
     
**10.37†
 
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††
     
**10.38†
 
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††
     
**10.39†
 
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††
     
**10.40†
 
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††
     
**10.41†
 
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††
     
**10.42†
 
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††
     
**10.43†
 
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††
     
**10.44†
 
Form of Notice of Bonus Award Under the Southwest Royalties Reward Plan, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on January 18, 2007††
     

 
 
62

 


Exhibit
Number
 
Description of Exhibit
**10.45†
 
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††
     
**10.46†
 
Participation Agreement relating to RMS/Warnick dated April 10, 2007, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 13, 2007††
     
**10.47†
 
Participation Agreement relating to East Texas Bossier – Big Bill Simpson dated December 17, 2007, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2007††
     
**10.48†
 
Participation Agreement relating to East Texas Bossier – Margarita dated December 17, 2007, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2007††
     
**10.49†
 
Amaker Tippett Reward Plan dated June 19, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
     
**10.50†
 
Austin Chalk Reward Plan dated June 19, 2008, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
     
**10.51†
 
Barstow Area Reward Plan dated June 19, 2008, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
     
**10.52†
 
Participation Agreement relating to CWEI Andrews Area dated June 19, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
     
**10.53†
 
Participation Agreement relating to CWEI Crockett County Area dated June 19, 2008, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
     
**10.54†
 
Participation Agreement relating to CWEI North Louisiana Bossier III dated June 19, 2008, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
     
**10.55†
 
Participation Agreement relating to CWEI North Louisiana Hosston/Cotton Valley III dated June 19, 2008, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
     
**10.56†
 
Participation Agreement relating to CWEI South Louisiana VI dated June 19, 2008, filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
     
**10.57†
 
Participation Agreement relating to CWEI Utah dated June 19, 2008, filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
     
**10.58†
 
Participation Agreement relating to CWEI Sacramento Basin I dated August 12, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on August 14, 2008††
     
**10.59†
 
Form of Director Indemnification Agreement
     
**10.60†
 
Participation Agreement relating to CWEI East Texas Bossier - Sunny dated November 19, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on November 20, 2008††
     
**10.61†
 
Fuhrman-Mascho Reward Plan dated December 1, 2009, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 2, 2009††
     
**10.62†
 
Employment Agreement by and between Clayton Williams Energy, Inc. and Clayton W. Williams, Jr., effective as of March 1, 2010, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 18, 2010††

 
 
63

 


Exhibit
Number
 
Description of Exhibit
**10.63†
 
Employment Agreement by and between Clayton Williams Energy, Inc. and Mel G. Riggs, effective as of March 1, 2010, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on March 18, 2010††
     
**10.64†
 
Employment Agreement by and between Clayton Williams Energy, Inc. and Patrick C. Reesby, effective as of March 1, 2010, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on March 18, 2010††
     
**10.65†
 
Employment Agreement by and between Clayton Williams Energy, Inc. and Michael L. Pollard, effective as of March 1, 2010, filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Commission on March 18, 2010††
     
**10.66†
 
Employment Agreement by and between Clayton Williams Energy, Inc. and Greg S. Welborn, effective as of March 1, 2010, filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K filed with the Commission on March 18, 2010††
     
**10.67†
 
Employment Agreement by and between Clayton Williams Energy, Inc. and T. Mark Tisdale, effective as of March 1, 2010, filed as Exhibit 10.7 to the Company’s Current Report on Form 8-K filed with the Commission on March 18, 2010††
     
**10.68†
 
CWEI Andrews Fee Reward Plan dated October 19, 2010, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on October 22, 2010††
     
**10.69†
 
CWEI Andrews Samson Reward Plan dated October 19, 2010, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on October 22, 2010††
     
**10.70†
 
CWEI Austin Chalk Reward Plan II dated October 19, 2010, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on October 22, 2010††
     
*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
     
*99.1
 
Report of Williamson Petroleum Consultants, Inc. independent consulting engineers
     
*99.2
 
Report of Ryder Scott Company, L.P. independent consulting engineers
                  
*             Filed herewith
**           Incorporated by reference to the filing indicated
***         Furnished herewith
†             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.

 
 
64

 

GLOSSARY OF TERMS

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

    3-D seismic.  An advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

    BOE.  Means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis.  Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid.

    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 for the production of oil or gas.

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

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

    Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

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

    Economically producible.  A resource that generates revenue that exceeds, or is reasonably expected to exceed, the cost of the operation.

    Exploratory well.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

    Extensions and discoveries.  As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.

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

    Horizontal drilling.  A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

    MBbls.  One thousand barrels.

    MBOE.  One thousand BOEs.

    Mcf.  One thousand cubic feet.

    Mcfe.  One thousand cubic feet of natural gas equivalents, based on a ratio of 6 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 temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

    MMBOE.  One million BOEs.

    MMcf.  One million cubic feet.

 
 
65

 


    MMcfe.  One million cubic feet of natural gas equivalents.

    Natural gas liquids.  Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.

    Net acres or wells.  Refers to gross the sum of fractional ownership working interest in gross acres or wells.

    Net production.  Oil and gas production that is owned by the Company, less royalties and production due others.

    NYMEX.  New York Mercantile Exchange, the exchange on which commodities, including crude oil and natural gas futures contracts, are traded.

    Oil.  Crude oil or condensate.

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

    Present value of proved reserves (“PV-10”).  The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, (ii) nonproperty related expenses such as general and administrative expenses, debt service and future income tax expense, or (iii) depreciation, depletion and amortization.

    Productive wells. Producing wells and wells mechanically capable of production.

    Proved Developed Reserves.  Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

    Proved reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.  (i) The area of the reservoir considered as proved includes:  (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.  (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.  (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.  (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:  (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including government entities.


 
 
66

 


    Proved undeveloped reserves (PUD).  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.  (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.  (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

    Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.  (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.  (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.  (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proves reserves.

    Royalty.  An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage.  Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner 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 adjusted to give effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, and (ii) estimated future income taxes.

    Undeveloped acreage.  Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas, regardless of whether such acreage contains proved reserves.

    Working interest.  An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.  The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.

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

 
 
67

 


    Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by 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


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature
 
Title
 
Date
         
/s/ CLAYTON W. WILLIAMS *
 
Chairman of the Board,
 
February 28, 2011
Clayton W. Williams
 
President and Chief Executive
   
   
Officer and Director
   
         
/s/ MEL G. RIGGS
 
Executive Vice President,
 
February 28, 2011
Mel G. Riggs
 
Chief Operating Officer and
   
   
Director
   
         
/s/ MICHAEL L. POLLARD
 
Senior Vice President -
 
February 28, 2011
Michael L. Pollard
 
Finance, Chief Financial Officer
   
   
and Treasurer
   
         
/s/ ROBERT L. THOMAS
 
Vice President – Accounting and
 
February 28, 2011
Robert L. Thomas
 
Principal Accounting Officer
   
         
/s/ TED GRAY, JR.*
 
Director
 
February 28, 2011
Ted Gray, Jr.
       
         
/s/ DAVIS L. FORD *
 
Director
 
February 28, 2011
Davis L. Ford
       
         
/s/ ROBERT L. PARKER *
 
Director
 
February 28, 2011
Robert L. Parker
       
         
/s/ JORDAN R. SMITH *
 
Director
 
February 28, 2011
Jordan R. Smith
       
         
*        By:  /s/ MEL G. RIGGS
       
Mel G. Riggs
       
Attorney-in-Fact
       








 
 
68

 

CLAYTON WILLIAMS ENERGY, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULE


   
Page
Report of Independent Registered Public Accounting Firm                                                                                                                     
 
F-2
Consolidated Balance Sheets                                                                                                                     
 
F-3
Consolidated Statements of Operations                                                                                                                     
 
F-5
Consolidated Statements of Comprehensive Income (Loss)                                                                                                                     
 
F-6
Consolidated Statements of Equity                                                                                                                     
 
F-7
Consolidated Statements of Cash Flows                                                                                                                     
 
F-8
Notes to Consolidated Financial Statements                                                                                                                     
 
F-9
Schedule II—Valuation and Qualifying Accounts                                                                                                                 
 
S-1



 
 
F-1

 




REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
Clayton Williams Energy, Inc.:

We have audited the accompanying consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries (the Company) as of December 31, 2010 and 2009, and the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the years in the three-year period ended December 31, 2010.  In connection with our audits of the consolidated financial statements, we also have audited the accompanying financial statement schedule.  These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these consolidated financial statements and the financial statement schedule based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.  Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Clayton Williams Energy, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2011, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.



/s/ KPMG LLP

Dallas, Texas
February 28, 2011

 
 
F-2

 

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

ASSETS
 
   
December 31,
 
   
2010
   
2009
 
CURRENT ASSETS
           
Cash and cash equivalents                                                                                     
  $ 8,720     $ 14,013  
Accounts receivable:
               
Oil and gas sales                                                                                
    35,361       28,721  
Joint interest and other, net                                                                                
    9,893       6,669  
Affiliates                                                                                
    796       624  
Inventory                                                                                     
    39,218       43,068  
Deferred income taxes                                                                                     
    5,074       1,362  
Assets held for sale                                                                                     
    8,762       7,411  
Prepaids and other                                                                                     
    5,997       1,729  
      113,821       103,597  
PROPERTY AND EQUIPMENT
               
Oil and gas properties, successful efforts method                                                                                     
    1,707,252       1,579,664  
Natural gas gathering and processing systems                                                                                     
    18,153       17,816  
Contract drilling equipment                                                                                     
    58,486       41,533  
Other                                                                                     
    17,425       16,550  
      1,801,316       1,655,563  
Less accumulated depreciation, depletion and amortization
    (1,034,227 )     (985,517 )
Property and equipment, net                                                                                
    767,089       670,046  
                 
OTHER ASSETS
               
Debt issue costs, net                                                                                     
    8,323       4,874  
Fair value of derivatives                                                                                     
    -       4,427  
Other                                                                                     
    1,684       1,660  
      10,007       10,961  
    $ 890,917     $ 784,604  





















The accompanying notes are an integral part of these consolidated financial statements.

 
 
F-3

 

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
   
December 31,
 
   
2010
   
2009
 
CURRENT LIABILITIES
           
Accounts payable:
           
Trade                                                                                
  $ 74,123     $ 47,211  
Oil and gas sales                                                                                
    28,920       18,063  
Affiliates                                                                                
    1,251       1,097  
Fair value of derivatives                                                                                     
    7,224       5,907  
Accrued liabilities and other                                                                                     
    22,202       11,995  
      133,720       84,273  
NON-CURRENT LIABILITIES
               
Long-term debt                                                                                     
    385,000       395,000  
Deferred income taxes                                                                                     
    78,035       54,065  
Fair value of derivatives                                                                                     
    3,409       -  
Other                                                                                     
    41,301       38,991  
      507,745       488,056  
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 – 12,154,536 shares in 2010
               
 and 12,145,536 shares in 2009                                                                                     
    1,215       1,215  
Additional paid-in capital                                                                                     
    152,290       152,051  
Retained earnings                                                                                     
    95,947       59,009  
      249,452       212,275  
    $ 890,917     $ 784,604  





















The accompanying notes are an integral part of these consolidated financial statements.

 
 
F-4

 

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share)

   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
REVENUES
                 
Oil and gas sales                                                                      
  $ 326,320     $ 242,338     $ 463,964  
Natural gas services                                                                      
    1,631       6,146       10,926  
Drilling rig services                                                                      
    -       6,681       46,124  
Gain on sales of assets                                                                      
    3,680       796       44,503  
Total revenues                                                                
    331,631       255,961       565,517  
                         
COSTS AND EXPENSES
                       
Production                                                                      
    83,146       76,288       89,054  
Exploration:
                       
Abandonments and impairments                                                                
    9,074       78,798       80,112  
Seismic and other                                                                
    6,046       8,189       22,685  
Natural gas services                                                                      
    1,209       5,348       10,060  
Drilling rig services                                                                      
    1,198       10,848       37,789  
Depreciation, depletion and amortization                                                                      
    101,145       129,658       120,542  
Impairment of property and equipment                                                                      
    11,908       59,140       12,882  
Accretion of abandonment obligations                                                                      
    2,623       3,120       2,355  
General and administrative                                                                      
    35,588       20,715       25,635  
Loss on sales of assets and impairment of inventory
    1,750       5,282       2,122  
Total costs and expenses                                                                
    253,687       397,386       403,236  
Operating income (loss)                                                                
    77,944       (141,425 )     162,281  
OTHER INCOME (EXPENSE)
                       
Interest expense                                                                      
    (24,402 )     (23,758 )     (24,994 )
Gain (loss) on derivatives                                                                      
    722       (17,416 )     74,743  
Other                                                                      
    3,308       2,543       6,539  
Total other income (expense)                                                                
    (20,372 )     (38,631 )     56,288  
Income (loss) before income taxes                                                                           
    57,572       (180,056 )     218,569  
Income tax (expense) benefit                                                                           
    (20,634 )     64,096       (77,327 )
NET INCOME (LOSS)                                                                           
    36,938       (115,960 )     141,242  
Less income attributable to
                       
noncontrolling interest, net of tax                                                                
    -       (1,455 )     (708 )
NET INCOME (LOSS) attributable to Clayton
                       
Williams Energy, Inc.                                                                      
  $ 36,938     $ (117,415 )   $ 140,534  
Net income (loss) per common share attributable to
                       
Clayton Williams Energy, Inc. stockholders:
                       
Basic                                                                      
  $ 3.04     $ (9.67 )   $ 11.78  
Diluted                                                                      
  $ 3.04     $ (9.67 )   $ 11.67  
                         
Weighted average common shares outstanding:
                       
Basic                                                                      
    12,148       12,138       11,932  
Diluted                                                                      
    12,148       12,138       12,039  
                         







The accompanying notes are an integral part of these consolidated financial statements.

 
 
F-5

 


CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)



   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
Net income (loss) attributable to
                 
Clayton Williams Energy, Inc.                                                                
  $ 36,938     $ (117,415 )   $ 140,534  
Unrealized gain on marketable securities, net of tax
                       
$2,015 in 2008                                                                   
    -       -       3,742  
Total comprehensive income (loss)                                                                
  $ 36,938     $ (117,415 )   $ 144,276  
                         













































The accompanying notes are an integral part of these consolidated financial statements.

 
 
F-6

 



CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)

   
Clayton Williams Energy, Inc. Stockholders’ Equity
       
                           
Accumulated
       
                           
Other
       
   
Common Stock
   
Additional
         
Compre-
   
Non-
 
   
No. of
   
Par
   
Paid-In
   
Retained
   
hensive
   
Controlling
 
   
Shares
   
Value
   
Capital
   
Earnings
   
Income
   
Interest
 
BALANCE,
                                   
December 31, 2007                                  
    11,354     $ 1,135     $ 121,063     $ 35,890     $ 2,718     $ 4,886  
Net income                                
    -       -       -       140,534       -       708  
Unrealized gain on
                                               
  marketable securities,
                                               
  net of tax of $2,015
    -       -       -       -       3,742       -  
Reclassification adjustment for
                                               
  securities gains included
                                               
  in income, net of tax of $3,479
    -       -       -       -       (6,460 )     -  
Issuance of stock through
                                               
  compensation plans, including
                                               
  income tax benefits
    762       77       15,983       -       -       -  
BALANCE,
                                               
December 31, 2008                                  
    12,116       1,212       137,046       176,424       -       5,594  
Net income (loss)                                
    -       -       -       (117,415 )     -       1,455  
Issuance of stock through
                                               
  compensation plans, including
                                               
  income tax benefits
    30       3       173       -       -       -  
Acquisition of noncontrolling
                                               
  interest                                
    -       -       14,832       -       -       (7,049 )
BALANCE,
                                               
December 31, 2009                                  
    12,146       1,215       152,051       59,009       -       -  
Net income                                
    -       -       -       36,938       -       -  
Issuance of stock through
                                               
  compensation plans, including
                                               
  income tax benefits
    9       -       239       -       -       -  
BALANCE,
                                               
December 31, 2010                                  
    12,155     $ 1,215     $ 152,290     $ 95,947     $ -     $ -  
                                                 






















The accompanying notes are an integral part of these consolidated financial statements.

 
 
F-7

 

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
 

   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
CASH FLOWS FROM OPERATING ACTIVITIES
                 
Net income (loss)                                                                           
  $ 36,938     $ (115,960 )   $ 141,242  
Adjustments to reconcile net income (loss) to cash
                       
   provided by operating activities:
                       
Depreciation, depletion and amortization                                                                     
    101,145       129,658       120,542  
Impairment of property and equipment                                                                     
    11,908       59,140       12,882  
Exploration costs                                                                     
    9,074       78,798       80,112  
(Gain) loss on sales of assets and impairment of inventory, net
    (1,930 )     4,486       (42,381 )
Deferred income tax expense (benefit)                                                                     
    20,259       (64,220 )     77,315  
Non-cash employee compensation                                                                     
    13,898       1,434       5,834  
Unrealized (gain) loss on derivatives                                                                     
    9,153       1,480       (49,738 )
Settlements on derivatives with financing elements
    -       -       43,486  
Amortization of debt issue costs                                                                     
    1,648       1,458       1,354  
Accretion of abandonment obligations                                                                     
    2,623       3,120       2,355  
Changes in operating working capital:
                       
Accounts receivable                                                                     
    (10,036 )     4,571       13,087  
Accounts payable                                                                     
    19,144       (19,590 )     (4,946 )
Other                                                                     
    (5,573 )     20,336       (19,164 )
Net cash provided by operating activities
    208,251       104,711       381,980  
CASH FLOWS FROM INVESTING ACTIVITIES
                       
Additions to property and equipment                                                                           
    (285,655 )     (142,623 )     (351,789 )
Proceeds from sales of assets                                                                           
    77,216       729       117,226  
Change in equipment inventory                                                                           
    4,638       (26,675 )     (8,247 )
Other                                                                           
    18       (29 )     3,935  
Net cash used in investing activities                                                               
    (203,783 )     (168,598 )     (238,875 )
CASH FLOWS FROM FINANCING ACTIVITIES
                       
Proceeds from long-term debt                                                                           
    -       75,900       7,500  
Repayments of long-term debt                                                                           
    (10,000 )     (39,375 )     (94,200 )
Proceeds from exercise of stock options                                                                           
    239       176       15,936  
Settlements on derivatives with financing elements
    -       -       (43,486 )
Net cash provided by (used in) financing activities
    (9,761 )     36,701       (114,250 )
NET INCREASE (DECREASE) IN CASH AND
                       
  CASH EQUIVALENTS                                                                                
    (5,293 )     (27,186 )     28,855  
CASH AND CASH EQUIVALENTS
                       
Beginning of period                                                                           
    14,013       41,199       12,344  
End of period                                                                           
  $ 8,720     $ 14,013     $ 41,199  
SUPPLEMENTAL DISCLOSURES
                       
Cash paid for interest, net of amounts capitalized
  $ 22,457     $ 23,349     $ 24,027  
Cash paid for income taxes                                                                           
  $ -     $ -     $ 16,652  








 
The accompanying notes are an integral part of these consolidated financial statements.

 
 
F-8

 

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
 
1.             Nature of Operations

Clayton Williams Energy, Inc. (a Delaware corporation), is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in its core areas in Texas, Louisiana and New Mexico.  Unless the context otherwise requires, references to “CWEI” mean Clayton Williams Energy, Inc., the parent company, and references to the “Company”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries.  Approximately 26% of the Company’s outstanding common stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board and Chief Executive Officer of the Company, and approximately 25% is owned by a partnership in which Mr. Williams’ adult children are limited partners.

Substantially all of our oil and gas production is sold under short-term contracts which are market-sensitive.  Accordingly, our results of operations and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control.  These factors include the level of global supply and demand for oil and natural gas, market uncertainties, weather conditions, domestic governmental regulations and taxes, political and economic conditions in oil producing countries, price and availability of alternative fuels, and overall domestic and foreign economic conditions.

2.             Summary of Significant Accounting Policies

    Estimates and Assumptions
    The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.  Actual results could differ materially from those estimates.  The accounting policies most affected by management’s estimates and assumptions are as follows:

·  
Provisions for depreciation, depletion and amortization and estimates of non-equity plans are based on estimates of proved reserves;

·  
Impairments of long-lived assets are based on estimates of future net cash flows and, when applicable, the estimated fair values of impaired assets;

·  
Exploration expenses related to impairments of unproved acreage are based on estimates of fair values of the underlying leases;

·  
Impairments of inventory are based on estimates of fair values of tubular goods and other well equipment held in inventory;

·  
Exploration expenses related to well abandonment costs are based on the judgments regarding the productive status of in-progress exploratory wells; and

·  
Abandonment obligations are based on estimates regarding the timing and cost of future asset abandonments.

    Principles of Consolidation
    The consolidated financial statements include the accounts of CWEI and its wholly-owned subsidiaries.  We also account for our undivided interests in oil and gas limited partnerships using the proportionate consolidation method.  Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of these limited partnerships.  Less than 5% of the Company’s consolidated total assets and total revenues are derived from oil and gas limited partnerships.  All significant intercompany transactions and balances associated with the consolidated operations have been eliminated.


 
 
F-9

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
 
    Oil and Gas Properties
    We follow the successful efforts method of accounting for oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities.  These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves.  Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned.

    Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred.  Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive.  The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities.  The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.

    Natural Gas Systems and Other Property and Equipment
    Natural gas gathering and processing systems consist primarily of gas gathering pipelines, compressors and gas processing plants.  Other property and equipment consists primarily of field equipment and facilities, office equipment, leasehold improvements and vehicles.  Major renewals and betterments are capitalized while repairs and maintenance are charged to expense as incurred.  The cost of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and any gain or loss is included in operating income in the accompanying consolidated statements of operations.

    Depreciation of natural gas gathering and processing systems and other property and equipment is computed on the straight-line method over the estimated useful lives of the assets, which generally range from 3 to 20 years.

    Contract Drilling
    We conduct contract drilling operations through Desta Drilling (see Note 10), formerly referred to as Larclay JV.  Desta Drilling recognizes revenues and expenses from daywork drilling contracts as the work is performed, but defers revenues and expenses from footage or turnkey contracts until the well is substantially completed or until a loss, if any, on a contract is determinable.

    Property and equipment, including major replacements, improvements and capitalized interest on construction-in-progress, are capitalized and are depreciated using the straight-line method over estimated useful lives of 3 to 7 years.  Upon disposition, the costs and related accumulated depreciation of assets are eliminated from the accounts and the resulting gain or loss is recognized.

    Valuation of Property and Equipment
    Our long-lived assets, including proved oil and gas properties and contract drilling equipment, are assessed for potential impairment in their carrying values, based on depletable groupings, whenever events or changes in circumstances indicate such impairment may have occurred.  An impairment is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value.  Any such impairment is recognized based on the difference in the carrying value and estimated fair value of the impaired asset.

    Unproved oil and gas properties are periodically assessed, and any impairment in value is charged to exploration costs.  The amount of impairment recognized on unproved properties which are not individually significant is determined by impairing the costs of such properties within appropriate groups based on our historical experience, acquisition dates and average lease terms.  The valuation of unproved properties is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.

    Abandonment Obligations
    We recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset.  The cost associated with the abandonment obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.

 
 
F-10

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 

 
    Income Taxes
    We utilize the asset and liability method to account for income taxes.  Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in income in the period that includes the enactment date.  We also record any financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return.  Financial statement recognition of the tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position.  Any interest and penalties related to uncertain tax positions are recorded as interest expense. 

    Hedging Activities
    From time to time, we utilize derivative instruments, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production.  All of our derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value.  The accounting for changes in the fair value of a derivative depends on both the intended purpose and the formal designation of the derivative.  Designation is established at the inception of a derivative, but subsequent changes to the designation are permitted.  For derivatives designated as cash flow hedges and meeting the effectiveness guidelines under applicable accounting standards, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings.  Hedge effectiveness is measured quarterly based on relative changes in fair value between the derivative contract and the hedged item over time.  Any change in fair value resulting from ineffectiveness is recognized immediately in earnings.  Changes in fair value of derivative instruments which are not designated as cash flow hedges or do not meet the effectiveness guidelines are recorded in earnings as the changes occur.  If designated as cash flow hedges, actual gains or losses on settled commodity derivatives are recorded as oil and gas revenues in the period the hedged production is sold, while actual gains or losses on interest rate derivatives are recorded in interest expense for the applicable period.  Actual gains or losses from derivatives not designated as cash flow hedges are recorded in other income (expense) as gain (loss) on derivatives.

    Inventory
    Inventory consists primarily of tubular goods and other well equipment which we plan to utilize in our exploration and development activities and is stated at the lower of average cost or estimated market value.

    Capitalization of Interest
    Interest costs associated with our inventory of unproved oil and gas property lease acquisition costs are capitalized during the periods for which exploration activities are in progress.  During the years ended December 31, 2010, 2009 and 2008, we capitalized interest totaling approximately $493,000, $698,000 and $3.8 million, respectively.

    Cash and Cash Equivalents
    We consider all cash and highly liquid investments with original maturities of three months or less to be cash equivalents.

    Net Income (Loss) Per Common Share
    Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period.  Diluted net income per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method.  The diluted net income per share calculations for 2010 and 2008 include changes in potential shares attributable to dilutive stock options.

    Marketable Securities
    All marketable equity securities are included in other non-current assets and are considered available-for-sale securities carried at fair value. The unrealized gains and losses related to these securities are included in accumulated other comprehensive income.  The fair values are based on quoted market prices.


 
 
F-11

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


    Stock-Based Compensation
    We measure and recognize compensation expense for all share-based payment awards, including employee stock options, based on estimated fair values. The value of the portion of the award that is ultimately expected to vest is recognized as expense on a straight-line basis over the requisite service periods, if any.

    We estimate the fair value of stock option awards on the date of grant using an option-pricing model.  We use the Black-Scholes option-pricing model (“Black-Scholes Model”) as our method of valuation for share-based awards granted on or after January 1, 2006.  Our determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price, as well as assumptions regarding a number of subjective variables.  These variables include, but are not limited to, our expected stock price volatility over the term of the awards, as well as actual and projected exercise and forfeiture activity.

    Fair Value Measurements
    We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.  Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.  We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities are as follows:

            Level 1 -
Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
   
            Level 2 -
Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

            Level 3 -
Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

    Revenue Recognition and Gas Balancing
    We utilize the sales method of accounting for oil, natural gas and natural gas liquids revenues whereby revenues, net of royalties, are recognized as the production is sold to purchasers.  The amount of gas sold may differ from the amount to which we are entitled based on our revenue interests in the properties.  We did not have any significant gas imbalance positions at December 31, 2010 or 2009.  Revenues from natural gas services are recognized as services are provided.

    Comprehensive Income
    There were no differences between net income and comprehensive income in 2010 and 2009.  In 2008, we reported an unrealized gain on marketable securities as comprehensive income.

    Concentration Risks
    We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties.  When management deems appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties.  Allowances for doubtful accounts at December 31, 2010 and 2009 relate to amounts due from joint interest owners.

    Reclassifications
    To the extent necessary, reclassifications of prior year financial statement amounts are made to conform to current year presentations.

 
 
F-12

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


    Adopted Accounting Pronouncements
In June 2009, the FASB issued accounting guidance on the consolidation of variable interest entities (“VIEs”). This new guidance revises previous guidance by replacing the quantitative-based risks and rewards calculation for determining which enterprise, if any, has a controlling financial interest in a VIE with a qualitative approach focused on identifying which enterprise has both the power to direct the activities of the VIE that most significantly impacts the entity’s economic performance and has the obligation to absorb losses or the right to receive benefits that could be significant to the entity. In addition, this guidance requires reconsideration of whether an entity is a VIE when any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of the entity that most significantly impact the entity’s economic performance. It also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE and additional disclosures about an enterprise’s involvement in variable interest entities. This guidance is effective for fiscal years beginning after November 15, 2009.  Our adoption of the new guidance during the first quarter of 2010 did not have a material effect on our consolidated financial statements.

3.             Long-Term Debt

    Long-term debt consists of the following:
   
December 31,
   
December 31,
 
   
2010
   
2009
 
   
(In thousands)
 
7¾% Senior Notes due 2013
  $ 225,000     $ 225,000  
Secured bank credit facility, due November 2015
    160,000       170,000  
    $ 385,000     $ 395,000  

    Aggregate maturities of long-term debt at December 31, 2010 are as follows: 2013 - $225 million, 2015- $160 million.

    7¾% Senior Notes due 2013
In July 2005, we issued $225 million of aggregate principal amount of 7¾% Senior Notes due 2013 (“Senior Notes”).  The Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006.

We may redeem some or all of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 101.938% for the twelve-month period beginning on August 1, 2010, and 100% beginning on August 1, 2011 or for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing the Senior Notes contains covenants that restrict our ability to:  (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business.  One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) exceeds 2.5 to 1 for the four most recently completed fiscal quarters.  However, this restriction does not prevent us from borrowing funds under the revolving credit facility provided that our outstanding balance on the facility does not exceed the greater of $150 million and 30% of Adjusted Consolidated Net Tangible Assets (as defined in the Indenture).  These covenants are subject to a number of important exceptions and qualifications as described in the Indenture.  We were in compliance with these covenants at December 31, 2010.


 
 
F-13

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
 
Secured Bank Credit Facility
In November 2010, we amended and restated our secured bank credit facility with a syndicate of banks to provide for a revolving line of credit of up to $500 million, limited to the amount of a borrowing base as determined by the banks.  The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November.  We or the banks may also request an unscheduled borrowing base redetermination at other times during the year.  If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency (or by a combination of such additional security and such prepayment eliminate such deficiency), or (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest.  The borrowing base was $350 million at December 31, 2010.  After allowing for outstanding letters of credit totaling $2 million, we had $188 million available under the credit facility at December 31, 2010.

The revolving credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in the revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base.  The obligations under the revolving credit facility are guaranteed by each of CWEI’s material domestic subsidiaries.

At our election, annual interest rates under the revolving credit facility are determined by reference to (1) LIBOR plus an applicable margin between 2% and 3% per year or (2) if an alternate base rate loan, the greatest of (A) the prime rate, (B) the federal funds rate plus 0.5%, or (C) one-month LIBOR plus 1% plus, if any of (A), (B) or (C), an applicable margin between 1% and 2%.  We also pay a commitment fee on the unused portion of the revolving credit facility at a flat rate of .5%.  Interest and fees are payable no less often than quarterly.  The effective annual interest rate on borrowings under the revolving credit facility, excluding bank fees and amortization of debt issue costs, for the twelve months ended December 31, 2010 was 3%.

The revolving credit facility also contains various covenants and restrictive provisions which may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens.  One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1.  Another financial covenant prohibits the ratio of our consolidated funded indebtedness to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1.  The computations of consolidated current assets, current liabilities, EBITDAX and indebtedness are defined in the loan agreement.  We were in compliance with all financial and non-financial covenants at December 31, 2010.

4.             Other Non-Current Liabilities

    Other non-current liabilities at December 31, 2010 and 2009 consist of the following:

   
2010
   
2009
 
   
(In thousands)
 
Abandonment obligations                                                                                   
  $ 40,444     $ 38,412  
Other                                                                                   
    857       579  
    $ 41,301     $ 38,991  

    Abandonment Obligations
    Changes in abandonment obligations for 2010 and 2009 are as follows:

   
2010
   
2009
 
   
(In thousands)
 
Beginning of year                                                                                   
  $ 38,412     $ 31,737  
Additional abandonment obligations from new properties
    1,786       1,654  
Sales or abandonments of properties                                                                               
    (2,057 )     (293 )
Accretion expense                                                                               
    2,623       3,120  
Revisions of previous estimates                                                                               
    (320 )     2,194  
End of year                                                                                   
  $ 40,444     $ 38,412  

    Our asset retirement obligation is measured using primarily Level 3 inputs.  The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life.  The inputs are calculated based on historical data as well as current estimated costs.

 
 
F-14

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
 
5.             Income Taxes

    Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax basis of assets and liabilities.  Significant components of net deferred tax assets (liabilities) at December 31, 2010 and 2009 are as follows:

   
2010
   
2009
 
   
(In thousands)
 
Deferred tax assets:
           
Net operating loss carryforwards                                                                                
  $ 27,156     $ 24,275  
Fair value of derivatives                                                                                
    3,536       518  
Statutory depletion carryforwards                                                                                
    7,075       6,589  
Abandonment obligations and other                                                                                
    16,451       11,389  
      54,218       42,771  
Deferred tax liabilities:
               
Property and equipment                                                                                
    (127,179 )     (95,474 )
      (127,179 )     (95,474 )
Net deferred tax liabilities                                                                                     
  $ (72,961 )   $ (52,703 )
                 
Components of net deferred tax liabilities:
               
Current assets                                                                                
  $ 5,074     $ 1,362  
Non-current liabilities                                                                                
    (78,035 )     (54,065 )
    $ (72,961 )   $ (52,703 )

For the years ended December 31, 2010, 2009 and 2008, effective income tax rates were different than the statutory federal income tax rates for the following reasons:

   
2010
   
2009
   
2008
 
   
(In thousands)
 
                   
Income tax expense (benefit) at statutory rate of 35%
  $ 20,150     $ (63,020 )   $ 76,500  
Tax depletion in excess of basis                                                              
    (490 )     (388 )     (700 )
Revision of previous tax estimates                                                              
    8       (130 )     55  
State income taxes, net of federal tax effect
    884       (655 )     1,375  
Other
    82       97       97  
Income tax expense (benefit)                                                       
  $ 20,634     $ (64,096 )   $ 77,327  
                         
Current                                                              
  $ 375     $ 124     $ 12  
Deferred                                                              
    20,259       (64,220 )     77,315  
Income tax expense (benefit)                                                       
  $ 20,634     $ (64,096 )   $ 77,327  

    We derive a tax deduction when employees and directors exercise options granted under our stock option plans.  To the extent these tax deductions are used to reduce currently payable taxes in any period, we record a tax benefit for the excess of the tax deduction over cumulative book compensation expense as additional paid-in capital and as a financing cash flow in the accompanying consolidated financial statements.  At December 31, 2010, our cumulative tax loss carryforwards were approximately $99 million, of which $21.4 million relates to excess tax benefits from exercise of stock options.

The Company and its subsidiaries file federal income tax returns with the United States Internal Revenue Service (“IRS”) and state income tax returns in various state tax jurisdictions.  As a general rule, the Company’s tax returns for fiscal years after 2006 currently remain subject to examination by appropriate taxing authorities.  None of our income tax returns are under examination at this time.

In December 2008, we made an estimated federal income tax payment of $16 million.  Since we reported a net operating loss on our 2008 federal income tax return, we received a refund of $16 million in 2009.


 
 
F-15

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
 
In 2007, we recorded a liability for taxes payable related to unrecognized tax benefits arising from uncertain tax positions taken by the Company in previous periods.  A reconciliation of the changes in this tax liability during the years ended December 31, 2010 and December 31, 2009 is as follows in thousands:

Balance at December 31, 2008                                                                                   
  $ 144  
Reductions for tax positions of prior years                                                                                
    (144 )
Balance at December 31, 2009                                                                                   
    -  
Reductions for tax positions of prior years                                                                                
    -  
Balance at December 31, 2010                                                                                   
  $ -  

No unrecognized tax benefits originated during 2010 or 2009.

6.             Derivatives

    Commodity Derivatives
    From time to time, we utilize commodity derivatives, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production.  When using swaps to hedge oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty.  In floor transactions, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity.  If the market price is greater than the put strike price, no payments are due from either party.  Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price).  If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price.  If the market price is between the call and the put strike prices, no payments are due from either party. Commodity derivatives are settled monthly as the contract production periods mature.

    The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 2010.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:
   
Oil
   
Gas
 
   
Bbls
   
Price
   
MMBtu (a)
   
Price
 
Production Period:
                       
1st Quarter 2011                              
    657,000     $ 83.74       1,710,000     $ 7.07  
2nd Quarter 2011                              
    632,000     $ 83.71       1,650,000     $ 7.07  
3rd Quarter 2011                              
    547,000     $ 83.78       1,560,000     $ 7.07  
4th Quarter 2011                              
    540,000     $ 83.78       1,500,000     $ 7.07  
2012                              
    1,170,000     $ 90.65       -     $ -  
      3,546,000               6,420,000          
                                              
(a)    One MMBtu equals one Mcf at a Btu factor of 1,000.
 

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives.  A $1 per barrel change in the price of oil and a $.50 per MMBtu change in the price of gas would change the fair value of our outstanding commodity derivatives at December 31, 2010 by approximately $5.8 million.

    Accounting for Derivatives
    We did not designate any of our currently open commodity 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 our statements of operations.  For the year ended December 31, 2010, we reported a $722,000 net gain on derivatives, consisting of a $9.9 million gain for settled contracts and a $9.2 million loss related to changes in mark-to-market valuations.  For the year ended December 31, 2009, we reported a $17.4 million net loss on derivatives, consisting of a $15.9 million loss for settled contracts and a $1.5 million loss related to changes in mark-to-market valuations.


 
 
F-16

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
 
Effect of Derivative Instruments on the Consolidated Balance Sheets

 
Fair Value of Derivative Instruments as of December 31, 2010
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet
     
Balance Sheet
   
 
Location
 
Fair Value
 
Location
 
Fair Value
     
(In thousands)
     
(In thousands)
Derivatives not designated as
           
hedging instruments:
             
               
Commodity derivatives
Fair value of derivatives:
     
Fair value of derivatives:
   
 
Current
 
$                                 -
 
Current
 
$                                    7,224
 
Non-current
 
                                      -
 
Non-current
 
                                3,409
Total
   
$                                 -
     
$                                  10,633

 
Fair Value of Derivative Instruments as of December 31, 2009
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet
     
Balance Sheet
   
 
Location
 
Fair Value
 
Location
 
Fair Value
     
(In thousands)
     
(In thousands)
Derivatives not designated as
           
hedging instruments:
             
               
Commodity derivatives
Fair value of derivatives:
     
Fair value of derivatives:
   
 
Current
 
$                                      -
 
Current
 
$                                    5,907
 
Non-current
 
                                  4,427
 
Non-current
 
                               -
Total
   
$                              4,427
     
$                                    5,907

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

   
December 31, 2010
 
   
Assets
   
Liabilities
 
   
(In thousands)
 
Fair value of derivatives – gross presentation
  $ 16,051     $ 26,684  
Effects of netting arrangements
    (16,051 )     (16,051 )
Fair value of derivatives – net presentation
  $ -     $ 10,633  

   
December 31, 2009
 
   
Assets
   
Liabilities
 
   
(In thousands)
 
Fair value of derivatives – gross presentation
  $ 20,105     $ 21,585  
Effects of netting arrangements
    (15,678 )     (15,678 )
Fair value of derivatives – net presentation
  $ 4,427     $ 5,907  

All of our derivative contracts are with JPMorgan Chase Bank, N.A., which has a credit rating of AA- as determined by a nationally recognized statistical ratings organization.  We have elected to net the outstanding positions with this counterparty between current and noncurrent assets or liabilities.


Effect of Derivative Instruments on the Consolidated Statements of Operations

   
Amount of Gain or (Loss) Recognized in Earnings
       
Year Ended
   
Location of Gain or (Loss)
 
December 31,
   
Recognized in Earnings
 
2010
 
2009
       
(In thousands)
Derivatives not designated as
           
hedging instruments:
           
             
Commodity derivatives
 
Other income (expense) -
       
   
Gain (loss) on derivatives
 
$                                               722
 
$                                      (17,416)
Total
     
$                                               722
 
$                                      (17,416)


 
 
F-17

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
 
7.             Fair Value of Financial Instruments

    Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments.  Indebtedness under our secured bank credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive.  The estimated fair value of our Senior Notes at December 31, 2010 and 2009 was approximately $226 million and $198 million, respectively, based on market valuations.

    The only financial assets and liabilities measured on a recurring basis at December 31, 2010 and 2009 were commodity derivatives.  Information regarding these assets and liabilities at December 31, 2010 is summarized below:

   
December 31,
 
   
2010
   
2009
 
   
Significant Other
 
   
Observable Inputs
 
Description
 
(Level 2)
 
   
(In thousands)
 
Assets:
           
Fair value of commodity derivatives                                                                  
  $ -     $ 4,427  
Total assets                                                                    
  $ -     $ 4,427  
                 
Liabilities:
               
Fair value of commodity derivatives                                                                  
  $ 10,633     $ 5,907  
Total liabilities                                                                    
  $ 10,633     $ 5,907  

8.         Compensation Plans

Stock-Based Compensation
Initially, we reserved 86,300 shares of common stock for issuance under the Outside Directors Stock Option Plan (“Directors Plan”).  Since the inception of the Directors Plan, CWEI has issued options covering 52,000 shares of common stock at option prices ranging from $3.25 to $41.74 per share.  All outstanding options expire 10 years from the grant date and are fully exercisable upon issuance.  No options were granted under the Directors Plan in 2010.  At December 31, 2010, 15,000 options were outstanding under this plan.  In December 2009, the Board of Directors reduced the number of shares available for issuance under the Directors Plan to a level sufficient to cover only the remaining outstanding shares.

The following table sets forth certain information regarding our stock option plans as of and for the year ended December 31, 2010:

               
Weighted
       
         
Weighted
   
Average
       
         
Average
   
Remaining
   
Aggregate
 
         
Exercise
   
Contractual
   
Intrinsic
 
   
Shares
   
Price
   
Term
   
Value(a)
 
Outstanding at January 1, 2010
    24,000     $ 26.66              
Exercised (b) 
    9,000     $ 26.70              
Outstanding at December 31, 2010
    15,000     $ 26.64       4     $ 859,990  
                                 
Vested at December 31, 2010
    15,000     $ 26.64       4     $ 859,990  
Exercisable at December 31, 2010
    15,000     $ 26.64       4     $ 859,990  
                                        
(a)     Based on closing price at December 31, 2010 of $83.97 per share.
 
(b)     Cash received for options exercised totaled $240,280.
 

 
 
F-18

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
 
The following table summarizes information with respect to options outstanding at December 31, 2010, all of which were granted under the Directors Plan and are currently exercisable.

 
Outstanding and Exercisable Options
         
Weighted
     
Weighted
 
Average
     
Average
 
Remaining
     
Exercise
 
Life in
 
Shares
 
Price
 
Years
Range of exercise prices:
         
$12.14 - $13.10                                                               
4,000
 
$                         12.62
 
1.5
$22.90 - $41.74                                                               
11,000
 
$                         31.73
 
4.5
 
15,000
 
$                         26.64
 
3.7

The following table presents certain information regarding stock-based compensation amounts for the years ended December 31, 2010, 2009 and 2008.

   
2010
   
2009
   
2008
 
   
(In thousands, except per share)
 
Weighted average grant date fair value of options granted per share
  $ -     $ -     $ 23.06  
Intrinsic value of options exercised
  $ 261     $ 586     $ 20,480  
                         
Stock-based employee compensation expense
  $ -     $ -     $ 92  
Tax benefit
    -       -       (32 )
Net stock-based employee compensation expense
  $ -     $ -     $ 60  

    The fair value of stock options issued for each year was estimated at the date of grant using the Black-Scholes option pricing model.  The following weighted average assumptions were used in this model.

 
2010
 
2009
 
2008
Risk-free interest rate                                                                               
-
 
-
 
4%
Stock price volatility                                                                              
-
 
-
 
63%
Expected life in years                                                                              
-
 
-
 
10
Dividend yield                                                                              
-
 
-
 
-

Non-Equity Award Plans
The Compensation Committee of the Board of Directors has adopted an after-payout (“APO”) incentive plan for officers, key employees and consultants who promote our drilling and acquisition programs.  The Compensation Committee’s objective in adopting this plan is to further align the interests of the participants with ours by granting the participants an APO interest in the production developed, directly or indirectly, by the participants.  The plan generally provides for the creation of a series of partnerships or participation arrangements, which are treated as partnerships for tax purposes (“APO Partnerships”), between us and the participants, to which we contribute a portion of our economic interest in wells drilled or acquired within certain areas.  Generally, we pay all costs to acquire, drill and produce applicable wells and receive all revenues until we have recovered all of our costs, plus interest (“payout”).  At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the APO Partnerships.  Between 5% and 7.5% of our economic interests in specified wells drilled or acquired by us subsequent to October 2002 are subject to the APO incentive plan.  We record our allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in our consolidated financial statements.  Participants in the APO Incentive Plan are immediately vested in all future amounts payable under the plan.


 
 
F-19

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
 
    The Compensation Committee has also authorized the formation of the APO Reward Plan which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations.  The wells subject to an APO Reward Plan are not included in the APO Incentive Plan.  Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan.  Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area.  Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan.  To date, we have granted awards under the APO Reward Plan in seven specified areas, each of which established a quarterly bonus amount equal to 7% of the APO cash flow from wells drilled or recompleted in the respective areas after the effective date set forth in each plan, which dates range from January 1, 2007 to August 9, 2010.  Under these seven awards, the full vesting dates for future amounts payable under the plan for one award is November 4, 2011, three awards are August 9, 2012, and three awards are May 5, 2013.
 
    In January 2007, we granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan which established a quarterly bonus amount for participants equal to the after-payout cash flow from a 22.5% working interest in one well.  Under the plan, two-thirds of the quarterly bonus amount is payable to the participants until the full vesting date of October 25, 2011.  After the full vesting date, the deferred portion of the quarterly bonus amount, with interest at 4.83% per year, as well as 100% of all subsequent quarterly bonus amounts, are payable to participants.
 
    To continue as a participant in the APO Reward Plan or the SWR Reward Plan, participants must remain in the employment or service of the Company through the full vesting date established for each plan.  The full vesting date may be accelerated in the event of a change of control or sale transaction, as defined in the plan documents.
 
    We recognize compensation expense related to the APO Partnerships based on the estimated value of economic interests conveyed to the participants.  Estimated compensation expense applicable to the APO Reward Plan and SWR Reward Plan is recognized over the applicable vesting periods, which range from two years to five years.  We recorded compensation expense of $13.9 million in 2010 and $2.8 million in 2009 in connection with all non-equity award plans.

9.             Transactions with Affiliates

    The Company and other entities (the “Williams Entities”) controlled by Mr. Williams are parties to an agreement (the “Service Agreement”) pursuant to which the Company furnishes services to, and receives services from, such entities.  Under the Service Agreement, as amended from time to time, CWEI provides legal, computer, payroll and benefits administration, insurance administration, tax preparation services, tax planning services, and financial and accounting services to the Williams Entities, as well as technical services with respect to certain oil and gas properties owned by the Williams Entities.  The Williams Entities provide business entertainment to or for the benefit of CWEI.  The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2010, 2009 and 2008.

 
 
F-20

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
 
   
2010
   
2009
   
2008
 
   
(In thousands)
 
Amounts received from the Williams Entities:
                 
Service Agreement:
                 
Services
  $ 513     $ 519     $ 581  
Insurance premiums and benefits
    859       826       868  
Reimbursed expenses
    319       300       467  
    $ 1,691     $ 1,645     $ 1,916  
Amounts paid to the Williams Entities:
                       
Rent(a) 
  $ 811     $ 895     $ 807  
Service Agreement:
                       
Business entertainment(b) 
    116       116       91  
Reimbursed expenses
    146       128       197  
    $ 1,073     $ 1,139     $ 1,095  
                                          
(a)   Rent amounts were paid to a Partnership within the Williams Entities.  The Company owns 31.9% of the Partnership and affiliates of the Company own 23.3%.
(b)   Consists of hunting and fishing rights pertaining to land owned by affiliates of Mr. Williams.

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

10.           Desta Drilling

 In 2006, we formed a drilling rig joint venture with Lariat Services, Inc. (“Lariat”).  Initially, we referred to this joint venture as Larclay JV, but in June 2009, we changed the legal name of the operating entity in the joint venture to Desta Drilling, LP (“Desta Drilling”).  Lariat was designated as the operator of the rigs and provided all management services on behalf of Desta Drilling.  To permit Desta Drilling to finance the construction of 12 drilling rigs and related equipment, we provided credit support in the form of (1) a limited guaranty to the secured lender in the original amount of $19.5 million, (2) a drilling contract with Desta Drilling that expired in 2009 under which we were obligated to use the drilling rigs or pay idle rig rates, and (3) a subordinated loan to Desta Drilling of $4.6 million to finance excess construction costs.  During the term of the drilling contract, we paid Desta Drilling $24.4 million in idle rig fees.  We and Lariat also made cash advances to Desta Drilling in the form of subordinated loans of $7.5 million each to provide additional financial support.

 We and Lariat each owned a 50% equity interest in Desta Drilling, but effective April 15, 2009, we entered into an agreement with Lariat whereby Lariat assigned to us their 50% equity interest  (the “Assignment”).  The Assignment from Lariat also included all of Lariat’s right, title and interest in the subordinated loans previously made by Lariat to Desta Drilling.  As consideration for the Assignment, CWEI assumed all of the obligations and liabilities of Lariat relating to Desta Drilling from and after the effective date, including Lariat’s obligations as operator of Desta Drilling’s rigs.  Upon consummation of the Assignment, CWEI contributed all of the subordinated loans to Desta Drilling’s capital.  In August 2009, we repaid in full all amounts outstanding under the secured term loan of Desta Drilling with borrowings of approximately $27.2 million under our revolving credit facility.

 Upon consummation of the Assignment, we adopted a plan of disposition whereby we committed to sell eight of the 12 drilling rigs owned by Desta Drilling.  The plan of disposition met the criteria under applicable accounting standards for the designated assets to be classified as held for sale.  We are required to value the designated assets at the lower of their carrying value or fair value, less cost to sell, as of the date the plan of disposition was adopted.  To estimate the fair value of the drilling rigs and related equipment owned by Desta Drilling on the measurement date of April 15, 2009, we used a weighting of the market approach and the discounted cash flow approach.  Level 3 inputs used in the determination of discounted cash flow included estimated rig utilization rates, gross profits from drilling operations, future capital costs required for equipment replacements, useful lives for the equipment and discount rates.  We weighted the values obtained through the market approach by 67% and the values obtained through the discounted cash flow approach by 33% to give greater emphasis to the lack of demand for drilling equipment on the measurement date.  We estimated the fair value of the designated assets to be approximately $18.8 million and recorded a related charge for impairment of property and equipment of approximately $32.1 million in our statement of operations during the second quarter of 2009.  Under applicable accounting standards, this plan of disposition did not qualify for discontinued operations reporting.

 
 
F-21

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 

 
 In December 2009, we modified the prior plan of disposition established in April 2009.  Based on significant improvements in oil prices, we escalated our developmental drilling program and put six of the drilling rigs previously held for sale back to work and transferred their estimated fair value of $11.4 million to property and equipment.  In the accompanying consolidated balance sheets at December 31, 2010 and December 31, 2009, assets held for sale were $8.8 million and $7.4 million, respectively, and consisted of two 2,000 horsepower drilling rigs and related equipment that was sold in February 2011 (see Note 18).

 In December 2010, we acquired two additional drillings rigs for $5 million to be used in our on-going developmental drilling programs.

11.         Sales of Assets and Impairments of Inventory

    Net gains and losses on sales of assets and impairments of inventory for the years ended December 31, 2010, 2009 and 2008 are as follows:

   
2010
   
2009
   
2008
 
   
(In thousands)
 
Gain on sales of assets                                                
  $ 3,680     $ 796     $ 44,503  
                         
Loss on sales of assets and impairment
                       
of inventory:
                       
Loss on sales of assets                                            
    (1,655 )     (348 )     (2,122 )
Impairment of inventory                                            
    (95 )     (4,934 )     -  
      (1,750 )     (5,282 )     (2,122 )
                         
Net gain (loss)                                                 
  $ 1,930     $ (4,486 )   $ 42,381  

 In June 2010, we sold our interests in 22 operated and 76 non-operated producing wells in North Louisiana for net proceeds of $73.1 million, after giving effect to customary closing adjustments and the allocation of approximately $2 million of proceeds to applicable APO Partnerships (see Note 8), resulting in a loss on the sale of approximately $1.4 million during the second quarter of 2010.  Proceeds from the sale were used to repay indebtedness under our revolving credit facility.  The assets that were sold in this transaction represented substantially all of our proved oil and gas properties in North Louisiana but did not meet the criteria for treatment as discontinued operations under applicable accounting standards.

 Additionally in August 2010, we sold our interest in a non-operated well and related leasehold interests in North Louisiana for net proceeds of $2.9 million, all of which was recorded as a gain on sale of assets.

 In June 2010, we acquired from a group of private investors an undivided 14% working interest in 36 Wolfberry operated wells in Andrews County, Texas for $9.6 million, after customary closing adjustments.  This purchase increased our working interest in these 36 wells to 100%.  In addition to the oil and gas reserves attributable to the acquired interests, the Company increased its stake in approximately 5,700 gross acres under lease in this area from 86% to 100%.

 In 2008, we sold our interests in 16 producing wells for proceeds of $89.2 million and recorded a gain of approximately $33.1 million in the transaction.  We also sold two 2,000 horsepower drilling rigs and a well servicing unit for aggregate proceeds of $23.6 million and recorded an aggregate gain of $5.7 million.  Also in 2008, we sold our interest in a prospect in North Louisiana for proceeds of $3.1 million and recorded a gain of $3 million.

    We maintain an inventory of tubular goods and other well equipment for use in our exploration and development drilling activities.  Inventory is carried at the lower of average cost or estimated fair market value.  We categorize the measurement of fair value of inventory as Level 2 under applicable accounting standards.  To determine estimated fair value of inventory, we subscribe to market surveys and obtain quotes from equipment dealers for similar equipment.  We then correlate the data as needed to estimate the fair value of the specific items (or groups of similar items) in our inventory.  If the estimated fair values for those specific items (or groups of similar items) in our inventory are less than the related average cost, a provision for impairment is made.


 
 
F-22

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 

 
12.           Commitments and Contingencies

    Leases
    We lease office space from affiliates and nonaffiliates under noncancelable operating leases.  Rental expense pursuant to the office leases amounted to $1 million, $1.1 million and $997,000 for the years ended December 31, 2010, 2009 and 2008, respectively.

Future minimum payments under noncancelable leases at December 31, 2010, are as follows:

   
Leases
       
   
Capital(a)
   
Operating
   
Total
 
   
(In thousands)
 
2011                                                
  $ 885     $ 1,123     $ 2,008  
2012                                                
    692       389       1,081  
2013                                                
    226       214       440  
Thereafter                                                
    -       13       13  
Total minimum lease payments
  $ 1,803     $ 1,739     $ 3,542  
                                         
          (a)      Relates to vehicle leases.

    Legal Proceedings
    CWEI is a defendant in several lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations.

13.           Impairment of Property and Equipment

    We impair our long-lived assets, including oil and gas properties and contract drilling equipment, when estimated undiscounted future net cash flows of an asset are less than its carrying value.  The amount of any such impairment is recognized based on the difference between the carrying value and the estimated fair value of the asset.    We categorize the measurement of fair value of these assets as Level 3 inputs.  We estimate the fair value of the impaired property by applying weighting factors to fair values determined under three different methods: discounted cash flow method, flowing daily production method and proved reserves per BOE method.  We then assign applicable weighting factors based on the relevant facts and circumstances.  We recorded provisions for impairment of proved properties of $11.9 million in 2010, $27 million in 2009, and $12.9 million in 2008.  The 2010 provision related primarily to $11.1 million for certain non-core properties in the Permian Basin.  The 2009 provision related primarily to $21.6 million for certain properties in South Louisiana.  The 2008 provision related primarily to oil and gas proved property impairments of $11.3 million for the Margarita #1 well on our Deep Bossier prospect.

    We impair our unproved oil and gas properties when we determine that a prospect’s carrying value exceeds its estimated fair value.  We categorize the measurement of fair value of these assets as Level 3 inputs.  Unproved properties are nonproducing and do not have estimable cash flow streams.  Therefore, we estimate the fair value of individually significant prospects by obtaining, when available, information about recent market transactions in the vicinity of the prospects and adjust the market data as needed to give consideration to location of the prospects to known fields and reservoirs, the extent of geological and geophysical data on the prospects, the remaining terms of leases holding the acreage in the prospects, recent drilling results in the vicinity of the prospects, and other risk-related factors such as drilling and completion costs, estimated product prices and other economic factors.  Individually insignificant prospects are grouped and impaired based on remaining lease terms and our historical experience with similar prospects.  We recorded provisions for impairment of unproved properties aggregating $7.8 million, $36.1 million and $51.2 million in 2010, 2009 and 2008, respectively, and charged these impairments to exploration costs in the accompanying statements of operations.


 
 
F-23

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 

 
14.           Quarterly Financial Data (Unaudited)

    The following table summarizes results for each of the four quarters in the years ended December 31, 2010 and 2009.
   
First
   
Second
   
Third
   
Fourth
       
   
Quarter
   
Quarter
   
Quarter
   
Quarter
   
Year
 
   
(In thousands, except per share)
 
Year ended December 31, 2010:
                             
Total revenues                                                        
  $ 79,831     $ 77,483     $ 85,232     $ 89,085     $ 331,631  
Operating income                                                        
  $ 20,873     $ 5,853     $ 27,083     $ 24,135     $ 77,944  
Net income (loss)(a)                                                        
  $ 16,675     $ 13,963     $ 11,623     $ (5,323 )   $ 36,938  
Net income (loss) per common share(b):
                                       
Basic                                                      
  $ 1.37     $ 1.15     $ .96     $ (.44 )   $ 3.04  
Diluted                                                      
  $ 1.37     $ 1.15     $ .96     $ (.44 )   $ 3.04  
Weighted average common shares outstanding:
                                       
Basic                                                      
    12,146       12,146       12,146       12,153       12,148  
Diluted                                                      
    12,146       12,146       12,146       12,153       12,148  
                                         
Year ended December 31, 2009:
                                       
Total revenues                                                        
  $ 57,782     $ 60,503     $ 62,426     $ 75,250     $ 255,961  
Operating loss                                                        
  $ (31,620 )   $ (33,462 )   $ (19,571 )   $ (56,772 )   $ (141,425 )
Net loss(a)                                                        
  $ (22,315 )   $ (38,608 )   $ (13,600 )   $ (42,892 )   $ (117,415 )
Net loss per common share(b):
                                       
Basic                                                      
  $ (1.84 )   $ (3.18 )   $ (1.12 )   $ (3.53 )   $ (9.67 )
Diluted                                                      
  $ (1.84 )   $ (3.18 )   $ (1.12 )   $ (3.53 )   $ (9.67 )
Weighted average common shares outstanding:
                                       
Basic                                                      
    12,122       12,142       12,144       12,144       12,138  
Diluted                                                      
    12,122       12,142       12,144       12,144       12,138  
              
(a)
The Company recorded an $11.1 million charge for impairment of property and equipment in the second quarter of 2010 and an $800,000 charge in the third quarter of 2010.  The Company recorded a $32.1 million charge for impairment of property and equipment in the second quarter of 2009 and a $27 million charge in the fourth quarter of 2009.
(b)
The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year since each period’s computation is based on the weighted average number of common shares outstanding during each period.
 

15.           Costs of Oil and Gas Properties

    The following table sets forth certain information with respect to costs incurred in connection with the Company's oil and gas producing activities during the years ended December 31, 2010, 2009 and 2008.

   
2010
   
2009
   
2008
 
 
 
(In thousands)
 
Property acquisitions:
                 
Proved                                                   
  $ 9,556     $ -     $ -  
Unproved                                                   
    29,680       12,558       36,397  
Developmental costs                                                           
    238,197       86,672       260,073  
Exploratory costs                                                           
    7,528       32,758       51,237  
Total                                                   
  $ 284,961     $ 131,988     $ 347,707  
                         


 
 
F-24

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 

 
    The following table sets forth the capitalized costs for oil and gas properties as of December 31, 2010 and 2009.

   
2010
   
2009
 
   
(In thousands)
 
Proved properties                                                                                
  $ 1,655,217     $ 1,532,508  
Unproved properties                                                                                
    52,035       47,156  
Total capitalized costs                                                                                
    1,707,252       1,579,664  
Accumulated depreciation, depletion and amortization
    (983,119 )     (945,047 )
Net capitalized costs                                                                        
  $ 724,133     $ 634,617  

16.           Segment Information

 We have two reportable operating segments, which are oil and gas exploration and production and contract drilling services. The following tables present selected financial information regarding our operating segments for 2010, 2009 and 2008.

         
Contract
   
Intercompany
   
Consolidated
 
For the Year Ended December 31, 2010
 
Oil and Gas
   
Drilling
   
Eliminations
   
Total
 
   
(In thousands)
 
Revenues
  $ 331,631     $ 35,269     $ (35,269 )   $ 331,631  
Depreciation, depletion and amortization(a)
    111,353       10,044       (8,344 )     113,053  
Other operating expenses(b) 
    139,514       26,614       (25,494 )     140,634  
Interest expense
    24,397       5       -       24,402  
Other expense
    (4,030 )     -       -       (4,030 )
Income (loss) before income taxes
    60,397       (1,394 )     (1,431 )     57,572  
Income tax expense (benefit)
    21,122       (488 )     -       20,634  
Net income (loss)
    39,275       (906 )     (1,431 )     36,938  
Less (income) loss attributable to
                               
noncontrolling interest, net of tax
    -       -       -       -  
Net income (loss) attributable to Clayton
                               
Williams Energy, Inc.
  $ 39,275     $ (906 )   $ (1,431 )   $ 36,938  
Total assets
  $ 854,621     $ 37,727     $ (1,431 )   $ 890,917  
Additions to property and equipment
  $ 286,285     $ 16,953     $ -     $ 303,238  
                                 
                                 


 
 
F-25

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


         
Contract
   
Intercompany
   
Consolidated
 
For the Year Ended December 31, 2009
 
Oil and Gas
   
Drilling
   
Eliminations
   
Total
 
   
(In thousands)
 
Revenues
  $ 249,280     $ 27,000     $ (20,319 )   $ 255,961  
Depreciation, depletion and amortization(a)
    154,328       38,027       (3,557 )     188,798  
Other operating expenses(b) 
    214,282       11,054       (16,748 )     208,588  
Interest expense
    22,267       1,491       -       23,758  
Other expense
    14,873       -       -       14,873  
Loss before income taxes
    (156,470 )     (23,572 )     (14 )     (180,056 )
Income tax benefit
    (55,864 )     (8,232 )     -       (64,096 )
Net loss
    (100,606 )     (15,340 )     (14 )     (115,960 )
Less (income) loss attributable to
                               
noncontrolling interest, net of tax
    783       (2,238 )     -       (1,455 )
Net loss attributable to Clayton
                               
Williams Energy, Inc.
  $ (99,823 )   $ (17,578 )   $ (14 )   $ (117,415 )
Total assets
  $ 773,631     $ 42,623     $ (31,650 )   $ 784,604  
Additions to property and equipment
  $ 133,860     $ 4,696     $ -     $ 138,556  

                         
         
Contract
   
Intercompany
   
Consolidated
 
For the Year Ended December 31, 2008
 
Oil and Gas
   
Drilling
   
Eliminations
   
Total
 
   
(In thousands)
 
Revenues
  $ 514,686     $ 64,153     $ (13,322 )   $ 565,517  
Depreciation, depletion and amortization(a)
    124,874       10,651       (2,101 )     133,424  
Other operating expenses(b) 
    232,047       47,493       (9,728 )     269,812  
Interest expense
    21,134       3,860       -       24,994  
Other income
    (81,282 )     -       -       (81,282 )
Income (loss) before income taxes
    217,913       2,149       (1,493 )     218,569  
Income tax expense
    76,546       781       -       77,327  
Net income (loss)
    141,367       1,368       (1,493 )     141,242  
Less (income) loss attributable to
                               
noncontrolling interest, net of tax
    381       (1,089 )     -       (708 )
Net income (loss) attributable to Clayton
                               
Williams Energy, Inc.
  $ 141,748     $ 279     $ (1,493 )   $ 140,534  
Total assets
  $ 864,260     $ 85,006     $ (5,857 )   $ 943,409  
Additions to property and equipment
  $ 350,184     $ 1,195     $ (1,493 )   $ 349,886  
                                              
(a)     Includes impairment of property and equipment.
(b)     Includes the following expenses:  production, exploration, natural gas services, accretion of abandonment obligations, general and administrative and loss on sales of assets and impairment of inventory.

17.           Guarantor Financial Information

    In July 2005, CWEI (“Issuer”) issued $225 million of Senior Notes (see Note 3).  All of the Issuer’s wholly-owned and active subsidiaries which have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the Senior Notes are referred to as “Guarantor Subsidiaries” in the following condensed consolidating financial statements.  Prior to August 2009, neither Desta Drilling nor WCEP, LLC, the general partner of West Coast Energy Properties, L.P., an affiliated limited partnership, were guarantors of the Senior Notes, but in August 2009, Desta Drilling became a guarantor of the Senior Notes.  As a result, we have reclassified the condensed consolidating financial statements prior to December 31, 2009 in this Note 17 to include the accounts of Desta Drilling in the Guarantor Subsidiaries column and to reflect only the accounts of WCEP, LLC in the Non-Guarantor Subsidiary column.


 
 
F-26

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 

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

Condensed Consolidating Balance Sheet
December 31, 2010
(Dollars in thousands)
             
Non-
             
         
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
                               
Current assets                                  
  $ 164,630     $ 137,156     $ 1,132     $ (189,097 )   $ 113,821  
Property and equipment, net
    430,870       329,957       6,262       -       767,089  
Investments in subsidiaries
    114,247       -       -       (114,247 )     -  
Other assets                                  
    9,837       170       -       -       10,007  
Total assets                               
  $ 719,584     $ 467,283     $ 7,394     $ (303,344 )   $ 890,917  
                                         
Current liabilities                                  
  $ 201,031     $ 121,664     $ 122     $ (189,097 )   $ 133,720  
Non-current liabilities:
                                       
Long-term debt                               
    385,000       -       -       -       385,000  
Fair value of derivatives
    3,409       -       -       -       3,409  
Other                               
    56,494       62,700       145       (3 )     119,336  
      444,903       62,700       145       (3 )     507,745  
                                         
Equity                                  
    73,650       282,919       7,127       (114,244 )     249,452  
                                         
Total liabilities and equity
  $ 719,584     $ 467,283     $ 7,394     $ (303,344 )   $ 890,917  


Condensed Consolidating Balance Sheet
December 31, 2009
(Dollars in thousands)
             
Non-
             
         
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
                               
Current assets                                  
  $ 205,950     $ 146,443     $ 920     $ (249,716 )   $ 103,597  
Property and equipment, net
    326,149       337,566       6,331       -       670,046  
Investments in subsidiaries
    112,018       -       -       (112,018 )     -  
Other assets                                  
    10,348       613       -       -       10,961  
Total assets                               
  $ 654,465     $ 484,622     $ 7,251     $ (361,734 )   $ 784,604  
                                         
Current liabilities                                  
  $ 153,505     $ 180,357     $ 127     $ (249,716 )   $ 84,273  
Non-current liabilities:
                                       
Long-term debt                               
    395,000       -       -       -       395,000  
Other                               
    31,039       61,883       136       (2 )     93,056  
      426,039       61,883       136       (2 )     488,056  
                                         
Equity                                  
    74,921       242,382       6,988       (112,016 )     212,275  
                                         
Total liabilities and equity
  $ 654,465     $ 484,622     $ 7,251     $ (361,734 )   $ 784,604  


 
 
F-27

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 

 
Condensed Consolidating Statement of Operations
Year Ended December 31, 2010
(Dollars in thousands)
             
Non-
             
         
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
                               
Total revenue                                  
  $ 209,046     $ 122,673     $ 723     $ (811 )   $ 331,631  
Costs and expenses                                  
    166,846       86,963       689       (811 )     253,687  
Operating income (loss)
    42,200       35,710       34       -       77,944  
Other income (expense)
    (26,801 )     6,282       147       -       (20,372 )
Income tax (expense) benefit
    (20,634 )     -       -       -       (20,634 )
Net income (loss)                               
  $ (5,235 )   $ 41,992     $ 181     $ -     $ 36,938  


Condensed Consolidating Statement of Operations
Year Ended December 31, 2009
(Dollars in thousands)
             
Non-
             
         
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
                               
Total revenue                                  
  $ 148,347     $ 108,098     $ 617     $ (1,101 )   $ 255,961  
Costs and expenses                                  
    254,655       142,807       1,025       (1,101 )     397,386  
Operating income (loss)
    (106,308 )     (34,709 )     (408 )     -       (141,425 )
Other income (expense)
    (42,820 )     4,043       146       -       (38,631 )
Income tax (expense) benefit
    64,096       -       -       -       64,096  
Noncontrolling interest,
                                       
  net of tax                                  
    (1,455 )     -       -       -       (1,455 )
Net income (loss)                               
  $ (86,487 )   $ (30,666 )   $ (262 )   $ -     $ (117,415 )


Condensed Consolidating Statement of Operations
Year Ended December 31, 2008
(Dollars in thousands)
             
Non-
             
         
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
                               
Total revenue                                  
  $ 346,570     $ 237,307     $ 1,033     $ (19,393 )   $ 565,517  
Costs and expenses                                  
    254,093       166,310       733       (17,900 )     403,236  
Operating income (loss)
    92,477       70,997       300       (1,493 )     162,281  
Other income (expense)
    65,414       (9,362 )     236       -       56,288  
Income tax (expense) benefit
    (77,327 )     -       -       -       (77,327 )
Noncontrolling interest,
                                       
  net of tax                                  
    (708 )     -       -       -       (708 )
Net income (loss)                               
  $ 79,856     $ 61,635     $ 536     $ (1,493 )   $ 140,534  



 
 
F-28

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 

 
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2010
(Dollars in thousands)
             
Non-
             
         
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
                               
Operating activities                                  
  $ 114,960     $ 84,490     $ 457     $ 8,344     $ 208,251  
Investing activities                                  
    (161,742 )     (33,440 )     (257 )     (8,344 )     (203,783 )
Financing activities                                  
    39,983       (49,723 )     (21 )     -       (9,761 )
Net increase (decrease) in
                                       
cash and cash equivalents
    (6,799 )     1,327       179       -       (5,293 )
Cash at the beginning of
                                       
the period                                 
    11,839       1,344       830       -       14,013  
Cash at end of the period
  $ 5,040     $ 2,671     $ 1,009     $ -     $ 8,720  


Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2009
(Dollars in thousands)
             
Non-
             
         
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
                               
Operating activities                                  
  $ (28,867 )   $ 129,934     $ 113     $ 3,531     $ 104,711  
Investing activities                                  
    (186,872 )     21,872       (67 )     (3,531 )     (168,598 )
Financing activities                                  
    192,197       (155,516 )     20       -       36,701  
Net increase (decrease) in
                                       
cash and cash equivalents
    (23,542 )     (3,710 )     66       -       (27,186 )
Cash at the beginning of
                                       
the period                                 
    35,381       5,054       764       -       41,199  
Cash at end of the period
  $ 11,839     $ 1,344     $ 830     $ -     $ 14,013  


Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2008
(Dollars in thousands)
             
Non-
             
         
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
                               
Operating activities                                  
  $ 319,182     $ 59,737     $ 960     $ 2,101     $ 381,980  
Investing activities                                  
    (126,079 )     (110,366 )     (329 )     (2,101 )     (238,875 )
Financing activities                                  
    (163,047 )     48,797       -       -       (114,250 )
Net increase (decrease) in
                                       
cash and cash equivalents
    30,056       (1,832 )     631       -       28,855  
Cash at the beginning of
                                       
the period                                 
    5,325       6,886       133       -       12,344  
Cash at end of the period
  $ 35,381     $ 5,054     $ 764     $ -     $ 41,199  

18.           Subsequent Events

    We have evaluated events and transactions that occurred after the balance sheet date of December 31, 2010.  In February 2011, we sold two 2,000 horsepower drilling rigs and related equipment for $22 million of total consideration, and we expect to record a gain on the sale of approximately $13.2 million during the first quarter of 2011.  Proceeds from the sale consisted of $11 million cash and an $11 million promissory note due in August 2011.

 
 
F-29

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 

 
19.           Oil and Gas Reserve Information (Unaudited)

    The estimates of proved oil and gas reserves utilized in the preparation of the consolidated financial statements were prepared by independent petroleum engineers.  Such estimates are in accordance with guidelines established by the SEC and the FASB.  All of our reserves are located in the United States.  For information about our results of operations from oil and gas activities, see the accompanying consolidated statements of operations.

    We emphasize that reserve estimates are inherently imprecise.  Accordingly, the estimates are expected to change as more current information becomes available.  In addition, a portion of our proved reserves are classified as proved developed nonproducing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.

    We did not have any capital costs relating to exploratory wells pending the determination of proved reserves for the years ended December 31, 2010, 2009 and 2008.

    The following table sets forth estimated proved oil and gas reserves together with the changes therein (oil in MBbls, gas in MMcf, gas converted to MBOE by dividing MMcf by six) for the years ended December 31, 2010, 2009 and 2008.

   
Oil
   
Gas
   
MBOE
 
Proved reserves:
                 
December 31, 2007                                                                      
    27,946       123,156       48,472  
Revisions                                                                
    (5,620 )     (15,938 )     (8,276 )
Extensions and discoveries                                                                
    2,057       23,824       6,028  
Sales of minerals-in-place                                                                
    (473 )     (8,560 )     (1,900 )
Production                                                                
    (3,134 )     (18,553 )     (6,226 )
December 31, 2008                                                                      
    20,776       103,929       38,098  
Revisions                                                                
    297       (15,898 )     (2,353 )
Extensions and discoveries                                                                
    2,985       4,021       3,655  
Production                                                                
    (3,105 )     (15,949 )     (5,763 )
December 31, 2009                                                                      
    20,953       76,103       33,637  
Revisions                                                                
    1,511       4,628       2,282  
Extensions and discoveries                                                                
    18,969       25,343       23,193  
Purchases of minerals-in-place                                                                
    317       190       349  
Sales of minerals-in-place                                                                
    (268 )     (16,017 )     (2,937 )
Production                                                                
    (3,667 )     (10,750 )     (5,459 )
December 31, 2010                                                                      
    37,815       79,497       51,065  
                         
Proved developed reserves:
                       
December 31, 2008                                                                      
    16,815       87,340       31,372  
December 31, 2009                                                                      
    16,779       70,840       28,586  
December 31, 2010                                                                      
    24,570       59,409       34,472  


 
 
F-30

 
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 

 
    Net upward revisions of 2,282 MBOE consisted of upward revisions of 6,005 MBOE related to pricing and downward revisions of 3,723 MBOE related to performance.  Upward revisions of 6,005 MBOE were attributable to the effects of higher product prices on the estimated quantities of proved reserves.  Most of the downward performance revisions resulted from the reclassification of reserves from proved undeveloped to probable.
   
    The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2010, 2009 and 2008 was as follows:

   
2010
   
2009
   
2008
 
   
(In thousands)
 
Future cash inflows                                                                      
  $ 3,058,637     $ 1,311,330     $ 1,374,684  
Future costs:
                       
Production                                                                
    (1,127,744 )     (588,564 )     (569,053 )
Development                                                                
    (308,420 )     (86,918 )     (104,223 )
Income taxes                                                                
    (455,980 )     (119,343 )     (126,819 )
Future net cash flows                                                                      
    1,166,493       516,505       574,589  
10% discount factor                                                                      
    (482,055 )     (152,232 )     (169,423 )
Standardized measure of discounted net cash flows
  $ 684,438     $ 364,273     $ 405,166  

    Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the years ended December 31, 2010, 2009 and 2008 were as follows:

   
2010
   
2009
   
2008
 
   
(In thousands)
 
Standardized measure, beginning of period
  $ 364,273     $ 405,166     $ 925,969  
Net changes in sales prices, net of production costs
    192,193       12,007       (600,719 )
Revisions of quantity estimates                                                                    
    56,190       (34,419 )     (101,889 )
Accretion of discount                                                                    
    45,963       51,123       131,824  
Changes in future development costs, including
                       
  development costs incurred that reduced future
                       
  development costs                                                                    
    39,689       33,217       69,466  
Changes in timing and other                                                                    
    20,839       (31,567 )     (9,385 )
Net change in income taxes                                                                    
    (210,090 )     15,457       299,193  
Future abandonment cost, net of salvage                                                                    
    (1,107 )     (5,075 )     (548 )
Extensions and discoveries                                                                    
    441,719       89,546       155,006  
Sales, net of production costs                                                                    
    (244,792 )     (171,182 )     (373,988 )
Purchases of minerals-in-place                                                                    
    9,290       -       -  
Sales of minerals-in-place                                                                    
    (29,729 )     -       (89,763 )
Standardized measure, end of period.                                                                    
  $ 684,438     $ 364,273     $ 405,166  

    The estimated present value of future cash flows relating to estimated proved reserves is extremely sensitive to prices used at any measurement period.  The average prices used for each commodity for the years ended December 31, 2010, 2009 and 2008 were as follows:

   
Average Price
 
   
Oil (a)
   
Gas
 
As of December 31:
           
2010 (b)                                                                                     
  $ 72.36     $ 5.44  
2009 (b)                                                                                     
  $ 54.81     $ 3.71  
2008                                                                                     
  $ 42.03     $ 5.90  
              
 
(a)
Includes natural gas liquids.
 
(b)
Average prices for December 31, 2010 and 2009 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from January through December during each respective calendar year.




 
 
F-31

 


Schedule II – Valuation and Qualifying Accounts
 
   
Balance at
               
Balance at
 
   
Beginning of
               
End of
 
Description
 
Period
   
Additions(a)
   
Deductions(b)
   
Period
 
         
(In thousands)
       
Year Ended December 31, 2010:
                       
Allowance for doubtful accounts - Joint interest and other
  $ 1,273     $ -     $ -     $ 1,273  
Year Ended December 31, 2009:
                               
Allowance for doubtful accounts - Joint interest and other
  $ 1,387     $ -     $ (114 )   $ 1,273  
Year Ended December 31, 2008:
                               
Allowance for doubtful accounts - Joint interest and other
  $ 1,387     $ -     $ -     $ 1,387  
                                              
(a)    Additions relate to provisions for doubtful accounts.
                         
(b)    Deductions relate to the write-off or recovery of the provisions for doubtful accounts.
                 




S-1